Boardwalk Pipeline Partners, LP
Annual Report 2020

Plain-text annual report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K (Mark One) ☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2020 OR ☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from _______________ to _______________ Commission file number: 01-32665 BOARDWALK PIPELINE PARTNERS, LP (Exact name of registrant as specified in its charter) Delaware (State or other jurisdiction of incorporation or organization) 20-3265614 (I.R.S. Employer Identification No.) 9 Greenway Plaza, Suite 2800 Houston, Texas 77046 (866) 913-2122 (Address and Telephone Number of Registrant's Principal Executive Office) Securities registered pursuant to Section 12(b) of the Act: Title of each class NONE Trading Symbol(s) NONE Name of each exchange on which registered NONE Securities registered pursuant to section 12(g) of the Act: NONE Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes☒ 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. Yes ☐ No ☒ Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒    No ☐ Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐ Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act. Large accelerated filer ☐ Accelerated filer ☐ Non-accelerated filer ☒ Smaller reporting company ☐ Emerging growth company ☐ If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐ Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒ Boardwalk Pipeline Partners, LP meets the conditions set forth in General Instructions I(1) (a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format. Documents incorporated by reference. None. TABLE OF CONTENTS 2020 FORM 10-K BOARDWALK PIPELINE PARTNERS, LP PART I Item 1. Business Item 1A. Risk Factors Item 1B. Unresolved Staff Comments Item 2. Properties Item 3. Legal Proceedings Item 4. Mine Safety Disclosures PART II Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Item 6. Selected Financial Data Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations Item 7A. Quantitative and Qualitative Disclosures About Market Risk Item 8. Financial Statements and Supplementary Data Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure Item 9A. Controls and Procedures Item 9B. Other Information PART III Item 10. Directors, Executive Officers and Corporate Governance Item 11. Executive Compensation Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters Item 13. Certain Relationships and Related Transactions, and Director Independence Item 14. Principal Accounting Fees and Services PART IV Item 15. Exhibits and Financial Statement Schedules Item 16. Form 10-K Summary 2 3 3 10 19 19 19 19 19 19 19 20 26 27 61 61 61 62 62 62 62 62 62 63 63 65 PART I Item 1. Business 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. Introduction We are a Delaware limited partnership formed in 2005. Our business, which is conducted by our primary subsidiary, Boardwalk Pipelines, LP (Boardwalk Pipelines) and its operating subsidiaries (together, the operating subsidiaries), consists of integrated natural gas and natural gas liquids and other hydrocarbons (herein referred to together as NGLs) pipeline and storage systems. All of our operations are conducted by the operating subsidiaries. As of December 31, 2020, Boardwalk Pipelines Holding Corp., a wholly-owned subsidiary of Loews Corporation (Loews), owned directly or indirectly, 100% of our capital. Our Business We operate in the midstream portion of the natural gas and NGLs industry, providing transportation and storage for those commodities. We own approximately 14,095 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 and the Midwestern states of 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 local distribution companies (LDCs), electric power generators, exporters of liquefied natural gas (LNG), industrial users, producers and marketers of natural gas, 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, 2020, approximately 90% of our revenues were derived from capacity reservation fees under firm contracts, approximately 6% 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 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 13,650 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 445 miles of NGLs pipelines in Louisiana and Texas. In 2020, our pipeline systems transported approximately 3.2 trillion cubic feet (Tcf) of natural gas and approximately 80.6 MMBbls of NGLs. Average daily throughput on our natural gas pipeline systems during 2020 was approximately 8.6 Bcf. Our natural gas storage facilities are comprised of fourteen underground storage fields located in four states with aggregate working gas capacity of approximately 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 seven salt-dome caverns and related brine infrastructure for use in providing brine supply services and to support the NGLs storage operations. 3 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  Pipeline  Company,  LLC  (Gulf  South): Effective January 1, 2020, Gulf South converted from a limited partnership to a limited liability company. Immediately subsequent to the conversion, our Gulf Crossing Pipeline Company LLC, operating subsidiary was merged into Gulf South. Our merged Gulf South pipeline system is located along the Gulf Coast in the states of Oklahoma, Texas, Louisiana, Mississippi, Alabama and Florida. The on-system markets directly served by the Gulf South system are generally located in eastern Texas, Louisiana, southern Mississippi, southern Alabama and the Florida Panhandle. Gulf South also services the Perryville Exchange. These markets include LNG export markets in the Freeport, Texas, area, power plants, LDCs and municipalities located across the system, including New Orleans, Louisiana; Jackson, Mississippi; Mobile, Alabama; Houston, Texas; and Pensacola, Florida, and other end-users located across the system, including the Baton Rouge to New Orleans industrial corridor and Lake Charles, Louisiana. Gulf South also has indirect access to off- system markets through numerous interconnections with unaffiliated interstate and intrastate pipelines and storage facilities. These pipeline interconnections provide access to markets throughout the northeastern, midwestern and southeastern U.S. Gulf South has ten natural gas storage facilities. The two natural gas storage facilities located in Bistineau, Louisiana, and Jackson, Mississippi, have approximately 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  Transmission,  LLC  (Texas  Gas): Our Texas Gas pipeline system is a bi-directional pipeline located in Louisiana, East Texas, Arkansas, Mississippi, Tennessee, Kentucky, Indiana and Ohio, with smaller diameter lines extending into Illinois. Texas Gas directly serves LDCs, municipalities and power generators in its market area, which encompasses eight states in the South and Midwest and includes the Memphis, Tennessee; Louisville, Kentucky; Cincinnati and Dayton, Ohio; and Evansville and Indianapolis, Indiana, metropolitan areas. Texas Gas also has indirect market access to, and receives supply from, the Northeast through interconnections with unaffiliated pipelines. A large portion of the gas delivered by the Texas Gas system is used for heating during the winter months, but Texas Gas also supplies gas for cooling needs during the summer months. Texas Gas owns nine natural gas storage fields, of which it owns the majority of the working and base gas. Texas Gas uses this gas to meet the operational requirements of its transportation and storage customers and the requirements of its NNS customers. Texas Gas also uses its storage capacity to offer firm and interruptible storage services. Boardwalk Louisiana Midstream, LLC and Boardwalk Petrochemical Pipeline, LLC (collectively, Louisiana Midstream): Louisiana Midstream provides transportation and storage services for natural gas, NGLs and ethylene, fractionation services for NGLs and brine supply services for producers and consumers of petrochemicals through two hubs in southern Louisiana - the Choctaw Hub in the Mississippi River corridor area and the Sulphur Hub in the Lake Charles area. These assets provide approximately 48.8 MMBbls of salt-dome storage capacity, including approximately 7.6 Bcf of working natural gas storage capacity; significant brine supply infrastructure; and approximately 285 miles of pipeline assets, including an extensive ethylene distribution system. Louisiana Midstream also owns and operates the Evangeline Pipeline, an approximately 175-mile interstate ethylene pipeline that is capable of transporting approximately 4.2 billion pounds of ethylene per year between Port Neches, Texas, and Baton Rouge, Louisiana, with interconnections with the ethylene distribution system and storage facilities at the Sulphur and Choctaw Hubs. Throughput for Louisiana Midstream was 80.6 MMBbls for the year ended December 31, 2020. 4 Boardwalk  Texas  Intrastate,  LLC  (Boardwalk  Texas  Intrastate):  Boardwalk Texas Intrastate provides intrastate natural gas transportation services on pipelines located in South Texas extending on the west side from Bee County, near the Eagle Ford Shale, and Agua Dulce to the Corpus Christi area and to an interconnect with Gulf South in Jackson County, Texas. Boardwalk Texas Intrastate is situated to provide access to industrial and power generation markets in the Corpus Christi area as well as LNG export markets and third-party pipelines for exports to Mexico. The following table provides information for our pipeline and storage systems as of February 9, 2021: Pipeline and Storage Systems Gulf South Texas Gas Louisiana Midstream Boardwalk Texas Intrastate (1) Bcf per day (Bcf/d) Current Growth Projects Miles of Pipeline 7,415 5,970 460 250 Working Gas Storage Capacity (Bcf) 121.1 84.3 7.6 — Liquids Storage Capacity (MMBbls) Peak-day Delivery Capacity (1) (Bcf/d) Average Daily Throughput (Bcf/d) (1) — — 32.1 — 10.9 5.9 — — 5.6 3.0 — — In 2020, we placed into service approximately $335.0 million of growth projects which represents approximately 1.5 Bcf/d of firm natural gas transportation capacity and additional NGL infrastructure. Additionally, we expanded our natural gas storage capacity at our Forrest County, Mississippi, storage facilities. Collectively, these projects were completed on-time and within budget. We expect to spend approximately $380.0 million on our growth projects currently under construction through 2024. Those projects are expected to serve increased natural gas demand from a power generation plant and liquids demand from petrochemical facilities. All of our growth projects are secured by long-term firm contracts. Refer to Liquidity  and  Capital  Resources  in Part II, Item 7. of this Annual Report on Form 10-K for further discussion of capital expenditures and financing. 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. Transportation Services: We offer transportation services on both a firm and interruptible basis. Our customers choose, based upon their particular needs, the applicable mix of services depending upon availability of pipeline capacity, the price of services and the volume and timing of customer requirements. Our firm transportation customers reserve a specific amount of pipeline capacity at specified receipt and delivery points on our system. 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. Capacity reservation revenues derived from a firm service contract are generally consistent during the contract term, but can be higher in winter periods than the rest of the year, especially for NNS agreements. Firm transportation contracts can range from one to twenty years, although we may enter into shorter- or longer-term contracts. In providing interruptible services to customers, we agree to transport natural gas or NGLs for a customer when capacity is available. Interruptible service customers pay a commodity charge only for the volume of gas actually transported, plus a fuel charge. Interruptible transportation agreements have terms ranging from day-to-day to multiple years, with rates that change on a daily, monthly or seasonal basis. Our NGLs transportation services are generally fee-based or based on minimum volume requirements. Storage  and  Parking  and  Lending  Services: We offer natural gas and NGLs storage services on both a firm and interruptible basis. Firm storage customers reserve a specific amount of storage capacity, including injection and withdrawal rights, while interruptible customers receive storage capacity and injection and withdrawal rights when available. Similar to firm transportation customers, firm storage customers generally pay fees based on the quantity of capacity reserved plus an injection and withdrawal fee. Firm storage contracts typically range in term from one to ten years. Interruptible storage customers pay for the volume of gas actually stored plus injection and withdrawal fees. Generally, interruptible storage 5 agreements are for monthly terms. We are able to charge market-based rates for the majority of our natural gas storage capacity pursuant to authority granted by the FERC. Our NGLs storage rates are market-based, and the contracts for NGLs services are typically fixed-price arrangements with escalation clauses. PAL is an interruptible service offered to customers providing them the ability to park (inject) or borrow (withdraw) natural gas into or out of our pipeline systems at a specific location for a specific period of time. Customers pay for PAL services in advance or on a monthly basis depending on the terms of the agreement. No-Notice Services: NNS consist of a combination of firm natural gas transportation and storage services that allow customers to inject or withdraw natural gas from storage with little or no notice. Customers pay a reservation charge based upon the capacity reserved plus a commodity and a fuel charge based on the volume of gas actually transported. In accordance with its tariff, Texas Gas loans stored gas to certain of its no-notice customers who are obligated to repay the gas in-kind. Customers and Markets Served We contract directly with end-use customers, including LDCs, electric power generators, exporters of LNG 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. Based on our 2020 transportation, storage and PAL revenues, net of fuel, our customer mix was as follows: marketers (22%), power generators (22%), natural gas producers (19%), LDCs (16%), industrial end-users (12%) and exporters of LNG (9%). Based upon our 2020 transportation, storage and PAL revenues, net of fuel, our deliveries were as follows: pipeline interconnects (32%), LDCs (19%), power generators (16%), industrial end-users (14%), storage activities (9%), exporters of LNG (9%) and others (1%). One customer comprised approximately 10% of our operating revenues in 2020. Marketers: Natural gas marketing companies utilize our services to provide services to our other customer groups as well as to customer groups in off- system markets. The services may include combined gas transportation and storage services to support the needs of the other customer groups. Some of the marketers are sponsored by LDCs or producers. Power Generators: Our natural gas pipelines are directly connected to 45 natural-gas-fired power generation facilities in nine states. The demand of the power generating customers generally peaks during the summer cooling season which is counter to the winter season peak demands of the LDCs, although demand from power generators remains strong in the winter months as well, due to the overall increase in the use of natural gas over other sources, such as coal, to generate electricity. Our power generating customers can use a combination of NNS, firm and interruptible transportation services.     Natural Gas Producers: Producers of natural gas use our services to transport gas supplies from producing areas, including shale natural gas production areas, to supply pools and to other customers on and off of our systems. Producers contract with us for storage services to store excess production and to optimize the ultimate sales prices for their gas. Local Distribution Companies: Most of our LDC customers use firm natural gas transportation services, including NNS. We serve approximately 175 LDCs at more than 300 delivery locations across our pipeline systems. The demand of these customers peaks during the winter heating season. Industrial  End-Users: We provide approximately 186 industrial facilities with a combination of firm and interruptible natural gas and NGLs transportation and storage services. Our pipeline systems are directly connected to industrial facilities in the Baton Rouge to New Orleans industrial corridor; Lake Charles, Louisiana; Mobile, Alabama; and Pensacola, Florida. We can also access the Houston Ship Channel through third-party natural gas pipelines. Exporters  of  LNG:  LNG exporters use our firm transportation services to reach LNG liquefaction and export facilities. We provide 1.4 Bcf/d of firm natural gas transportation service directly to the Freeport LNG liquefaction and export facility in Freeport, Texas. 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, 2020, we had approximately $9.5 billion of projected operating revenues under committed firm transportation agreements, of which our deliveries are expected to be as follows: power generators (30%), exporters of LNG (22%), pipeline interconnects (21%) industrial end-users (13%), LDCs (8%), storage activities (5%) and others (1%). 6 Government Regulation Federal Energy Regulatory Commission: The FERC regulates our interstate natural gas transmission operating subsidiaries under the Natural Gas Act of 1938 (NGA) and the Natural Gas Policy Act of 1978 (NGPA). The FERC regulates, among other things, the rates and charges for the transportation and storage of natural gas in interstate commerce and the construction, extension, enlargement or abandonment of facilities under its jurisdiction. Where required, our interstate natural gas pipeline subsidiaries hold certificates of public convenience and necessity issued by the FERC covering certain of their facilities, activities and services. The FERC also prescribes accounting treatment for our interstate natural gas pipeline subsidiaries which is separately reported pursuant to forms filed with the FERC. The regulatory books and records and other activities of our subsidiaries that operate under the FERC's jurisdiction may be periodically audited by the FERC. 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. Boardwalk Texas Intrastate transports 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. Surface Transportation Board and Louisiana Public Service Commission: The STB regulates the rates we charge for interstate service on our ethylene pipelines. The LPSC regulates the rates we charge for intrastate service within the state of Louisiana on our petrochemical and NGL pipelines. The STB and LPSC require that our transportation rates are reasonable and that our practices cannot unreasonably discriminate among our shippers. U.S. Department of Transportation (DOT): We are regulated by the DOT, through the Pipeline and Hazardous Material Safety Administration (PHMSA), under the Natural Gas Pipeline Safety Act of 1968, as amended (NGPSA), and the Hazardous Liquids Pipeline Safety Act of 1979, as amended (HLPSA). The NGPSA and HLPSA govern the design, installation, testing, construction, operation, replacement and management of interstate natural gas and NGLs pipeline facilities. We have authority from PHMSA to operate certain natural gas pipeline assets under issued permits with specific conditions that allow us to operate those pipeline assets at higher than normal operating pressures of up to 0.80 of the pipeline's Specified Minimum Yield Strength (SMYS). Operating at these pressures allows us to transport all the existing natural gas volumes we have contracted for on those facilities with our customers. PHMSA retains discretion whether to grant or maintain authority for us to operate our natural gas pipeline assets at higher pressures and, in the event that PHMSA should elect not to allow us to operate at these higher pressures, 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. PHMSA's regulations also require transportation pipeline operators to implement integrity management programs to comprehensively evaluate certain high risk areas, known as high consequence areas (HCAs), high population areas (also known as moderate consequence areas (MCAs)), and Class 3 and Class 4 areas, which are determined by specific population densities near our pipelines, as well as certain drinking water sources and unusually sensitive ecological areas, along our pipelines, and take additional safety measures to protect people and property in these areas. 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) and the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (2016 Act). 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. Pursuant to the 2016 Act, PHMSA published a final rule in February 2020 that amended the minimum safety issues related to natural gas storage facilities, including wells, wellbore tubing and casing, which final rule was amended to add applicable reporting requirements and was subsequently published in July 2020. Also, in October 2019, PHMSA published the first of three expected regulations relating to new or more stringent 7 requirements for certain natural gas pipelines, that had originally been proposed in 2016 as part of PHMSA's “gas Mega Rule,” which first final rule became effective on July 1, 2020. This regulation imposed numerous requirements, including maximum allowable operating pressure (MAOP) reconfirmation through re- verification of all historical records for pipelines in service, which re-certification process may require natural gas pipelines installed before 1970 (previously excluded from certain pressure testing obligations) to be pressure tested, the periodic assessment of additional pipeline mileage outside of HCAs (in MCAs as well as Class 3 and Class 4 areas), the reporting of exceedances of MAOP and the consideration of seismicity as a risk factor in integrity management. Additional amendments to this October 2019 final rule relating to recordkeeping for gas transmission lines were published by PHMSA in July 2020. We are currently evaluating the operational and financial impact related to this final rule. The remaining rulemakings comprising the gas Mega Rule have not yet been published, and we cannot predict when they will be finalized; however, they are expected to include revised pipeline repair criteria as well as more stringent corrosion control requirements. Also, in the Fiscal Year 2021 Omnibus Appropriations Bill passed by Congress and made effective December 27, 2020, the Congress reauthorized PHMSA through fiscal year 2023 and directed the agency to move forward with several regulatory actions, including the “Pipeline Safety: Class Location Change Requirements” and the “Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines” proposed rulemakings. Congress has also instructed PHMSA to issue final regulations that will require operators of non-rural gas gathering lines and new and existing transmission and distribution pipeline facilities to conduct certain leak detection and repair programs and to require facility inspection and maintenance plans to align with those regulations. New 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. Other: Our operations are also 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 and in connection with spills, releases, discharges and emissions of various substances into the environment. Environmental regulations also require that our facilities, sites and other properties be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Occupational health and safety regulations establish standards protective of workers, both generally and within the pipeline industry. These laws, as amended from time to time, that our operations are subject to, include, for example: • • • • • • • the Clean Air Act (CAA) and analogous state laws, which regulate air emission pollutants, greenhouse gas (GHG) emissions and reciprocating engines subject to Maximum Achievable Control Technology standards; the Federal Water Pollution Control Act, commonly referred to as the Clean Water Act, and analogous state laws, which establish the extent to which waterways are subject to federal or state jurisdiction and serve to regulate the discharge of wastewater from our facilities into state and federal waters; the Comprehensive Environmental Response, Compensation and Liability Act, commonly referred to as CERCLA, or the Superfund law, and analogous state laws, which regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent hazardous substances for disposal; the Resource Conservation and Recovery Act (RCRA) and analogous state laws, which impose requirements for the generation, storage, treatment, transportation and disposal of solid and hazardous wastes at or from our facilities; the Endangered Species Act (ESA), which restricts activities that may affect federally identified endangered and threatened species or their habitats by the implementation of operating restrictions or a temporary, seasonal or permanent ban in affected areas; the National Environmental Policy Act (NEPA), which requires federal agencies to evaluate major agency actions having the potential to impact the environment and that may require the preparation of environmental assessments and more detailed environmental impact statements that may be made available for public review and comment; and the Occupational Safety and Health Act (OSHA) and analogous state laws, which establish workplace standards for the protection of the health and safety of employees, including the implementation of hazard communications programs designed to inform employees about hazardous substances in the workplace, potential harmful effects of these substances and appropriate control measures. 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 8 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. President Biden has indicated that he intends to pursue additional environmental regulations, whether by new legislation, executive actions or regulatory initiatives, which may impact our operations. For example, in recent years, there have been conflicting interpretations of what waterways are subject to jurisdiction under the Clean Water Act, with competing rulemakings being developed, and subsequently challenged in courts, by different presidential administrations. The incoming Biden Administration may propose another interpretation of the extent of this jurisdiction, though we cannot predict the likelihood or effects of any such proposal at this time. Similarly, President Biden has announced plans to take action with regards to climate change and signed executive orders to this effect on January 20, 2021; for more information, see Item 1A. Risk Factors—Business Risks—Legislative and regulatory initiatives related to climate change make our operations, as well as the operations of our fossil-fuel producer customers, subject to a series of regulatory, political, litigation and financial risks associated with the production and processing of fossil fuels and emission of GHGs. 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 or 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. Human Capital At December 31, 2020, we had 1,240 employees, approximately 100 of whom were included under collective bargaining agreements. A satisfactory relationship exists between management and labor. 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 our primary core value. Our emphasis on safety extends to our approach to managing the risk of operational disruptions due to coronavirus disease 2019 (COVID-19), and we have maintained full, continuous operations throughout the pandemic. Available Information Our website is located at www.bwpipelines.com. We make available free of charge through our website our Annual Reports on Form 10-K, which include our audited financial statements, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (Exchange Act) as soon as we electronically file such material with the Securities and Exchange Commission (SEC). These documents are also available on the SEC's website at www.sec.gov. 9 Item 1A. Risk Factors 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. Business Risks 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. Our natural gas transportation and storage operations are subject to extensive regulation by the FERC, including the types, rates and terms of services we may offer to our customers, construction of new facilities, creation, modification or abandonment of services or facilities and recordkeeping and relationships with affiliated companies. An adverse FERC action in any of these areas could affect our ability to compete for business, construct new facilities, offer new services or recover the full cost of operating our pipelines. This regulatory oversight can result in longer lead times to develop and complete any future project than competitors that are not subject to the FERC's regulations. The FERC can also deny us the right to abandon certain facilities from service. The FERC also 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 are allowed to charge in accordance with Section 5 of the NGA. 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. 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. Our interstate pipelines are subject to regulation by PHMSA which is part of the DOT. PHMSA regulates the design, installation, testing, construction, operation and maintenance of existing interstate natural gas and NGLs pipeline facilities. PHMSA regulation currently requires pipeline operators to implement integrity management programs, including frequent inspections, correction of certain identified anomalies and other measures to promote pipeline safety in HCAs, MCAs, and Class 3 and Class 4 areas, as well as in areas unusually sensitive to environmental damage and commercially navigable waterways. States have jurisdiction over certain of our intrastate pipelines and have adopted regulations similar to existing PHMSA regulations. State regulations may impose more stringent requirements than found under federal law that affect our intrastate operations. Compliance with these rules over time generally has resulted in an overall increase in our maintenance costs. The imposition of new or more stringent pipeline safety rules applicable to natural gas or NGL pipelines, or any issuance or reinterpretation of guidance from PHMSA or any state agencies with respect thereto, could cause us to install new or modified safety controls, pursue additional capital projects or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in us incurring increased capital and operating costs, experiencing operational delays and suffering potential adverse impacts to our operations or our ability to reliably serve our customers. Requirements that are imposed under the 2011 Act or the more recent 2016 Act may also increase our capital and operating costs or impact the operation of our pipelines. In the Fiscal Year 2021 Omnibus Appropriations Bill, Congress reauthorized PHMSA through fiscal year 2023 and directed the agency to move forward with several regulatory actions. See Part I, Item 1. Business—Government Regulation—U.S. Department of Transportation of this Annual Report on Form 10-K for further discussion on pipeline safety matters. Any 10 new pipeline safety legislation or implementing regulations could impose more stringent or costly compliance obligations on us and could require us to pursue additional capital projects or conduct integrity or maintenance programs on an accelerated basis, any or all of which tasks could result in us incurring increased operating costs that could have a material adverse effect on our costs of providing transportation services. We have entered into certain firm transportation contracts with shippers on certain of our expansion projects 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 an existing facility, the design, construction and development occurs over an extended period of time, and we will not receive any revenue or cash flow from that project until after it is placed into commercial service. On our interstate pipelines, there are several years between when the project is announced and when customers begin using the new facilities. During this period we spend capital and incur costs without receiving any of the financial benefits associated with the projects. The construction of new assets involves regulatory (federal, state and local), landowner opposition, environmental, activist, legal, political, materials and labor costs, as well as operational and other risks that are difficult to predict and some are beyond our control. A project may not be completed on time or at all due to a variety of factors, may be impacted by significant cost overruns or may be materially changed prior to completion as a result of developments or circumstances that we are not aware of when we commit to the project. Any of these events could result in material unexpected costs or have a material adverse effect on our ability to realize the anticipated benefits from our growth projects. Legislative and regulatory initiatives related to climate change make our operations, as well as the operations of our fossil-fuel producer customers, subject to a series of regulatory, political, litigation and financial risks associated with the production and processing of fossil fuels and emission of GHGs. The threat of climate change continues to attract considerable attention in the U.S. and in foreign countries. Numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit existing emissions of GHGs as well as to restrict or eliminate such future emissions, which makes our operations as well as the operations of our fossil fuel producer customers subject to a series of regulatory, political, litigation and financial risks associated with the production and processing of fossil fuels and emission of GHGs. In the U.S., no comprehensive climate change legislation has been implemented at the federal level. With the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the Environmental Protection Agency (EPA) has adopted several rules that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain natural gas system sources in the U.S., implement New Source Performance Standards (NSPS) directing the reduction of methane from certain new, modified or reconstructed facilities in the natural gas sector, and together with the DOT, implement GHG emissions limits on vehicles manufactured for operation in the U.S. In recent years, there has been considerable uncertainty surrounding regulation of methane emissions, as the EPA under the Obama Administration published final regulations under the CAA establishing new performance standards for methane in 2016, but since that time the EPA under the Trump Administration has undertaken several measures, including publishing in September 2020 final rule policy and technical amendments to the NSPS, for stationary sources of air emissions. The policy amendments, effective September 14, 2020, notably removed the transmission and storage sector from the regulated source category and rescinded methane and volatile organic compound (VOC) requirements for the remaining sources that were established by former President Obama’s Administration; whereas the technical amendments, effective November 16, 2020, included changes to fugitive emissions monitoring and repair schedules for gathering and boosting compressor stations and low-production wells, and recordkeeping and reporting requirements. Various states and industry and environmental groups are separately challenging both the original 2016 standards and the EPA's September 2020 final rules, and on January 20, 2021, President Biden issued an executive order, that directed the EPA to reconsider the technical amendments and issue a proposed rule suspending, revising or rescinding 11 those amendments by no later than September 2021. A reconsideration of the September 2020 policy amendments is expected to follow. The January 20, 2021, executive order also directed the establishment of new methane and VOC standards applicable to existing oil and gas operations, including the production, transmission, processing and storage segments. Various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs and restriction of emissions. At the international level, the non-binding Paris Agreement requests that nations limit their GHG emissions through individually-determined reduction goals every five years after 2020. Although the U.S. had withdrawn from the Paris Agreement, President Biden has issued executive orders recommitting the U.S. to the Paris Agreement and calling for the federal government to begin formulating the U.S.’ nationally determined emissions reduction goal under the agreement. With the U.S. recommitting to the Paris Agreement, additional executive orders may be issued or federal legislation or regulatory initiatives may be adopted to achieve the Paris Agreement’s goals. 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. On January 27, 2021, President Biden issued an executive order that commits to substantial action on climate change, calling for, among other things, suspending the issuance of new leases for oil and gas development on federal lands, pending completion of a review of leasing and permitting practices and expanding on the Acting Secretary of the U.S. Department of the Interior's January 20, 2020, order, effective immediately, that suspends new oil and gas leases and drilling permits on federal lands and waters for a period of 60 days. The executive order also called for the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and an increased emphasis on climate-related risks across government agencies and economic sectors. Legal challenges to these suspensions are expected, with at least one industry group filing a lawsuit on January 27, 2021, in Wyoming federal district court and seeking to have the moratorium declared invalid. The new presidential administration could also pursue the imposition of more restrictive requirements for the establishment of pipeline infrastructure or the permitting of LNG export facilities, as well as more restrictive GHG emissions limitations for oil and gas facilities. Litigation risks are also increasing, as a number of cities and other local governments have sought to bring suit against fossil fuel producer companies in state or federal court, alleging, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels, and are responsible for roadway and infrastructure damages as a result, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors or customers by failing to adequately disclose those impacts. There are also increasing financial risks for fossil fuel energy companies as investors invested in fossil fuel energy companies 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-energy related sectors. Institutional lenders who provide financing to fossil fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. Additionally, there is the possibility that financial institutions will be required to adopt policies that limit funding for fossil fuel energy companies. Recently, the Federal Reserve announced that it has joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. This could make it more difficult to secure funding for exploration and production or midstream energy business activities. The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from the oil and gas sector or otherwise restrict the areas in which this sector may produce fossil fuels or generate GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for fossil fuels, which could reduce demand for our transportation and storage services. Political, litigation and financial risks may result in our fossil fuel producer customers restricting or canceling production activities, incurring liability for infrastructure damages as a result of climatic changes or impairing their ability to continue to operate in an economic manner, which also could reduce demand for our services. Moreover, the increased competitiveness of alternative energy sources (such as wind, solar, geothermal, tidal and biofuels) could reduce demand for hydrocarbons, and for our services. Finally, increasing concentrations of GHG in the earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods, rising sea levels and other climatic events. 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 COVID-19 has materially negatively impacted worldwide economic and commercial activity and financial markets and has 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. If significant portions of our workforce are unable to work 12 effectively, including because of illness, quarantines, government actions, facility closures or other restrictions in connection with COVID-19, 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; and cause other unpredictable events. The impact of COVID-19 has impacted capital markets, which may impact our customers' financial position, and recoverability of our receivables from our customers may be at risk. The full impact of COVID-19 is unknown and continues to evolve. The extent to which COVID-19 negatively impacts our business and operations will depend on the severity, location and duration of the effects and spread of COVID-19, the continued actions undertaken by national, regional and local governments and health officials to contain the virus or treat its effects, and how quickly and to what extent economic conditions improve and normal business and operating conditions resume. It might also have the effect of increasing several of the other risk factors contained herein. 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. The recent volatility in the pricing levels of natural gas, oil and NGLs has adversely affected 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. The current erosion in 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. The price differentials between natural gas supplies and market demand for natural gas have reduced 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. Over the past several years, as a result of market conditions, we have renewed 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. 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 affect adversely 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 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. As cyber-incidents continue to evolve, legislation could be enacted to mitigate cyber-threats. This will likely 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 13 that affect our facilities, or those of our customers, suppliers or others with whom we do business could have a material adverse effect on our business, cause us a financial loss and/or damage our reputation. We are exposed to credit risk relating to 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 2020, one customer comprised approximately 10% of our 2020 operating revenues. Additionally, the top ten customers holding firm capacity under firm agreements comprised approximately 40% 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 or series of acquisitions, where the purchase price exceeds $100.0 million over a rolling 12-month period, which limits the amount of additional indebtedness we can incur to grow our business, and could require us to reduce indebtedness if our earnings before interest, income taxes, depreciation and amortization (EBITDA) decreases to a level that would cause us to breach this covenant. Future financing agreements we may enter into could contain similar or more restrictive covenants or may not be as favorable as those under our existing indebtedness. Our ability to comply with the covenants and restrictions contained in our credit agreement may be affected by events beyond our control, including 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 substantial indebtedness could affect our ability to meet our obligations and may otherwise restrict our activities. As of December 31, 2020, we had $3.5 billion in principal amount of long-term debt outstanding, including amounts borrowed under our revolving credit facility. 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 substantial indebtedness could have important consequences. For example, it could: • limit our ability to borrow money for our working capital, capital expenditures, debt service requirements or other general partnership purposes; 14 • • • impact the ratings received from credit rating agencies; increase our vulnerability to general adverse economic and industry conditions; and limit our ability to respond to business opportunities, including growing our business through acquisitions. 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, in the case of unsecured debt, under 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 spending requirements through our available financing options, including cash generated from operations and borrowings under our revolving credit facility. 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. 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. 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 renew right-of-way or easement contracts or permits, licenses, consents or otherwise, could have a material adverse effect on our operations. Rising sea levels, subsidence and erosion could damage our pipelines and the facilities that serve our customers, particularly along coastal waters and offshore in the Gulf of Mexico. Our pipeline operations along coastal waters and offshore in the Gulf of Mexico could be impacted by rising sea levels, subsidence and erosion. Subsidence issues are also a concern for our pipelines at major river crossings. Rising sea levels, subsidence and erosion could cause serious damage to our pipelines, which could affect our ability to provide transportation services or result in leakage, migration, releases or spills from our operations to surface or subsurface soils, surface water, groundwater or offshore waters, which could result in liability, remedial obligations and/or otherwise have a negative impact on continued operations. Such rising sea levels, subsidence and erosion processes could impact our customers who operate along coastal waters or offshore in the Gulf of Mexico, and they may be unable to utilize our services. Rising sea levels, subsidence 15 and erosion could also expose our operations to increased risks associated with severe weather conditions and other adverse events and conditions, such as hurricanes and flooding. As a result, we may incur significant costs to repair and preserve our pipeline infrastructure. In recent years, local governments and landowners have filed lawsuits in Louisiana against energy companies, alleging that their operations contributed to increased coastal rising seas and erosion and seeking substantial damages. 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. Any such transactions involve potential risks that may include, among other things: • • • • • • • the diversion of management's and employees' attention from other business concerns; inaccurate assumptions about volume, revenues and project costs, including potential synergies; a decrease in our liquidity as a result of our using available cash or borrowing capacity to finance the acquisition or project; a significant increase in our interest expense or financial leverage if we incur additional debt to finance the acquisition or project or if we make inaccurate assumptions about the overall costs of debt; an inability to hire, train or retain qualified personnel to manage and operate the acquired business and assets or the developed assets; unforeseen difficulties operating in new product areas or new geographic areas; and changes in regulatory requirements or delays of regulatory approvals. Additionally, acquisitions also contain the following risks: • • • • an inability to integrate successfully the businesses we acquire; the assumption of unknown liabilities for which we are not indemnified, for which our indemnity is inadequate or for which our insurance policies may exclude from coverage; limitations on rights to indemnity from the seller; and customer or key employee losses of an acquired business. 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. 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 federal, state and local laws and regulations relating to protection of worker safety or the environment. These laws include, for example, the CAA, the Clean Water Act, CERCLA, the 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 16 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 performance or expansion of projects and the issuance of orders enjoining future operations in a particular area. Under certain of these environmental laws and regulations, we could be subject to joint and several or strict liability for the removal or remediation of previously released pollutants or property contamination regardless of whether we were responsible for the release or contamination or if our operations were not in compliance with all laws. We may not be able to recover some or any of the costs incurred from insurance. Stricter environmental or worker safety laws, regulations or enforcement policies could significantly increase our operational or compliance costs and compliance with new or more stringent environmental legal requirements could delay or prohibit our ability to obtain permits for operations or require us to install additional pollution control equipment. For example, in April 2020, the federal district court for the District of Montana determined that the U.S. Army Corps of Engineers (the Corps) Clean Water Act Section 404 Nationwide Permit 12 (NWP 12) failed to comply with consultation requirements under the federal ESA. The district court vacated NWP 12 and enjoined the issuance of new authorizations for oil and gas pipeline projects. While the district court's order has subsequently been limited pending appeal and NWP 12 authorizations remain available for certain oil and gas pipeline projects, we cannot predict the ultimate outcome of this case and its impacts to the Nationwide Permit program. Additionally, in response to the vacatur, on January 13, 2021, the Corps published a reissuance of a restructured NWP 12 for oil and natural gas pipeline activities that separated certain utilities formerly covered under the permit into other NWPs. While the rule is effective March 15, 2021, the rule may be subject to further revisions or suspension under the Biden Administration. While the full extent and impact of the vacatur is unclear at this time, any disruption in our ability to obtain coverage under NWP 12 or other general permits may result in increased costs and project delays if we are forced to seek individual permits from the Corps. See Part I, Item 1. Business—Government Regulation—Other of this Annual Report on Form 10- K for further discussion on environmental matters. 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 all 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 17 the negative impact of factors that adversely affect the demand for our services, such as adverse economic conditions, weather, higher fuel costs and taxes or other regulatory actions that increase the cost, or limit the use, of products we transport and store. 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. 18 Item 1B. Unresolved Staff Comments None. Item 2. Properties We are headquartered in approximately 103,000 square feet of leased office space located in Houston, Texas. We also have approximately 60,000 square feet of leased office space in Owensboro, Kentucky. Our operating subsidiaries own their respective pipeline and storage systems in fee. However, substantial portions of these systems are constructed and maintained on property owned by others pursuant to rights-of-way, easements, permits, licenses or consents. Our Pipeline and Storage Systems, in Part I, Item 1 of this Annual Report on Form 10-K contains additional information regarding our material property, including our pipelines and storage facilities. Item 3. Legal Proceedings Refer to Note 5 in Part II, Item 8. of this Annual Report on Form 10-K for a discussion of our legal proceedings. Item 4. Mine Safety Disclosures Not applicable. PART II Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Not applicable. Item 6. Selected Financial Data We are omitting disclosure under this item because we meet the conditions set forth in General Instructions I(1) (a) and (b) of Form 10-K. 19 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) Overview 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. Current Events In 2020, the COVID-19 pandemic and measures to mitigate the spread of COVID-19 significantly impacted the world and the U.S. An excess supply of energy products also led to disruptions in the energy sector and volatility in energy prices early in 2020, with a partial recovery of prices and demand occurring in the latter half of 2020. Our operations are considered essential critical infrastructure under current Cybersecurity and Infrastructure Security Agency guidelines, which allowed us to remain operating during the pandemic. As a result, the impacts from COVID-19 and the volatile energy prices have not been significant to our business, though some of our customers have been and continue to be directly impacted by COVID-19 and the volatility in commodity prices. In 2020, we transported approximately 3.2 Tcf of natural gas, or an 8% increase from 2019. Refer to Note 5 in Part II, Item 8. of this Annual Report on Form 10-K for further information about a producer customer bankruptcy in 2020. Firm Agreements A substantial portion of our transportation and storage capacity is contracted for under firm agreements. For the year ended December 31, 2020, approximately 90% 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, 2019, to December 31, 2020, including agreements for transportation, storage and other services, over the remaining term of those agreements (in millions): Total projected operating revenues under committed firm agreements as of December 31, 2019 Adjustments for: Actual revenues recognized from firm agreements in 2020 Firm agreements entered into in 2020 Total projected operating revenues under committed firm agreements as of December 31, 2020 (1) $ $ 9,329.0 (1,155.5) 1,276.5 9,450.0 (1) As of December 31, 2019, we expected our 2020 revenues from fixed fees under firm agreements to be approximately $1,065.0 million, including agreements for transportation, storage and other services. Our actual 2020 revenues recognized from fixed fees under firm agreements were $1,155.5 million, an increase of $90.5 million resulting primarily from contract renewals that occurred in 2020 and the receipt of proceeds related to a customer bankruptcy, as discussed in Note 5 in Part II, Item 8. of this Annual Report on Form 10-K. During 2020, we entered into approximately $1.3 billion of new firm agreements, of which approximately 55% were from new growth projects executed in 2020, but will not be placed into commercial service until 2024 or later years. As of December 31, 2020, our top ten customers holding firm capacity under firm agreements comprised approximately 40% of our total projected operating revenues. Additionally, the credit profile associated with our customers comprising the total projected operating revenues under firm agreements as of December 31, 2020, was 75% rated as investment grade, 4% rated as non-investment grade and 21% not rated. Note 3 in Part II, Item 8. of this Annual Report on Form 10-K contains more information regarding the revenues we expect to earn from fixed fees under committed firm agreements. 20 Contract Renewals Each year a portion of our firm transportation and storage agreements expire. The 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). Our storage rates are additionally 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. Demand for firm service is primarily based on market conditions which can vary across our pipeline systems. While we did not see a decrease in the demand for our transportation services as a result of the COVID-19 pandemic or the volatility in energy prices during 2020, if these conditions were to remain for an extended period of time or worsen, we could see a decline in the demand for our services. We focus our marketing efforts on enhancing the value of the capacity that is up for renewal and work with customers to match gas supplies from various basins to new and existing customers and markets, including aggregating supplies at key locations along our pipelines to provide end-use customers with attractive and diverse supply options. If the market perceives the value of our available capacity to be lower than our long-term view of the capacity, we may seek to shorten contract terms until market perception improves. Over the past several years, as a result of market conditions, we have renewed some expiring contracts at lower rates or for shorter terms than in the past. In addition to normal contract expirations, in the 2018 to 2020 timeframe, transportation agreements associated with our significant pipeline expansion projects that were placed into service in the 2007-2009 timeframe, have expired. A substantial portion of the capacity associated with the pipeline expansion projects was renewed or the contracts were restructured, usually at lower rates or lower volumes, which has negatively impacted our operating revenues. The last of the contract expirations associated with the 2007-2009 pipeline expansion projects have occurred and the associated impacts on operating revenues have been, and will continue to be, realized. Historically, we had delivered the majority of production volumes from these pipeline expansion projects to other pipelines. Over the past several years, we have focused on diversifying our deliveries to end-use markets through utilizing available capacity from contract expirations and the capacity created from our growth projects. We have diversified our deliveries such that almost 75% of our projected future firm reservation revenues, from firm agreements in place as of December 31, 2020, are for deliveries to end-use customers. Pipeline System Maintenance We incur substantial costs for ongoing maintenance of our pipeline systems and related facilities, including those incurred for pipeline integrity management activities, equipment overhauls, general upkeep and repairs. These costs are not dependent on the amount of revenues earned from our transportation services. PHMSA has developed regulations that require transportation pipeline operators to implement integrity management programs to comprehensively evaluate certain areas along pipelines and take additional measures to protect pipeline segments located in highly populated areas. These regulations have resulted in an overall increase in our ongoing maintenance costs, including maintenance capital and maintenance expense. In 2019, PHMSA issued the first part of its gas Mega Rule, which became effective on July 1, 2020. This regulation imposed numerous requirements, including MAOP reconfirmation through re-verification of all historical records for pipelines in service, which re-certification process may require natural gas pipelines installed before 1970 (previously excluded from certain pressure testing obligations) to be pressure tested, the periodic assessment of additional pipeline mileage outside of HCAs (in MCAs as well as Class 3 and Class 4 areas), the reporting of exceedances of MAOP and the consideration of seismicity as a risk factor in integrity management. The remaining rulemakings comprising the gas Mega Rule have not been published yet and we cannot predict when they will be finalized; however, they are expected to include revised pipeline repair criteria as well as more stringent corrosion control requirements. It is expected that these new rules will cause us to incur increased capital and operating costs, experience operational delays and result in potential adverse impacts to our ability to reliably serve our customers. See Part I, Item 1. Business and Item 1A. Risk Factors of this Annual Report on Form 10-K for further information. Maintenance costs may be capitalized or expensed, depending on the nature of the activities. For any given reporting period, the mix of projects that we undertake will affect the amounts we record as property, plant and equipment on our Consolidated Balance Sheets or recognize as expenses, which impacts our earnings. In 2021, we expect to spend approximately $370.0 million to maintain our pipeline systems, of which approximately $150.0 million is expected to be maintenance capital. In 2020, we spent $361.1 million, of which $148.8 million was recorded as maintenance capital. Refer to Capital Expenditures for more information regarding certain of our maintenance costs. 21 Results of Operations Note 2 in Part II, Item 8. of this Annual Report on Form 10-K contains a summary of our revenues and the related revenue recognition policies. A significant portion of our revenues are fee-based, being derived from capacity reservation charges under firm agreements with customers, which do not vary significantly period to period, but are impacted by longer-term trends in our business such as lower pricing on contract renewals and other factors discussed elsewhere in this MD&A. Our operating costs and expenses do not vary significantly based upon the amount of products transported, with the exception of costs recorded in Fuel and transportation expense, which are netted with fuel retained on our Consolidated Statements of Income. Please refer to the disclosures in this Item 7. of this Annual Report on Form 10-K of items that have impacted, or could impact in the future, our results of operations. 2020 Compared with 2019 Our net income for the year ended December 31, 2020, decreased $5.2 million, or 2%, to $290.5 million compared to $295.7 million for the year ended December 31, 2019, primarily due to the factors discussed below. Excluding the impacts from the 2020 and 2019 customer bankruptcies, 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, 2020, would have decreased $13.8 million, or 5%, compared to the comparative period. Operating revenues for the year ended December 31, 2020, increased $2.4 million, or less than 1%, to $1,297.6 million, compared to $1,295.2 million for the year ended December 31, 2019. Including the effect of the items in fuel and transportation expense, and excluding the impact from the customer bankruptcies as discussed in Note 5 in Part II, Item 8. of this Annual Report on Form 10-K, operating revenues decreased $10.7 million, or 1%. The decrease was driven by contract expirations that were recontracted at overall lower average rates as discussed above, mostly offset by revenues from our recently completed growth projects and higher storage and PAL revenues due to favorable market conditions. Operating costs and expenses for the year ended December 31, 2020, increased $21.5 million, or 3%, to $843.0 million, compared to $821.5 million for the year ended December 31, 2019. Excluding items offset with operating revenues, operating costs and expenses increased $17.0 million, or 2%, when compared to 2019. The operating expense increase was primarily due to an increased asset base from recently completed growth projects and the expiration of property tax abatements, partially offset by lower maintenance project spending and employee-related costs. Total other deductions for the year ended December 31, 2020, decreased $13.7 million, or 8%, to $163.8 million compared to $177.5 million for 2019 primarily due to lower interest rates and higher allowance for funds used for construction. Liquidity and Capital Resources We are a partnership holding company and derive all of our operating cash flow from our operating subsidiaries. Our principal sources of liquidity include cash generated from operating activities, our revolving credit facility 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. At December 31, 2020, we had no guarantees of off-balance sheet debt or other similar commitments to third parties, no debt obligations that contain provisions requiring accelerated payment of the related obligations in the event of specified levels of declines in credit ratings and no other off-balance sheet arrangements. At December 31, 2020, we had $2.9 million of cash on hand and more than $1.3 billion of available borrowing capacity under our $1.475 billion revolving credit facility. We anticipate that our existing capital resources, including our revolving credit facility and our cash flows from operating activities, will be adequate to fund our operations and capital expenditures for 2021. We may seek to access the debt markets to fund some or all capital expenditures for growth projects, acquisitions or for general partnership purposes. During 2020 we utilized the remaining capacity under our effective shelf registration statement, and we plan to file with the SEC and expect to have declared effective in the first quarter 2021, a $1.0 billion shelf registration statement under which we may publicly issue debt securities, warrants or rights from time to time. As of December 31, 2020, we have $4.6 billion of contractual cash payment obligations under firm agreements, of which $4.4 billion represents principal and interest payments related to our long-term debt. Note 11 in Part II, Item 8. of this Annual Report 22 on Form 10-K contains more information regarding our long-term debt and financing activities and Notes 4 and 5 contain more information about our other commitments. 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 8, 2021, our credit ratings for our senior unsecured notes and that of our operating subsidiaries having outstanding rated debt were as follows: Rating agency Standard and Poor's Moody's Investor Services Fitch Ratings, Inc. Rating (Us/Operating Subsidiaries) BBB-/BBB- Baa3/Baa2 BBB-/BBB- Outlook (Us/Operating Subsidiaries) Stable/Stable Stable/Stable Positive/Positive 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 During the second quarter 2020, we early adopted the SEC's Financial Disclosures about Guarantors and Issuers of Guaranteed Securities and Affiliates Whose  Securities  Collateralize  a  Registrant's  Securities rules, which simplify the disclosure requirements under Rule 3-10 of Regulation S-X related to our registered securities and allow for the simplified disclosure to be included within this MD&A. Accordingly, the required disclosures are provided below. Our debt is primarily issued at Boardwalk Pipelines, a wholly owned subsidiary of us, although we have historically also issued debt at our operating subsidiaries. As of December 31, 2020, 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. 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): Principal amounts guaranteed by Boardwalk Pipeline Partners Principal amounts not guaranteed Other (2) (3) Long-term debt and finance lease obligation (1) As of December 31, 2020 As of December 31, 2019 $ $ 2,950.0 400.0 110.7 3,460.7 $ $ 2,450.0 840.0 276.1 3,566.1 (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), and as of December 31, 2020, this includes the notes issued by Boardwalk Pipelines in August 2020, as further discussed above and in Note 11 in Part II, Item 8. of this Annual Report on Form 10-K. (2) This represents principal amounts of outstanding debt at Gulf South and Texas Gas, excluding any borrowings under the revolving credit facility. (3) As of December 31, 2020 and 2019, this represents the amounts related to a finance lease, unamortized debt discount and issuance costs and outstanding borrowings under the revolving credit facility guaranteed by Boardwalk Pipeline Partners. 23 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, 2020, 2019 and 2018 were $148.8 million, $138.7 million and $108.4 million. Growth capital expenditures were $270.6 million, $277.7 million and $359.8 million for the years ended December 31, 2020, 2019 and 2018. 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 2019 and 2018, we purchased $12.6 million and $18.5 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 $340.0 million in 2021, including approximately $150.0 million for maintenance capital and $190.0 million related to growth projects. Critical Accounting Estimates and Policies 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, 2020, our annual goodwill testing date, we performed a quantitative analysis on our two reporting units to measure whether the fair value of either of our reporting units was less than their carrying amounts. The fair value 24 measurement of the reporting units was derived based on judgments and assumptions we believe market participants would use in assessing the fair value of the reporting units. These judgments and assumptions included the valuation premise, use of a discounted cash flow model to estimate fair value under an income approach and inputs to the valuation model. The inputs included our five-year financial plan operating results, the long-term outlook for growth in natural gas 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 we applied EBITDA multiples derived from publicly-available information to each reporting unit's EBITDA. The use of alternate judgments and assumptions could substantially change the results of our goodwill impairment analysis, including the recognition of an impairment charge in our Consolidated Financial Statements. The results of the quantitative goodwill impairment test for 2020 and 2019 indicated that the fair value of our two reporting units exceeded their carrying amounts and no goodwill impairment charges were recognized. The estimated fair values of our reporting units fluctuate from year to year, and in 2020, the estimated fair values of the reporting units exceeded their carrying amounts by amounts that were lower than indicated in 2019, with the cushion of a reporting unit that had goodwill of $73.9 million being approximately 15%. Although the prospects for our reporting units remain positive, including their strong base operating cash flows and the markets in which they operate, significant changes in future estimated operating revenues or cash flows, or any other changes to the inputs to the valuation model, such as those previously discussed, could result in the recognition of future 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, 2020, 2019 and 2018, we recognized immaterial amounts related to asset impairment charges. Forward-Looking Statements Certain statements contained in this Annual Report on Form 10-K, as well as some statements in periodic press releases and some oral statements made by our officials and our subsidiaries during presentations about us, are “forward-looking.” Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance, intentions or achievements, and may contain the words “expect,” “intend,” “plan,” “anticipate,” “estimate,” “believe,” “will likely result” and similar expressions. In addition, any statement made by our management concerning future financial performance (including future revenues, earnings or growth rates), ongoing business strategies or prospects and possible actions by 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, risks and uncertainties related to the impacts of recent volatility in energy prices and the COVID-19 pandemic, the impacts of changes to laws and regulations or the implementation thereof, the costs of maintaining and ensuring the integrity and reliability of our pipeline systems, our ability to maintain or replace expiring gas transportation and storage contracts, our ability to complete projects that we have commenced or will commence, successful negotiation, consummation and completion of contemplated transactions, projects and agreements, and our ability to contract and sell short-term capacity on our pipelines. 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 these statements to reflect any change in our expectations or beliefs or any change in events, conditions or circumstances on which any forward-looking statement is based. Refer to Part I, Item 1A. of this Annual Report on Form 10-K for additional risks and uncertainties regarding our forward-looking statements. 25 Item 7A. Quantitative and Qualitative Disclosures About Market Risk Interest Rate Risk: With the exception of our revolving credit facility, for which the interest rates are periodically reset, our debt has been issued at fixed rates. For fixed-rate debt, changes in interest rates affect the fair value of the debt instruments but do not directly affect 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): Carrying amount of fixed-rate debt Fair value of fixed-rate debt 100 basis point increase in interest rates and resulting debt decrease 100 basis point decrease in interest rates and resulting debt increase Weighted-average interest rate $ $ $ $ 2020 2019 3,330.4 3,717.6 182.8 195.7 4.84 % $ $ $ $ 3,270.7 3,503.3 158.6 169.5 5.06 % At December 31, 2020, we had $130.0 million of variable-rate debt outstanding at a weighted-average interest rate of 1.39%. A 1.00% increase in interest rates would increase our cash payments for interest on our variable-rate debt by $1.3 million on an annualized basis. At December 31, 2019, we had $295.0 million outstanding under variable-rate agreements at a weighted-average interest rate of 3.00%. Commodity Risk: Our pipelines do not take title to the natural gas and NGLs which they transport and store, therefore, they do not assume the related commodity price risk associated with the products. Credit Risk: Our credit exposure generally relates to receivables for services provided, as well as volumes owed by customers for imbalances or gas lent by us to them, generally under PAL and 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, 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 trillion British thermal units (TBtu). Assuming an average market price during December 2020 of $2.45 per million British thermal unit (MMBtu), the market value of that gas was approximately $27.4 million. As of December 31, 2019, 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 12.8 TBtu. Assuming an average market price during December 2019 of $2.08 per MMBtu, the market value of that gas at December 31, 2019, was approximately $26.6 million. As of December 31, 2020 and 2019, there were no outstanding NGL imbalances owed to our operating subsidiaries. 26 Item 8. Financial Statements and Supplementary Data REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors of Boardwalk GP, LLC and the Partners of Boardwalk Pipeline Partners, LP Opinion on the Financial Statements We have audited the accompanying consolidated balance sheets of Boardwalk Pipeline Partners, LP and subsidiaries (the "Company") as of December 31, 2020 and 2019, 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, 2020, 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, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with accounting principles generally accepted in the United States of America. Basis for Opinion 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. Critical Audit Matter 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 committee 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 Critical Audit Matter Description The Company’s evaluation of goodwill for impairment involves a quantitative analysis to measure whether the fair value of either of the reporting units is less than their carrying amounts, including goodwill. If the carrying amount of a reporting unit exceeds its fair value, an impairment loss shall be recognized in an amount equal to that excess, limited to the total amount of goodwill recorded on the reporting unit. The fair value measurement of the reporting units is derived based on judgments and assumptions including the use of a discounted cash flow model to estimate fair value and inputs to the valuation model. The inputs included the long-term outlook for growth in natural gas and NGLs demand, the applied discount rate, and the five-year financial plan operating results. The use of alternate judgments and assumptions could substantially change the results of the goodwill impairment analysis, including the recognition of an impairment charge in the Consolidated Statement of Income. The results of the 27 quantitative goodwill impairment test indicated that the fair value of the Company’s reporting units exceeded their carrying amounts and no goodwill impairment charges were recognized. We identified goodwill for Boardwalk Pipeline Partners, LP as a critical audit matter because of the significant judgments made by management to estimate the fair value of each reporting unit. This required a high degree of auditor judgment and an increased extent of effort, including the need to involve fair value specialists, when performing audit procedures to evaluate the reasonableness of management’s judgments and assumptions related to the applied discount rate, the long-term outlook for growth in natural gas and NGLs demand, and the Company’s future estimated operating revenues within the five-year financial plan operating results. How the Critical Audit Matter Was Addressed in the Audit Our audit procedures related to management’s assumptions underlying the applied discount rates, the long-term outlook for growth in natural gas and NGLs demand, and the Company’s future estimated operating revenues within the five-year financial plan operating results included the following, among others: • We tested the effectiveness of controls over management’s goodwill impairment test, including controls over management’s estimate of the applied discount rate, the long-term outlook for growth in natural gas and NGLs demand, and the future estimated operating revenues for each reporting unit. • We evaluated management’s ability to accurately forecast future operating revenues by comparing actual results to management’s historical forecasts for each reporting unit. • We evaluated the reasonableness of the future estimated operating revenues within the five-year financial plan operating results by comparing the forecasts to: – Historical operating revenues of the Company’s similar or existing contracts with customers and average annual growth rates. – Forecasted information in analyst and industry reports for the Company and certain of its peer companies. • With the assistance of our fair value specialists, we evaluated the reasonableness of the applied discount rate, and the long-term outlook for growth in natural gas and NGLs demand used as inputs to management’s goodwill impairment test for each reporting unit by: – Comparing the Company’s estimate of the long-term outlook for growth in natural gas and NGLs demand for each reporting unit to industry reports and other market data. – Developing a range of independent estimates of the applied discount rate for each reporting unit and comparing those to the applied discount rates selected by management for each reporting unit. /s/ Deloitte & Touche LLP Houston, Texas February 9, 2021 We have served as the Company's auditor since 2003. 28 BOARDWALK PIPELINE PARTNERS, LP CONSOLIDATED BALANCE SHEETS (Millions) ASSETS December 31, 2020 2019 Current Assets: Cash and cash equivalents Receivables: Trade, net Other Gas transportation receivables Prepayments Other current assets Total current assets Property, Plant and Equipment: Natural gas transmission and other plant Construction work in progress Property, plant and equipment, gross Less—accumulated depreciation and amortization Property, plant and equipment, net Other Assets: Goodwill Gas stored underground Other Total other assets Total Assets $ 2.9 $ 115.1 23.4 6.6 18.5 7.0 173.5 11,964.1 184.2 12,148.3 3,598.5 8,549.8 237.4 101.9 167.3 506.6 3.7 117.2 15.2 7.5 16.0 8.1 167.7 11,489.5 253.9 11,743.4 3,263.7 8,479.7 237.4 97.1 161.2 495.7 $ 9,229.9 $ 9,143.1 The accompanying notes are an integral part of these consolidated financial statements. 29 BOARDWALK PIPELINE PARTNERS, LP CONSOLIDATED BALANCE SHEETS (Millions) LIABILITIES AND PARTNERS' CAPITAL December 31, 2020 2019 Current Liabilities: Payables: Trade Affiliates Other Gas payables Accrued taxes, other Accrued interest Accrued payroll and employee benefits Construction retainage Regulatory liability Deferred income Other current liabilities Total current liabilities Long-term debt and finance lease obligation Other Liabilities and Deferred Credits: Pension liability Asset retirement obligations Provision for other asset retirement Other Total other liabilities and deferred credits Commitments and Contingencies Partners' Capital: Partners' capital Accumulated other comprehensive loss Total partners' capital Total Liabilities and Partners' Capital $ $ 43.6 $ 9.9 9.6 10.9 70.3 33.1 34.5 11.5 14.1 4.9 24.5 266.9 65.8 4.6 11.6 6.4 60.1 35.6 38.1 16.8 9.5 2.2 18.8 269.5 3,460.7 3,566.1 18.0 54.9 81.6 98.7 253.2 5,328.9 (79.8) 5,249.1 9,229.9 $ 20.5 56.8 75.1 95.6 248.0 5,140.6 (81.1) 5,059.5 9,143.1 The accompanying notes are an integral part of these consolidated financial statements. 30 BOARDWALK PIPELINE PARTNERS, LP CONSOLIDATED STATEMENTS OF INCOME (Millions) Operating Revenues: Transportation Storage, parking and lending Other Total operating revenues Operating Costs and Expenses: Fuel and transportation Operation and maintenance Administrative and general Depreciation and amortization Loss (gain) on sale of assets and impairments Taxes other than income taxes Total operating costs and expenses Operating income Other Deductions (Income): Interest expense Interest income Miscellaneous other income, net Total other deductions Income before income taxes Income taxes Net income For the Year Ended December 31, 2019 2020 2018 $ 1,117.9 $ 110.5 69.2 1,297.6 1,146.2 $ 92.0 57.0 1,295.2 1,083.6 90.4 49.7 1,223.7 18.3 212.3 139.9 358.8 0.9 112.8 843.0 454.6 169.7 — (5.9) 163.8 290.8 0.3 13.8 219.1 141.1 346.1 (3.2) 104.6 821.5 473.7 178.7 (0.3) (0.9) 177.5 296.2 0.5 $ 290.5 $ 295.7 $ 19.0 205.6 136.3 344.7 (0.2) 103.8 809.2 414.5 175.7 (0.1) (2.0) 173.6 240.9 0.6 240.3 The accompanying notes are an integral part of these consolidated financial statements. 31 BOARDWALK PIPELINE PARTNERS, LP CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Millions) Net income Other comprehensive income (loss): Reclassification adjustment transferred to Net income from cash flow hedges Pension and other postretirement benefit costs, net of tax Total Comprehensive Income $ $ For the Year Ended December 31, 2019 2020 2018 290.5 $ 295.7 $ 0.8 0.5 291.8 $ 0.9 3.2 299.8 $ 240.3 1.2 (5.4) 236.1 The accompanying notes are an integral part of these consolidated financial statements. 32 BOARDWALK PIPELINE PARTNERS, LP CONSOLIDATED STATEMENTS OF CASH FLOWS (Millions) OPERATING ACTIVITIES: Net income Adjustments to reconcile net income to cash provided by operations: Depreciation and amortization Amortization of deferred costs and other Loss (gain) on sale of assets and impairments Changes in operating assets and liabilities: Trade and other receivables Gas receivables and storage assets Other assets Trade and other payables Gas payables Accrued liabilities Regulatory assets and liabilities Other liabilities Net cash provided by operating activities INVESTING ACTIVITIES: Capital expenditures Proceeds from sale of operating assets Advances to affiliates Net cash used in investing activities FINANCING ACTIVITIES: Proceeds from long-term debt, net of issuance cost Repayment of borrowings from long-term debt Proceeds from borrowings on revolving credit agreement Repayment of borrowings on revolving credit agreement Principal payment of finance lease obligation Advances from affiliates Distributions paid Net cash used in financing activities (Decrease) increase in cash and cash equivalents Cash and cash equivalents at beginning of period Cash and cash equivalents at end of period For the Year Ended December 31, 2019 2018 2020 $ 290.5 $ 295.7 $ 240.3 358.8 12.4 0.9 (6.1) (9.0) (4.5) (10.6) 1.4 4.7 4.8 (2.1) 641.2 (438.2) 3.8 — (434.4) 495.0 (440.0) 687.9 (852.9) (0.7) 5.3 (102.2) (207.6) (0.8) 3.7 2.9 $ 346.1 13.1 (3.2) 21.2 (27.6) 0.4 2.9 (0.1) 1.7 20.7 (8.9) 662.0 (429.0) 5.7 — (423.3) 495.2 (350.0) 660.0 (945.0) (0.7) 4.1 (102.2) (238.6) 0.1 3.6 3.7 $ 344.7 8.9 (0.2) (20.4) 12.6 (1.1) (0.2) 1.2 6.0 (16.0) (10.2) 565.6 (486.7) 1.0 (0.1) (485.8) — (185.0) 640.0 (445.0) (0.6) (1.0) (102.2) (93.8) (14.0) 17.6 3.6 $ The accompanying notes are an integral part of these consolidated financial statements. 33 BOARDWALK PIPELINE PARTNERS, LP CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL (Millions) Balance December 31, 2017 (Deduct) add: Cumulative effect adjustment from the implementation of ASC 606 Adjustment related to registration rights agreement Net income Distributions paid Other comprehensive loss, net of tax General Partner purchase of common units and conversion to partnership interests Balance December 31, 2018 Add (deduct): Net income Distributions paid Other comprehensive income, net of tax Balance December 31, 2019 Add (deduct): Net income Distributions paid Other comprehensive income, net of tax Balance December 31, 2020 Common Units General Partner Partners' Capital Accumulated Other Comprehensive (Loss) Income Total Partners' Capital $ 4,713.1 $ 92.7 $ — $ (81.0) $ 4,724.8 (12.6) 16.0 136.6 (50.1) — (0.2) — 2.8 (1.0) — — — 100.9 (51.1) — (4,803.0) (94.3) — $ — $ 4,897.3 4,947.1 $ — — — — $ — — — — $ — — — — $ — — — — $ 295.7 (102.2) — 5,140.6 $ 290.5 (102.2) — 5,328.9 $ $ $ $ — — — — (4.2) — (85.2) — — 4.1 (81.1) — — 1.3 (79.8) $ $ $ (12.8) 16.0 240.3 (102.2) (4.2) — 4,861.9 295.7 (102.2) 4.1 5,059.5 290.5 (102.2) 1.3 5,249.1 The accompanying notes are an integral part of these consolidated financial statements. 34 BOARDWALK PIPELINE PARTNERS, LP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 1: Corporate Structure 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 Petrochemical Pipeline, LLC and Boardwalk Texas Intrastate, LLC (together, the operating subsidiaries), which consists of integrated natural gas and natural gas liquids and other hydrocarbons (herein referred to together as NGLs) pipeline and storage systems. All of the Company's operations are conducted by the operating subsidiaries. Effective January 1, 2020, Gulf South converted from a limited partnership to a limited liability company. Immediately subsequent to the conversion, Gulf Crossing Pipeline Company LLC was merged into Gulf South. As of December 31, 2020, Boardwalk Pipelines Holding Corp. (BPHC), a wholly-owned subsidiary of Loews Corporation (Loews), owned directly or indirectly, 100% of the Company's capital. Note 2: Basis of Presentation and Accounting Policies Basis of Presentation The accompanying consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States of America (U.S.) (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 one 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 which are located in the Gulf Coast region, Oklahoma, Arkansas and the Midwestern states of Tennessee, Kentucky, Illinois, Indiana and Ohio and integrated natural gas storage facilities located in Indiana, Kentucky, Louisiana and Mississippi, and NGL pipelines and storage facilities 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. 35 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, 2020 and 2019. 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) 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 36 providing these services, the Company does not record the related gas on its Consolidated Balance Sheets. Certain of the Company's operating subsidiaries also periodically lend gas and NGLs to customers. In the course of providing transportation and storage services to customers, the operating subsidiaries may receive different quantities of gas from shippers and operators than the quantities delivered on behalf of those shippers and operators. This results in transportation and exchange gas receivables and payables, commonly known as imbalances, which are 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 Materials and supplies are carried at average cost and are included in Other  Assets on the Consolidated Balance Sheets. The Company expects its materials and supplies to be used for projects related to its property, plant and equipment (PPE) and for future growth projects. At December 31, 2020 and 2019, the Company held approximately $25.5 million and $21.8 million of materials and supplies. Property, Plant and Equipment and Repair and Maintenance Costs PPE is recorded at its original cost of construction or fair value of assets purchased. Construction costs and expenditures for major renewals and improvements which extend the lives of the respective assets are capitalized. Construction work in progress is included in the financial statements as a component of PPE. Repair and maintenance costs are expensed as incurred. Depreciation of PPE related to operations for which regulatory accounting does not apply is provided for using the straight-line method of depreciation over the estimated useful lives of the assets, which range from 3 to 35 years. The ordinary sale or retirement of PPE for these assets could result in a gain or loss 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. Intangible assets are those assets which provide future economic benefit but have no physical substance. The Company recorded intangible assets for customer relationships obtained through its acquisitions. The customer relationships, which are included in Other Assets on the Consolidated Balance Sheets, have a finite life and are being amortized over their estimated useful lives. Note 8 contains more information regarding the Company's goodwill and intangible assets. 37 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) The Company records capitalized interest, which represents the cost of borrowed funds used to finance construction activities for operations where regulatory accounting is not applicable. The Company records AFUDC, which represents the cost of funds, including equity funds, applicable to regulated natural gas transmission plant under construction as permitted by FERC regulatory practices, in connection with the Company's operations where regulatory accounting is applicable. Capitalized interest and the allowance for borrowed funds used during construction are recognized as a reduction to Interest expense and the allowance for equity funds used during construction is included in Miscellaneous  other  income,  net within the Consolidated Statements of Income. The following table summarizes capitalized interest and the allowance for borrowed funds and allowance for equity funds used during construction (in millions): Capitalized interest and allowance for borrowed funds used during construction Allowance for equity funds used during construction Income Taxes 2020 $ For the Year Ended December 31, 2019 2018 6.1 $ 4.1 5.6 $ 1.5 8.5 0.5 The Company is not a taxable entity for federal income tax purposes. As such, it does not directly pay federal income tax. The Company's taxable income or loss, which may vary substantially from the net income or loss reported in the Consolidated Statements of Income, is includable in the federal income tax returns of each of its partners. The aggregate difference in the basis of the Company's net assets for financial and income tax purposes is $4.4 billion. The subsidiaries of the Company directly incur some income-based state taxes which are presented in Income taxes on the Consolidated Statements of Income. Note 13 contains more information regarding the Company's income taxes. Asset Retirement Obligations The accounting requirements for existing legal obligations associated with the future retirement of long-lived assets require entities to record the fair value of a liability for an ARO in the period during which the liability is incurred. The liability is initially recognized at fair value and is increased with the passage of time as accretion expense is recorded, until the liability is ultimately settled. The accretion expense is included within Operation and maintenance costs within the Consolidated Statements of Income. An amount corresponding to the amount of the initial liability is capitalized as part of the carrying amount of the related long-lived asset and depreciated over the useful life of that asset. Note 9 contains more information regarding the 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. 38 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 Prior to the purchase of the Company's issued and outstanding publicly-owned common units by the Company's general partner in the third quarter 2018 (Purchase Transaction), the Company provided awards of phantom common units (Phantom Common Units) to certain employees under its Long-Term Incentive Plan (LTIP). The Company also provides to certain employees 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 and as of December 31, 2020, all remaining Phantom Common Units had vested and were paid. Beginning in 2019, the Company provided awards of 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. The Company measures the cost of an award issued in exchange for employee services based on the grant-date fair value of the award in the case of Phantom Common Units, or the stated amount in the case of Long-Term Cash Bonuses or 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. Prior to the Purchase Transaction, unit-based compensation awards were remeasured each reporting period until the final amount of awards were determined. Outstanding phantom units after the Purchase Transaction were fair valued at the $12.06 cash purchase price per common unit of the Purchase Transaction plus amounts credited under the distribution equivalent rights (DERs). 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 prior to the Purchase Transaction, 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. Lease Accounting 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 most of the Company's leases do not provide an implicit rate. Revenue Recognition Nature of Contracts The Company primarily earns revenues from contracts with customers by providing transportation and storage services for natural gas and NGLs on a firm and interruptible basis. The Company also provides interruptible natural gas PAL services. The Company's customers choose, based upon their particular needs, the applicable mix of services depending upon availability of pipeline and storage capacity, the price of services and the volume and timing of customer requirements. The maximum rates that may be charged by the majority of the Company's operating subsidiaries are established through the FERC's cost-based rate- making process; however, rates actually charged by those operating subsidiaries may be less than those allowed by the FERC. Under the FERC regulations, certain revenues that the Company's subsidiaries collect may be subject to possible refunds to customers. Accordingly, during a rate case, estimated refund liabilities are recorded considering regulatory proceedings, 39 advice of counsel and estimated risk-adjusted total exposure, as well as other factors. The Company's service contracts can range from one to twenty years although the Company may enter into shorter- or longer-term contracts, and services are invoiced monthly with payment from the customer generally expected within ten to thirty days, depending on the terms of the contract. Firm Service Contracts: The Company offers firm services to its customers. The Company's customers can reserve a specific amount of pipeline capacity at specified receipt and delivery points on the Company's pipeline system (transportation service) or can reserve a specific amount of storage capacity at specified injection and withdrawal points at the Company's storage facilities (storage service). The Company accounts for firm services as a single promise to stand ready each month of the contract term to provide the committed capacity for either transportation or storage services when needed by the customer, which represents a series of distinct monthly services that are substantially the same with the same pattern of transfer to the customer. Although several activities may be required to provide the firm service, the individual activities do not represent distinct performance obligations because all of the activities must be performed in combination in order for the Company to provide the firm service. 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. Interruptible  Service  Contracts: In providing interruptible services to customers, the Company agrees to transport or store natural gas or NGLs for a customer when capacity is available. The Company does not account for interruptible services with a customer as a contract until the customer nominates for service and the Company accepts the nomination based upon available pipeline or storage capacity because there are no enforceable rights and obligations until that time. The nomination and acceptance process is a daily activity and acceptance is granted based upon priority of service and availability of capacity. Upon acceptance, the Company accounts for interruptible services similarly to its firm services. 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. Minimum Volume Commitment (MVC) Contracts: Certain of the Company's transportation or storage contracts require customers to transport or store a minimum volume of commodity over a specified time period. If a customer fails to meet its MVC for the specified time period, the customer is obligated to pay a contractually-determined deficiency fee based upon the shortfall between the actual volumes transported or stored and the MVC for that period. MVC contracts are similar in nature to a firm service contract where the performance obligation is a stand-ready obligation that is a series of distinct services that are substantially the same with the same pattern of transfer to the customer. The transaction price for an MVC is a fee for the volume of commodity actually transported or stored, which is allocated to each distinct monthly performance obligation, consistent with the allocation objective and based upon the level of effort required to satisfy the obligation of the transacted service in a given month. Revenues are generally recognized over time based on the output measure of volume transported or stored, with the recognition of the deficiency fee in the period when it is known the customer cannot make up the deficient volume in the specified period. Other: Periodically, the Company may enter into contracts with customers for the sale of natural gas or NGLs. The Company recognizes revenues for these transactions at the point in time of the physical sale of the commodity, which corresponds with the transfer of control of the commodity to the customer and the consideration is measured as the stated sales price in the contract. 40 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. Note 3: Revenues The Company operates in one 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, 2020, 2019 and 2018 (in millions): Revenues from Contracts with Customers (1) Firm Service Interruptible Service Other revenues Total Revenues from Contracts with Customers Other operating revenues (2) Total Operating Revenues 2020 For the Year Ended December 31, 2019 2018 $ $ 1,211.7 33.2 18.9 1,263.8 33.8 1,297.6 $ $ 1,228.3 29.0 9.1 1,266.4 28.8 1,295.2 $ $ 1,161.7 32.2 11.6 1,205.5 18.2 1,223.7 (1) Revenues earned from contracts with MVCs are included in firm service given the stand-ready nature of the performance obligation and the guaranteed nature of the fees over the contract term. The years ended December 31, 2020 and 2019, contain $34.4 million and $26.2 million of incremental revenues received related to customer bankruptcies as discussed in Note 5. (2) Other operating revenues include certain revenues earned from operating leases, pipeline management fees and other activities that are not considered central and ongoing major business operations of the Company and do not represent revenues earned from contracts with customers. Contract Balances As of December 31, 2020 and 2019, the Company had receivables recorded in Trade Receivables from contracts with customers of $115.1 million and $117.2 million, contract assets recorded in Other  Assets from contracts with a customer of $2.9 million and $1.5 million and contract liabilities recorded in Deferred income (current portion) and Other Liabilities (noncurrent portion) from contracts with customers of $17.2 million and $11.8 million. As of December 31, 2020, contract liabilities are expected to be recognized through 2040. Significant changes in the contract liabilities balances during the year ended December 31, 2020, are as follows (in millions): (1) Balance as of December 31, 2019 Revenues recognized that were included in the contract liability balance at the beginning of the period Increases due to cash received, excluding amounts recognized as revenues during the period Balance as of December 31, 2020 (1) Contract Liabilities 11.8 (5.1) 10.5 17.2 $ $ 41 (1) As of December 31, 2020 and 2019, $4.9 million and $2.2 million were recorded in Deferred income (current portion) and $12.3 million and $9.6 million were recorded in Other Liabilities (noncurrent portion). Significant changes in the contract liabilities balances during the year ended December 31, 2019, are as follows (in millions): Contract Liabilities (1) Balance as of December 31, 2018 Revenues recognized that were included in the contract liability balance at the beginning of the period Increases due to cash received, excluding amounts recognized as revenues during the period Balance as of December 31, 2019 (1) $ $ 9.2 (2.1) 4.7 11.8 (1) As of December 31, 2019 and 2018, $2.2 million and $0.5 million were recorded in Deferred income (current portion) and $9.6 million and $8.7 million were recorded in Other Liabilities (noncurrent portion). 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, 2020. The amounts presented primarily consist of fixed fees or MVCs which are typically recognized over time as the performance obligation is satisfied, as in accordance with firm service contracts. Additionally, for 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 are recognized in revenue as invoiced, such as for interruptible services; and (c) consideration that was received prior to December 31, 2020, that will be recognized in future periods, such as 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. 2021 2022 Thereafter Total In millions Estimated revenues from contracts with customers from unsatisfied performance obligations as of December 31, 2020 Operating revenues which are fixed and determinable (operating leases) Total projected operating revenues under committed firm agreements as of December 31, 2020 $ $ 1,087.0 $ 1,028.5 $ 7,092.0 $ 9,207.5 23.0 23.0 196.5 242.5 1,110.0 $ 1,051.5 $ 7,288.5 $ 9,450.0 Note 4: Leases 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, that has a fifteen-year term with two twenty-year renewal options. 42 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 most of the Company's leases do not provide an implicit rate. The components of lease cost were as follows (in millions): Operating lease cost Short-term lease cost Finance lease cost: Amortization of right-of-use asset Interest on lease liabilities Total lease cost For the Year Ended December 31, 2019 2020 $ $ 4.2 $ 3.9 0.7 0.4 9.2 $ The following provides supplemental balance sheet information related to the Company's leases: Right-of-use assets (in millions) Operating leases (recorded in Other Assets) Finance lease (recorded in Property, Plant and Equipment) $ $ 11.8 5.4 As of December 31, 2020 2019 Lease liabilities (in millions) Operating leases (recorded in Other Liabilities, current and non-current) Finance lease Weighted-average remaining lease term (years) Operating leases Finance lease Weighted-average discount rate Operating leases Finance lease The table below presents the maturities of lease liabilities (in millions): 13.8 6.8 3.8 7.6 4.72 % 5.89 % 4.3 2.6 0.7 0.5 8.1 15.0 6.1 17.5 7.5 4.4 8.6 4.68 % 5.89 % 2021 2022 2023 2024 2025 Thereafter Total Less: discount Total lease liabilities As of December 31, 2020 Operating Leases Finance Lease 4.5 4.4 3.9 1.3 0.3 0.7 15.1 (1.3) 13.8 $ $ 1.1 1.1 1.1 1.1 1.1 2.9 8.4 (1.6) 6.8 $ $ 43 Note 5: Commitments and Contingencies Legal Proceedings and Settlements 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 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 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 Court denied approval of the Proposed Settlement. On February 11, 2019, a substitute verified class action complaint was filed in this proceeding. The Defendants filed a motion to dismiss, which was heard by the Court in July 2019. In October 2019, the Court ruled on the motion and granted a partial dismissal, with certain aspects of the case proceeding to trial. The case is set for trial in February 2021. 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. th In October 2020, this case was stayed pending the outcome of an appeal to the 5 Circuit Court of Appeals in a similar case. Letter of Credit Proceeds 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. Environmental and Safety Matters The Company's operating subsidiaries are subject to federal, state and local environmental laws and regulations in connection with the operation and remediation of various operating sites. As of December 31, 2020 and 2019, the Company had an accrued liability of approximately $4.2 million and $3.8 million related to assessment and/or remediation costs associated 44 with the historical use of polychlorinated biphenyls, petroleum hydrocarbons and mercury. The liability represents management's estimate of the undiscounted future obligations based on evaluations and discussions with counsel and operating personnel and the current known facts and circumstances related to these matters. The related expenditures are expected to occur over the next thirty years. As of December 31, 2020 and 2019, approximately $1.0 million was recorded in Other current liabilities and approximately $3.2 million and $2.8 million were recorded in Other Liabilities and Deferred Credits. 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 attention in the U.S. and in foreign countries. Numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit existing emissions of greenhouse gases (GHGs) as well as to restrict or eliminate future emissions through such efforts as GHG cap and trade programs, carbon taxes, reporting and tracking programs and restriction of emissions, such as methane 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. Commitments for Construction 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. The commitments as of December 31, 2020, were approximately $128.4 million, all of which are expected to be settled within the next twelve months. Pipeline Capacity Agreements 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 $4.2 million, $3.8 million and $4.6 million related to pipeline capacity agreements for the years ended December 31, 2020, 2019 and 2018. The future commitments related to pipeline capacity agreements as of December 31, 2020, were $5.5 million in 2021 and $2.7 million in 2022, with no future commitments after 2022. Note 6: Other Comprehensive Income and Fair Value Measurements Other Comprehensive Income The Company estimates that approximately $0.9 million of net losses reported in AOCI as of December 31, 2020, are expected to be reclassified into earnings within the next twelve months related to cash flow hedges. The amounts related to cash flow hedges are from treasury rate locks used in hedging interest payments associated with debt offerings that were settled in previous periods and are being amortized to earnings over the terms of the related interest payments, generally the terms of the related debt. 45 Financial Assets and Liabilities As of December 31, 2020 and 2019, 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: Cash and Cash Equivalents: For cash and short-term financial assets, the carrying amount is a reasonable estimate of fair value due to the short maturity of those instruments. Long-Term Debt: The estimated fair value of the Company's publicly traded debt is based on quoted market prices at December 31, 2020 and 2019. The fair market value of the debt that is not publicly traded is based on market prices of similar debt at December 31, 2020 and 2019. The carrying amount of the Company's variable-rate debt at December 31, 2020 and 2019, approximated fair value because the instruments bear a floating market-based interest rate. 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, 2020 and 2019, were as follows (in millions): As of December 31, 2020 Financial Assets Cash and cash equivalents Financial Liabilities Long-term debt Carrying Amount 2.9 $ $ 3,460.4 (1) $ $ 2.9 — $ $ — 3,847.6 $ $ Level 1 Level 2 Level 3 Total Estimated Fair Value — — — — $ $ $ $ 2.9 3,847.6 Total 3.7 3,798.3 (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. As of December 31, 2019 Financial Assets Cash and cash equivalents Financial Liabilities Long-term debt Carrying Amount 3.7 $ $ 3,565.7 (1) Level 1 Level 2 Level 3 Estimated Fair Value $ $ 3.7 — $ $ — 3,798.3 $ $ (1) The carrying amount of long-term debt excludes a $6.8 million long-term finance lease obligation and $6.4 million of unamortized debt issuance costs. 46 Note 7: Property, Plant and Equipment The following table presents the Company's PPE as of December 31, 2020 and 2019 (in millions): Category Depreciable plant: Transmission Storage Gathering General Rights of way and other Total utility depreciable plant Non-depreciable: Construction work in progress Storage Land Total non-depreciable assets Total PPE Less: accumulated depreciation 2020 Amount Weighted-Average Useful Lives (Years) 2019 Amount Weighted-Average Useful Lives (Years) $ 10,417.9 863.5 108.0 224.9 153.2 11,767.5 184.2 152.3 44.3 380.8 12,148.3 3,598.5 $ 37 38 23 14 33 37 37 38 23 14 34 37 10,025.2 804.2 107.9 219.3 149.2 11,305.8 253.9 139.4 44.3 437.6 11,743.4 3,263.7 Total PPE, net $ 8,549.8 $ 8,479.7 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. The proportionate share of investment associated with these interests has been recorded as PPE on the Consolidated Balance Sheets. The Company records its portion of direct operating expenses associated with the assets in Operation  and  maintenance expense. The following table presents the gross PPE investment and related accumulated depreciation for the Company's undivided interests as of December 31, 2020 and 2019 (in millions): (1) Bistineau storage Mobile Bay Pipeline NGL pipelines and facilities Offshore and other assets Total 2020 2019 Gross PPE Investment Accumulated Depreciation Gross PPE Investment Accumulated Depreciation $ $ — 14.5 42.5 12.8 69.8 $ $ — 7.1 8.8 10.1 26.0 $ $ 89.4 $ 14.5 34.8 14.5 153.2 $ 29.3 6.7 7.2 11.6 54.8 (1) In 2019, the Company entered into an agreement to purchase the approximately 8% undivided interest that it did not already own in the Bistineau storage facility in Louisiana for $18.8 million. The FERC approved the purchase in early 2020 and the transaction closed on April 1, 2020. The purchase was recorded in Capital 47 expenditures on the Consolidated Statement of Cash Flows. After this transaction, the Company owns 100% of the Bistineau storage facility. Note 8: Goodwill and Intangible Assets Goodwill As of December 31, 2020 and 2019, the Company had recorded on its Consolidated Balance Sheets $237.4 million of goodwill. The Company performed its annual goodwill impairment test for its two reporting units as of November 30, 2020 and 2019. The results of the quantitative goodwill impairment test indicated that the fair value of the Company's reporting units exceeded their carrying amounts and no impairment charges related to goodwill were recorded for any of the Company's reporting units during 2020, 2019 or 2018. 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, 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. 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): Gross carrying amount Accumulated amortization Net carrying amount December 31, 2020 2019 $ $ 59.4 (15.3) 44.1 $ $ 59.4 (13.4) 46.0 For each of the years ended December 31, 2020, 2019 and 2018, amortization expense for intangible assets was $1.9 million, $1.9 million and $2.0 million and was recorded in Depreciation and amortization on the Consolidated Statements of Income. Amortization expense for the next five years and in total thereafter as of December 31, 2020, is expected to be as follows (in millions): 2021 2022 2023 2024 2025 Thereafter Total $ $ 1.9 1.9 1.9 2.0 2.0 34.4 44.1 The weighted-average remaining useful life of the Company's intangible assets as of December 31, 2020, was 23 years. 48 Note 9: Asset Retirement Obligations 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, 2020 and 2019 (in millions): Balance at beginning of year Liabilities recorded Liabilities settled Accretion expense Balance at end of year Less: Current portion of ARO Long-term ARO 2020 2019 60.4 $ 1.3 (0.9) 2.3 63.1 (8.2) 54.9 $ 62.3 1.0 (5.1) 2.2 60.4 (3.6) 56.8 $ $ For the Company's operations where regulatory accounting is applicable, depreciation rates for PPE are comprised of two components. One component is based on economic service life (capital recovery) and the other is based on estimated costs of removal (as a component of negative salvage) which is collected in rates and does not represent an existing legal obligation. The Company has reflected $81.6 million and $75.1 million as of December 31, 2020 and 2019, on the Consolidated Balance Sheets as Provision for other asset retirement related to the estimated cost of removal collected in rates. Note 10: Regulatory Assets and Liabilities The amounts recorded as regulatory assets and liabilities on the Consolidated Balance Sheets as of December 31, 2020 and 2019, are summarized in the table below. The table also includes amounts related to unamortized debt expense and unamortized discount on long-term debt, which while not regulatory assets and liabilities, are a critical component of the embedded cost of debt financing utilized in Texas Gas' rate proceedings. The tax effect of the equity component of AFUDC represents amounts recoverable from rate payers for the tax recorded in regulatory accounting. Certain amounts in the table are reflected as a negative, or a reduction, to be consistent with the regulatory books of account. The period of recovery for the regulatory assets included in rates varies from one to eighteen years. The remaining period of recovery for regulatory assets not yet included in rates would be determined in future rate proceedings. None of the regulatory assets shown below were earning a return as of December 31, 2020 and 2019 (in millions): Regulatory Assets: Pension Tax effect of AFUDC equity Fuel tracker Other Total regulatory assets 49 2020 2019 $ $ 10.6 $ 0.6 4.2 0.5 15.9 $ 10.6 0.8 4.4 0.5 16.3 Regulatory Liabilities: Cashout and fuel tracker Provision for other asset retirement Unamortized debt expense Unamortized discount on long-term debt Postretirement benefits other than pension Total regulatory liabilities $ $ 14.1 $ 81.6 (1.8) (0.2) 63.3 157.0 $ 9.5 75.1 (3.1) (0.4) 56.8 137.9 Note 11: Financing Long-Term Debt The following table presents all long-term debt issuances outstanding as of December 31, 2020 and 2019 (in millions): 2020 2019 Notes and Debentures: Boardwalk Pipelines 3.375% Notes due 2023 4.95% Notes due 2024 5.95% Notes due 2026 4.45% Notes due 2027 4.80% Notes due 2029 3.40% Notes due 2031 Gulf South 4.00% Notes due 2022 Texas Gas 4.50% Notes due 2021 (Texas Gas 2021 Notes) 7.25% Debentures due 2027 Total notes and debentures Revolving Credit Facility: Gulf South Texas Gas Total revolving credit facility Finance lease obligation Less: Unamortized debt discount Unamortized debt issuance costs Total Long-Term Debt and Finance Lease Obligation 50 $ $ 300.0 $ 600.0 550.0 500.0 500.0 500.0 300.0 — 100.0 3,350.0 30.0 100.0 130.0 6.1 3,486.1 (19.6) (5.8) 3,460.7 $ 300.0 600.0 550.0 500.0 500.0 — 300.0 440.0 100.0 3,290.0 295.0 — 295.0 6.8 3,591.8 (19.3) (6.4) 3,566.1 Maturities of the Company's long-term debt for the next five years and in total thereafter are as follows (in millions): 2021 2022 2023 2024 2025 Thereafter Total long-term debt $ $ — 430.0 300.0 600.0 — 2,150.0 3,480.0 Notes and Debentures As of December 31, 2020 and 2019, the weighted-average interest rate of the Company's notes and debentures was 4.84% and 5.06%. The Company had no debt issuances for the year ended December 31, 2018. For the years ended December 31, 2020 and 2019, the Company completed the following debt issuances (in millions, except interest rates): Date of Issuance August 2020 May 2019 Issuing Subsidiary Boardwalk Pipelines Boardwalk Pipelines Amount of Issuance $ $ 500.0 $ 500.0 $ Purchaser Discounts and Expenses Net Proceeds Interest Rate Maturity Date 5.0 4.8 $ $ 495.0 (1) 3.40 % February 15, 2031 495.2 (2) 4.80 % May 3, 2029 Interest Payable February 15 and August 15 May 3 and November 3 (1) The net proceeds of this offering were used to retire the Texas Gas 2021 Notes on November 3, 2020, to fund growth capital expenditures and for general partnership purposes. Initially, the Company used the net proceeds to reduce outstanding borrowings under its revolving credit facility. (2) The net proceeds of this offering were used to retire the outstanding $350.0 million aggregate principal amount of Boardwalk Pipelines 5.75% notes due 2019 at maturity and for general partnership purposes. Initially, the Company used the net proceeds to reduce outstanding borrowings under its revolving credit facility. The Company's notes and debentures are redeemable, in whole or in part, at the Company's option at any time, at a redemption price equal to the greater of 100% of the principal amount of the notes to be redeemed or a “make whole” redemption price based on the remaining scheduled payments of principal and interest discounted to the date of redemption at a rate equal to the Treasury rate plus 20 to 50 basis points depending upon the particular issue of notes, plus accrued and unpaid interest, if any. Other customary covenants apply, including those concerning events of default. The indentures governing the notes and debentures have restrictive covenants which provide that, with certain exceptions, neither the Company nor any of its subsidiaries may create, assume or suffer to exist any lien upon any property to secure any indebtedness unless the debentures and notes shall be equally and ratably secured. All of the Company's debt obligations are unsecured. As of December 31, 2020, Boardwalk Pipelines and its operating subsidiaries were in compliance with their debt covenants. 51 Revolving Credit Facility The Company has a revolving credit facility that includes Boardwalk Pipelines, Texas Gas and Gulf South as borrowers (Borrowers). Interest is determined, at the Company's election, by reference to (a) the base rate which is the highest of (1) the prime rate, (2) the federal funds rate plus 0.50% and (3) the one month Eurodollar Rate plus 1.00%, plus an applicable margin, or (b) the one-month LIBOR plus an applicable margin. The applicable margin ranges from 0.00% to 0.75% for loans bearing interest based on the base rate and ranges from 1.00% to 1.75% for loans bearing interest based on the LIBOR rate, in each case determined based on the individual Borrower's credit rating from time to time. The Third Amended and Restated Revolving Credit Agreement (amended credit agreement) provides for a quarterly commitment fee charged on the average daily unused amount of the revolving credit facility ranging from 0.10% to 0.275% which is determined based on the individual Borrower's credit rating from time to time. The revolving credit facility has a borrowing capacity of $1.475 billion through May 26, 2022. The revolving credit facility contains various restrictive covenants and other usual and customary terms and conditions, including restrictions regarding the incurrence of additional debt, the sale of assets and sale-leaseback transactions. The financial covenants under the revolving credit facility require the Company and its subsidiaries to maintain, among other things, a ratio of total consolidated debt to consolidated EBITDA (as defined in the amended credit agreement) measured for the previous twelve months of not more than 5.0 to 1.0, or up to 5.5 to 1.0 for the three quarters following a qualified acquisition or series of acquisitions, where the purchase price exceeds $100.0 million over a rolling 12-month period. The Company and its subsidiaries were in compliance with all covenant requirements under the revolving credit facility as of December 31, 2020. Outstanding borrowings under the Company's revolving credit facility as of December 31, 2020 and 2019, were $130.0 million and $295.0 million, with weighted-average borrowing rates of 1.39% and 3.00%. As of February 8, 2021, the Company had $170.0 million outstanding borrowings and approximately $1.3 billion of available borrowing capacity under the revolving credit facility. Cash Distributions For each of the years ended December 31, 2020, 2019 and 2018, the Company paid cash distributions of $102.2 million to its partners as determined by Boardwalk GP. Note 12: Employee Benefits Retirement Plans Defined Benefit Retirement Plans (Retirement Plans) Texas Gas employees hired prior to November 1, 2006, are covered under a non-contributory, defined benefit pension plan (Pension Plan). The Texas Gas Supplemental Retirement Plan (SRP) provides pension benefits for the portion of an eligible employee's pension benefit under the Pension Plan that becomes subject to compensation limitations under the Internal Revenue Code. Collectively, the Company refers to the Pension Plan and the SRP as Retirement Plans. The Company uses a measurement date of December 31 for its Retirement Plans. As a result of the Texas Gas rate case settlement in 2006, the Company is required to fund the amount of annual net periodic pension cost associated with the Pension Plan, including a minimum of $3.0 million, which is the amount included in rates. In 2020 and 2019, the Company funded $3.6 million and $4.7 million to the Pension Plan and expects to fund an additional $4.5 million to the plan in 2021. In 2020 and 2019, there were no payments made to the SRP. The Company recognizes in expense each year the actuarially determined amount of net periodic pension cost associated with the Retirement Plans, including a minimum amount of $3.0 million related to its Pension Plan, in accordance with the 2006 rate case settlement. Texas Gas is permitted to seek future rate recovery for amounts of annual Pension Plan costs in excess of $6.0 million and is precluded from seeking future recovery of annual Pension Plan costs between $3.0 million and $6.0 million. As a result, the Company would recognize a regulatory asset for amounts of annual Pension Plan costs in excess of $6.0 million and would reduce its regulatory asset to the extent that annual Pension Plan costs are less than $3.0 million. Annual Pension Plan costs between $3.0 million and $6.0 million will be charged to expense. 52 Postretirement Benefits Other Than Pension (PBOP) Texas Gas provides postretirement medical benefits and life insurance to retired employees who were employed full time, hired prior to January 1, 1996, and have met certain other requirements. In each of 2020 and 2019, the Company contributed $0.1 million to the PBOP plan. The PBOP plan is in an overfunded status; therefore, the Company does not expect to make any contributions to the plan in 2021. The Company does not anticipate that any plan assets will be returned to the Company during 2021. The Company uses a measurement date of December 31 for its PBOP plan. Projected Benefit Obligation, Fair Value of Assets and Funded Status The projected benefit obligation, fair value of assets, funded status and the amounts not yet recognized as components of net periodic pension and postretirement benefits cost for the Retirement Plans and PBOP at December 31, 2020 and 2019, were as follows (in millions): Change in benefit obligation: Benefit obligation at beginning of period Service cost Interest cost Plan participants' contributions Actuarial loss (gain) Benefits paid Settlement Benefit obligation at end of period Change in plan assets: Fair value of plan assets at beginning of period Actual return on plan assets Benefits paid Settlement Company contributions Plan participants' contributions Fair value of plan assets at end of period Funded status Items not recognized as components of net periodic cost: Net actuarial loss (gain) Retirement Plans For the Year Ended December 31, PBOP For the Year Ended December 31, 2020 2019 2020 2019 122.2 $ 2.8 2.7 — 6.0 (0.5) (12.5) 120.7 $ 101.7 $ 10.4 (0.5) (12.5) 3.6 — 102.7 $ 125.1 $ 3.0 3.9 — 5.9 (0.5) (15.2) 122.2 $ 100.3 $ 12.5 (0.5) (15.2) 4.6 — 101.7 $ 36.5 $ 0.1 1.1 1.1 (0.3) (3.3) — 35.2 $ 90.8 $ 7.5 (3.3) — 0.1 1.1 96.2 $ (18.0) $ (20.5) $ 61.0 $ 35.6 0.1 1.4 1.1 1.9 (3.6) — 36.5 85.0 8.2 (3.6) — 0.1 1.1 90.8 54.3 18.2 $ 20.6 $ (3.4) $ 1.1 $ $ $ $ $ $ At December 31, 2020 and 2019, the following aggregate information relates only to the underfunded plans (in millions): Retirement Plans For the Year Ended December 31, 2020 2019 Projected benefit obligation Accumulated benefit obligation Fair value of plan assets $ 120.7 $ 113.7 102.7 122.2 115.4 101.7 53 Components of Net Periodic Benefit Cost Components of net periodic benefit cost for both the Retirement Plans and PBOP for the years ended December 31, 2020, 2019 and 2018, were as follows (in millions): Service cost Interest cost Expected return on plan assets Amortization of unrecognized net loss Settlement charge Net periodic benefit cost Retirement Plans For the Year Ended December 31, 2019 2020 2018 2020 PBOP For the Year Ended December 31, 2019 2018 $ $ 2.8 $ 2.7 (6.3) 1.9 2.4 3.5 $ 3.0 $ 3.9 (6.4) 2.2 2.9 5.6 $ 3.3 $ 4.5 (7.5) 1.4 3.0 4.7 $ 0.1 $ 1.1 (3.2) — — (2.0) $ 0.1 $ 1.4 (3.0) — — (1.5) $ 0.1 1.5 (4.6) — — (3.0) Due to the Texas Gas rate case settlement in 2006, Texas Gas is permitted to seek future rate recovery for amounts of annual Pension Plan costs in excess of $6.0 million. Estimated Future Benefit Payments The following table shows benefit payments, which reflect expected future service, as appropriate, which are expected to be paid for both the Retirement Plans and PBOP (in millions): 2021 2022 2023 2024 2025 2026-2030 PBOP $ $ Retirement Plans 19.1 13.4 11.4 11.7 13.4 39.2 2.4 2.3 2.3 2.2 2.1 8.9 Weighted-Average Assumptions Weighted-average assumptions used to determine benefit obligations for the years ended December 31, 2020 and 2019, were as follows: PBOP For the Year Ended December 31, Retirement Plans For the Year Ended December 31, Discount rate Expected return on plan assets Rate of compensation increase 2020 2019 2020 2019 Pension SRP Pension SRP 1.70 % 6.50 % 3.00 % 1.55 % 6.50 % 3.00 % 2.70 % 7.00 % 3.00 % 2.70 % 7.00 % 3.00 % 2.60 % 2.81 % — 3.30 % 3.61 % — 54 Weighted-average assumptions used to determine net periodic benefit cost for the periods indicated were as follows: Retirement Plans For the Year Ended December 31, 2019 2020 2018 Pension SRP Pension SRP Pension SRP PBOP For the Year Ended December 31, 2019 2020 2018 Discount rate Expected return on plan assets Rate of compensation increase (1) 7.00% 3.00% 2.70 % 7.00 % 3.00 % (1) 7.00% 3.86% 4.10 % 7.00 % 3.86 % (1) 7.25% 3.86% 3.40 % 7.25 % 3.86 % 3.30 % 3.61 % — 4.30 % 3.61 % — 3.70 % 5.30 % — (1) Pension expense was remeasured quarterly in 2020, 2019 and 2018. The quarterly remeasurements for each quarter in 2020, 2019 and 2018 were as follows: Quarter 1: 2.95%, 3.80% and 3.75%; Quarter 2: 2.20%, 3.25% and 3.85%; Quarter 3: 1.85%, 2.60% and 3.95%; and Quarter 4: 1.70%, 2.70% and 4.00%. In determining the discount rate assumption, current market and liability information is utilized, including a discounted cash flow analysis of the pension and postretirement obligations. In particular, the basis for the discount rate selection was the yield on indices of highly rated fixed income debt securities with durations comparable to that of the Company's plan liabilities. The yield curve was applied to expected future retirement plan payments to adjust the discount rate to reflect the cash flow characteristics of the plans. The yield curves and indices evaluated in the selection of the discount rate are comprised of high-quality corporate bonds that are rated AA by an accepted rating agency. The expected long-term rate of return for plan assets was determined based on widely-accepted capital market principles, long-term return analysis for global fixed income and equity markets as well as the active total return oriented portfolio management style. Long-term trends are evaluated relative to market factors such as inflation, interest rates and fiscal and monetary policies, in order to assess the capital market assumptions as applied to the plan. Consideration of diversification needs and rebalancing is maintained. Pension Plan and PBOP Asset Allocation and Investment Strategy Pension Plan The Pension Plan investments are held in a trust account and consist of an undivided interest in an investment account of the Loews Corporation Employees Retirement Trust (Master Trust), established by Loews and its participating subsidiaries. Use of the Master Trust permits the co-investing of trust assets of the Pension Plan with the assets of the Loews Corporation Cash Balance Retirement Plan for investment and administrative purposes. Although assets of all plans are co-invested in the Master Trust, the custodian maintains supporting records for the purpose of allocating the net gain or loss of the investment account to the participating plans. The net investment income of the investment assets is allocated by the custodian to each participating plan based on the relationship of the interest of each plan to the total of the interests of the participating plans. The Master Trust assets are measured at fair value. The fair value of the interest in the assets of the Master Trust associated with the Pension Plan as of December 31, 2020 and 2019, was $102.7 million (or 43.9%) and $101.7 million (or 48.1%), of the total Master Trust assets. Equity securities are publicly traded securities which are valued using quoted market prices and are considered a Level 1 investment under the fair value hierarchy. Short-term investments that are actively traded or have quoted prices, such as money market funds, are considered Level 1 investments. Fixed income mutual funds include highly liquid government securities and exchange traded bonds, valued using quoted market prices, and are considered a Level 1 investment. The limited partnership investments held within the Master Trust are recorded at fair value, which represents the Master Trust's shares of the net asset value of each partnership, as determined by the general partner. The limited partnership and other invested assets consist primarily of hedge fund strategies that generate returns through investing in marketable securities in the public fixed income and equity markets. 55 The following table sets forth, by level within the fair value hierarchy, a summary of the Master Trust's investments measured at fair value on a recurring basis at December 31, 2020 (in millions): Master Trust Assets Equity securities Short-term investments Fixed income mutual funds Total assets measured at fair value Total limited partnerships measured at net asset value Total Measured under Fair Value Hierarchy Level 1 Level 2 Level 3 Total Measured at Net Asset Value Total Master Trust Assets $ $ 59.9 $ 3.9 112.5 176.3 — 176.3 $ — $ — — — — — $ — $ — — 59.9 $ 3.9 112.5 — 176.3 — — $ — 176.3 $ — $ — — — 57.5 57.5 $ 59.9 3.9 112.5 176.3 57.5 233.8 The following table sets forth, by level within the fair value hierarchy, a summary of the Master Trust's investments measured at fair value on a recurring basis at December 31, 2019 (in millions): Master Trust Assets Equity securities Short-term investments Fixed income mutual funds Total assets measured at fair value Total limited partnerships measured at net asset value Total PBOP Measured under Fair Value Hierarchy Level 1 Level 2 Level 3 Total Measured at Net Asset Value Total Master Trust Assets $ $ 33.3 $ 6.6 97.9 137.8 — 137.8 $ — $ — — — — — $ — $ — — 33.3 $ 6.6 97.9 — 137.8 — — $ — 137.8 $ — $ — — — 73.6 73.6 $ 33.3 6.6 97.9 137.8 73.6 211.4 The PBOP plan assets are held in a trust and are measured at fair value. Short-term investments that are actively traded or have quoted prices, such as money market or mutual funds, are considered Level 1 investments. Fixed income mutual funds are actively traded and valued using quoted market prices and are considered Level 1 investments. Tax exempt securities, consisting of municipal securities, corporate and other taxable bonds and asset-backed securities are valued using a methodology based on information generated by market transactions involving identical or comparable assets, a discounted cash flow methodology or a combination of both when necessary. Common inputs for tax exempt securities include pricing for similar securities, marketplace quotes, benchmark yields, spreads off benchmark yields, interest rates and U.S. Treasury or swap curves and other pricing models utilizing observable inputs and are considered Level 2 investments. Specifically for asset-backed securities, key inputs include prepayment and default projections based on past performance of the underlying collateral and current market data. 56 The following table sets forth, by level within the fair value hierarchy, a summary of the PBOP trust investments measured at fair value on a recurring basis at December 31, 2020 (in millions): Short-term investments Fixed income mutual funds Asset-backed securities Corporate bonds Tax exempt securities Total investments Level 1 Level 2 Level 3 Total PBOP Trust Assets $ $ 5.7 $ 19.5 — — — 25.2 $ — $ — 14.4 23.7 32.9 71.0 $ — $ — — — — — $ 5.7 19.5 14.4 23.7 32.9 96.2 The following table sets forth, by level within the fair value hierarchy, a summary of the PBOP trust investments measured at fair value on a recurring basis at December 31, 2019 (in millions): Short-term investments Fixed income mutual funds Asset-backed securities Corporate bonds Tax exempt securities Total investments Investment Strategy Level 1 Level 2 Level 3 Total PBOP Trust Assets $ $ 3.4 $ 17.6 — — — 21.0 $ — $ — 16.4 22.3 31.1 69.8 $ — $ — — — — — $ 3.4 17.6 16.4 22.3 31.1 90.8 Pension Plan: The Company employs a total-return approach using a mix of equities and fixed income securities to maximize the long-term return on plan assets for a prudent level of risk and generate cash flows adequate to meet plan requirements. The intent of this strategy is to minimize plan expenses by generating investment returns that exceed the growth of the plan liabilities over the long run. Risk tolerance is established through careful consideration of the plan liabilities, plan funded status and corporate financial conditions. The target allocation of plan assets is 40% to 60% of the investment portfolio to equity and limited partnerships, with the remainder primarily invested in fixed income securities. The investment portfolio contains a diversified blend of fixed income, equity and short-term securities. Alternative investments, including limited partnerships, have been used to enhance risk adjusted long-term returns while improving portfolio diversification. At December 31, 2020, the pension trust had committed $2.3 million to future capital calls from various third party limited partnership investments in exchange for an ownership interest in the related partnerships. Investment risk is monitored through annual liability measurements, periodic asset and liability studies and quarterly investment portfolio reviews. PBOP: The investment strategy for the PBOP assets is to reduce the volatility of plan investments while protecting the initial investment given the overfunded status of the plan. At December 31, 2020 and 2019, all of the PBOP investments were in fixed income securities. Defined Contribution Plan Texas Gas employees hired on or after November 1, 2006, and all other employees of the Company are provided retirement benefits under a defined contribution plan, which also provides 401(k) plan benefits to its participants. Costs related to the Company's defined contribution plan were $11.9 million, $11.5 million and $11.1 million for the years ended December 31, 2020, 2019 and 2018. 57 Long-Term Incentive Compensation Plans The Company grants to selected employees long-term compensation awards under the LTIP (prior to 2019), the UAR and Cash Bonus Plan (prior to 2019) and the 2018 LTIP. These awards are intended to align the interests of the employees with those of the Company, encourage superior performance, attract and retain employees who are essential for the Company's growth and profitability and to encourage employees to devote their best efforts to advancing the Company's business over both long and short-term time horizons. LTIP Beginning in 2019, as a result of the Purchase Transaction, no further grants of Phantom Common Units have been or will be made under the LTIP. As of December 31, 2020, all of the remaining Phantom Common Units had vested and were paid. A summary of the status of the outstanding Phantom Common Units under the Company's LTIP as of December 31, 2020 and 2019, and changes during the years ended December 31, 2020 and 2019, is presented below: Outstanding at January 1, 2019 Paid Forfeited Outstanding at December 31, 2019 Paid Forfeited Outstanding at December 31, 2020 Phantom Common Units Total Fair Value (in millions) Weighted-Average Vesting Period (in years) 889,702 (520,753) (21,493) 347,456 (344,596) (2,860) — $ $ 11.2 (6.7) — 4.5 (4.5) — — 1.2 — — 0.6 — — — Outstanding phantom units after the Purchase Transaction were fair valued at the $12.06 cash purchase price per common unit of the Purchase Transaction plus amounts credited under the DERs. The fair value of the awards were recognized ratably over the vesting period until settlement in accordance with the treatment of awards classified as liabilities, and taking into account the payment elections selected by the grantees. The Company recorded $1.1 million, $4.6 million and $7.3 million in Administrative and general expenses during 2020, 2019 and 2018 for the Phantom Common Unit awards. The total estimated remaining unrecognized compensation expense related to the Phantom Common Units outstanding at December 31, 2019, was $1.0 million. UAR and Cash Bonus Plan The UAR and Cash Bonus Plan provided for grants of UARs and Long-Term Cash Bonuses to select employees of the Company. Beginning in 2019, as a result of the Purchase Transaction, no further grants of UARs or Long-Term Cash Bonuses have been or will be made under the UAR and Cash Bonus Plan. In 2018, the Company granted to certain employees $2.9 million of Long-Term Cash Bonuses, which vested and were paid to the holders in cash equal to the amount of the grant in 2020. The Company recorded compensation expense of $0.3 million, $1.6 million and $2.2 million for the years ended December 31, 2020, 2019 and 2018, related to the Long-Term Cash Bonuses. As of December 31, 2020, all of the remaining Long-Term Cash Bonuses had vested and were paid. As of December 31, 2019, the Company had $0.4 million remaining unrecognized compensation expense related to the Long-Term Cash Bonuses. 2018 LTIP The 2018 LTIP provides for grants of Performance Awards to selected employees of the Company. A Performance Award is a long-term incentive award with a stated target amount which is payable in cash, after adjustments, upon vesting based on certain specified performance criteria being met. The stated target can be adjusted based on the level of achievement of the performance goals for the vesting period, but not to be below 90% or to exceed 110% of the target amount. In the case of retirement, any outstanding and unvested awards would become fully vested upon retirement and the Performance Awards will be paid at the original vesting date. In 2020 and 2019, the Company granted to certain employees $12.2 million and $12.0 million of Performance Awards. The Company recorded compensation expense of $10.9 million and $6.1 million for the years ended December 31, 2020 and 2019, and had $7.0 million and $5.6 million of remaining unrecognized compensation expense related to the Performance Awards as of December 31, 2020 and 2019. 58 Note 13: Income Taxes The Company is not a taxable entity for federal income tax purposes. The following is a summary of the provision for income taxes for the years ended December 31, 2020, 2019 and 2018 (in millions): Current expense: State Deferred provision: State Income taxes For the Year Ended December 31, 2019 2020 2018 $ $ 0.1 $ 0.2 0.3 $ 0.4 $ 0.1 0.5 $ 0.4 0.2 0.6 The Company's tax years 2017 through 2020 remain subject to examination by the Internal Revenue Service and the states in which it operates. There were no differences between the provision at the statutory rate to the income tax provision at December 31, 2020, 2019 and 2018. As of December 31, 2020 and 2019, there were no significant deferred income tax assets or liabilities. Note 14: Credit Risk Major Customers For the year ended December 31, 2020, the Company earned $132.5 million of operating revenues from one customer which represented approximately 10% of total operating revenues. For the years ended December 31, 2019 and 2018, no customer comprised 10% or more of the Company's operating revenues. Gas Loaned to Customers Natural gas price volatility can cause changes in credit risk related to gas and NGLs loaned to customers. As of December 31, 2020, the amount of gas owed to the Company's operating subsidiaries due to gas imbalances and gas loaned under PAL and certain firm service agreements was approximately 11.2 trillion British thermal units (TBtu). Assuming an average market price during December 2020 of $2.45 per million British thermal unit (MMBtu), the market value of that gas was approximately $27.4 million. As of December 31, 2019, the amount of gas owed to the Company's operating subsidiaries due to gas imbalances and gas loaned under PAL and certain firm service agreements was approximately 12.8 TBtu. Assuming an average market price during December 2019 of $2.08 per MMBtu, the market value of that gas was approximately $26.6 million. As of December 31, 2020 and 2019, there were no outstanding NGL imbalances owed to the Company's operating subsidiaries. If any significant customer should have credit or financial problems resulting in a delay or failure to repay the gas owed to the operating subsidiaries, it could have a material adverse effect on the Company's financial condition, results of operations or cash flows. Note 15: Related Party Transactions Loews provides a variety of corporate services to the Company under services agreements, including information technology, tax, risk management, internal audit and corporate development services and also charges the Company for allocated overheads. The Company incurred charges related to these services of $5.7 million, $5.7 million and $6.2 million for the years ended December 31, 2020, 2019 and 2018, which were recorded in Administrative and general on the Consolidated Statements of Income. Total distributions paid to BPHC and Boardwalk GP were $102.2 million, $102.2 million and $77.2 million for each of the years ended December 31, 2020, 2019 and 2018. 59 Note 16: Supplemental Disclosure of Cash Flow Information (in millions): Cash paid during the period for: Interest (net of amount capitalized) Income taxes, net Non-cash adjustments: Accounts payable and PPE Right-of-use assets obtained in exchange for lease obligations For the Year Ended December 31, 2019 2018 2020 $ 162.1 $ 0.6 29.2 0.4 171.5 $ 0.3 42.7 18.3 166.0 0.8 39.3 — Note 17: Selected Quarterly Financial Data (Unaudited) The following tables summarize selected quarterly financial data for 2020 and 2019 for the Company (in millions): Operating revenues Operating expenses Operating income Interest expense Other income Income before income taxes Income taxes Net income Operating revenues Operating expenses Operating income Interest expense, net Other (income) expense Income before income taxes Income taxes Net income $ $ $ $ 2020 For the Quarter Ended: December 31 September 30 June 30 March 31 374.8 $ 219.8 155.0 42.5 (2.4) 114.9 — 114.9 $ 288.0 $ 213.1 74.9 43.8 (1.0) 32.1 0.1 32.0 $ 295.0 $ 202.5 92.5 41.1 (1.3) 52.7 0.1 52.6 $ 339.8 207.6 132.2 42.3 (1.2) 91.1 0.1 91.0 2019 For the Quarter Ended: December 31 September 30 June 30 March 31 294.8 $ 207.4 87.4 45.4 (0.6) 42.6 0.1 42.5 $ 327.3 $ 204.9 122.4 45.5 1.1 75.8 0.1 75.7 $ 345.9 192.8 153.1 45.0 (0.2) 108.3 0.2 108.1 327.2 $ 216.4 110.8 42.5 (1.2) 69.5 0.1 69.4 $ 60 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None. Item 9A. Controls and Procedures Disclosure Controls and Procedures As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Annual Report on Form 10-K. Our disclosure controls and procedures are designed to allow timely decisions regarding required disclosure and to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of December 31, 2020, at the reasonable assurance level. Changes in Internal Control over Financial Reporting There were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the quarter ended December 31, 2020, that have materially affected or that are reasonably likely to materially affect our internal control over financial reporting. Management's Report on Internal Control Over Financial Reporting Our management is responsible for establishing and maintaining adequate internal control over financial reporting for us. Our internal control system was designed to provide reasonable assurance regarding the preparation and fair presentation of our published financial statements. There are inherent limitations to the effectiveness of any control system, however well designed, including the possibility of human error and the possible circumvention or overriding of controls. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Management must make judgments with respect to the relative cost and expected benefits of any specific control measure. The design of a control system also is based in part upon assumptions and judgments made by management about the likelihood of future events, and there can be no assurance that a control will be effective under all potential future conditions. As a result, even an effective system of internal control over financial reporting can provide no more than reasonable assurance with respect to the fair presentation of financial statements and the processes under which they were prepared. Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2020. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control – Integrated Framework (2013). Based on this assessment, our management believes that, as of December 31, 2020, our internal control over financial reporting was effective. Item 9B. Other Information Not applicable. 61 PART III Item 10. Directors, Executive Officers and Corporate Governance We are omitting disclosure under this item because we meet the conditions set forth in General Instructions I(1) (a) and (b) of Form 10-K. Item 11. Executive Compensation We are omitting disclosure under this item because we meet the conditions set forth in General Instructions I(1) (a) and (b) of Form 10-K. Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters We are omitting disclosure under this item because we meet the conditions set forth in General Instructions I(1) (a) and (b) of Form 10-K. Item 13. Certain Relationships and Related Transactions, and Director Independence We are omitting disclosure under this item because we meet the conditions set forth in General Instructions I(1) (a) and (b) of Form 10-K. Item 14. Principal Accounting Fees and Services Audit Fees and Services Deloitte & Touche LLP (Deloitte & Touche) has served as our auditor since our inception in 2005, and our predecessors since 2003. The following table presents fees billed by Deloitte & Touche and its affiliates for professional services rendered to us and our subsidiaries in 2020 and 2019 by category as described in the notes to the table (in millions): (1) Audit fees Audit related fees (2) Total 2020 2019 $ $ 2.6 $ 0.1 2.7 $ 2.8 0.1 2.9 (1) Includes the aggregate fees and expenses for annual financial statement audit and quarterly financial statement reviews. (2) Includes the aggregate fees and expenses for services that were reasonably related to the performance of the financial statement audits or reviews described above and not included under Audit fees above, mainly including consents, comfort letters and audits of employee benefits plans. Auditor Engagement Pre-Approval Policy We are a wholly-owned indirect subsidiary of Loews and the Loews Audit Committee has responsibility for the appointment, compensation and oversight of the independent external audit firm retained to audit our financial statements and the audit fee negotiations associated with their retention. To assure the continued independence of our independent auditor, Deloitte & Touche, the Loews Audit Committee has adopted a policy requiring its pre-approval of all audit and non-audit services performed for us and our subsidiaries by the independent auditor. Under this policy, the Loews Audit Committee annually pre-approved certain limited, specified recurring services which may be provided by Deloitte & Touche, subject to maximum dollar limitations. All other engagements for services to be performed by Deloitte & Touche were specifically pre-approved by the Loews Audit Committee, or a designated committee member to whom this authority had been delegated. Under that policy, the Loews Audit Committee, or a designated member, pre-approved all engagements by us and our subsidiaries for services of Deloitte & Touche, including the terms and fees thereof, and the Loews Audit Committee concluded that all such engagements were compatible with the continued independence of Deloitte & Touche in serving as our independent auditor. 62 PART IV Item 15. Exhibits and Financial Statement Schedules (a) 1. Financial Statements Included in Item 8 of this Annual Report on Form 10-K: Report of Independent Registered Public Accounting Firm Consolidated Balance Sheets at December 31, 2020 and 2019 Consolidated Statements of Income for the years ended December 31, 2020, 2019 and 2018 Consolidated Statements of Comprehensive Income for the years ended December 31, 2020, 2019 and 2018 Consolidated Statements of Cash Flows for the years ended December 31, 2020, 2019 and 2018 Consolidated Statements of Changes in Partners' Capital for the years ended December 31, 2020, 2019 and 2018 Notes to Consolidated Financial Statements (a) 2. Financial Statement Schedules Schedule II not material. (a) 3. Exhibits The following documents are filed or furnished as exhibits to this report: Exhibit Number Description 3.1 3.2 4.1 4.2 4.3 4.4 4.5 4.6 Certificate of Limited Partnership of Boardwalk Pipeline Partners, LP (Incorporated by reference to Exhibit 3.1 to the Registrant's Registration Statement on Form S-1, Registration No. 333-127578, filed on August 16, 2005). Fourth Amended and Restated Agreement of Limited Partnership of Boardwalk Pipeline Partners, LP dated as of July 19, 2018 (Incorporated by reference to Exhibit 3.2 to the Registrant's Annual Report on Form 10-K filed on February 13, 2019). Indenture dated as of June 12, 2012, between Gulf South Pipeline Company, LP (now known as Gulf South Pipeline Company, LLC) and The Bank of New York Mellon Trust Company, N.A. (Incorporated by reference to Exhibit 4.1 to the Registrant's Current Report on Form 8-K filed on June 13, 2012). First Supplemental Indenture dated as of January 3, 2020, among Gulf South Pipeline Company, LLC, Gulf South Pipeline Company, LP and The Bank of New York Mellon Trust Company, N.A. (Incorporated by reference to Exhibit 4.2 to the Registrant's Annual Report on Form 10-K filed on February 11, 2020). Indenture dated July 15, 1997, between Texas Gas Transmission Corporation (now known as Texas Gas Transmission, LLC) and The Bank of New York, as Trustee (Incorporated by reference to Exhibit 4.1 to Texas Gas Transmission Corporation's Registration Statement on Form S-3, Registration No. 333-27359, filed on May 19, 1997). Indenture dated January 19, 2011, between Texas Gas Transmission, LLC and the Bank of New York Trust Company, N.A. (Incorporated by reference to Exhibit 4.1 to the Registrant's Current Report on Form 8-K filed on January 19, 2011). First Supplemental Indenture dated June 7, 2011, between Texas Gas Transmission, LLC and The Bank of New York Mellon Trust Company, N.A., as Trustee (Incorporated by reference to Exhibit 4.1 to the Registrant's Current report on Form 8-K, filed on June 13, 2011). Second Supplemental Indenture dated June 16, 2011, between Texas Gas Transmission, LLC and The Bank of New York Mellon Trust Company, N.A., as Trustee (Incorporated by reference to Exhibit 4.1 to the Registrant's Current report on Form 8-K, filed on June 20, 2011). 63 Exhibit Number 4.7 4.8 4.9 4.10 4.11 4.12 4.13 4.14 10.1 10.2 10.3 Description Indenture dated August 21, 2009, by and among Boardwalk Pipelines, LP, as issuer, Boardwalk Pipeline Partners, LP, as guarantor, and The Bank of New York Mellon Trust Company, N.A., as trustee (Incorporated by reference to Exhibit 4.1 to Boardwalk Pipeline Partners, LP’s Current Report on Form 8-K, filed on August 21, 2009). Second Supplemental Indenture dated November 8, 2012, by and among Boardwalk Pipelines, LP, as issuer, Boardwalk Pipeline Partners, LP, as guarantor, and The Bank of New York Mellon Trust Company, N.A., as trustee (Incorporated by reference to Exhibit 4.1 to Boardwalk Pipeline Partners, LP's Current Report on Form 8-K, filed on November 8, 2012). Third Supplemental Indenture to the indenture dated August 21, 2009, among Boardwalk Pipelines, LP, as issuer, Boardwalk Pipeline Partners, LP, as guarantor, and The Bank of New York Mellon Trust Company, N.A., as trustee (Incorporated by reference to Exhibit 4.2 to the Registrant's Current Report on Form 8-K filed on April 23, 2013). Fourth Supplemental Indenture to the indenture dated August 21, 2009, among Boardwalk Pipelines, LP, as issuer, Boardwalk Pipeline Partners, LP, as guarantor, and The Bank of New York Mellon Trust Company, N.A., as trustee (Incorporated by reference to Exhibit 4.1 to the Registrant's Current Report on Form 8-K filed on November 26, 2014). Fifth Supplemental Indenture to the indenture dated August 21, 2009, among Boardwalk Pipelines, LP, as issuer, Boardwalk Pipeline Partners, LP, as guarantor, and The Bank of New York Mellon Trust Company, N.A., as trustee (Incorporated by reference to Exhibit 4.1 to the Registrant's Current Report on Form 8-K filed on May 20, 2016). Sixth Supplemental Indenture to the indenture dated August 21, 2009, by and among Boardwalk Pipelines, LP, as issuer, Boardwalk Pipeline Partners, LP, as guarantor, and The Bank of New York Mellon Trust Company, N.A., as trustee (Incorporated by reference to Exhibit 4.1 to Boardwalk Pipeline Partners, LP's Current Report on Form 8-K, filed on January 12, 2017). Seventh Supplemental Indenture to the indenture dated August 21, 2009, by and among Boardwalk Pipelines, LP, as issuer, Boardwalk Pipeline Partners, LP, as guarantor, and The Bank of New York Mellon Trust Company, N.A., as trustee (Incorporated by reference to Exhibit 4.1 to Boardwalk Pipeline Partners, LP's Current Report on Form 8-K, filed on May 6, 2019). Eighth Supplemental Indenture to the indenture dated August 21, 2009, by and among Boardwalk Pipelines, LP, as issuer, Boardwalk Pipeline Partners, LP, as guarantor, and The Bank of New York Mellon Trust Company, N.A., as trustee (Incorporated by reference to Exhibit 4.1 to Boardwalk Pipeline Partners, LP's Current Report on Form 8-K, filed on August 12, 2020). Services Agreement dated as of May 16, 2003, by and between Loews Corporation and Texas Gas Transmission, LLC (Incorporated by reference to Exhibit 10.8 to Amendment No. 3 to the Registrant's Registration Statement on Form S-1, Registration No. 333-127578, filed on October 24, 2005). Third Amended and Restated Revolving Credit Agreement, dated as of May 26, 2015, among Boardwalk Pipelines, LP, Texas Gas Transmission, LLC, Gulf South Pipeline Company, LP and Gulf Crossing Pipeline Company LLC, as borrowers, Boardwalk Pipeline Partners, LP, as guarantor, the several lenders and issuers party thereto, Wells Fargo Bank, N.A., as administrative agent, Citibank, N.A. and JPMorgan Chase Bank, N.A., as co-syndication agents, and Bank of China, New York Branch, Barclays Bank PLC, Deutsche Bank Securities Inc., Mizuho Bank, Ltd., MUFG Union Bank, N.A., and Royal Bank of Canada, as co-documentation agents, and Wells Fargo Securities, LLC, Citigroup Global Markets, Inc., J.P. Morgan Securities LLC, Bank of China, New York Branch, Barclays Bank PLC, Deutsche Bank Securities Inc., Mizuho Bank, Ltd., MUFG Union Bank, N.A., and RBC Capital Markets, as joint lead arrangers and joint bookrunners (Incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on May 26, 2015). Amendment No. 1 to the Third Amended and Restated Revolving Credit Agreement, dated as of July 29, 2016, among Boardwalk Pipelines, LP, Texas Gas Transmission, LLC, Gulf South Pipeline Company, LP and Gulf Crossing Pipeline Company LLC, as borrowers, Boardwalk Pipeline Partners, LP, as guarantor, the several lenders and issuers party thereto, Wells Fargo Bank, N.A., as administrative agent, Citibank, N.A. and JPMorgan Chase Bank, N.A., as co-syndication agents, and Bank of China, New York Branch, Barclays Bank PLC, Deutsche Bank Securities Inc., Mizuho Bank, Ltd., MUFG Union Bank, N.A., and Royal Bank of Canada, as co- documentation agents, and Wells Fargo Securities, LLC, Citigroup Global Markets, Inc., J.P. Morgan Securities LLC, Bank of China, New York Branch, Barclays Bank PLC, Deutsche Bank Securities Inc., Mizuho Bank, Ltd., MUFG Union Bank, N.A., and RBC Capital Markets, as joint lead arrangers and joint bookrunners (Incorporated by reference to Exhibit 10.2 to the Registrant's Quarterly Report on Form 10-Q filed on August 1, 2016). (1) 64 Exhibit Number 10.4 *22.1 *23.1 *31.1 *31.2 **32.1 **32.2 *101.INS *101.SCH *101.CAL *101.DEF *101.LAB *101.PRE *104 * Filed herewith ** Furnished herewith Description Amendment No. 2 to the Third Amended and Restated Revolving Credit Agreement, dated as of July 28, 2017, among Boardwalk Pipelines, LP, Texas Gas Transmission, LLC, Gulf South Pipeline Company, LP and Gulf Crossing Pipeline Company LLC, as borrowers, Boardwalk Pipeline Partners, LP, as guarantor, the several lenders and issuers party thereto, Wells Fargo Bank, N.A., as administrative agent, Citibank, N.A. and JPMorgan Chase Bank, N.A., as co-syndication agents, and Bank of China, New York Branch, Barclays Bank PLC, Deutsche Bank Securities Inc., Mizuho Bank, Ltd., MUFG Union Bank, N.A., and Royal Bank of Canada, as co-documentation agents, and Wells Fargo Securities, LLC, Citigroup Global Markets, Inc., J.P. Morgan Securities LLC, Bank of China, New York Branch, Barclays Bank PLC, Deutsche Bank Securities Inc., Mizuho Bank, Ltd., MUFG Union Bank, N.A., and RBC Capital Markets, as joint lead arrangers and joint bookrunners (Incorporated by reference to Exhibit 10.1 to the Registrant's Quarterly Report on Form 10-Q filed on July 31, 2017). Subsidiary Issuers and Guarantors of Registered Securities. Consent of Independent Registered Public Accounting Firm. Certification of Stanley C. Horton, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a). Certification of Jamie L. Buskill, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a). Certification of Stanley C. Horton, Chief Executive Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. Certification of Jamie L. Buskill, Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. Inline XBRL Taxonomy Extension Schema Document Inline XBRL Taxonomy Calculation Linkbase Document Inline XBRL Taxonomy Extension Definitions Document Inline XBRL Taxonomy Label Linkbase Document Inline XBRL Taxonomy Presentation Linkbase Document Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) (1) The Services Agreements between Gulf South Pipeline Company, LP (now known as Gulf South Pipeline Company, LLC) and Loews Corporation and between Boardwalk Pipelines, LP (formerly known as Boardwalk Pipelines, LLC) and Loews Corporation are not filed because they are identical to Exhibit 10.1 except for the identities of Gulf South Pipeline Company, LLC and Boardwalk Pipelines, LLC and the date of the agreement. Item 16. Form 10-K Summary We are omitting disclosure under this item as it is provided elsewhere in this Report. 65  Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. SIGNATURE Boardwalk Pipeline Partners, LP By: Boardwalk GP, LP its general partner By: Boardwalk GP, LLC its general partner Dated: February 9, 2021 By: /s/  Jamie L. Buskill Jamie L. Buskill Senior Vice President, Chief Financial and Administrative Officer, Treasurer and Director Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the date indicated. Dated: February 9, 2021 Dated: February 9, 2021 Dated: February 9, 2021 Dated: February 9, 2021 Dated: February 9, 2021 Dated: February 9, 2021 Dated: February 9, 2021 /s/  Stanley C. Horton                                            Stanley C. Horton President, Chief Executive Officer and Director (principal executive officer) /s/  Jamie L. Buskill                                 Jamie L. Buskill Senior Vice President, Chief Financial and Administrative Officer, Treasurer and Director (principal financial officer) /s/  Steven A. Barkauskas Steven A. Barkauskas Senior Vice President, Controller and Chief Accounting and Information Officer (principal accounting officer) /s/  Michael E. McMahon                                 Michael E. McMahon Senior Vice President, General Counsel, Secretary and Director /s/  Kenneth I. Siegel Kenneth I. Siegel Director, Chairman of the Board /s/  Andrew H. Tisch Andrew H. Tisch Director /s/  Jane Wang Jane Wang Director 66 Subsidiary Issuers and Guarantors of Registered Securities EXHIBIT 22.1 Subsidiary Issuer Boardwalk Pipelines, LP 3.375% Notes due 2023 Boardwalk Pipelines, LP 4.95% Notes due 2024 Boardwalk Pipelines, LP 5.95% Notes due 2026 Boardwalk Pipelines, LP 4.45% Notes due 2027 Boardwalk Pipelines, LP 4.80% Notes due 2029 Boardwalk Pipelines, LP 3.40% Notes due 2031 Guarantor Boardwalk Pipeline Partners, LP Boardwalk Pipeline Partners, LP Boardwalk Pipeline Partners, LP Boardwalk Pipeline Partners, LP Boardwalk Pipeline Partners, LP Boardwalk Pipeline Partners, LP CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM We consent to the incorporation by reference in Registration Statement No. 333-228714 on Form S-3 of our report dated February 9, 2021, relating to the consolidated financial statements of Boardwalk Pipeline Partners, LP, and subsidiaries appearing in this Annual Report on Form 10-K of Boardwalk Pipeline Partners, LP for the year ended December 31, 2020. EXHIBIT 23.1 /s/ Deloitte & Touche LLP Houston, Texas February 9, 2021 I, Stanley C. Horton, certify that: EXHIBIT 31.1 I have reviewed this Annual Report on Form 10-K of Boardwalk Pipeline Partners, LP; 1) 2) Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3) Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4) The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5) The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Dated: February 9, 2021 /s/ Stanley C. Horton Stanley C. Horton President and Chief Executive Officer EXHIBIT 31.2 I, Jamie L. Buskill, certify that: I have reviewed this Annual Report on Form 10-K of Boardwalk Pipeline Partners, LP; 1) 2) Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3) Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4) The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5) The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Dated: February 9, 2021 /s/ Jamie L. Buskill Jamie L. Buskill Senior Vice President, Chief Financial and Administrative Officer and Treasurer Certification by the Chief Executive Officer of Boardwalk GP, LLC pursuant to 18 U.S.C. Section 1350 (as adopted by Section 906 of the Sarbanes-Oxley Act of 2002) EXHIBIT 32.1 Pursuant to 18 U.S.C. Section 1350, the undersigned chief executive officer of Boardwalk GP, LLC hereby certifies, to such officer's knowledge, that the annual report on Form 10-K for the year ended December 31, 2020, (the Report) of Boardwalk Pipeline Partners, LP (the Company) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. February 9, 2021 /s/ Stanley C. Horton                                   Stanley C. Horton President and Chief Executive Officer (principal executive officer) Certification by the Chief Financial Officer of Boardwalk GP, LLC pursuant to 18 U.S.C. Section 1350 (as adopted by Section 906 of the Sarbanes-Oxley Act of 2002) EXHIBIT 32.2 Pursuant to 18 U.S.C. Section 1350, the undersigned chief financial officer of Boardwalk GP, LLC hereby certifies, to such officer's knowledge, that the annual report on Form 10-K for the year ended December 31, 2020, (the Report) of Boardwalk Pipeline Partners, LP (the Company) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. February 9, 2021 /s/ Jamie L. Buskill                                   Jamie L. Buskill Senior Vice President, Chief Financial and Administrative Officer and Treasurer (principal financial officer) 

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