Boardwalk Pipeline Partners, LP Form 10-K Annual Report Filed 2023-02-07 Changes

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We serve a broad mix of customers, including electric power generators, producers and marketers of natural gas, local distribution companies (LDCs), industrial users, exporters of liquefied natural gas (LNG), and interstate and intrastate pipelines. We provide a significant portion of our natural gas pipeline transportation and storage services through firm contracts under which our customers pay monthly capacity reservation fees, which are fixed fees based on the quantity of capacity reserved, regardless of use. Other fees are based on actual utilization of the capacity under firm contracts and contracts for interruptible services. Contracts for our NGLs services are generally fee-based or based on minimum volume requirements, while others are dependent on actual volumes transported or stored. For the year ended December 31, 20212022, approximately 8987% of our revenues were derived from capacity reservation fees under firm contracts, approximately 78% of our revenues were derived from fees based on utilization under firm contracts and approximately 45% of our revenues were derived from interruptible transportation, interruptible storage, parking and lending (PAL) and other services.

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

We own and operate approximately 13,615515 miles of interconnected natural gas pipelines, directly serving customers in thirteen states and indirectly serving customers throughout the northeastern and southeastern United States (U.S.) through numerous interconnections with unaffiliated pipelines. We also own and operate approximately 450 miles of NGLs pipelines in Louisiana and Texas. In 20212022, our pipeline systems transported approximately 3.4 trillion cubic feet of natural gas and approximately 90.46 MMBbls of NGLs. Average daily throughput on our natural gas pipeline systems during 20212022 was approximately 9.43 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 32.13 MMBbls. We also own nine salt-dome caverns and related brine infrastructure for use in providing brine supply services and to support the NGLs storage operations.

The principal sources of supply for our natural gas pipeline systems are regional supply hubs and market centers located in the Gulf Coast and Mid-Continent regions, including offshore Louisiana, the Perryville, Louisiana, area, the Henry Hub in Louisiana and the Carthage, Texas, area. Our pipelines in the Carthage, Texas, area provide access to natural gas supplies from the Barnett and Haynesville Shales and other natural gas producing regions in eastern Texas and northern Louisiana. The Henry Hub serves as the designated delivery point for natural gas futures contracts traded on the New York Mercantile Exchange. Our pipeline systems also have access to supply basins such as the Woodford and Scoop/Stack Shales in Oklahoma, the Fayetteville Shale in Arkansas, the Eagle Ford Shale in southern Texas and wellhead supplies in northern and southern Louisiana and Mississippi, and we also receive gas in the Lebanon, Ohio, area from the Marcellus and Utica Shales located in the northeastern U.S. Our NGLs pipeline systems access the Gulf Coast petrochemical industry through our operations at our Choctaw Hub in the Mississippi River corridor area of Louisiana and the Sulphur Hub in the Lake Charles, Louisiana, area. We also access ethylene supplies at Port Neches, Texas, which we deliver to petrochemical-industry customers in Louisiana.

Gulf South Pipeline Company, LLC (Gulf South): Our 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.

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.

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 48.79 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 180-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 90.46 MMBbls for the year ended December 31, 20212022.

In 20212022, we placed into service approximately $137157.50 million of growth projects which primarily represents approximately 0.27 Bcf/d of firm natural gas transportation capacity, compressor station modernization and which added additional capacity to our ethylene system, and the completion of the deepest brine well in North America, which will provide access to additional NGLs infrastructuresalt reserves and reliability for our brine customers. We expect to spend approximately $410.0 million on our growth projects currently under construction through 2024 and2025. These projects will add another approximately 0.67 Bcf/d of firm natural gas transportation capacity and additional NGLs infrastructure. Thosecapacity. The additional NGLs capacity, when completed and in conjunction with the 2022 completed project, will result in an approximate increase of 20% in the capacity of our ethylene systems. These projects are expected to serve increased natural gas demand from power generation plants and liquids demand from petrochemical facilities. All of our growth projects are secured by long-term firm contracts.

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 the 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 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

We contract directly with end-use customers, including LDCs, electric power generators, LDCs, industrial users and 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 20212022 transportation, storage and PAL revenues, net of fuel, our customer mix was as follows: power generators (23%), natural gas producers (2120%), marketers (1719%), LDCs (16%), industrial end-users (13%) and exporters of LNG and others (10(9%). Based upon our 20212022 transportation, storage and PAL revenues, net of fuel, our deliveries were as follows: pipeline interconnects (29%), LDCs (18%), power generators (1718%), industrial end-users (1615%), storage activities (910%), exporters of LNG (98%) and others (2%). No customer comprised 10% or more of our operating revenues in 20212022.

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.

The FERC issued a Notice of Inquiry (NOI) on April 19, 2018 (2018 NOI), initiating a review of its policies on certification of natural gas pipelines, including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities (1999 Policy Statement), issued in 1999, that is used to determine whether to grant certificates for new pipeline projects. On February 18, 2021, the FERC issued another NOI (2021 NOI), reopening its review of the 1999 Policy Statement. CommentsOn February 18, 2022, the FERC issued a Policy Statement on the 2021 NOICertification of were due on May 26, 2021, and although the FERC has not taken any further action regardingNew Interstate Natural Gas Facilities and a Policy Statement on the Consideration of Greenhouse Gas Emissions in Natural Gas Infrastructure Project Reviews (2022 Policy Statements), to be effective that same day. On March 24, 2022, the FERC issued an order converting the 2022 Policy Statements into draft policy statements and requested further comments. The FERC will not apply the 2018 NOI or 2021 NOI, wedraft 2022 Policy Statements until it issues final guidance on these topics. We are unable to predict what, if any, changes may be proposed as a resultresult upon finalization of the NOIsdraft 2022 Policy Statements that will affect our natural gas pipeline operations or when such proposals, if any, might become effectivenew policies, if any, might become effective. We do not expect that any change in these policy statements would affect us in a materially different manner than any other natural gas pipeline company operating in the U.S.

U.S. Department of Transportation (DOT): We are regulated by the DOT, through the Pipeline and Hazardous Materials 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) and moderate consequence areas (MCAs), along pipelines and take additional safety measures to protect people and property in these areas. The HCAs for natural gas pipelines are predicated on high-population density areas (which, for natural gas transmission lines, include Class 3 and 4 areas and, depending on the potential impacts of a risk event, may include Class 1 and

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

WithAs the adoptiona result of the 2011 Act, the 2016 Act and the 2020 Act, there exist mandates for PHMSA to make pipeline safety requirements more stringent. As a result, PHMSA has issued a series of significant rulemakings. In October 2019, PHMSA published a final rule imposing numerous new requirements on onshore gas transmission pipelines, also known as the Mega Rule, relating to maximum allowable operating pressure (MAOP) reconfirmation and exceedance reporting, the integrity assessment of additional pipeline mileage found in MCAs and Class 3 and Class 4 non-HCAs by 2033, and the consideration of seismicity as a risk factor in integrity management. PHMSA published a second final rule in October 2019 for hazardous liquid transmission and gathering pipelines that significantly extends and expands the reach of certain of its integrity management requirements, and that requires the accommodation of in-line inspection tools by 2039 unless the pipeline cannot be modified to permit such accommodation, increased annual, accident and safety-related conditional reporting requirements, and expanded use of leak detection systems beyond HCAs. PHMSA also published final rules during February and July 2020 that amended the minimum safety requirements related to natural gas storage facilities, including wells, wellbore tubing and casing, and added applicable reporting requirements. In November 2021, PHMSA issued a final rule that will impose safety regulations on approximately 400,000 miles of previously unregulated onshore gas gathering lines that, among other things, will impose criteria for inspection and repair of fugitive emissions, extend reporting requirements to all gas gathering operators and apply a set of minimum safety requirements to certain gas gathering pipelines with large diameters and high operating pressures. Separately, in June 2021, PHMSA issued an Advisory Bulletin advising pipeline and pipeline facility operators of applicable requirements to update their inspection and maintenance plans for the elimination of hazardous leaks and minimization of natural gas released from pipeline facilities. PHMSA, together with and state regulators, is expected to commence inspection of these plans in 2022. These new and any future regulations adopted by PHMSA reportedly began their review of these plans in 2022, and PHMSA has separately announced plans to propose rules addressing methane leaks from pipelines. In August 2022, PHMSA published another final rule expanding the Management of Change process, extending corrosion control requirements for gas transmission pipelines, adding requirements that operators ensure no conditions exist following an extreme weather event that could adversely affect the safe operation of the pipeline, and adopting repair criteria for non-HCAs similar to those applicable to HCAs. These new and any future regulations adopted by PHMSA have imposed and 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:

Many states where we operate also have, or are developing, similar environmental or occupational health and safety legal requirements governing many of the same types of activities, and those requirements can be more stringent than those adopted under federal laws and regulations. Failure to comply with these federal, state and local laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of corrective or remedial obligations, the incurrence of capital expenditures, the occurrence of delays, denials or cancellations in permitting or in 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 initiated, and indicated that he intends to continuecontinues to pursue additional action to bolster environmental regulations, whether by new legislation, executive actions or regulatory initiatives, which may impact our operations. For example, the Biden Administration has announced that it plans to reconsider or revise various rulemakingsrules to be more stringent than thoseand repeal various rules issued by the Trump Administration, includingand, among othersto that end, has announced forthcoming actions or released proposed rules regarding restrictions on methane emissions from oil and gas operations, ground level ozone emission standards, requirements for environmental reviews under NEPA, and the definition of Waters ofand Nationwide Permit (NWP) 12. The Biden Administration has also signaled a strong focus on directing agency action to mitigate climate change and further limit GHG emissions. For example, in January 2023, the United States for purposes of Clean Water Act jurisdiction. Similarly, President Biden has issued executive orders bolsteringWhite House’s Council on Environmental Quality (CEQ) released guidance to assist federal agencies in assessing the GHG emissions limitations and the Biden Administration continues to consider actions to further advance responses toand climate change; for effects of their proposed actions under the NEPA. The guidance follows the publication of a final rule in April 2022 revoking some modifications made to the regulations under the Trump Administration and reincorporating consideration of direct, indirect, and cumulative effects of major federal actions. CEQ’s guidance is effective immediately and could result in additional challenges to NEPA reviews performed in connection with our projects, which in turn could result in further permitting and approval delays. For more information, see Item 1A. Risk Factors—Business Risks—"Our operations, and those of our customers, are subject to a series of risks regarding climate change.

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 instance, the construction or expansion of pipelines often requires authorizations under the Clean Water Act, which authorizations may be subject to challenge. For instance, there is ongoing litigation with respect to the status and use of the U.S. Army Corps of Engineers (the Corps) Clean Water Act Section 404 NWP 12, which was vacated in April 2020. In January 2021, the Corps reissued a restructured NWP 12 for oil and natural gas pipeline activities. The reissued NWP 12, alongside other NWPs, relies upon the Clean Water Act Section 401 certification process, which is also subject to ongoing litigation. In October 2021, the Northern District of California federal court vacated a 2020 rule revising the Section 401 certification process, which was later appealed to the Ninth Circuit and stayed by the Supreme Court. However, following a temporary pause on permitting decisions, in November 2021, the Corps announced that permitting under such NWPs would resume, with the Corps coordinating with certifying authorities for Section 401 certification as needed. Although the full extent and impact of the ongoing litigation and vacaturs 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. There also continues to be uncertainty with respect to the federal government’s jurisdictional reach under the Clean Water Act over "waters of the United States", including wetlands, as the Environmental Protection Agency (EPA) and the Corps have pursued multiple rulemakings under different administrations since 2015 in an attempt to determine the scope of such reach. In December 2022, the Administration finalized a new and more expansive definition of “waters of the United States,” which repealed the Trump Administration’s April 2020 rule and largely restored the definition in place prior to 2015, with modifications reflecting Supreme Court decisions issued after 2015. Judicial developments also add to this uncertainty—the Supreme Court recently heard oral arguments in Sackett v. EPA and is expected to rule on the scope of the Clean Water Act’s jurisdiction with respect to wetlands in 2023. For more information, see Item 1A. Risk Factors—Business Risks— "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."

Climate change continues to attract considerable public, governmental and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional, state and local levels of government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes and GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. Due to the nature of our business, our operations emit various types of GHGs. We seek to carefully monitor our emissions and expect to incur additional costs to mitigate emissions. New legislation or regulations could increase the costs related to operating and maintaining our facilities. Depending on the particular law, regulation or program, we could be required to incur capital expenditures for installing new monitoring equipment or emission controls on our facilities, acquire and surrender allowances for GHG emissions, pay taxes or fees related to GHG emissions and/or administer and manage a more comprehensive GHG emissions program. While we may be able to include some or all of the increased costs in the rates charged by our pipelines, recovery of costs is not certain and would require the FERC’s approval of a rate mechanism designed to recover those costs.

We recognize that relative to certain other fossil fuels, natural gas has an important role in reducing GHG emissions and may act as a bridge to scaling up renewable energy or other alternative energy sources in the U.S. WeWhile we are workingseeking to reduce our GHG emissions, butwe cannot predict all risks that may be associated with climate change or other ESGenvironmental, social and governance (ESG) matters. For more information, please see Item 1A. Risk Factors—Business Risks—"Our operations, and those of our customers, are subject to a series of risks regarding climate change" and "Increased attention to climate change, environmental, social and governance (ESG) matters and conservation measures may adversely impact our business."

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

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

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 issued a NOI on April 19, 2018, initiating a review of its policies on certification of natural gas pipelines, including an examination of the 1999 Policy Statement that is used to determine whether to grant certificates for new pipeline projects. On February 18, 2021, the FERC issued the 2021 NOI, reopening its review of the 1999 Policy Statement. On February 18, 2022, the FERC issued the 2022 Policy Statements, to be effective that same day. On March 24, 2022, the FERC issued an order converting the 2022 Policy Statements into draft policy statements and requested further comments. The FERC will not apply the draft 2022 Policy Statements until it issues final guidance on these topics. We are unable to predict what, if any, changes may result upon finalization of the draft 2022 Policy Statements that will affect our natural gas pipeline operations or when such new policies, if any, might become effective. We do not expect that any change in these policy statements would affect us in a materially different manner than any other natural gas pipeline company operating in the U.S.

In the U.S., no comprehensive climate change legislation has been implemented at the federal level. However, but President Biden has shown that action to address climate change is an important part of his Administration’s agenda. For example, in August 2022, the Inflation Reduction Act of 2022 (IRA) passed which advanced numerous climate-related objectives. Additionally, the EPA has issued several rules regulating GHGs following the U.S. Supreme Court finding that GHGs are air pollutants under the CAA and the EPA's own endangerment finding for certain GHGs, including carbon dioxide and methane. The EPA regulates GHGs through various requirements, including permitting for GHG emissions from large stationary sources, annual reporting on GHG emissions from oil and gas facilities, New Source Performance Standards (NSPS) restricting methane emissions from new facilities in the natural gas sector, and GHG emissions limits on vehicles (together with the DOT). The EPA's regulation of methane emissions continues to undergo significant changes. In June 2021, President Biden signed into law a joint resolution of Congress under the Congressional Review Act that rescinded the EPA's 2020 Policy Rule, effectively reinstating the 2012 and 2016 NSPS for the transmission and storage sector. In November 2021, the EPA proposed a rule to establish standards of performance for methane and volatile organic compound emissions from new sources and, for the first time, existing sources (those that commenced construction or reconstruction after November 15, 2021), within the crude oil and natural gas source category, including the transmission and storage sector. On November 11, 2022, the EPA released a supplemental methane proposal that modified the original proposal and provided additional detail. The proposed rule includes several requirements relevant to our operations, including stricter emissions limits for various facilities and equipment (including pneumatic controllersdevices, storage tanks, reciprocating compressors, and wet seal and dry seal centrifugal compressors), more frequent leak detection and monitoring of fugitive emissions from compressor stations, and deadlines for repairing fugitive

emissions. The EPA plans to issueemissions. The proposal also establishes a program for third-party notification of “super-emitter” events. The final rule will likely work alongside the IRA, which appropriates significant federal funding for renewable energy initiatives as well as amends the CAA to impose a supplemental proposal containing proposed regulations in 2022 and aims to finalizefirst-time fee on the emission of methane from sources required to report their GHG emissions to the EPA. The methane emissions fee applies to excess methane emissions from certain facilities and starts at $900 per metric ton of leaked methane in 2024 and increases to $1,200 in 2025 and $1,500 in 2026 and thereafter. Compliance with the EPA’s proposed new rule and the IRA’s methane emissions fee could increase our operating costs and the costs of our customers and accelerate the transition away from fossil fuels which could, in turn, reduce the rule bydemand for the end of 2022our services, thereby adversely affecting our operations.

Governmental entities, including certain states and groups of states, have adopted or are considering legislation, regulations or other initiatives, such as GHG cap and trade programs, carbon taxes, GHG reporting and tracking programs, and emissions limits. At the international level, in February 2021 the U.S. rejoined the Paris Agreement, which requires member nations to submit non-binding GHG emissions reduction goals every five years. In April 2021, President Biden announced a new target for the U.S. to reduce GHG emissions 50-52% from 2005 levels by 2030. In November 2021, the U.S. joined other nations for the 26th Conference to the Partiesof the Parties to the United Nations Framework Convention on Climate Change (COP26), during which nations including the U.S. made various commitments, including the Global Methane Pledge to reduce methane emissions 30% from 2020 levels by 2030. Additionally, at the 27th Conference of the Parties to the United Nations Framework Convention on Climate Change (COP27) in November 2022, countries, including the U.S., reiterated the agreements from COP26 and were called upon to accelerate efforts toward the phase out of inefficient fossil fuel subsidies. The U.S. also announced, in conjunction with the European Union and other partner countries, that it would develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity gas. Although no firm commitment or timeline to phase out or phase down fossil fuels were made at COP27, there can be no guarantees that countries will not seek to implement such a phase out or phase down in the future. Additionally, we cannot predict whether similar efforts at future climate conferences will be successful and the potential resultant impact this may have upon our business or financial condition.

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

fuel energy related sectors. Some institutional lenders who provide financing to fossil fuel energy companies also have become more attentive to sustainable lending practices that favor alternative power sources (such as wind, solar, geothermal, tidal and biofuels), making those sources more attractive, and some of them may elect not to provide funding for fossil fuel energy companies. Many of the largest U.S. banks have made “net zero” carbon emission commitments and have announced that they will be assessing financed emissions across their portfolios and taking steps to quantify and reduce those emissions. At COP26, the Glasgow Financial Alliance for Net Zero announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. Financial institutions could be required to adopt policies that limit funding for fossil fuel energy companies. In late 2020 the Federal Reserve joined the Network for Greening the Financial System (NGFS), a consortium of financial regulators focused on addressing climate-related risks in the financial sector, and in 2021 the Federal Reserve issued a statement supporting the effortsSeptember 2022, announced that six of the U.S.’ largest banks will participate in a pilot climate scenario analysis to enhance the ability of firms and supervisors to measure and manage climate-related financial risk. The Federal Reserve released its pilot exercise in January 2023, which is designed to analyze the impact of NGFS in identifying potential solutions for climate-both physical and transition risks related challenges relevant to central to climate change on specific assets of the banks and supervisory authorities’ portfolios. While we cannot predict what policies may result from these announcements and activities, a material reduction in the capital available to the fossil fuel industry could make it more difficult to secure funding for exploration and production or midstream energy business activities, which could adversely impact our business and operations. Additionally, in March 2022, the SEC released a proposed rule that would establish a framework for the reporting of climate risks, targets, and metrics. A final rule is expected to be released in 2023, but we cannot predict the final form and substance of the rule and its requirements. The ultimate impact of the rule on our business is uncertain and, upon finalization, may result in increased compliance costs and increased costs of and restrictions on access to capital. Separately, the SEC has also announced that it is scrutinizing existing climate-change related disclosures in public filings, increasing the potential for enforcement if the SEC were to allege that an issuer’s existing climate disclosures are misleading or deficient. These agency actions could increase the potential for litigation.

The adoption and implementation of new or more stringent international, federal, regional, state or local legislation, regulations or other initiatives that impose more stringent standards for GHG emissions from the oil and gas sector or otherwise restrict fossil fuel production could result in increased costs of compliance for fossil fuel use, 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 and other 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 could reduce demand for hydrocarbons and for our services. Finally, we may also be subject to various physical risks from climate change. For more information on these physical risks, see our risk factor titled "Climatic conditions and events could adversely impact our operations, pipelines and facilities, or those of our customers or suppliers."

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

Public statements with respect to ESG matters, such as emissions reduction goals, other environmental targets, or other commitments addressing certain social issues, are becoming increasingly subject to heightened scrutiny from public and governmental authorities related to the risk of potential “greenwashing,” i.e., misleading information or false claims overstating potential ESG benefits. For example, in March 2021, the SEC established the Climate and ESG Task Force in the Division of Enforcement to identify and address potential ESG-related misconduct, including greenwashing. Certain non-governmental organizations and other private actors have also filed lawsuits under various securities and consumer protection laws alleging that certain ESG-statements, goals, or standards were misleading, false, or otherwise deceptive. As a result, we may face increased litigation risks from private parties and governmental authorities related to our ESG efforts. In addition, any alleged claims of greenwashing against us or others in our industry may lead to further negative sentiment and diversion of investments. Additionally, we could face increasing costs as we attempt to comply with and navigate further ESG-related regulatory focus and scrutiny.

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

Our business, operations and financial condition may be adversely impacted as a result of negative public opinion. We operate in an industry which receives negative portrayals and opposition to development projects. Our reputation and public opinion could be impacted by the actions, activities and responses of other companies operating in the energy industry, particularly other energy infrastructure providers, over which we have no control. Our reputation also could be impacted by negative publicity related to pipeline incidents, unpopular expansion projects and opposition to development of hydrocarbons and energy infrastructure, particularly projects involving resources that are considered to increase GHG emissions and contribute to climate change. Negative impacts from a compromised reputation or changes in public opinion (including with respect to the production, transportation and use of hydrocarbons generally) could include increased regulatory oversight, delays in obtaining, or challenges to, regulatory approvals with respect to growth projects, blockades, project cancellations, difficulty securing financing at reasonable terms, revenue loss or a reduction in customer base.

RCRA, ESA, NEPA, OSHA and analogous state laws. These laws and regulations may restrict or impact our business activities, including requiring the acquisition or renewal of permits or other approvals to conduct regulated activities, restricting the manner in which we handle or dispose of wastes, imposing remedial obligations to remove or mitigate contamination resulting from a spill or other release, requiring capital expenditures to comply with pollution control requirements and imposing safety and health criteria addressing worker protection. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, the incurrence of capital expenditures, the occurrence of delays, denials or cancellations in the permitting or

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 exampleinstance, the construction or expansion of pipelines often requires authorizations under the Clean Water Act, which authorizations may be subject to challenge. In April 2020, the federal district courtFor instance, there is ongoing litigation with respect to the status and use for the District of Montana vacated the U.S. Army Corps of Engineers (the Corps)of the Corps Clean Water Act Section 404 Nationwide Permit (NWP) 12 after determining that it failed to comply with consultation requirements under the federal ESA. While the district court's order has subsequently been limited pending appeal, we 12, which cannot predict the ultimate outcome of this case and its impacts to the NWP program. In response to the vacatur, inwas vacated in April 2020. In January 2021, the Corps published a reissuance ofreissued a restructured NWP 12 for oil and natural gas pipeline activities. that separated certain utilities formerly covered under the permit intoThe reissued NWP 12, alongside other NWPs., An October 2021 decision by the federal district court for the Northern District of California resulted in a vacatur of a 2020 rule revisingrelies upon the Clean Water Act Section 401 certification process. Several NWPs, including, which is also subject to ongoing litigation. In October 2021, the revised NWP 12, rely on the vacated ruleNorthern District of California federal court vacated a 2020 rule revising the Section 401 certification process, which was later appealed to the Ninth Circuit and stayed by the Supreme Court. However, following a temporary pause on permitting decisions, in NovembersNovember 2021, the Corps announced that permitting under such NWPs would resume, with the Corps coordinating with certifying authorities for Section 401 certification as needed. Litigation regarding the use of NWP 12 is ongoing. WhileAlthough the full extent and impact of thesethe ongoing litigation and vacaturs 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. There also continues to be uncertainty with respect to the federal government’s jurisdictional reach under the Clean Water Act over “waters of the United States,” including wetlands, as the EPA and the Corps have pursued multiple rulemakings under different administrations since 2015 in an attempt to determine the scope of such reach. In December 2022, the Administration finalized a new and more expansive definition of “waters of the United States,” which repealed the Trump Administration’s April 2020 rule and largely restored the definition in place prior to 2015, with modifications reflecting Supreme Court decisions issued after 2015. Judicial developments also add to this uncertainty—the Supreme Court recently heard oral arguments in Sackett v. EPA and is expected to rule on the scope of the Clean Water Act’s jurisdiction with respect to wetlands in 2023. See Part I, Item 1. Business—Government Regulation—Other of this Annual Report on Form 10-K for further discussion on environmental matters.

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, remediation of certain identified anomalies and other measures to promote pipeline safety in HCAs, MCAs, Class 1 and 2 areas (depending on the potential impacts of a risk event), Class 3 and Class 4 areas, as well as in areas unusually sensitive to environmental damage and commercially navigable waterways. PHMSA has revised its standards from time-to-time. In October 2019, PHMSA published a final rule imposing numerous new requirements, also known as the Mega Rule, on onshore gas transmission pipelines relating to MAOP reconfirmation and exceedance reporting, the integrity assessment of additional pipeline mileage found in MCAs and Class 3 and Class 4 non-HCAs by 2033, and the consideration of seismicity as a risk factor in integrity management. PHMSA published a second final rule in October 2019 for hazardous liquid transmission and gathering pipelines that significantly extends and expands the reach of certain of its integrity management requirements, and that requires the accommodation of in-line inspection tools by 2039 unless the pipeline cannot be modified to permit such accommodation, increased annual, accident and safety-related conditional reporting requirements, and expanded use of leak detection systems beyond HCAs. PHMSA also published final rules during February and July 2020 that amended the minimum safety requirements related to natural gas storage facilities, including wells, wellbore tubing and casing, and added applicable reporting requirements. In June 2021, PHMSA issued an Advisory Bulletin advising pipeline and pipeline facility operators of applicable requirements to update their inspection and maintenance plans for the elimination of hazardous leaks and minimization of natural gas released from pipeline facilities. PHMSA and state regulators reportedly began their review of these plans in 2022, and PHMSA has separately announced plans to propose rules addressing methane leaks from pipelines. In

August 2022, PHMSA published another final rule expanding the Management of Change process, extending corrosion control requirements for gas transmission pipelines, adding requirements that operators ensure no conditions exist following an extreme weather event that could adversely affect the safe operation of the pipeline, and adopting repair criteria for non-HCAs similar to those applicable to HCAs. These new and any future regulations adopted by PHMSA have imposed and may impose more stringent requirements applicable to integrity management programs and other pipeline safety aspects of our operations, which is expected to cause us to incur increased capital and operating costs, may cause us to experience operational delays and may result in potential adverse impacts to our ability to reliably serve our customers.

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, 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, the 2016 Act or, the 2020 Act, or other pipeline safety legislation or implementing regulations, may also increase our capital and operating costs or impact the operation of our pipelines. 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.

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

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.

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

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

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

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

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

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, or 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.

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

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

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

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.

The principal elements of competition among pipeline systems are availability of capacity, rates, terms of service, access to gas supplies, flexibility and reliability of service. Additionally, the FERC's policies promote competition in natural gas markets by increasing the number of natural gas transportation options available to our customer base. Increased competition could reduce the volumes of product we transport or store or, in instances where we do not have long-term contracts with fixed rates, could cause us to decrease the transportation or storage rates we can charge our customers. Competition could intensify the negative impact of factors that adversely affect the demand for our services, such as adverse economic conditions, weather, higher fuel costs and taxes or regulatory actions that increase the cost, or limit the use, of products we transport and store.

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 NGLsNGL 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.

During 20212022, we entered into approximately $01.83 billion of new firm agreements, of which approximately 284% were from new growth projects executed in 20212022. For firm agreements associated with new growth projects, the associated assets may not be placed into commercial service until sometime in the future. 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). Refer to Part I, Item 1. Business and Item 1A. Risk Factors of this Annual Report on Form 10-K for further information. As of December 31, 20212022, our top ten customers holding firm capacity under firm agreements comprised approximately 3956% of our total projected operating revenues. Additionally, and the credit profile associated with our customers comprising the total projected operating revenues under firm agreements as of December 31, 2021, was 7473% rated as investment grade, 10% rated as non-investment grade and 1617% 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.

lines, include Class 3 and 4 areas and, depending on the potential impacts of a risk event, may include Class 1 and 2 areas) whereas HCAs along our NGL pipelines are based on high-population density areas, areas near certain drinking water sources and unusually sensitive ecological 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. In 2021, PHMSA issued a final rule that will impose safety regulations related to onshore gas gathering lines and in June 2021, PHMSA issued an Advisory Bulletin advising pipeline and pipeline facility operators of applicable requirements to update their inspection and maintenance plans for the elimination of hazardous leaks and minimization of natural gas released from pipeline facilities. PHMSA, together with and state regulators, is expected to commence inspection reportedly began their review of these plans in 2022. It is expected that these new rules will, and PHMSA has separately announced plans to propose rules addressing methane leaks from pipelines. In August 2022, PHMSA published another final rule expanding the Management of Change process, extending corrosion control requirements for gas transmission pipelines, adding requirements that operators ensure no conditions exist following an extreme weather event that could adversely affect the safe operation of the pipeline, and adopting repair criteria for non-HCAs similar to those applicable to HCAs.

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

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 20222023, we expect to spend approximately $400460.0 million to maintain our pipeline systems and to, comply with new regulatory initiatives previously mentionedregulations and monitor, control and reduce our GHG emissions, of which approximately $155195.0 million is expected to be maintenance capital. In 20212022, we spent $381408.23 million, of which $154157.34 million was recorded as maintenance capital. Refer to Capital Expenditures for more information regarding certain of our maintenance costs.

Note 2 in Part II, Item 8. of this Annual Report on Form 10-K contains a summary of our revenuesrevenue contracts 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 lowerchanges in pricing on contract renewals and other factors discussed elsewhere in this Annual Report on Form 10-K. 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. Our operations and maintenance expenses are impacted by our compliance with the requirements of, among other regulations, the Mega Rule and our efforts to monitor, control and reduce emissions, as further discussed in this Annual Report on Form 10-K.

At December 31, 20212022, we had $39215.16 million of cash on hand and all of the available borrowing capacity under our $1.0 billion revolving credit facility. We anticipate that our existing capital resources, including our cash on hand, revolving credit facility and our cash flows from operating activities, will be adequate to fund our operations and capital expenditures for 20222023. We may seek to access the debt markets to fund some or all capital expenditures for growth projects, acquisitions, to refinance maturing debt or for general partnership purposes. We have an effective shelf registration statement on file with the SEC under which we may publicly issue $1.0 billion of debt securities, warrants or rights from time to time. We have $300.0 In February 2022, we issued $500.0 million aggregate principal amount of Boardwalk Pipelines 3.60% notes due September 2032, which utilized $500.0 million of capacity under our shelf registration statement. The net proceeds from this offering were used to retire $300.0 million of Gulf South 4.00% notes maturing indue June 2022 in March 2022, to fund growth capital expenditures and for general partnership purposes. In June 2022, which we expect to retire near or at their maturity through available capital resources, including, using available cash, borrowing underwe amended our revolving credit facility or publicly issuing debt securitiesto, among other things, extend the maturity date by one year to May 27, 2027. In November 2022, we used our available cash to retire $300.0 million of Boardwalk Pipelines 3.375% notes that were due in February 2023. In December 2022, we paid $102.2 million of distributions to our general partner and BPHC. As of December 31, 20212022, we have $4.32 billion of contractual cash payment obligations under firm agreements, of which $4.1 billion represents principal and interest payments related to our long-term debt. Note 11 in Part II, Item 8. of this Annual Report 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.

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 43, 20222023, our credit ratings for our senior unsecured notes (including those issued by Boardwalk Pipelines) and that of our operating subsidiariessubsidiary having outstanding rated debt were as follows:

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.

Maintenance capital expenditures for the years ended December 31, 2022, 2021, and 2020 and 2019 werewere $157.4 million, $154.3 million, and $148.8 million and $138.7 million. Growth capital expenditures were $174.9 million, $270.6 million and $277.7 million for the years ended December 31, 2022, 2021, and 2020 and 2019were $180.2 million, $174.9 million and $270.6 million. During the year ended December 31, 2022, we spent $6.7 million on natural gas to be used in our integrated natural gas pipeline system. During the year ended December 31, 2021, we acquired certain natural gas pipeline assets in the Lake Charles, Louisiana, area for approximately $20.0 million in cash. During the year ended December 31, 2020, we purchased the remaining undivided interest in the Bistineau storage facility that we did not previously own for $18.8 million. In 2021 and 2019, we purchased $6.8 million and $12.6 million of natural gas to be used as base gas for our integrated natural gas pipeline system.

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 accordanceconformity with accounting principles generally accepted in the U.S. requires us to make estimates and judgmentsassumptions 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 amountamounts of assets and liabilities that are not readily apparent from other sources. We review our estimates and judgmentsassumptions 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.

Goodwill represents the excess of the cost of an acquisition over the fair value of the net identifiable assets acquired and liabilities assumed. Goodwill is tested for impairment at the reporting unit level at least annually, as of November 30, or more frequently when events occur and circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Accounting requirements provide that a reporting entity may perform an optional qualitative assessment on an annual basis to determine whether events occurred or circumstances changed that would more likely than not reduce the fair value of a reporting unit below its carrying amount. If an initial qualitative assessment identifies that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, or the optional qualitative assessment is not performed, a quantitative analysis is performed. The quantitative goodwill impairment test is performed by calculating the fair value of the reporting unit and comparing it to the reporting unit's carrying amount. If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is not impaired. However, if the carrying amount of a reporting unit exceeds its fair value, an impairment loss is recognized in an amount equal to that excess, limited to the total amount of goodwill recorded on the reporting unit.

As of November 30, 2021, we elected to perform2022, 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 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, including operating revenues, the long-term outlook for growth in natural gas and NGLs demand, measures of the risk-free rate, equity premium and systematic risk used in the calculation of the

The results of the quantitative goodwill impairment test for 2022 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. In 2022, the estimated fair values of the reporting units exceeded their carrying amounts by amounts that were similar to that indicated in 2020, the last time that a quantitative test was performed, with the excess of both reporting units being in the range of 10% - 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.

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

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. ForWe recognized asset impairment charges of $7.5 million for the year ended December 31, 2022, and immaterial asset impairment charges for the years ended December 31, 2021, 2020 and 2019,2020. we recognized immaterial amountsThe charges recorded in 2022 were primarily due to an increase in the estimate of existing asset retirement obligations related to asset impairment chargesretired assets.

Certain statements contained in this Annual Report on Form 10-K, as well as some statements in our other filings with the SEC and periodic press releases and some oral statements made by our officials and our subsidiaries during presentations about us, are “forward-looking.” Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance, intentions or achievements, and may contain the words “expect,” “intend,” “plan,” “anticipate,” “estimate,” “believe,” “will likely result” and similar expressions. In addition, any statement concerning future financial performance (including future revenues, earnings or growth rates), ongoing business strategies or prospects and possible actions by us or our subsidiaries, are also forward-looking statements.

Forward-looking statements are based on current expectations and projections about future events and their potential impact on us. While management believes that these forward-looking statements are reasonable as and when made, there is no assurance that future events affecting us will be those that we anticipate. All forward-looking statements are inherently subject to a variety of risks and uncertainties, many of which are beyond our control, which could cause actual results to differ materially from those anticipated or projected. These include, among others, the impacts of legislative and regulatory initiatives, or the implementation thereof, the impacts of climate change, ESG matters and pipeline safety requirements and initiatives, the costs of maintaining and ensuring the integrity and reliability of our pipeline systems, our ability to complete growth projects that we have commenced or will commence, the risk of a failure in our computer systems or cybersecurity attack, successful negotiation, consummation and completion of contemplated transactions, projects and agreements, risks and uncertainties related to the impacts of volatility in energy prices, and our exposure to credit risk relating to default or bankruptcy by our customers. Developments in any of these areas could cause our results to differ materially from results that have been or may be anticipated or projected. Forward-looking statements speak only as of the date they are made and we expressly disclaim any obligation or undertaking to update

As of December 31, 2022, 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 13.3 trillion British thermal units (TBtu). Assuming an average market price during December 2022 of $5.33 per million British thermal unit (MMBtu), the market value of that gas was approximately $70.9 million. As of December 31, 2021, the amount of gas owed to our operating subsidiaries due to gas imbalances and gas loaned under PAL and certain firm service agreements was approximately 7.4 trillion British thermal units (TBtu). Assuming an average market price during December 2021 of $3.59 per million British thermal unit (MMBtu), the market value of that gas was approximately $26.6 million. As of December 31, 2020, the amount of gas owed to our operating subsidiaries due to gas imbalances and gas loaned under PAL and certain firm service agreements was approximately 11.2 TBtu. Assuming an average market price during December 2020 of $2.45 per MMBtu, the market value of that gas at December 31, 2020, was approximately $27.4 million. As of December 31, 2021 and 20202022 and 2021, there were no outstanding NGL imbalances owed to our operating subsidiaries.

We have audited the accompanying consolidated balance sheets of Boardwalk Pipeline Partners, LP and subsidiaries (the "Company") as of December 31, 20212022 and 20202021, 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, 20212022, 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, 20212022 and 20202021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 20212022, in conformity with accounting principles generally accepted in the United States of America.

Goodwill is tested for impairment at the reporting unit level at least annually as of November 30, or more frequently when events occur and circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. As of November 30, 20212022, the Company elected to perform a qualitative assessmentquantitative analysis for its annual goodwill impairment test of its two reporting units. The qualitative assessment included the Company’s consideration of, among other things, the overall macroeconomic conditions, industry and market considerations, current discount rates and valuation multiples, overall financial performance, including operating revenue, and other relevant company specific events. Based on this assessment of these items, the Company concluded that it is more likely than not that the fair value of to measure whether the fair value of either of the two reporting units exceededis less than their respective carrying amounts. AsIf the carrying amount of December 31, 2021,a reporting unit exceeds its fair value, an impairment loss is recognized in an amount equal to that excess, limited to the Company hadtotal amount of goodwill recorded on its Consolidated Balance Sheets $237.4 million of goodwillthe reporting unit.

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 its assessment of operating revenues and current discount rates, including the need to involve fair value specialists, in determining whether it was more likely than not that the fair value ofthe applied discount rate, the long-term outlook for growth in natural gas and NGLs demand, and the Company’s reporting units was less than their respective carrying amounts.future estimated operating revenues within the five-year financial plan operating results.


	December 31,
ASSETS	2022		2021
Current Assets:
Cash and cash equivalents	$	215.6	$	39.1
Receivables:
Trade, net	148.4		126.2
Other	25.4		31.4
Gas transportation receivables	22.0		8.0
Gas stored underground	41.6		26.1

Prepayments	23.7		21.4
Other current assets	8.7		7.1
Total current assets	485.4		259.3

Property, Plant and Equipment:
Natural gas transmission and other plant	12,616.7		12,248.6
Construction work in progress	187.6		239.5
Property, plant and equipment, gross	12,804.3		12,488.1
Less—accumulated depreciation and amortization	4,288.3		3,947.0
Property, plant and equipment, net	8,516.0		8,541.1

Other Assets:
Goodwill	237.4		237.4
Gas stored underground	153.5		114.0
Other	177.6		179.6
Total other assets	568.5		531.0

Total Assets	$	9,569.9	$	9,331.4


	December 31,
LIABILITIES AND PARTNERS' CAPITAL	2022		2021
Current Liabilities:
Payables:
Trade	$	70.7	$	31.1
Affiliates	2.6		1.7
Other	17.4		20.3
Gas transportation payables	41.2		20.0
Accrued taxes, other	62.8		65.8
Accrued interest	33.9		32.7
Accrued payroll and employee benefits	38.3		37.4
Construction retainage	12.0		16.6
Regulatory liabilities	55.1		12.7

Other current liabilities	38.7		21.4
Total current liabilities	372.7		259.7

Long-term debt and finance lease obligation	3,233.4		3,334.5

Other Liabilities and Deferred Credits:
Pension liability	8.8		5.6
Asset retirement obligations	53.9		61.5
Provision for other asset retirement	93.2		88.2

Other	105.7		112.8
Total other liabilities and deferred credits	261.6		268.1

Commitments and Contingencies

Partners' Capital:
Partners' capital	5,781.7		5,541.7
Accumulated other comprehensive loss	(79.5)		(72.6)
Total partners' capital	5,702.2		5,469.1
Total Liabilities and Partners' Capital	$	9,569.9	$	9,331.4


	For the Year Ended December 31,
	2022		2021		2020
Operating Revenues:
Transportation	$	1,228.8	$	1,152.6	$	1,117.9
Storage, parking and lending	129.2		110.4		110.5
Other	74.0		77.1		69.2
Total operating revenues	1,432.0		1,340.1		1,297.6
Operating Costs and Expenses:
Fuel and transportation	23.4		22.1		18.3
Operation and maintenance	250.9		226.9		212.3
Administrative and general	147.7		144.6		139.9
Depreciation and amortization	392.3		366.3		358.8
Loss (gain) on sale of assets, impairments and other	4.0		(0.1)		0.9
Taxes other than income taxes	114.5		113.2		112.8
Total operating costs and expenses	932.8		873.0		843.0

Operating income	499.2		467.1		454.6
Other Deductions (Income):
Interest expense	165.9		160.8		169.7
Interest income	(3.3)		—		—
Miscellaneous other income, net	(6.4)		(9.4)		(5.9)
Total other deductions	156.2		151.4		163.8
Income before income taxes	343.0		315.7		290.8
Income taxes	0.8		0.7		0.3
Net income	$	342.2	$	315.0	$	290.5

(Millions)


	For the Year Ended December 31,
	2022		2021		2020
OPERATING ACTIVITIES:
Net income	$	342.2	$	315.0	$	290.5
Adjustments to reconcile net income to cash provided by operations:
Depreciation and amortization	392.3		366.3		358.8
Amortization of deferred costs and other	4.0		9.0		12.4
Loss (gain) on sale of assets, impairments and other	4.0		(0.1)		0.9
Changes in operating assets and liabilities:
Trade and other receivables	(16.7)		(19.1)		(6.1)

Gas transportation receivables and storage assets	(63.4)		(32.8)		(9.0)

Prepayments and other assets	(9.8)		(2.7)		(4.5)
Trade and other payables	15.6		1.1		(10.6)
Other payables, affiliates	(0.2)		—		—
Gas transportation payables	21.0		9.3		1.4
Accrued liabilities	(0.9)		(1.3)		4.7
Regulatory assets and liabilities	49.3		(4.1)		4.8
Other liabilities	(10.6)		(11.3)		(2.1)
Net cash provided by operating activities	726.8		629.3		641.2
INVESTING ACTIVITIES:
Capital expenditures	(344.3)		(349.2)		(438.2)
Proceeds from sale of operating assets	1.5		1.7		3.8




Net cash used in investing activities	(342.8)		(347.5)		(434.4)
FINANCING ACTIVITIES:
Proceeds from long-term debt, net of issuance cost	495.0		—		495.0
Repayment of borrowings from long-term debt	(600.0)		—		(440.0)
Proceeds from borrowings on revolving credit facility	—		150.0		687.9
Repayment of borrowings on revolving credit facility, including financing fees	(0.6)		(284.4)		(852.9)
Principal payment of finance lease obligation	(0.8)		(0.8)		(0.7)
Advances from affiliates	1.1		(8.2)		5.3
Distributions paid	(102.2)		(102.2)		(102.2)
Net cash used in financing activities	(207.5)		(245.6)		(207.6)
Increase (decrease) in cash and cash equivalents	176.5		36.2		(0.8)
Cash and cash equivalents at beginning of period	39.1		2.9		3.7
Cash and cash equivalents at end of period	$	215.6	$	39.1	$	2.9

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Commission file number:		01-32665
BOARDWALK PIPELINE PARTNERS, LP
(Exact name of registrant as specified in its charter)
Delaware		20-3265614
(State or other jurisdiction of incorporation or organization)		(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	Trading Symbol(s)	Name of each exchange on which registered
NONE	NONE	NONE

Securities registered pursuant to section 12(g) of the Act: NONE



Total projected operating revenues under committed firm agreements as of December 31, 2021	$	9,060.0
Adjustments for:
Actual revenues recognized from firm agreements in 2022(1)	(1,236.0)
Firm agreements entered into in 2022	1,300.5
Total projected operating revenues under committed firm agreements as of December 31, 2022	$	9,124.5


	As of December 31, 2022
Principal amounts guaranteed by Boardwalk Pipeline Partners (1)	$	3,150.0
Principal amounts not guaranteed (2)	100.0
Other (3)	(16.6)
Total debt and finance lease obligation	$	3,233.4


	2022			2021
Carrying amount of fixed-rate debt	$	3,234.0		$	3,334.0
Fair value of fixed-rate debt	$	3,041.4		$	3,631.5
100 basis point increase in interest rates and resulting debt decrease	$	134.1		$	151.5
100 basis point decrease in interest rates and resulting debt increase	$	143.1		$	160.4
Weighted-average interest rate	4.84		%	4.84		%


PART I			4
Item 1. Business			4
Item 1A. Risk Factors			12
Item 1B. Unresolved Staff Comments			23
Item 2. Properties			23
Item 3. Legal Proceedings			23
Item 4. Mine Safety Disclosures			23
PART II			23
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			23
Item 6. Reserved			23
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations			24
Item 7A. Quantitative and Qualitative Disclosures About Market Risk			31
Item 8. Financial Statements and Supplementary Data			32
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			66
Item 9A. Controls and Procedures			66
Item 9B. Other Information			66
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections			66
PART III			67
Item 10. Directors, Executive Officers and Corporate Governance			67
Item 11. Executive Compensation			67
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			67
Item 13. Certain Relationships and Related Transactions, and Director Independence			67
Item 14. Principal Accountant Fees and Services			67
PART IV			68
Item 15. Exhibit and Financial Statement Schedules			68
Item 16. Form 10-K Summary			71


Pipeline and Storage Systems	Miles of Pipeline	Working Gas Storage Capacity (Bcf)	Liquids Storage Capacity (MMBbls)	Peak-day Delivery Capacity (Bcf/d) (1)	Average Daily Throughput (Bcf/d) (1)
Gulf South	7,260	121.1	—	10.9	5.8
Texas Gas	5,975	84.3	—	6.1	3.4
Louisiana Midstream	465	7.6	32.3	—	—


	Partners' Capital		Accumulated Other Comprehensive Income (Loss)		Total Partners' Capital
Balance December 31, 2019	$	5,140.6	$	(81.1)	$	5,059.5
Add (deduct):
Net income	290.5		—		290.5
Distributions paid	(102.2)		—		(102.2)
Other comprehensive income, net of tax	—		1.3		1.3
Balance December 31, 2020	$	5,328.9	$	(79.8)	$	5,249.1
Add (deduct):
Net income	315.0		—		315.0
Distributions paid	(102.2)		—		(102.2)
Other comprehensive income, net of tax	—		7.2		7.2
Balance December 31, 2021	$	5,541.7	$	(72.6)	$	5,469.1
Add (deduct):
Net income	342.2		—		342.2
Distributions paid	(102.2)		—		(102.2)
Other comprehensive loss, net of tax	—		(6.9)		(6.9)
Balance December 31, 2022	$	5,781.7	$	(79.5)	$	5,702.2


	For the Year Ended December 31,
	2022		2021		2020
Capitalized interest and allowance for borrowed funds used during construction	$	2.2	$	3.8	$	6.1
Allowance for equity funds used during construction	6.2		7.9		4.1


	Contract Liabilities
Balance as of December 31, 2021(1)	$	19.2
Revenues recognized that were included in the contract liability balances at the beginning of the period	(5.1)
Increases due to cash received, excluding amounts recognized as revenues during the period	8.9
Balance as of December 31, 2022(1)	$	23.0


	Contract Liabilities
Balance as of December 31, 2020(1)	$	17.2
Revenues recognized that were included in the contract liability balances at the beginning of the period	(5.3)
Increases due to cash received, excluding amounts recognized as revenues during the period	7.3
Balance as of December 31, 2021(1)	$	19.2


	In millions
	2023		2024		Thereafter		Total

Estimated revenues from contracts with customers from unsatisfied performance obligations as of December 31, 2022	$	1,254.5	$	1,125.5	$	6,533.5	$	8,913.5
Operating revenues which are fixed and determinable (operating leases)	25.5		25.5		160.0		211.0
Total projected operating revenues under committed firm agreements as of December 31, 2022	$	1,280.0	$	1,151.0	$	6,693.5	$	9,124.5


	As of December 31,
	2022			2021
Right-of-use assets (in millions)
Operating leases (recorded in Other Assets)	$	18.7		$	21.6
Finance lease (recorded in Property, Plant and Equipment)		4.0			4.7
Lease liabilities (in millions)
Operating leases (recorded in Other Liabilities, current and non-current)		20.6			23.5
Finance lease		5.4			6.1
Weighted-average remaining lease term (years)
Operating leases		10.4			10.8
Finance lease		5.6			6.6
Weighted-average discount rate
Operating leases		2.86	%		2.94	%
Finance lease		5.89	%		5.89	%


	As of December 31, 2022
	Operating Leases		Finance Lease
2023	$	3.9	$	1.1
2024	2.5		1.1
2025	2.3		1.1
2026	1.4		1.1
2027	1.1		1.2
Thereafter	12.5		0.7
Total	23.7		6.3
Less: discount	(3.1)		(0.9)
Total lease liabilities	$	20.6	$	5.4


As of December 31, 2022				Estimated Fair Value
Financial Assets	Carrying Amount			Level 1		Level 2		Level 3		Total
Cash and cash equivalents	$	215.6		$	215.6	$	—	$	—	$	215.6

Financial Liabilities
Long-term debt	$	3,234.0	(1)	$	—	$	3,041.4	$	—	$	3,041.4


2023	$	1.9
2024	2.0
2025	2.0
2026	2.0
2027	1.9
Thereafter	30.5
Total	$	40.3


As of December 31, 2021				Estimated Fair Value
Financial Assets	Carrying Amount			Level 1		Level 2		Level 3		Total
Cash and cash equivalents	$	39.1		$	39.1	$	—	$	—	$	39.1

Financial Liabilities
Long-term debt	$	3,334.0	(1)	$	—	$	3,631.5	$	—	$	3,631.5


Category	2022 Amount		Weighted-Average Useful Lives (Years)	2021 Amount		Weighted-Average Useful Lives (Years)
Depreciable plant:
Transmission	$	10,913.0	38	$	10,672.7	37
Storage	921.9		38	886.5		38
Gathering	111.1		24	109.6		23
General, intangibles and other	473.0		21	382.3		27
Total utility depreciable plant	12,419.0		37	12,051.1		37

Non-depreciable:
Construction work in progress	187.6			239.5
Storage	151.6			152.3
Land	46.1			45.2
Total non-depreciable assets	385.3			437.0

Total PPE	12,804.3			12,488.1
Less: accumulated depreciation and amortization	4,288.3			3,947.0

Total PPE, net	$	8,516.0		$	8,541.1


	2022				2021
	Gross PPE Investment		Accumulated Depreciation		Gross PPE Investment		Accumulated Depreciation
Mobile Bay Pipeline	$	15.4	$	7.9	$	14.6	$	7.5
NGLs pipelines and facilities	54.4		12.0		51.3		10.4
Offshore and other assets	13.0		10.6		12.8		10.4
Total	$	82.8	$	30.5	$	78.7	$	28.3


Regulatory Liabilities:
Cashout and fuel tracker	$	55.1	$	12.7
Provision for other asset retirement	93.2		88.2
Unamortized debt issuance costs	(1.2)		(1.5)
Unamortized discount on long-term debt	(0.1)		(0.2)
Postretirement benefits other than pension	59.0		64.7
Total regulatory liabilities	$	206.0	$	163.9


	2022		2021
Notes and Debentures:

Boardwalk Pipelines
3.375% Notes due 2023 (Boardwalk Pipelines 2023 Notes)	$	—	$	300.0
4.95% Notes due 2024	600.0		600.0
5.95% Notes due 2026	550.0		550.0
4.45% Notes due 2027	500.0		500.0
4.80% Notes due 2029	500.0		500.0
3.40% Notes due 2031	500.0		500.0
3.60% Notes due 2032	500.0		—

Gulf South
4.00% Notes due 2022 (Gulf South 2022 Notes)	—		300.0

Texas Gas
7.25% Debentures due 2027	100.0		100.0
Total notes and debentures	3,250.0		3,350.0






Finance lease obligation	4.5		5.3
	3,254.5		3,355.3
Less:
Unamortized debt discount	(16.0)		(16.0)
Unamortized debt issuance costs	(5.1)		(4.8)
Total Long-Term Debt and Finance Lease Obligation	$	3,233.4	$	3,334.5


Date of Issuance	Issuing Subsidiary	Amount of Issuance		Purchaser Discounts and Expenses		Net Proceeds			Interest Rate		Maturity Date	Interest Payable
February 2022	Boardwalk Pipelines	$	500.0	$	5.0	$	495.0	(1)	3.60	%	September 1, 2032	March 1 and September 1
August 2020	Boardwalk Pipelines	$	500.0	$	5.0	$	495.0	(2)	3.40	%	February 15, 2031	February 15 and August 15


	Retirement Plans				PBOP
	For the Year Ended December 31,				For the Year Ended December 31,
	2022		2021		2022		2021
Change in benefit obligation:
Benefit obligation at beginning of period	$	109.1	$	120.7	$	30.6	$	35.2
Service cost	2.2		2.6		—		0.1
Interest cost	3.1		2.1		0.8		0.9
Plan participants' contributions	—		—		1.0		1.1
Actuarial gain	(7.9)		(1.4)		(4.4)		(2.6)
Benefits paid	(0.5)		(0.5)		(4.3)		(4.1)
Settlements	(19.6)		(14.4)		—		—
Benefit obligation at end of period	$	86.4	$	109.1	$	23.7	$	30.6

Change in plan assets:
Fair value of plan assets at beginning of period	$	103.5	$	102.7	$	93.0	$	96.2
Actual return on plan assets	(13.2)		10.5		(8.6)		(0.3)
Company's contribution	7.4		5.2		0.2		0.1
Plan participants' contributions	—		—		0.9		1.1
Benefits paid	(0.5)		(0.5)		(4.3)		(4.1)
Settlements	(19.6)		(14.4)		—		—
Fair value of plan assets at end of period	$	77.6	$	103.5	$	81.2	$	93.0

Funded status	$	(8.8)	$	(5.6)	$	57.5	$	62.4

Items not recognized as components of net periodic cost:

Net actuarial loss (gain)	$	16.9	$	10.0	$	3.2	$	(2.9)


	Pension Plan Trust Assets
	Level 1		Level 2		Level 3		Total
Equity securities	$	17.5	$	—	$	—	$	17.5
Short-term investments	28.3		—		—		28.3
Fixed income mutual funds	31.8		—		—		31.8
Total assets	$	77.6	$	—	$	—	$	77.6


	Master Trust Assets
	Measured under Fair Value Hierarchy								Measured at Net Asset Value		Total Master Trust Assets
	Level 1		Level 2		Level 3		Total
Equity securities	$	69.1	$	—	$	—	$	69.1	$	—	$	69.1
Short-term investments	1.9		—		—		1.9		—		1.9
Other assets	2.2		—		—		2.2		—		2.2
Fixed income mutual funds	111.3		—		—		111.3		—		111.3

Total assets measured at fair value	184.5		—		—		184.5		—		184.5
Total limited partnerships measured at net asset value	—		—		—		—		54.9		54.9
Total	$	184.5	$	—	$	—	$	184.5	$	54.9	$	239.4


	PBOP Trust Assets
	Level 1		Level 2		Level 3		Total
Short-term investments	$	2.2	$	—	$	—	$	2.2
Other assets	1.8		—		—		1.8
Asset-backed securities	—		0.9		—		0.9
Corporate bonds	—		54.9		—		54.9
Tax exempt securities	—		34.4		—		34.4
Total assets	$	4.0	$	90.2	$	—	$	94.2

Other liabilities	(13.0)		—		—		(13.0)
Total liabilities	$	(13.0)	$	—	$	—	$	(13.0)


	2022		2021
Audit fees (1)	$	2.7	$	2.6
Audit related fees (2)	0.1		0.1
Total	$	2.8	$	2.7


Exhibit Number						Description

3.1						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).
3.2						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).
4.1						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).
4.2						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).
4.3						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).
4.4						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).
4.5						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).
4.6						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).
4.7						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).
4.8						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).
4.9						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).
4.10						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).
4.11						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).


Exhibit Number						Description
4.12						Ninth 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 February 17, 2022).
10.1						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). (1)
10.2						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).
10.3						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).
10.4						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).
10.5						Master Assignment and Amendment No. 3 to Third Amended and Restated Revolving Credit Agreement, dated as of May 27, 2021, among Boardwalk Pipelines, LP, Texas Gas Transmission, LLC and Gulf South Pipeline Company, LLC, as borrowers, Boardwalk Pipeline Partners, LP, as guarantor, the several lenders and issuers party thereto, and Wells Fargo Bank, N.A., as administrative agent (Incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on May 27, 2021).
10.6						Agreement and Amendment No. 4 to Third Amended and Restated Revolving Credit Agreement, dated as of June 30, 2022, among Boardwalk Pipelines, LP, Texas Gas Transmission, LLC and Gulf South Pipeline Company, LLC, as borrowers, Boardwalk Pipeline Partners, LP, as guarantor, the several lenders and issuers party thereto, and Wells Fargo Bank, N.A., as administrative agent (Incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on July 5, 2022).
*22.1						Subsidiary Issuers and Guarantors of Registered Securities.
*23.1						Consent of Independent Registered Public Accounting Firm.
*31.1						Certification of Stanley C. Horton, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a).
*31.2						Certification of Steven A. Barkauskas , Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a).


Exhibit Number						Description
**32.1						Certification of Stanley C. Horton, Chief Executive Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
**32.2						Certification of Steven A. Barkauskas , Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*101.INS						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.
*101.SCH						Inline XBRL Taxonomy Extension Schema Document
*101.CAL						Inline XBRL Taxonomy Calculation Linkbase Document
*101.DEF						Inline XBRL Taxonomy Extension Definitions Document
*101.LAB						Inline XBRL Taxonomy Label Linkbase Document
*101.PRE						Inline XBRL Taxonomy Presentation Linkbase Document
*104						Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
* Filed herewith ** Furnished herewith


		Boardwalk Pipeline Partners, LP
		By: Boardwalk GP, LP
		its general partner
		By: Boardwalk GP, LLC
		its general partner
Dated:	February 87, 20222023	By:	/s/ JamieSteven LA. BuskillBarkauskas
			JamieSteven LA. BuskillBarkauskas
			Senior Vice President, Chief Financial and AdministrativeInformation Officer, Treasurer and Director


Dated:	February 87, 20222023	/s/ Stanley C. Horton
		Stanley C. Horton President, Chief Executive Officer and Director (principal executive officer)
Dated:	February 87, 20222023	/s/ JamieSteven LA. BuskillBarkauskas
		JamieSteven LA. BuskillBarkauskas Senior Vice President, Chief Financial and AdministrativeInformation Officer, Treasurer and Director (principal financial officer)
Dated:	February 87, 20222023	/s/ Steven A. BarkauskasChristine Fernandez
		Steven A. BarkauskasChristine Fernandez Senior Vice President, Controller and Chief Accounting and Information Officer (principal accounting officer)
Dated:	February 87, 20222023	/s/ Michael E. McMahon
		Michael E. McMahon Senior Vice President, General Counsel, Secretary and Director
Dated:	February 87, 20222023	/s/ Kenneth I. Siegel
		Kenneth I. Siegel Director, Chairman of the Board
Dated:	February 87, 20222023	/s/ Benjamin J. Tisch
		Benjamin J. Tisch Director
Dated:	February 87, 20222023	/s/ Jane Wang
		Jane Wang Director


Subsidiary Issuer			Guarantor
Boardwalk Pipelines, LP 3.375% Notes due 2023			Boardwalk Pipeline Partners, LP
Boardwalk Pipelines, LP 4.95% Notes due 2024			Boardwalk Pipeline Partners, LP
Boardwalk Pipelines, LP 5.95% Notes due 2026			Boardwalk Pipeline Partners, LP
Boardwalk Pipelines, LP 4.45% Notes due 2027			Boardwalk Pipeline Partners, LP
Boardwalk Pipelines, LP 4.80% Notes due 2029			Boardwalk Pipeline Partners, LP
Boardwalk Pipelines, LP 3.40% Notes due 2031			Boardwalk Pipeline Partners, LP
Boardwalk Pipelines, LP 3.60% Notes due 2032			Boardwalk Pipeline Partners, LP