Boardwalk Pipeline Partners (BWP) 10-K2021 FY Annual report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 (Mark One)

For the fiscal year ended December 31, 2021

OR

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes☒ No☐

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

TABLE OF CONTENTS

2021 FORM 10-K

BOARDWALK PIPELINE PARTNERS, LP

PART I

Unless the context otherwise requires, references in this Annual Report on Form 10-K to “we,” “our,” “us” or like terms refer to the business of Boardwalk Pipeline Partners, LP and its consolidated subsidiaries.

We are a Delaware limited partnership formed in 2005. Our business, which is conducted by our primary subsidiary, Boardwalk Pipelines, LP (Boardwalk Pipelines) and its operating subsidiaries (together, the operating subsidiaries), consists of integrated pipeline and storage systems for natural gas and natural gas liquids and other hydrocarbons (herein referred to together as NGLs). All of our operations are conducted by the operating subsidiaries. As of December 31, 2021, Boardwalk Pipelines Holding Corp., a wholly owned subsidiary of Loews Corporation (Loews), owned directly or indirectly, 100% of our capital.

We operate in the midstream portion of the natural gas and NGLs industry, providing transportation and storage for those commodities. We own approximately 14,065 miles of natural gas and NGLs pipelines and underground storage caverns having aggregate capacity of approximately 213.0 billion cubic feet (Bcf) of working natural gas and 32.1 million barrels (MMBbls) of NGLs. Our natural gas pipeline systems are located in the Gulf Coast region, Oklahoma, Arkansas, Tennessee, Kentucky, Illinois, Indiana and Ohio, and our NGLs pipelines and storage facilities are located in Louisiana and Texas.

We serve a broad mix of customers, including electric power generators, producers and marketers of natural gas, local distribution companies (LDCs), industrial users, exporters of liquefied natural gas (LNG), 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 fixed fees based on the quantity of capacity reserved, regardless of use. Other fees are based on actual utilization of the capacity under firm contracts and contracts for interruptible services. Contracts for our NGLs services are generally fee-based or based on minimum volume requirements, while others are dependent on actual volumes transported or stored. For the year ended December 31, 2021, approximately 89% of our revenues were derived from capacity reservation fees under firm contracts, approximately 7% of our revenues were derived from fees based on utilization under firm contracts and approximately 4% of our revenues were derived from interruptible transportation, interruptible storage, parking and lending (PAL) and other services.

The maximum rates we can charge for most of our natural gas transportation services, as well as the general terms and conditions of those services, are established by, and subject to review and revision by, the Federal Energy Regulatory Commission (FERC). These rates are based upon certain assumptions to allow us the opportunity to recover the cost of providing these services and earn a reasonable return on equity. However, it is possible that we may not recover all of our costs or earn a return. We are authorized to charge market-based rates for the majority of our natural gas storage capacity pursuant to authority granted by the FERC. The Surface Transportation Board (STB) regulates the rates we charge for interstate service on our ethylene pipelines. The Louisiana Public Service Commission (LPSC) regulates the rates we charge for intrastate service within the state of Louisiana on our petrochemical and NGLs pipelines. The STB and LPSC require that our transportation rates are reasonable and that our practices cannot unreasonably discriminate among our shippers.

Our Pipeline and Storage Systems

We own and operate approximately 13,615 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 approximately 450 miles of NGLs pipelines in Louisiana and Texas. In 2021, our pipeline systems transported approximately 3.4 trillion cubic feet of natural gas and approximately 90.4 MMBbls of NGLs. Average daily throughput on our natural gas pipeline systems during 2021 was approximately 9.4 Bcf. Our natural gas storage facilities are comprised of fourteen underground storage fields located in four states with aggregate working gas capacity of approximately 213.0 Bcf and our NGLs storage facilities consist of eleven salt-dome caverns located in Louisiana with an aggregate storage capacity of approximately 32.1 MMBbls. We also own nine salt-dome caverns and related brine infrastructure 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 and Mid-Continent regions, 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 Barnett and Haynesville Shales 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 supply basins such as the Woodford and Scoop/Stack Shales in Oklahoma, the Fayetteville Shale in Arkansas, the Eagle Ford Shale in southern Texas and wellhead supplies in northern and southern Louisiana and Mississippi, and we also receive gas in the Lebanon, Ohio, area from the Marcellus and Utica Shales located in the northeastern U.S. Our NGLs pipeline systems access the Gulf Coast petrochemical industry through our operations at our Choctaw Hub in the Mississippi River corridor area of Louisiana and the Sulphur Hub in the Lake Charles, Louisiana, area. We also access ethylene supplies at Port Neches, Texas, which we deliver to petrochemical-industry customers in Louisiana.

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

Gulf South has ten natural gas storage facilities. The two natural gas storage facilities located in Bistineau, Louisiana, and Jackson, Mississippi, have approximately 91.5 Bcf of working gas storage capacity from which Gulf South offers firm and interruptible storage service, including no-notice service (NNS), and are used to support pipeline operations. Gulf South also owns and operates eight high deliverability salt-dome natural gas storage caverns in Forrest County, Mississippi, having approximately 46.0 Bcf of total storage capacity, of which approximately 29.6 Bcf is working gas capacity, and owns undeveloped land which is suitable for up to five additional storage caverns. 

Texas Gas owns nine natural gas storage fields, of which it owns the majority of the working and base gas. Texas Gas uses this gas to meet the operational requirements of its transportation and storage customers and the requirements of its NNS customers. Texas Gas also uses its storage capacity to offer firm and interruptible storage services.

The following table provides information for our principal pipeline and storage systems as of February 8, 2022:

Current Growth Projects

Nature of Contracts

We contract with our customers to provide transportation and storage services on both a firm and interruptible basis. We also provide bundled firm transportation and storage services, such as NNS, interruptible PAL services for our customers, brine supply services for certain petrochemical customers and fractionation services.

Customers and Markets Served

Our delivery market has diversified over time, with increased deliveries to our end-use customers, whereas historically, our delivery markets were primarily to other pipelines who then delivered to the end-use customers. As of December 31, 2021, we had approximately $9.1 billion of projected operating revenues under committed firm transportation agreements, of which our deliveries are expected to be as follows: power generators (31%), pipeline interconnects (22%), exporters of LNG (22%), industrial end-users (12%), LDCs (6%), storage activities (5%) and others (2%).

Government Regulation

The maximum rates that our FERC-regulated operating subsidiaries may charge for all aspects of the natural gas transportation services they provide are established through the FERC's cost-based rate-making process. Key determinants in the FERC's cost-based rate-making process are the costs of providing service, the volumes of gas being transported, the rate design, the allocation of costs between services, the capital structure and the rate of return a pipeline is permitted to earn. The maximum rates that may be charged by us for storage services on Texas Gas, except for services associated with a portion of the working gas capacity on that system, are also established through the FERC's cost-based rate-making process. The FERC has authorized us to charge market-based rates for firm and interruptible storage services for the majority of our other natural gas storage facilities. None of our FERC-regulated entities currently have an obligation to file a new rate case, and Gulf South is prohibited from filing a rate case until May 1, 2023, subject to certain exceptions.

Some of our other subsidiaries transport natural gas in intrastate commerce under the rules and regulations established by the Texas Railroad Commission and in interstate commerce that is subject to FERC jurisdiction under Section 311 of the NGPA. The maximum rates for services are established under Section 311 of the NGPA and are generally subject to review every five years by the FERC.

The FERC issued a Notice of Inquiry (NOI) on April 19, 2018 (2018 NOI) initiating a review of its policies on certification of natural gas pipelines, including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities (1999 Policy Statement), issued in 1999, that is used to determine whether to grant certificates for new pipeline projects. On February 18, 2021, the FERC issued another NOI (2021 NOI), reopening its review of the 1999 Policy Statement. Comments on the 2021 NOI were due on May 26, 2021, and although the FERC has not taken any further action regarding the 2018 NOI or 2021 NOI, we are unable to predict what, if any, changes may be proposed as a result of the NOIs that will affect our natural gas pipeline operations or when such proposals, if any, might become effective.

Legislation in the past decade has resulted in more stringent mandates for pipeline safety and has charged PHMSA with developing and adopting regulations that impose increased pipeline safety requirements on pipeline operators. In particular, the NGPSA and HLPSA were amended by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (2011 Act), the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (2016 Act) and, most recently, the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2020 (2020 Act). Each of these laws imposed increased pipeline safety obligations on pipeline operators. The 2011 Act increased the penalties for safety violations, established additional safety requirements for newly constructed pipelines and required studies of safety issues that could result in the adoption of new regulatory requirements by PHMSA for existing pipelines. The 2016 Act, among other things, required PHMSA to complete its outstanding mandates under the 2011 Act and develop new safety standards for natural gas storage facilities. The 2020 Act reauthorized PHMSA through fiscal year 2023 and directed the agency to move forward with several regulatory initiatives, including obligating operators of non-rural gas gathering lines and new and existing transmission and

With the adoption of the 2011 Act, the 2016 Act and the 2020 Act, there exist mandates for PHMSA to make pipeline safety requirements more stringent. As a result, PHMSA has issued a series of significant rulemakings. In October 2019, PHMSA published a final rule imposing numerous new requirements on onshore gas transmission pipelines relating to maximum allowable operating pressure (MAOP) reconfirmation and exceedance reporting, the integrity assessment of additional pipeline mileage found in MCAs and Class 3 and Class 4 non-HCAs by 2033, and the consideration of seismicity as a risk factor in integrity management. PHMSA published a second final rule in October 2019 for hazardous liquid transmission and gathering pipelines that significantly extends and expands the reach of certain of its integrity management requirements, and that requires the accommodation of in-line inspection tools by 2039 unless the pipeline cannot be modified to permit such accommodation, increased annual, accident and safety-related conditional reporting requirements, and expanded use of leak detection systems beyond HCAs. PHMSA also published final rules during February and July 2020 that amended the minimum safety requirements related to natural gas storage facilities, including wells, wellbore tubing and casing, and added applicable reporting requirements. In November 2021, PHMSA issued a final rule that will impose safety regulations on approximately 400,000 miles of previously unregulated onshore gas gathering lines that, among other things, will impose criteria for inspection and repair of fugitive emissions, extend reporting requirements to all gas gathering operators and apply a set of minimum safety requirements to certain gas gathering pipelines with large diameters and high operating pressures. Separately, in June 2021, PHMSA issued an Advisory Bulletin advising pipeline and pipeline facility operators of applicable requirements to update their inspection and maintenance plans for the elimination of hazardous leaks and minimization of natural gas released from pipeline facilities. PHMSA, together with state regulators, is expected to commence inspection of these plans in 2022. These new and any future regulations adopted by PHMSA may impose more stringent requirements applicable to integrity management programs and other pipeline safety aspects of our operations, which could cause us to incur increased capital and operating costs and operational delays.

Many states where we operate also have, or are developing, similar environmental or occupational health and safety legal requirements governing many of the same types of activities, and those requirements can be more stringent than those adopted under federal laws and regulations. Failure to comply with these federal, state and local laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of corrective or remedial obligations, the incurrence of capital expenditures, the occurrence of delays, denials or cancellations in permitting or the development or expansion of projects and the issuance of orders enjoining performance of some or all of our operations in affected areas.

Historically, our environmental compliance costs have not had a material adverse effect on our results of operations, but there can be no assurance that future compliance with existing requirements will not materially affect us or that the current regulatory standards will not become more onerous in the future, resulting in more significant costs to maintain compliance and increased exposure to significant liabilities. Note 5 in Part II, Item 8. of this Annual Report on Form 10-K contains information regarding environmental compliance.

Climate Change

We have been focused on seeking to meet and, in certain instances, pursing projects aimed at exceeding regulatory obligations (such as those found in the CAA) by reducing emissions of regulated air pollutants, including methane, associated with our pipeline transportation and storage assets. For example, in selecting new compression equipment for growth or asset reliability projects, we consider air emissions as a component in the decision-making process and, when appropriate, place increased emphasis in the selection process on equipment with emissions performance that exceeds applicable federal standards. Several of our reliability projects over the last few years have resulted in replacement of older, higher-emitting compressor drivers with units equipped with advanced emission control systems. As a result, these projects have resulted in decreases in emissions of nitrogen oxides and other air pollutants.

We have identified the reduction of GHG emissions as an area of focus and look for opportunities to reduce emissions using a variety of strategies, including the following:

However, we cannot guarantee that we will be able to implement any of the opportunities we may review or explore, or, for any opportunities we do choose to implement, to implement them in their intended manner or within a specific timeframe or across all operational assets.

We are active members of several industry groups. These include the Our Nation’s Energy Future Coalition (ONE Future), a group of natural gas companies working together to voluntarily reduce methane emissions across the natural gas supply chain. ONE Future’s goal is to lower methane emissions to less than 1% of total natural gas produced by 2025. We also adhere to the Interstate Natural Gas Association of America’s Methane Emissions Commitments and Climate Statement aimed at improving practices to minimize methane emissions from interstate natural gas transmission and storage operations in a prudent and environmentally responsible manner. We also participate in the EPA Natural Gas STAR Program for voluntary methane and GHG reductions and reporting.

Human Capital

At December 31, 2021, we had approximately 1,210 employees, approximately 95 of whom were included under collective bargaining agreements. A satisfactory relationship exists between management and our employees. As of December 31, 2021, approximately 21% of our workforce was comprised of women and women held 22% of our management roles (considered vice president and above). Minorities comprised 13% of our workforce and held 8% of our management roles.

Hiring and retaining the right people is critical to our long-term strategic success. We have programs in place to help employees build their knowledge, skills and experience, as well as to guide their career development. A cornerstone of our human capital strategy is our commitment to fostering a diverse and inclusive work environment, where all people are respected and encouraged to contribute their ideas. Employing individuals with different backgrounds and experiences helps meet the diverse needs of all our stakeholders.

We are part of a critical infrastructure industry whose customers and communities depend upon us to provide safe and reliable service. Our employees are essential to ensuring we continue to meet these objectives, and we consider safety in our day-to-day activities to be a primary core value. We want every person who lives near or works on our facilities to stay safe every day by also maintaining our strong commitment to safety.

Our business faces many risks and uncertainties. We have described below the material risks facing us. These risks and uncertainties could lead to events or circumstances that may have a material adverse effect on our business, financial condition, results of operations or cash flows. There may be additional risks that we do not yet know of or that we do not currently perceive to be as material that may also materially adversely affect our business, financial condition, results of operations or cash flows.

All of the information included in this Annual Report on Form 10-K 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.

Our natural gas transportation and storage operations are subject to extensive regulation by the FERC, including rules and regulations related to the rates we can charge for our services and our ability to construct or abandon facilities. We may not be able to recover the full cost of operating our pipelines, including earning a reasonable return.

The FERC regulates the rates we can charge for our natural gas transportation and storage operations. For our cost-based services, the FERC establishes both the maximum and minimum rates we can charge. The basic elements that the 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 our costs, including certain costs associated with pipeline integrity, through existing or future rates.

The FERC and/or our customers could challenge the maximum applicable rates that any of our regulated pipelines can charge in accordance with Section 5 of the NGA. Adoption of potential legislation that would amend Section 5 of the NGA to add refund provisions could increase the likelihood of such a challenge. If such a challenge is successful for any of our pipelines, the revenues associated with transportation and storage services the pipeline provides pursuant to cost-of-service rates could materially decrease in the future, which would adversely affect the revenues on that pipeline going forward.

Our operations, and those of our customers, are subject to a series of risks regarding climate change.

The threat of climate change continues to attract considerable attention in the U.S. and in other countries. Numerous proposals have been made and could continue to be made at the international, national, regional, state and local levels of government to monitor, limit and eliminate both existing and future emissions of GHGs. These proposals expose our operations as well as the operations of our fossil fuel producer customers to a series of regulatory, political, litigation and financial risks.

In the U.S., no comprehensive climate change legislation has been implemented at the federal level. However, the EPA has issued several rules regulating GHGs following the U.S. Supreme Court finding that GHGs are air pollutants under the CAA and the EPA's own endangerment finding for certain GHGs, including carbon dioxide and methane. The EPA regulates GHGs through various requirements, including permitting for GHG emissions from large stationary sources, annual reporting on GHG emissions from oil and gas facilities, New Source Performance Standards (NSPS) restricting methane emissions from new facilities in the natural gas sector, and GHG emissions limits on vehicles together with the DOT. The EPA's regulation of methane emissions continues to undergo significant changes. In June 2021, President Biden signed into law a joint resolution of Congress under the Congressional Review Act that rescinded the EPA's 2020 Policy Rule, effectively reinstating the 2012 and 2016 NSPS for the transmission and storage sector. In November 2021, the EPA proposed a rule to establish standards of performance for methane and volatile organic compound emissions from new sources and, for the first time, existing sources, within the crude oil and natural gas source category, including the transmission and storage sector. The proposed rule includes several requirements relevant to our operations, including stricter emissions limits for various facilities and equipment (including pneumatic controllers, storage tanks, reciprocating compressors, and wet seal centrifugal compressors), more frequent leak detection and monitoring of fugitive emissions from compressor stations, and deadlines for repairing fugitive

Governmental entities, including certain states and groups of states, have adopted or are considering legislation, regulations or other initiatives, such as GHG cap and trade programs, carbon taxes, GHG reporting and tracking programs, and emissions limits. At the international level, in February 2021 the U.S. rejoined the Paris Agreement, which requires member nations to submit non-binding GHG emissions reduction goals every five years. In April 2021, President Biden announced a new target for the U.S. to reduce GHG emissions 50-52% from 2005 levels by 2030. In November 2021, the U.S. joined other nations for the 26th Conference to the Parties (COP26), during which nations including the U.S. made various commitments, including the Global Methane Pledge to reduce methane emissions 30% from 2020 levels by 2030.

Governmental, scientific and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the U.S. The Biden administration and future administrations could take various actions to curtail oil and natural gas production and transportation, including limiting fracturing of oil and natural gas wells, restricting flaring and venting during natural gas production on federal properties, limiting or banning oil and gas leases on federal lands and offshore waters, increasing requirements for construction and permitting of pipeline infrastructure and LNG export facilities, and further restricting GHG emissions from oil and gas facilities. Litigation risks are also increasing, as a number of cities and other governmental entities have brought suit alleging that fossil fuel producers created public nuisances by producing fuels that contributed to global warming effects such as rising sea levels, are responsible for associated roadway and infrastructure damage, or defrauded investors or customers by failing to timely and adequately disclose adverse effects of climate change.

There are also increasing financial risks for fossil fuel energy companies as investors become increasingly concerned about the potential effects of climate change and may elect in the future to shift some or all of their investments into non-fossil fuel energy related sectors. Institutional lenders who provide financing to fossil fuel energy companies also have become more attentive to sustainable lending practices that favor alternative power sources (such as wind, solar, geothermal, tidal and biofuels), making those sources more attractive, and some of them may elect not to provide funding for fossil fuel energy companies. Many of the largest U.S. banks have made “net zero” carbon emission commitments and have announced that they will be assessing financed emissions across their portfolios and taking steps to quantify and reduce those emissions. At COP26, the Glasgow Financial Alliance for Net Zero announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. Financial institutions could be required to adopt policies that limit funding for fossil fuel energy companies. In late 2020 the Federal Reserve joined the Network for Greening the Financial System (NGFS), a consortium of financial regulators focused on addressing climate-related risks in the financial sector, and in 2021 the Federal Reserve issued a statement supporting the efforts of NGFS in identifying potential solutions for climate-related challenges relevant to central banks and supervisory authorities. While we cannot predict what policies may result from these announcements, a material reduction in the capital available to the fossil fuel industry could make it more difficult to secure funding for exploration and production or midstream energy business activities, which could adversely impact our business and operations. Separately, the SEC has also announced that it is scrutinizing existing climate-change related disclosures in public filings, increasing the potential for enforcement if the SEC were to allege an issuer’s existing climate disclosures are misleading or deficient.

Increased attention to climate change, environmental, social and governance (ESG) matters and conservation measures may adversely impact our business.

Increasing attention to climate change, societal expectations on companies to address climate change, investor and societal expectations regarding ESG matters and disclosures, and consumer demand for alternative forms of energy may result in increased costs, reduced demand for our services, reduced profits, increased investigations and litigation, and negative impacts on our access to capital markets. Increasing attention to climate change and environmental conservation, for example,

While we may publish voluntary disclosures regarding ESG matters from time to time, many of the statements in those disclosures may not be material and may be based on expectations and assumptions that may not be representative of actual risks or events or forecasts of expected risks or events. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many ESG matters.

Organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters, and many of these rating processes are inconsistent with each other. Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our access to and costs of capital. Institutional lenders may decide not to provide funding for fossil fuel energy companies based on climate change related concerns, which could affect our access to capital.

In addition, other stakeholders, including customers, employees, regulators, credit rating agencies and suppliers, have also been focused on ESG matters. Companies that do not adapt to or comply with investor or other stakeholder expectations and standards, which are evolving, or that are perceived to have not responded appropriately to the growing concern regarding ESG issues, regardless of whether there is a legal requirement to do so, may suffer from reputational damage and other adverse consequences. Additionally, to the extent ESG matters negatively impact our reputation, we may not be able to compete as effectively to recruit or retain employees, which may adversely affect our operations.

Climatic conditions and events could adversely impact our operations, pipelines and facilities, or those of our customers or suppliers.

Climatic events can cause disruptions to, delays in or suspension of our services, by interrupting our operations, causing loss of or damage to our equipment, or having similar impacts on our customers or third party suppliers. In general, our operations could be significantly impacted by climatic conditions such as increased frequency and severity of storms, floods and wintry conditions. Our pipeline operations along coastal waters and offshore in the Gulf of Mexico could be adversely impacted by climatic conditions such as rising sea levels, subsidence and erosion, which could result in serious damage to our facilities and affect our ability to provide transportation services. Such damage could result in leakage, migration, releases or spills from our operations and could result in liability, remedial obligations or otherwise have a negative impact on operations. Such climactic conditions could also impact our customers’ ability to utilize our services and third party suppliers’ ability to provide us with the products and services necessary to maintain operation of our facilities. We may incur significant damages as well as costs to repair or maintain our facilities, which could adversely affect our operations and the financial health of our business. In recent years, local governments and landowners in Louisiana have filed lawsuits against energy companies, alleging that their operations contributed to increased coastal rising seas and erosion and seeking substantial damages. Changing meteorological conditions, particularly temperature, may affect the amount, timing, or location of demand for energy or the products we transport, which may impact demand for our services.

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

Our operations are subject to extensive federal, state and local laws and regulations relating to protection of the environment and occupational health and safety. 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 various substances, including hazardous substances and waste in connection with spills, releases, discharges and emissions of various substances into the environment. These laws include, for example, the CAA, the Clean Water Act, CERCLA, the RCRA, ESA, NEPA, OSHA and analogous state laws. These laws and regulations may restrict or impact our business activities, including requiring the acquisition or renewal of permits or other approvals to conduct regulated activities, restricting the manner in which we handle or dispose of wastes, imposing remedial obligations to remove or mitigate contamination resulting from a spill or other release, requiring capital expenditures to comply with pollution control requirements and imposing safety and health criteria addressing worker protection. 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, the incurrence of capital expenditures, the occurrence of delays, denials or cancellations in the permitting or

Legislative and regulatory initiatives relating to pipeline safety that require the use of new or more prescriptive compliance activities, substantial changes to existing integrity management programs or withdrawal of regulatory waivers could subject us to increased capital and operating costs and operational delays.

    

We have entered into certain firm transportation contracts with shippers that utilize the design capacity of certain of our pipeline assets, based upon the authority we received from PHMSA to operate those pipelines at higher than normal operating pressures of up to 0.80 of the pipeline's SMYS under issued permits with specific conditions. PHMSA retains discretion to withdraw or modify this authority. If PHMSA were to withdraw or materially modify such authority, it could affect our ability to transport all of our contracted quantities of natural gas on these pipeline assets and we could incur significant additional costs to reinstate this authority or to develop alternate ways to meet our contractual obligations.

Our actual construction and development costs could exceed our forecasts; our anticipated cash flow from construction and development projects will not be immediate; and our construction and development projects may not be completed on time or at all.

We are and have been engaged in several construction projects involving our existing assets and the construction of new facilities for which we have expended or will expend significant capital. We expect to continue to engage in the construction of additional growth projects and modifications of our system. When we build a new pipeline or expand or modify

A failure in our computer systems or a cybersecurity attack on any of our facilities, or those of third parties, could cause substantial damage and may adversely affect our ability to operate our business.

We have become more reliant on technology to help increase efficiency in our business processes. 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.

At the same time, the U.S. government has issued public and industry-specific warnings that indicate that energy assets might be specific targets of cybersecurity threats. Our technologies, systems and networks, and those of our vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, significant damage to property, personal injury or loss of life, substantial financial damage or other disruption of operations. In addition, certain cyber-incidents may remain undetected for an extended period.

The Transportation Security Administration, the Sector Risk Management Agency for interstate pipelines, has initiated a series of Security Directives for 100 of the nation’s most critical pipeline systems, including us, which require stringent and broad cybersecurity measures to be implemented. As cyber-incidents continue to evolve, more legislation could be enacted to mitigate cyber-threats. This will require us to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber-incidents at significantly increased costs. Our insurance coverage for cyberattacks may not be sufficient to cover all the losses we may experience as a result of such cyberattacks. Any cyberattacks 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 may face opposition to the operation of our pipelines and facilities or construction or expansion of facilities or new pipeline projects from various groups.

We may face opposition to the operation of our pipelines and facilities or construction or expansion of our facilities or new pipeline projects from governmental officials, environmental groups, landowners, communities, tribal or local groups and other advocates. Such opposition could take many forms, including organized protests, attempts to block or sabotage our operations, acts of eco-terrorism, intervention in regulatory or administrative proceedings involving our assets, or lawsuits or other actions designed to prevent, disrupt or delay the operation of our assets and business. For example, repairing our pipelines often involves securing consent from individual landowners to access their property; one or more landowners may resist our efforts to make needed repairs, which could lead to an interruption in the operation of the affected pipeline or facility for a period of time that is significantly longer than would have otherwise been the case. Acts of sabotage or eco-terrorism could cause significant damage or injury to people, property or the environment and lead to extended interruptions of our operations and material damages and costs.

The price differentials between natural gas supplies and market demand for natural gas may reduce the transportation rates that we can charge on certain portions of our pipeline systems.

Each year a portion of our firm natural gas transportation contracts expire and need to be replaced or renewed. As a result of current market conditions, we may renew some expiring contracts at lower rates or for shorter terms than in the past. The transportation rates we are able to charge customers are heavily influenced by market trends (both short and longer term), including the available supply, geographical location of natural gas production, the competition between producing basins, competition with other pipelines for supply and markets, the demand for gas by end-users such as power plants, petrochemical facilities and LNG export facilities and the price differentials between the gas supplies and the market demand for the gas (basis differentials). Market conditions have resulted in a sustained narrowing of basis differentials on certain portions of our pipeline system, which has reduced transportation rates that can be charged in the affected areas and adversely affected the contract terms we can secure from our customers for available transportation capacity and for contracts being renewed or replaced. We expect these market conditions to continue.

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

Our customers, especially producers and certain plant operators, are directly impacted by changes in commodity prices. The prices of natural gas, oil and NGLs fluctuate in response to changes in both domestic and worldwide supply and demand, market uncertainty and a variety of additional factors, including for natural gas the realization of potential LNG exports and demand growth within the power generation market. Volatility in the pricing levels of natural gas, oil and NGLs could adversely affect the businesses of certain of our producer customers and could result in defaults or the non-renewal of our contracted capacity when existing contracts expire. Commodity prices could affect the operations of certain of our industrial customers, including the temporary closure or reduction of plant operations, resulting in decreased deliveries to those customers. Future increases in the price of natural gas and NGLs could make alternative energy and feedstock sources more competitive and decrease demand for natural gas and NGLs. A reduced level of demand for natural gas and NGLs could diminish the utilization of capacity on our systems and reduce the demand for our services.

We are exposed to credit risk relating to default or bankruptcy by our customers.

Credit risk relates to the risk of loss resulting from the default by a customer of its contractual obligations or the customer filing bankruptcy. We have credit risk with both our existing customers and those supporting our growth projects. Credit risk exists in relation to our growth projects, both because the expansion customers make long-term firm capacity commitments to us for such projects and certain of those expansion customers agree to provide credit support as construction for such projects progresses. If a customer fails to post the required credit support or defaults during the growth project process, overall returns on the project may be reduced to the extent an adjustment to the scope of the project occurs or we are unable to replace the defaulting customer with a customer willing to pay similar rates. In 2020 and 2019, two expansion customers declared bankruptcy for which we were able to use the credit support obtained during the growth project process to cover a portion of their remaining long-term commitment. For more information, refer to Note 5 in Part II, Item 8. of this Annual Report on Form 10-K.

Our credit exposure also includes receivables for services provided, future performance under firm agreements and volumes of gas owed by customers for imbalances or gas loaned by us to them under certain NNS and PAL services.

We rely on a limited number of customers for a significant portion of revenues.

For 2021, no customer comprised 10% or more of our operating revenues. However, the top ten customers holding firm capacity under firm agreements comprised approximately 39% of our total projected operating revenues. If any of our significant customers have credit or financial problems which result in bankruptcy, a delay or failure to pay for services provided by us, to post the required credit support for construction associated with our growth projects or existing contracts or to repay the gas they owe us, it could have a material adverse effect on our revenues.

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 business activities. 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. This agreement also requires us to maintain a ratio of consolidated debt to consolidated EBITDA (as defined in the agreement) of not more than 5.0 to 1.0, or up to 5.5 to 1.0 for the three quarters following a qualified acquisition

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

Our indebtedness could affect our ability to meet our obligations and may otherwise restrict our activities.

As of December 31, 2021, we had $3.4 billion in principal amount of long-term debt outstanding. This level of debt requires significant interest payments. Our inability to generate sufficient cash flow to satisfy our debt obligations, or to refinance our obligations on commercially reasonable terms, would have a material adverse effect on our business. Our indebtedness could have important consequences. For example, it could:

    

We are permitted, under our revolving credit facility and the indentures governing our notes, to incur additional debt, subject to certain limitations under our revolving credit facility and the indentures governing the notes. If we incur additional debt, our increased leverage could also result in the consequences described above.

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

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 fulfill our debt obligations 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.

Limited access to the debt markets and increases in interest rates could adversely affect our business.

We anticipate funding our capital and other spending requirements through our available financing options, including cash generated from operations, borrowings under our revolving credit facility and issuances of additional debt. Changes in the debt markets, including market disruptions, limited liquidity, and an increase in interest rates, may increase the cost of financing as well as the risks of refinancing maturing debt. This may affect our ability to raise needed financing and reduce the amount of cash available to fund our operations or growth projects or refinance maturing debt. If the debt markets were not available, it is not certain if other adequate financing options would be available to us on terms and conditions that we would find acceptable.

Any disruption in the debt markets 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 certain business opportunities, any of which could negatively impact our business.

The outbreak of COVID-19 and the measures to mitigate the spread of COVID-19 could materially adversely affect our business, financial condition and results of operations and those of our customers, suppliers and other business partners.

The global outbreak of the COVID-19 pandemic and measures to mitigate the spread of COVID-19 significantly impacted the world and the U.S., and impacted global demand for oil and petrochemical products. COVID-19 has also resulted in significant business and operational disruptions, including business closures, supply chain disruptions, travel restrictions, stay-at-home orders and limitations on the availability of workforces. Our operations are considered essential critical infrastructure under current Cybersecurity and Infrastructure Security Agency guidelines, however, if significant portions of our workforce are unable to work effectively, including because of illness or quarantines, our business could be materially adversely affected. We may also be unable to perform fully on our contracts, and our costs may increase as a result of the COVID-19 outbreak. These cost increases may not be fully recoverable. It is possible that the continued spread of COVID-19 could also further cause disruption in our customers' business; cause delay, or limit the ability of our customers to perform, including in making timely payments to us. The impact of COVID-19 has impacted capital markets, which may impact our customers' financial position. The COVID-19 pandemic may also have the effect of increasing several of the other risk factors contained herein.

We do not own all of the land on which our pipelines, storage and other facilities are located, which could result in disruptions to our operations.

Substantial portions of our pipelines, storage and other facilities are constructed and maintained on property owned by others pursuant to rights-of-way, easements, permits, licenses or consents, and we are subject to the possibility of more onerous terms and/or increased costs to retain necessary land use rights if we do not have valid land use rights or if such land use rights lapse or terminate. Some of the rights to construct and operate our pipelines, storage or other facilities on land owned by third parties and governmental agencies that we obtain are for specific periods of time. We cannot guarantee that we will always be able to renew, when necessary, existing land use rights or obtain new land use rights without experiencing significant costs or experiencing landowner opposition. Any loss of these land use rights with respect to the operation of our pipelines, storage and other facilities, through our inability to acquire or renew right-of-way or easement contracts or permits, licenses, consents or otherwise, could have a material adverse effect on our operations.

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

We rely primarily on the revenues generated from our natural gas transportation and storage services. Negative developments in these services have significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets. Our ability to grow, diversify and increase cash flows will depend, in part, on our ability to expand our existing business lines and to close and execute on accretive acquisitions. We may not be successful in acquiring or developing such assets or may do so on terms that ultimately are not profitable.

Our ability to replace expiring gas storage contracts at attractive rates or on a long-term basis and to sell short-term services at attractive rates or at all are subject to market conditions.

We own and operate substantial natural gas storage facilities. The market for the storage and PAL services that we offer is impacted by the factors and market conditions discussed above for our transportation services, and is also impacted by natural gas price differentials between time periods, such as winter to summer (time period price spreads), and the volatility in time period price spreads. When market conditions cause a narrowing of time period price spreads and a decline in the price volatility of natural gas, these factors adversely impact the rates we can charge for our storage and PAL services.

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

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

We currently possess property, business interruption, cyber threat 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 events, hazards or potential losses.

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

Our operations and management require the retention and recruitment of a skilled executive team and workforce including engineers, technical personnel and other professionals. 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 retain our current employees, successfully complete the knowledge transfer and/or recruit new employees of comparable knowledge and experience, our business could be negatively impacted.

Our business is highly competitive.

The principal elements of competition among pipeline systems are availability of capacity, rates, terms of service, access to gas supplies, flexibility and reliability of service. Additionally, the 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 regulatory actions that increase the cost, or limit the use, of products we transport and store.

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

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

None.

Refer to Note 5 in Part II, Item 8. of this Annual Report on Form 10-K for a discussion of our legal proceedings.

Not applicable.

Not applicable.

We operate in the midstream portion of the natural gas and NGLs industry, providing transportation and storage for those commodities. Refer to Part I, Item 1. Business, of this Annual Report on Form 10-K for further discussion of our operations and business. We are not in the business of buying and selling natural gas and NGLs other than for system management purposes, but changes in natural gas and NGLs prices may impact the volumes of natural gas or NGLs transported and stored by customers on our systems. We conduct all of our business through our operating subsidiaries as one reportable segment. Due to the capital-intensive nature of our business, our operating costs and expenses typically do not vary significantly based upon the amount of products transported, with the exception of fuel consumed at our compressor stations and not included in a fuel tracker, which is netted with fuel retained on our Consolidated Statements of Income. Please refer to Part I, Item 1. Business, for further discussion of the services that we offer and our customer mix.

A substantial portion of our transportation and storage capacity is contracted for under firm agreements. For the year ended December 31, 2021, approximately 89% of our revenues were derived from capacity reservation fees under firm contracts. The table below shows a rollforward of operating revenues under committed firm agreements in place as of December 31, 2020, to December 31, 2021, including agreements for transportation, storage and other services, over the remaining term of those agreements (in millions):

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 transportation services. PHMSA has developed regulations that require transportation pipeline operators to implement integrity management programs to comprehensively evaluate certain high risk areas, known as HCAs, and MCAs, along pipelines and take additional safety measures to protect people and property in these

Please refer to the disclosures in this Item 7. and Item 1A. Risk Factors of this Annual Report on Form 10-K of items that have impacted, or could impact in the future, our results of operations.

Our net income for the year ended December 31, 2021, increased $24.5 million, or 8%, to $315.0 million compared to $290.5 million for the year ended December 31, 2020, primarily due to the factors discussed below. Excluding the impact from the 2020 customer bankruptcy, as discussed in Note 5 in Part II, Item 8. of this Annual Report on Form 10-K, our net income for the year ended December 31, 2021, would have increased $58.9 million, or 23%, compared to 2020.

Operating revenues for the year ended December 31, 2021, increased $42.5 million, or 3%, to $1,340.1 million, compared to $1,297.6 million for the year ended December 31, 2020. Including the effect of the items in fuel and transportation expense, and excluding the impact from the customer bankruptcy as discussed in Note 5 in Part II, Item 8. of this Annual Report on Form 10-K, operating revenues increased $73.1 million, or 6%. The increase was driven by our recently completed growth projects and higher utilization based revenues due to higher volumes.

Operating costs and expenses for the year ended December 31, 2021, increased $30.0 million, or 4%, to $873.0 million, compared to $843.0 million for the year ended December 31, 2020. Excluding items offset with operating revenues, operating costs and expenses increased $26.2 million, or 3%, when compared to 2020. The operating expense increase was primarily due to an increase in maintenance project costs and an increased asset base from recently completed growth projects.

Total other deductions for the year ended December 31, 2021, decreased $12.4 million, or 8%, to $151.4 million compared to $163.8 million for 2020 primarily due to lower interest rates and lower average outstanding long-term debt.

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 and debt issuances. 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.

Credit Ratings

Most of our senior unsecured debt is rated by independent credit rating agencies. The credit ratings affect our ability to access the public and private debt markets, as well as the terms and the cost of our borrowings. Our ability to satisfy financing requirements or fund planned growth capital expenditures will depend upon our future operating performance and our ability to access the capital markets, which are affected by economic factors in our industry as well as other financial and business factors, some of which are beyond our control. As of February 4, 2022, our credit ratings for our senior unsecured notes and that of our operating subsidiaries having outstanding rated debt were as follows:    

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

Guarantee of Securities of Subsidiaries

Our debt is primarily issued at Boardwalk Pipelines, our wholly owned subsidiary, although we have historically also issued debt at our operating subsidiaries. As of December 31, 2021, all of the outstanding notes issued by Boardwalk Pipelines (Subsidiary Issuer) and the full amount of the revolving credit facility, are guaranteed by us (Parent Guarantor). The purpose of the guarantees is to help simplify our reporting and capital structure.

We guarantee the amounts borrowed under the revolving credit facility, but those amounts are not subject to the reporting requirements of Rule 13-01 of Regulation S-X. As of December 31, 2021, there were no outstanding borrowings under the revolving credit facility. The below table identifies our principal amounts outstanding for the debt that is subject to the disclosure rules of Rule 13-01 of Regulation S-X (in millions):

(1) This represents principal amounts of all outstanding debt at Boardwalk Pipelines subject to the disclosure rules of Rule 13-01 of Regulation S-X (the Guaranteed Notes).

(2) This represents principal amounts of outstanding debt at Gulf South and Texas Gas.

(3) As of December 31, 2021, this represents the amounts related to a finance lease and unamortized debt discount and issuance costs.

The Guaranteed Notes are fully and unconditionally guaranteed by the Parent Guarantor on a senior unsecured basis. The guarantees of the Guaranteed Notes rank equally with all of our existing and future senior debt, including our guarantee of indebtedness under our revolving credit facility. The guarantees will be effectively subordinated in right of payment to all of our future secured debt to the extent of the value of the assets securing such debt. There are no restrictions on the Subsidiary Issuer's ability to pay dividends or make loans to the Parent Guarantor. The guarantee obligations will be terminated with respect to any series of notes if that series has been discharged or defeased.

Our operating assets, operating liabilities, operating revenues, expenses and other comprehensive income either exist at or are generated by our operating subsidiaries. The Parent Guarantor and the Subsidiary Issuer have no material assets, liabilities or operations independent of their respective financing activities, including the Guaranteed Notes and advances to and from each other and the operating subsidiaries as a result of the cash management program described in Note 2 of Part II, Item 8. of this Annual Report on Form 10-K, and their investments in the operating subsidiaries. For these reasons, we meet the criteria in Rule 13-01 of Regulation S-X to omit the summarized financial information from our disclosures.

Capital Expenditures

Maintenance capital expenditures for the years ended December 31, 2021, 2020 and 2019 were $154.3 million, $148.8 million and $138.7 million. Growth capital expenditures were $174.9 million, $270.6 million and $277.7 million for the years ended December 31, 2021, 2020 and 2019. During the year ended December 31, 2021, we acquired certain natural gas pipeline assets in the Lake Charles, Louisiana, area for approximately $20.0 million in cash. During the year ended December 31, 2020, we purchased the remaining undivided interest in the Bistineau storage facility that we did not previously own for $18.8 million. In 2021 and 2019, we purchased $6.8 million and $12.6 million of natural gas to be used as base gas for our integrated natural gas pipeline system.

We expect total capital expenditures to be approximately $360.0 million in 2022, including approximately $155.0 million for maintenance capital and $205.0 million related to growth projects.

Our significant accounting policies are described in Note 2 in Part II, Item 8. of this Annual Report on Form 10-K. The preparation of these consolidated financial statements in accordance with accounting principles generally accepted in the U.S. 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.

Goodwill

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 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. The quantitative goodwill impairment test is performed by calculating the fair value of the reporting unit and comparing it to the reporting unit's carrying amount. If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is not impaired. However, if the carrying amount of a reporting unit exceeds its fair value, an impairment loss is recognized in an amount equal to that excess, limited to the total amount of goodwill recorded on the reporting unit.

As of November 30, 2021, we elected to perform a qualitative assessment for our annual goodwill impairment test of our two reporting units. The qualitative assessment included our consideration of, among other things, the overall macroeconomic conditions, industry and market considerations, current discount rates and valuation multiples, overall financial performance, including operating revenues, and other relevant company specific events. Based on the assessment of these items, we concluded that it is more likely than not that the fair value of our two reporting units exceeded their respective carrying amounts. Accordingly, there were no indicators of impairment and the quantitative impairment test was not performed.

The estimated fair values of our reporting units can fluctuate from year to year, and 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 qualitative goodwill impairment test for 2021 and the quantitative goodwill test for 2020 did not result in any goodwill impairment charges.

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. For the years ended December 31, 2021, 2020 and 2019, we recognized immaterial amounts related to asset impairment charges.

Certain statements contained in this Annual Report on Form 10-K, as well as some statements in our other filings with the SEC and 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, intentions or achievements, and may contain the words “expect,” “intend,” “plan,” “anticipate,” “estimate,” “believe,” “will likely result” and similar expressions. In addition, any statement concerning future financial performance (including future revenues, earnings or growth rates), ongoing business strategies or prospects and possible actions by us 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 which could cause actual results to differ materially from those anticipated or projected. These include, among others, the impacts of legislative and regulatory initiatives, or the implementation thereof, the impacts of climate change, ESG matters and pipeline safety, the costs of maintaining and ensuring the integrity and reliability of our pipeline systems, our ability to complete projects that we have commenced or will commence, the risk of a failure in our computer systems or cybersecurity attack, successful negotiation, consummation and completion of contemplated transactions, projects and agreements, risks and uncertainties related to the impacts of volatility in energy prices, and our exposure to credit risk relating to default or bankruptcy by our customers. 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 they are made and we expressly disclaim any obligation or undertaking to update

Refer to Part I, Item 1A. of this Annual Report on Form 10-K for additional risks and uncertainties regarding our forward-looking statements.

With the exception of our revolving credit facility, for which the interest rates are periodically reset, our debt has been issued at fixed rates. For fixed-rate debt, changes in interest rates affect the fair value of the debt instruments but do not directly affect our 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, 2021, we had no variable-rate debt outstanding. At December 31, 2020, we had $130.0 million outstanding under variable-rate agreements at a weighted-average interest rate of 1.39%.

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.

Our credit exposure generally relates to receivables for services provided, as well as volumes owed by customers for imbalances or gas lent by us to them, generally under PAL and certain firm services. Natural gas price volatility can materially increase credit risk related to gas loaned to customers. We also have credit risk related to customers supporting some of our growth projects. If any significant customer of ours should have credit or financial problems resulting in a delay or failure to pay for services provided by us or repay gas they owe to us, this could have a material adverse effect on our business, financial condition, results of operations or cash flows.

As of December 31, 2021, the amount of gas owed to our operating subsidiaries due to gas imbalances and gas loaned under PAL and certain firm service agreements was approximately 7.4 trillion British thermal units (TBtu). Assuming an average market price during December 2021 of $3.59 per million British thermal unit (MMBtu), the market value of that gas was approximately $26.6 million. As of December 31, 2020, the amount of gas owed to our operating subsidiaries due to gas imbalances and gas loaned under PAL and certain firm service agreements was approximately 11.2 TBtu. Assuming an average market price during December 2020 of $2.45 per MMBtu, the market value of that gas at December 31, 2020, was approximately $27.4 million. As of December 31, 2021 and 2020, there were no outstanding NGL imbalances owed to our operating subsidiaries.

We have audited the accompanying consolidated balance sheets of Boardwalk Pipeline Partners, LP and subsidiaries (the "Company") as of December 31, 2021 and 2020, the related consolidated statements of income, comprehensive income, cash flows and changes in partners' capital, for each of the three years in the period ended December 31, 2021, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America.

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit council and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Goodwill – Refer to Notes 2 and 8 to the financial statements

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. As of November 30, 2021, the Company elected to perform a qualitative assessment for its annual goodwill impairment test of its two reporting units. The qualitative assessment included the Company’s consideration of, among other things, the overall macroeconomic conditions, industry and market considerations, current discount rates and valuation multiples, overall financial performance, including operating revenue, and other relevant company specific events. Based on this assessment of these items, the Company concluded that it is more likely than not that the fair value of the two reporting units exceeded their respective carrying amounts. As of December 31, 2021, the Company had recorded on its Consolidated Balance Sheets $237.4 million of goodwill.

We identified goodwill for the Company as a critical audit matter because of the high degree of auditor judgment and an increased extent of effort when performing audit procedures to evaluate the reasonableness of management’s judgments and assumptions related to its assessment of operating revenues and current discount rates, including the need to involve fair value specialists, in determining whether it was more likely than not that the fair value of the Company’s reporting units was less than their respective carrying amounts.

Our audit procedures related to management’s consideration of current discount rates and operating revenues in its qualitative assessment of the fair value of the two reporting units included the following, among others:

Houston, Texas

February 8, 2022

We have served as the Company's auditor since 2003.

BOARDWALK PIPELINE PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

BOARDWALK PIPELINE PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

BOARDWALK PIPELINE PARTNERS, LP

CONSOLIDATED STATEMENTS OF INCOME

BOARDWALK PIPELINE PARTNERS, LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

BOARDWALK PIPELINE PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

BOARDWALK PIPELINE PARTNERS, LP

BOARDWALK PIPELINE PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Boardwalk Pipeline Partners, LP (the Company) 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 South Pipeline Company, LLC (Gulf South), Texas Gas Transmission, LLC (Texas Gas), Boardwalk Louisiana Midstream, LLC (Louisiana Midstream), Boardwalk Louisiana Gas Transmission, LLC (Louisiana Gas Transmission), Boardwalk Petrochemical Pipeline, LLC and Boardwalk Texas Intrastate, LLC (together, the operating subsidiaries), which consists of integrated pipeline and storage systems for natural gas and natural gas liquids and other hydrocarbons (herein referred to together as NGLs). All of the Company's operations are conducted by the operating subsidiaries.

As of December 31, 2021, Boardwalk Pipelines Holding Corp. (BPHC), a wholly owned subsidiary of Loews Corporation (Loews), owned directly or indirectly, 100% of the Company's capital.

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

Principles of Consolidation

The consolidated financial statements include the Company's accounts and those of its wholly owned subsidiaries after elimination of intercompany transactions.

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 Company 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 Company operates in 1 reportable segment - the operation of interstate natural gas and NGLs pipeline systems and integrated storage facilities. This segment consists of interstate natural gas pipeline systems located in the Gulf Coast region, Oklahoma, Arkansas, Tennessee, Kentucky, Illinois, Indiana and Ohio and integrated natural gas storage facilities located in Indiana, Kentucky, Louisiana and Mississippi, and NGLs pipelines and storage facilities located in Louisiana and Texas.

Regulatory Accounting

Most of the Company'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 Company's Texas Gas subsidiary, which records certain costs and benefits as regulatory assets and liabilities in order to provide for recovery from or refunds to customers in future periods, but is not applicable to the operations associated with the Fayetteville and Greenville Laterals due to rates charged under negotiated rate agreements and a portion of Texas Gas' storage capacity due to the regulatory treatment associated with the rates charged for that capacity.

The Company applies regulatory accounting for its fuel trackers on Gulf South, under which the value of fuel received from customers paying the maximum tariff rate and the related value of fuel used in transportation are recorded to a regulatory asset or liability depending on whether Gulf South uses more fuel than it collects from customers or collects more fuel than it uses. Other than as described for Texas Gas and for the fuel trackers on Gulf South, regulatory accounting is not applicable to the Company's other FERC-regulated operations.

The Company monitors the regulatory and competitive environment in which it operates to determine whether its regulatory assets continue to be probable of recovery. If the Company determines that all or a portion of its regulatory assets no longer meets the criteria for recognition as regulatory assets, that portion which is not recoverable will be written off, net of any regulatory liabilities.

Note 10 contains more information regarding the Company'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 Company uses fair value measurements to account for asset retirement obligations (ARO) and any impairment charges.

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 Company had no restricted cash at December 31, 2021 and 2020.

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 are recognized on an accrual basis when collection is reasonably assured. The interest rate on intercompany demand notes is London Interbank Offered Rate (LIBOR), or such benchmark replacement rate, plus 1.00% 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 Company establishes an allowance for doubtful accounts under an expected credit loss model based on historical credit loss experience and specific facts and circumstances. 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 Company'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.

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 Company in

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 primarily settled in cash or the receipt or delivery of gas in the future. Settlement of imbalances requires agreement between the pipelines and shippers or operators as to allocations of volumes to specific transportation contracts and timing of delivery of gas based on operational conditions. The receivables and payables are valued at market price for operations where regulatory accounting is not applicable and are valued at the historical value of gas in storage for operations where regulatory accounting is applicable.

Materials and Supplies

Property, Plant and Equipment and Repair and Maintenance Costs

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 being recorded in the income statement. 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 Company'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. 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. The quantitative goodwill impairment test is performed by calculating the fair value of the reporting unit and comparing it to the reporting unit's carrying amount. If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is not impaired. However, if the carrying amount of a reporting unit exceeds its fair value, an impairment loss is recognized in an amount equal to that excess, limited to the total amount of goodwill recorded on the reporting unit.

Note 8 contains more information regarding the Company's goodwill and intangible assets.

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

The Company 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 (or asset group) is compared to the carrying amount of the asset (or asset group) 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 (or asset group) 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)

Income Taxes

Note 13 contains more information regarding the Company's income taxes.

Asset Retirement Obligations

Note 9 contains more information regarding the Company's ARO.

Environmental Liabilities

The Company records environmental liabilities based on management's estimates 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 known facts and circumstances related to these environmental matters.

Note 5 contains more information regarding the Company's environmental liabilities.

Defined Benefit Plans

The Company maintains postretirement benefit plans for certain employees. The Company funds these plans through periodic contributions which are invested until the benefits are paid out to the participants, and records an asset or liability based on the overfunded or underfunded status of the plan. The net benefit costs of the plans are recorded in the Consolidated Statements of Income. 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 Company's pension and postretirement benefit obligations.

Long-Term Compensation

The Company provides performance awards (Performance Awards) to certain of its employees under its 2018 Long-Term Incentive Plan (2018 LTIP). A Performance Award is a long-term incentive award with a stated target amount which is payable in cash, after certain adjustments, upon vesting based on certain specified performance criteria being met. Prior to 2019, the Company provided awards of phantom common units (Phantom Common Units) to certain employees under its Long-Term Incentive Plan (LTIP) and awards of long-term cash bonuses (Long-Term Cash Bonuses) under the Boardwalk Pipeline Partners Unit Appreciation Rights (UAR) and Cash Bonus Plan. Since 2018, the Company has not granted awards in the form of Phantom Common Units or as Long-Term Cash Bonuses and as of December 31, 2020, all Phantom Common Units and Long-Term Cash Bonuses had vested and were paid.

The Company measures the cost of an award issued in exchange for employee services based on the stated target amount for Performance Awards. All outstanding awards are required to be settled in cash and are classified as a liability until settlement. The related compensation expense, less 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 more information regarding the Company's long-term compensation.

Partner Capital Accounts

For purposes of maintaining capital accounts, items of income and loss of the Company are allocated among the partners each period, or portion thereof, in accordance with the partnership agreement, based on their respective ownership interests.

Leases

Operating lease right-of-use assets and lease liabilities are recognized at the lease commencement date based on the present value of lease payments over the lease term. The discount rate used to determine the commencement date present value of lease payments is typically the Company's secured borrowing rate, as the implicit rate of most of the Company's leases is not readily determinable. The Company has elected not to record any leases with terms of twelve months or less on the Consolidated Balance Sheets.

Revenue Recognition

Nature of Contracts

The transaction price for firm service contracts is comprised of a fixed fee based on the quantity of capacity reserved, regardless of use (capacity reservation fee), plus variable fees in the form of a usage fee paid on the volume of commodity actually transported or injected and withdrawn from storage. Both the fixed and usage fees are allocated to the single performance obligation of providing transportation or storage service and recognized over time based upon the output measure of time as the Company completes its stand-ready obligation to provide contracted capacity and the customer receives and consumes the benefit of the reserved capacity, which corresponds with the transfer of control to the customer. The fixed fee is recognized ratably over the contract term, representative of the proportion of the committed stand-ready capacity obligation that has been fulfilled to date, and the usage fee is recognized upon satisfaction of each distinct monthly performance obligation, consistent with the allocation objective and based upon the level of effort required to satisfy the stand-ready obligation in a given month. 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 based upon seasonal rates.

The transaction price for interruptible service contracts is comprised of a variable fee in the form of a usage fee paid on the volume of commodity actually transported or injected and withdrawn from storage. The usage fee is allocated to the single performance obligation of providing interruptible service. Interruptible service revenues are generally recognized over time based on the output measure of volume transported or stored when services are rendered upon the successful allocation of the services provided to the customer's account, which best depicts the transfer of control to the customer and satisfaction of the promised service. Interruptible services are recognized in the month services are provided because the Company has a right to consideration from customers in amounts that correspond directly to the value that the customer receives from the Company's performance. The rates charged may vary on a daily, monthly or seasonal basis.

Contract Balances

The Company records contract assets primarily related to performance obligations completed but not billed, or partially billed, as of the reporting date. The Company records contract liabilities, or deferred income, when payment is received in advance of satisfying its performance obligations.

The Company operates in 1 reportable segment and contracts directly with end-use customers, including local distribution companies, electric power generators, exporters of liquefied natural gas, and industrial users, with producers and marketers of natural gas, and with interstate and intrastate pipelines who, in turn, provide transportation and storage services for end-users. The following table presents the Company's revenues disaggregated by type of service for the years ended December 31, 2021, 2020 and 2019 (in millions):

Contract Balances

As of December 31, 2021, contract liabilities are expected to be recognized through 2040. Significant changes in the contract liability balances during the year ended December 31, 2021, are as follows (in millions):

Significant changes in the contract liability balances during the year ended December 31, 2020, are as follows (in millions):

Performance Obligations

The following table includes estimated operating revenues expected to be recognized in the future related to agreements that contain performance obligations that were unsatisfied as of December 31, 2021. The amounts presented primarily consist of fixed fees or MVCs which are typically recognized over time as the performance obligation is satisfied, in accordance with firm service contracts. The Company's customers that are charged maximum tariff rates related to its FERC-regulated operating subsidiaries, the amounts below reflect the current tariff rate for such services for the term of the agreements; however, the tariff rates may be subject to future adjustment. The Company has elected to exclude the following from the table: (a) unsatisfied performance obligations from usage fees associated with its firm services because of the stand-ready nature of such services; (b) consideration in contracts that is recognized in revenue as invoiced, such as for interruptible services; and (c) consideration received prior to December 31, 2021, that will be recognized in revenue in future periods, such as the consideration recorded in contract liabilities. The estimated revenues reflected in the table may include estimated revenues that are anticipated under executed precedent transportation agreements for projects that are subject to regulatory approvals.

The Company has various operating lease commitments extending through 2050, generally covering office space and equipment rentals, some of which contain options to renew or extend the lease term. The Company also has a finance lease related to the lease of an office building in Owensboro, Kentucky, entered into in 2013, that has a fifteen-year term with two twenty-year renewal options.

Operating lease right-of-use assets and lease liabilities are recognized at the lease commencement date based on the present value of lease payments over the lease term. The discount rate used to determine the commencement date present value of lease payments is typically the Company's secured borrowing rate, as the implicit rate of most of the Company's leases is not readily determinable. The components of lease cost were as follows (in millions):

The following provides supplemental balance sheet information related to the Company's leases:

The table below presents the maturities of lease liabilities (in millions):

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

Mishal and Berger Litigation

On May 25, 2018, plaintiffs Tsemach Mishal and Paul Berger (on behalf of themselves and the purported class, Plaintiffs) initiated a purported class action in the Court of Chancery of the State of Delaware (the Trial Court) against the following defendants: the Company, Boardwalk GP, LP (Boardwalk GP), Boardwalk GP, LLC and BPHC (together, Defendants), regarding the potential exercise by Boardwalk GP of its right to purchase the issued and outstanding common units of the Company not already owned by Boardwalk GP or its affiliates (Purchase Right).

On June 25, 2018, Plaintiffs and Defendants entered into a Stipulation and Agreement of Compromise and Settlement, subject to the approval of the Trial Court (the Proposed Settlement). Under the terms of the Proposed Settlement, the lawsuit would be dismissed, and related claims against the Defendants would be released by the Plaintiffs, if BPHC, the sole member of the general partner of Boardwalk GP, elected to cause Boardwalk GP to exercise its Purchase Right for a cash purchase price, as determined by the Company's Third Amended and Restated Agreement of Limited Partnership, as amended (the Limited Partnership Agreement), and gave notice of such election as provided in the Limited Partnership Agreement within a period specified by the Proposed Settlement. On June 29, 2018, Boardwalk GP elected to exercise the Purchase Right and gave notice within the period specified by the Proposed Settlement. On July 18, 2018, Boardwalk GP completed the purchase of the Company's common units pursuant to the Purchase Right.

On September 28, 2018, the Trial Court denied approval of the Proposed Settlement. On February 11, 2019, a substitute verified class action complaint was filed in this proceeding, which, among other things, added Loews as a Defendant. The Defendants filed a motion to dismiss, which was heard by the Trial Court in July 2019. In October 2019, the Trial Court ruled on the motion and granted a partial dismissal, with certain aspects of the case proceeding to trial. A trial was held the week of February 22, 2021, and post-trial oral arguments were held on July 14, 2021.

On November 12, 2021, the Trial Court issued a ruling in the case. The Trial Court held that Boardwalk GP breached the Limited Partnership Agreement and found that Boardwalk GP is liable to the Plaintiffs for approximately $690.0 million in damages, plus pre-judgment interest (approximately $166.0 million), post-judgment interest and attorneys’ fees. The Trial Court’s ruling and damages award is against Boardwalk GP, and not the Company or its subsidiaries.

The Defendants believe that the Trial Court ruling includes factual and legal errors. Therefore on January 3, 2022, the Defendants appealed the Trial Court’s ruling to the Supreme Court of the State of Delaware (the Supreme Court). On January 17, 2022, the Plaintiffs filed a cross-appeal to the Supreme Court contesting the calculation of damages by the Trial Court.

City of New Orleans Litigation

Gulf South, along with several other energy companies operating in Southern Louisiana, has been named as a defendant in a petition for damages and injunctive relief in state district court for Orleans Parish, Louisiana, (Case No. 19-3466) by the City of New Orleans. The case was filed on March 29, 2019. The lawsuit claims include, among other things, negligence, strict liability, nuisance and breach of contract, 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 City of New Orleans. In October 2020, this case was stayed pending the outcome of a consolidated appeal to the 5th Circuit Court of Appeals in a similar case. On August 5, 2021, the 5th Circuit Court of Appeals ruled in favor of the oil-and-gas defendants in that consolidated appeal, finding that the two cases being appealed should be re-examined in federal district court since they involve operations that were federally overseen at the time. The ruling reverses a previous decision that allowed the cases to be heard in state court, which the plaintiffs had sought. As a result of the 5th Circuit Court of Appeals' decision, it is anticipated that this case will be reviewed in federal district court to determine whether the case should be heard in that court.

In the fourth quarter 2020 and the second quarter 2019, two customers of Texas Gas declared bankruptcy and rejected the transportation agreements they had with Texas Gas as part of the bankruptcy proceedings. As a result, Texas Gas pursued and received proceeds from existing letters of credit provided to Texas Gas as credit support of $37.7 million from the 2020 bankruptcy and $27.7 million from the 2019 bankruptcy. In both cases, the bankruptcy courts approved the rejection of the transportation agreements, which relieved Texas Gas from providing further transportation services to those customers and allowed Texas Gas to remarket that capacity to other customers. Texas Gas first applied the proceeds from the letters of credit to any outstanding receivables related to the applicable customers and then recognized as transportation revenues the remaining $34.4 million of proceeds in December 2020 related to the 2020 bankruptcy and $26.2 million of proceeds in June 2019 related to the 2019 bankruptcy, which represent a portion of the future performance obligations that were eliminated under the transportation agreements.    

Clean Air Act and Climate Change

The Company's pipelines and associated facilities are subject to the Clean Air Act (CAA) and comparable state laws and regulations, which regulate the emission of air pollutants from many sources and impose various compliance monitoring and reporting requirements. Under the CAA, the Company may be required to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions. The need to obtain permits has the potential to delay the development or expansion of the Company's projects. Over the next several years, the Company may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in 2015, the Environmental Protection Agency (EPA) issued a final rule under the CAA, lowering the National Ambient Air Quality Standard (NAAQS) for ground-level ozone to 70 parts per billion under both the primary and secondary standards to provide requisite protection of public health and welfare, respectively. Since that time, the EPA issued area designations with respect to ground-level ozone, issued final requirements that apply to state, local and tribal air agencies for implementing the 2015 NAAQS for ground-level ozone and, on December 31, 2020, published notice of a final action to retain the 2015 ozone NAAQS without revision on a going-forward basis. However, several groups have filed litigation over this December 2020 final action, and the NAAQS may be subject to further revision under the Biden Administration. States are expected to implement more stringent regulations that could apply to the Company's operations. Compliance with this final rule could, among other things, require installation of new emission controls on some of the Company's equipment, result in longer permitting timelines and significantly increase its capital expenditures and operating costs. Additionally, the threat of climate change continues to attract considerable public, governmental and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional, state and local levels of government to monitor and limit emissions of greenhouse gases (GHGs). These efforts have included consideration of cap-and-trade programs, carbon taxes, and GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. The EPA has determined that GHG emissions endanger public health and the environment and, as a result, has adopted regulations under the CAA related to GHG emissions.

The Company'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. As of December 31, 2021, the commitments were approximately $95.3 million, all of which are expected to be settled within the next twelve months.

The Company'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 Company incurred expenses of $5.9 million, $4.2 million and $3.8 million related to pipeline capacity agreements for the years ended December 31, 2021, 2020 and 2019. The future commitments related to pipeline capacity agreements as of December 31, 2021, were $2.7 million in 2022, with no future commitments after 2022.

As of December 31, 2021 and 2020, the Company had no assets and liabilities which were recorded at fair value on a recurring basis. The following methods and assumptions were used in estimating the fair value amounts included in the disclosures for financial assets and liabilities:

The carrying amounts and estimated fair values of the Company's financial assets and liabilities which were not recorded at fair value on the Consolidated Balance Sheets as of December 31, 2021 and 2020, were as follows (in millions):

(1) The carrying amount of long-term debt excludes a $5.3 million long-term finance lease obligation and

$4.8 million of unamortized debt issuance costs.

(1) The carrying amount of long-term debt excludes a $6.1 million long-term finance lease obligation and

$5.8 million of unamortized debt issuance costs.

The following table presents the Company's PPE as of December 31, 2021 and 2020 (in millions):

The non-depreciable assets were not included in the calculation of the weighted-average useful lives. 

    

The Company holds undivided interests in certain assets, including the Mobile Bay Pipeline of which the Company owns 64% and offshore and other assets, comprised of pipeline and gathering assets in which the Company holds various ownership interests. In addition, the Company 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.

In September 2021, the Company, through its newly created operating subsidiary, Louisiana Gas Transmission, acquired certain natural gas pipeline assets in the Lake Charles, Louisiana, area for approximately $20.0 million in cash.

In 2019, the Company entered into an agreement, subject to regulatory approval, to purchase the approximately 8% undivided interest that it did not already own in the Bistineau storage facility in Louisiana for approximately $18.8 million in cash. The FERC approved the purchase in early 2020 and the transaction closed on April 1, 2020. After this transaction, the Company owns 100% of the Bistineau storage facility.

Goodwill

As of December 31, 2021 and 2020, the Company had recorded on its Consolidated Balance Sheets $237.4 million of goodwill.

As of November 30, 2021, the Company elected to perform a qualitative assessment for its annual goodwill impairment test of its two reporting units. The qualitative assessment included the Company’s consideration of, among other things, the overall macroeconomic conditions, industry and market considerations, current discount rates and valuation multiples, overall financial performance and other relevant company specific events. Based on the assessment of these items, the Company concluded that it is more likely than not that the fair value of the two reporting units exceeded their respective carrying amounts. Accordingly, there were no indicators of impairment and the quantitative impairment test was not performed.

As of November 30, 2020, the Company performed a quantitative annual goodwill impairment test for its two reporting units. The results of the quantitative goodwill impairment test indicated that the fair value of the Company's reporting units exceeded their carrying amounts. The fair value measurement of the reporting units was derived based on judgments and assumptions the Company believes 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 under an income approach and inputs to the valuation model. The inputs included the Company’s five-year financial plan operating results, including operating revenues, the long-term outlook for growth in natural gas and NGLs demand, 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 and views regarding future market conditions, among others. The reasonableness of fair value estimates under the income approach were supported by a market approach under which the Company applied EBITDA multiples derived from publicly-available information to each reporting unit's EBITDA.

No impairment charges related to goodwill were recorded for any of the Company's reporting units during 2021, 2020 or 2019.

Intangible Assets

The following table contains information regarding the Company's intangible assets, which includes customer relationships acquired as part of its acquisitions (in millions):

The weighted-average remaining useful life of the Company's intangible assets as of December 31, 2021, was 22 years.

The Company 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 Company assets; however, the fair value of these obligations cannot be determined because the lives of the assets are indefinite. As a result, 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 Company's ARO as of December 31, 2021 and 2020 (in millions):

The following table presents all long-term debt issuances outstanding as of December 31, 2021 and 2020 (in millions):