Boardwalk Pipeline Partners, LP

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
 FORM 10-K
 (Mark One)
☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2024
OR
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _______________ to _______________
Commission file number: 01-32665
BOARDWALK PIPELINE PARTNERS, LP
(Exact name of registrant as specified in its charter)
Delaware
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
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes☒ No☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes ☐ No ☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90
days.    Yes ☒    No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T
(§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging
growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the
Exchange Act.
    Large accelerated filer ☐ Accelerated filer ☐ Non-accelerated filer ☒ Smaller reporting company ☐
Emerging growth company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised
financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over
financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit
report.    ☐
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the
correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the
registrant's executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes ☐ No ☒
Boardwalk Pipeline Partners, LP meets the conditions set forth in General Instructions I(1) (a) and (b) of Form 10-K and is therefore filing this form with the
reduced disclosure format.
Documents incorporated by reference.    None.

2024 FORM 10-K
BOARDWALK PIPELINE PARTNERS, LP
TABLE OF CONTENTS
PART I
4
Item 1. Business
4
Item 1A. Risk Factors
14
Item 1B. Unresolved Staff Comments
25
Item 1C. Cybersecurity
25
Item 2. Properties
26
Item 3. Legal Proceedings
26
Item 4. Mine Safety Disclosures
26
PART II
27
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
27
Item 6. Reserved
27
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
28
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
38
Item 8. Financial Statements and Supplementary Data
39
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
79
Item 9A. Controls and Procedures
79
Item 9B. Other Information
79
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
79
PART III
80
Item 10. Directors, Executive Officers and Corporate Governance
80
Item 11. Executive Compensation
80
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
80
Item 13. Certain Relationships and Related Transactions, and Director Independence
80
Item 14. Principal Accountant Fees and Services
80
PART IV
81
Item 15. Exhibit and Financial Statement Schedules
81
Item 16. Form 10-K Summary
84
3

PART I
Item 1. Business
Unless the context otherwise requires, references in this Annual Report on Form 10-K to "we," "our," "us" or like terms refer to the business of Boardwalk
Pipeline Partners, LP and its consolidated subsidiaries.
Introduction
We are a Delaware limited partnership formed in 2005. Our business, which is conducted by our primary subsidiary, Boardwalk Pipelines, LP (Boardwalk
Pipelines) and its operating subsidiaries (together, the operating subsidiaries), consists of integrated pipeline and storage systems for natural gas and natural gas liquids,
olefins and other hydrocarbons (herein referred to together as NGLs). All of our operations are conducted by the operating subsidiaries of Boardwalk Pipelines. As of
December 31, 2024, Boardwalk Pipelines Holding Corp. (BPHC), a wholly owned subsidiary of Loews Corporation (Loews), owned directly or indirectly, 100% of our
capital.
Our Business
We operate in the midstream portion of the natural gas and NGLs industry, providing transportation and storage for those commodities. We also provide ethane
supply and transportation services for industrial customers in Louisiana and Texas. We own approximately 14,315 miles of natural gas and NGLs pipelines and
underground storage caverns having aggregate capacity of approximately 199.5 billion cubic feet (Bcf) of working natural gas and 31.2 million barrels (MMBbls) of
NGLs. Our integrated natural gas pipeline and storage systems are located in the Gulf Coast region, Oklahoma, Arkansas, Tennessee, Kentucky, Illinois, Indiana and
Ohio, and our NGLs pipelines and storage facilities are located in Louisiana and Texas.
We serve a broad mix of customers, including electric power generators, producers and marketers of natural gas, local distribution companies (LDCs),
industrial users, exporters of liquefied natural gas (LNG), and interstate and intrastate pipelines. We provide a significant portion of our natural gas pipeline
transportation and storage services through firm contracts under which our customers pay monthly capacity reservation fees, which are fixed fees based on the quantity
of capacity reserved, regardless of use. Other fees are based on actual utilization of the capacity under firm contracts and contracts for interruptible services. Contracts
for our NGLs services are generally fee-based or contain a minimum volume commitment (MVC), while others are dependent on actual volumes transported, stored or
delivered. For the year ended December 31, 2024, approximately 86% of our revenues were derived from capacity reservation fees under firm contracts or from
contracts with MVCs, approximately 5% of our revenues were derived from fees based on utilization under firm contracts and approximately 9% of our revenues were
derived from interruptible transportation, interruptible storage, parking and lending (PAL), ethane supply and other services.
   
The maximum applicable 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
FERC also has jurisdiction over the rates, charges and terms and conditions of service for transportation on our interstate ethane pipeline. The Surface Transportation
Board (STB) regulates the rates we charge for interstate service on our ethylene pipeline systems. The Louisiana Public Service Commission (LPSC) regulates the rates
we charge for intrastate service within the state of Louisiana on our NGLs pipelines. The STB and LPSC require that our transportation rates are reasonable and that our
practices cannot unreasonably discriminate among our shippers.
Business Segments
In the fourth quarter 2024, we identified and began reporting in two segments - Natural Gas and Natural Gas Liquids. The following contains a detailed
discussion of each of our segments.
Natural Gas
Our Natural Gas segment, which provides transportation, storage and PAL services for natural gas customers, consists of integrated interstate and intrastate
natural gas pipelines and storage facilities. We own and operate approximately 13,445 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
4

pipelines. In 2024, our natural gas pipeline systems transported approximately 3.7 trillion cubic feet of natural gas. Average daily throughput on our natural gas pipeline
systems during 2024 was approximately 10.2 Bcf. Our natural gas storage facilities are comprised of fourteen underground storage fields located in four states with
aggregate working gas capacity of approximately 191.9 Bcf.
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.
Following is a summary of the primary subsidiaries comprising our Natural Gas segment:
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, electric power generators, 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 those located in the Baton Rouge to New Orleans industrial corridor
and Lake Charles, Louisiana. Gulf South also has indirect access to off-system markets through numerous interconnections with unaffiliated interstate and intrastate
pipelines and storage facilities. These pipeline interconnections provide access to markets throughout the northeastern, midwestern and southeastern U.S.
Gulf South has ten natural gas storage facilities. The two natural gas storage facilities located in Bistineau, Louisiana, and Jackson, Mississippi, have
approximately 78.0 Bcf of working gas storage capacity from which Gulf South offers firm and interruptible storage service, including no-notice service (NNS), and are
used to support pipeline operations. Gulf South also owns and operates eight high deliverability salt-dome natural gas storage caverns in Forrest County, Mississippi,
having approximately 46.0 Bcf of total storage capacity, of which approximately 29.6 Bcf is working gas capacity, and owns undeveloped land which is suitable for up
to five additional storage caverns. Gulf South is regulated by the FERC.
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 electric power
generators in its market area, which encompasses seven states in the South and Midwest and includes the Memphis, Tennessee; Louisville, Kentucky; Cincinnati and
Dayton, Ohio; and Evansville and Indianapolis, Indiana, metropolitan areas. Texas Gas also has indirect market access to, and receives supply from, the Northeast
through interconnections with unaffiliated pipelines. A large portion of the gas delivered by the Texas Gas system is used for heating during the winter months, but
Texas Gas also supplies gas for cooling needs during the summer months.
Texas Gas owns nine natural gas storage fields, of which it owns the majority of the working and base gas. Texas Gas uses this gas to meet the operational
requirements of its transportation and storage customers and the requirements of its NNS customers. Texas Gas also uses its storage capacity to offer firm and
interruptible storage services. Texas Gas is regulated by the FERC.
Other: We have minor intrastate and Hinshaw pipeline assets in South Texas and the Lake Charles area serving end-use, electric power generators and
industrial customers.
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The following table provides information for our Natural Gas segment assets we own and operate as of December 31, 2024:
Assets
Miles of Pipeline
Average Daily
Throughput
(Bcf/d) 
Peak-day
Delivery
Capacity (Bcf/d)
Working Gas
Storage Capacity
(Bcf)
Gulf South
7,180 
6.8 
10.9 
107.6 
Texas Gas
6,000 
3.3 
6.3 
84.3 
Other Natural Gas
265 
0.1 
— 
— 
(1) Bcf per day (Bcf/d)
Natural Gas Liquids
Our Natural Gas Liquids segment, which provides transportation and storage services for NGLs and supply services for ethane and brine customers, consists
primarily of NGLs pipelines, salt-dome storage facilities and brine infrastructure. We own and operate approximately 870 miles of NGLs pipelines in Louisiana and
Texas. In 2024, our Natural Gas Liquids pipeline systems transported approximately 136.6 MMBbls of NGLs. Our NGLs storage facilities consist of eleven salt-dome
caverns located in Louisiana with an aggregate storage capacity of approximately 31.2 MMBbls. We also own ten salt-dome caverns and related brine infrastructure
located in Louisiana for use in providing brine supply services and to support the NGLs storage operations. 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 access ethylene supplies at Port Neches, Texas, which we deliver to petrochemical-industry customers in Louisiana. We purchase ethane at Mont
Belvieu, Texas, and various locations in Louisiana and utilize our NGLs pipelines to supply ethane to customers in Texas and Louisiana. The majority of our Natural
Gas Liquids segment's customers are industrial end-users.
Following is a summary of the primary subsidiaries comprising our Natural Gas Liquids segment:
Boardwalk Louisiana Midstream, LLC (Louisiana Midstream): Louisiana Midstream provides transportation and storage services for NGLs, primarily
ethylene, 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 have approximately 47.8 MMBbls of salt-dome storage capacity, including approximately 7.6
Bcf of working natural gas storage capacity; significant brine supply infrastructure; and approximately 310 miles of pipeline assets, including an extensive ethylene
distribution system. 
Louisiana Midstream's Choctaw pipeline network is a common carrier pipeline system situated along the Mississippi River Corridor that serves chemical
complexes throughout southeastern Louisiana and provides connectivity to producers and consumers of ethylene. Through interconnections with Boardwalk
Petrochemical Pipeline, LLC’s (Boardwalk Petrochemical) Evangeline Pipeline and other third-party pipelines, the system links ethylene producers in Texas and the
Lake Charles area to the Mississippi River Corridor. Louisiana Midstream offers storage services for ethylene, ethane, propylene and ethane-propane mix at the
Choctaw Hub, and has the ability to modify its existing product storage configuration to meet market demand. Louisiana Midstream also owns eight salt-dome caverns
and related brine infrastructure located on the Choctaw Hub for use in providing brine supply services and supporting its NGLs storage operations. The Choctaw Hub,
through Louisiana Midstream’s ownership of Boardwalk Storage Company, LLC, is also the owner and operator of the Choctaw Natural Gas Storage cavern.
Louisiana Midstream's Sulphur pipeline network is located near Lake Charles, Louisiana, and is connected to local ethylene producers and consumers and area
refineries. Its pipeline infrastructure supports local industry by connecting their facilities to Louisiana Midstream's Sulphur Hub storage terminal as well as the
Boardwalk Petrochemical pipeline. At the Sulphur Hub, Louisiana Midstream owns and operates five active storage caverns, which are currently in ethylene, ethane and
propane service.
(1)
6

Boardwalk Petrochemical: Boardwalk Petrochemical owns and operates the Evangeline Pipeline, an approximately 180-mile bi-directional, common carrier,
interstate ethylene pipeline that is capable of transporting approximately 4.8 billion pounds of ethylene per year between Port Neches, Texas, and Baton Rouge,
Louisiana, and interconnects with the ethylene distribution system and storage facilities at Louisiana Midstream's Sulphur and Choctaw Hubs. The Evangeline Pipeline
links ethylene producers and consumers from Port Neches, Texas, to the Mississippi River Corridor, near Baton Rouge, Louisiana.
Boardwalk Ethane Pipeline Company, LLC (Bayou Ethane): Bayou Ethane owns and operates the Bayou Ethane Pipeline, an approximately 380-mile pipeline
system originating in Mont Belvieu, Texas, that transports ethane to Southeast Texas and to the Mississippi River corridor in Louisiana. The Bayou Ethane Pipeline
provides common carrier, interstate and intrastate transportation services and interconnects with Louisiana Midstream's storage facilities at the Sulphur and Choctaw
Hubs. The Bayou Ethane Pipeline has the ability to deliver approximately 55.0 MMBbls of ethane per year to customers in Texas and Louisiana. Bayou Ethane provides
ethane supply and transportation services for industrial customers in Louisiana and Texas. In providing ethane supply services, Bayou Ethane purchases ethane at Mont
Belvieu and various locations in Louisiana and utilizes its pipeline to deliver supply to its customers.
The following table provides information for our Natural Gas Liquids segment assets we own and operate as of December 31, 2024:
Assets
Miles of
Pipeline
Annual
Throughput
(MMBbls)
Working Gas
Storage Capacity
(Bcf)
Liquids Storage
Capacity
(MMBbls)
Louisiana Midstream
310 
60.2 
7.6 
31.2 
Boardwalk Petrochemical
180 
36.3 
— 
— 
Bayou Ethane
380 
40.1 
— 
— 
Current Growth Projects
In 2024, we placed into service approximately $245.0 million of growth projects, which represents approximately 0.4 Bcf/d of firm natural gas transportation
capacity, additional capacity on our ethylene pipeline systems and increased storage capacity and reliability. We expect to spend a total of approximately $1.6 billion on
our ongoing and announced growth projects, with expected in-service dates for these projects ranging from 2025-2029. These projects are expected to add over 2.0
Bcf/d of firm natural gas transportation capacity. These projects are expected to serve increased natural gas demand from electric power generation plants and industrial
customers. Our growth projects are secured by long-term firm contracts, though some are supported by executed precedent transportation agreements for projects that
are subject to regulatory approvals.
Refer to Liquidity and Capital Resources in Part II, Item 7. of this Annual Report on Form 10-K for further discussion of capital expenditures and financing.
Nature of Contracts
We contract with our customers to provide transportation, storage and ethane supply services on both a firm and interruptible basis. We also provide bundled
firm transportation and storage services, such as NNS, interruptible PAL services, brine supply services for certain petrochemical customers and fractionation services.
Transportation Services: We offer transportation services on both a firm and interruptible basis. Our customers choose, based upon their particular needs, the
applicable mix of services depending upon 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
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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 contain an MVC.
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 specific period of time. Customers pay for PAL services in advance or on a monthly
basis, depending on the terms of the agreement.
No-Notice Services: NNS consist of a combination of firm natural gas transportation and storage services that allow customers to inject or withdraw natural gas
from storage with little or no notice. Customers pay a reservation charge based upon the capacity reserved plus a commodity and a fuel charge based on the volume of
gas actually transported. In accordance with its tariff, Texas Gas loans stored gas to certain of its no-notice customers who are obligated to repay the gas in-kind.
Ethane Supply Services: We offer ethane supply services on a firm basis, typically with an MVC or a stated volume with any requested additional volumes
supplied based on availability. The pricing contained in the purchase and sales agreements associated with our ethane supply services is generally based on the same
ethane commodity index, plus a fixed delivery fee. As a result, except for possible timing differences that may occur when volumes are purchased in one month and sold
in another month, we have little to no direct commodity price exposure.
Other Product Sales: We occasionally sell natural gas, propane and ethylene based upon our available inventory for sale and market conditions.
Customers and Markets Served
We contract directly with end-use customers, including electric power generators, LDCs, industrial users and exporters of LNG. We also contract with other
customers, including producers and marketers of natural gas, and interstate and intrastate pipelines, who, in turn, provide transportation and storage services for end-
users. Excluding product sales, based upon our 2024 transportation, storage, PAL and other revenues, net of fuel, our customer mix was as follows: electric power
generators (22%), marketers (22%), natural gas producers (21%), LDCs (14%), industrial end-users (13%) and exporters of LNG (8%). Excluding product sales, based
upon our 2024 transportation, storage, PAL and other revenues, net of fuel, our deliveries were as follows: pipeline interconnects (32%), electric power generators
(17%), LDCs (15%), industrial end-users (15%), storage activities (12%), exporters of LNG (7%) and others (2%). Our deliveries related to our ethane supply services
were to industrial end-users. No customer comprised 10% or more of our operating revenues in 2024.
Electric Power Generators: Our natural gas pipelines are directly connected to 44 natural-gas-fired electric power generation facilities in eight states. The
demand of the power generating customers generally peaks during the summer cooling season, which is counter to the winter season peak demands of the LDCs,
although demand from electric power generators remains strong in the winter months as well, due to the overall increase in the use of natural gas over other sources,
such as coal, to generate electricity. Our electric power generating customers can use a combination of NNS, firm and interruptible transportation services.
Natural Gas Marketers: Natural gas marketing companies utilize our services to provide services to our other customer groups as well as to customer groups in
off-system markets. The services may include combined gas transportation and storage services to support the needs of other customer groups. Some of the marketers
are sponsored by LDCs or producers.
Natural Gas Producers: Producers of natural gas use our services to transport gas supplies from producing areas, including shale natural gas production areas,
to supply pools and other customers on and off of our systems. Producers contract with us for storage services to store excess production and to optimize the ultimate
sales prices for their gas.
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Local Distribution Companies: Most of our LDC customers use firm natural gas transportation services, including NNS. We serve 162 LDCs at more than 300
delivery locations across our pipeline systems. The demand of these customers peaks during the winter heating season.
Industrial End-Users: We provide approximately 210 industrial facilities with a combination of firm and interruptible natural gas and NGLs transportation,
storage and ethane supply services. Our pipeline systems are directly connected to industrial facilities in the Baton Rouge to New Orleans industrial corridor; Lake
Charles, Louisiana; Mont Belvieu, Texas; Mobile, Alabama; Ingleside, Texas; and Pensacola, Florida. We can also access the Houston Ship Channel through third-party
natural gas pipelines.
Exporters of LNG: LNG exporters use our natural gas firm transportation services to reach LNG liquefaction and export facilities. We provide 1.4 Bcf/d of firm
natural gas transportation service directly to the Freeport LNG liquefaction and export facility in Freeport, Texas.
Our natural gas delivery markets have diversified over time, with increased deliveries to our end-use customers, whereas historically, our natural gas delivery
markets were primarily to other pipelines who then delivered to the end-use customers. As of December 31, 2024, we had approximately $14.2 billion of projected
operating revenues under committed firm agreements, of which our deliveries are expected to be as follows: pipeline interconnects (42%), electric power generators
(22%), exporters of LNG (12%), industrial end-users (11%), LDCs (5%), storage activities (6%) and others (2%).
Government Regulation
Federal Energy Regulatory Commission: The FERC regulates our interstate natural gas transmission operating subsidiaries under the Natural Gas Act of 1938
(NGA) and the Natural Gas Policy Act of 1978 (NGPA). The FERC regulates, among other things, the rates and charges for the transportation and storage of natural gas
in interstate commerce and the construction, extension, enlargement or abandonment of facilities under its jurisdiction. Where required, our interstate natural gas
pipeline subsidiaries hold certificates of public convenience and necessity issued by the FERC covering certain of their facilities, activities and services. The FERC also
prescribes accounting treatment for our interstate natural gas pipeline subsidiaries, which is separately reported pursuant to forms filed with the FERC. The regulatory
books and records and other activities of our subsidiaries that operate under the FERC's jurisdiction may be periodically audited by the FERC.
The maximum applicable 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; however, the FERC also allows for discounted or negotiated rates as an alternative to cost-based
rates. 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 applicable rates that we may charge 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.
Some of our other subsidiaries transport natural gas in intrastate commerce under the rules and regulations established by the Texas Railroad Commission and
in interstate commerce that is subject to FERC jurisdiction under Section 311 of the NGPA. The maximum rates for services are established under Section 311 of the
NGPA and are generally subject to review every five years by the FERC. The rates and terms of service on our interstate ethane transportation pipeline are also subject
to regulation by the FERC under, among other statutes, the Interstate Commerce Act and the Energy Policy Act of 1992.
Over time, the FERC may change, amend or announce that it will undertake a review of its existing policies. There were no major policy changes announced
by the FERC during 2024 that materially impacted us.
The FERC has authority to impose civil penalties for violations of the NGA and NGPA and the implementing regulations thereunder, up to a maximum amount
that is adjusted annually for inflation, which for 2025 is approximately $1.6 million per day per violation. Should we fail to comply with applicable statutes, rules,
regulations and orders administered by the FERC, we could be subject to substantial penalties and fines, in addition to reputational damage.
Surface Transportation Board and Louisiana Public Service Commission: The STB regulates the rates we charge for interstate service on our ethylene pipeline
systems. The 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.
9

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 2 areas), whereas
HCAs along our NGLs pipelines are based on high-population density areas, areas near certain drinking water sources and unusually sensitive ecological areas.
Legislation 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 which 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 distribution pipeline facilities to conduct certain leak detection and repair programs and to require facility inspection and maintenance plans to align
with those requirements.
As a result of the 2011 Act, the 2016 Act and the 2020 Act, PHMSA has issued a series of significant rulemakings for onshore gas transmission pipelines (e.g.,
relating to maximum allowable operating pressure (MAOP) reconfirmation and exceedance reporting, the integrity assessment of additional pipeline mileage and the
consideration of seismicity as a risk factor in integrity management), and hazardous liquid transmission and gathering pipelines (e.g., expanding the reach of certain of
PHMSA's integrity management requirements, requiring the accommodation of in-line inspection tools by 2039 for certain pipelines, increasing annual, accident and
safety-related conditional reporting requirements, and expanding the use of leak detection systems beyond HCAs). PHMSA also regulates the minimum safety
requirements applicable to natural gas storage facilities, including wells, wellbore tubing and casing. In August 2022, PHMSA published a final rule that attempted to
expand the Management of Change process, corrosion control requirements for gas transmission pipelines, requirements that operators ensure no conditions exist
following an extreme weather event that could adversely affect the safe operation of the pipeline and repair criteria for non-HCAs. Five safety standards included in that
rule were challenged by industry trade groups, and in August 2024, the U.S. Court of Appeals for the D.C. Circuit struck down four of the five challenged safety
standards. In September 2023, PHMSA published a proposed rule that, if finalized, would enhance the safety requirements for gas distribution pipelines and would
require updates to distribution integrity management programs, emergency response plans, operations and maintenance manuals and other safety practices. 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.
Transportation Safety Administration: The Department of Homeland Security's Transportation Safety Administration (TSA) has issued a series of security
directives between 2022 and 2024 applicable to major pipeline owners and operators intended to strengthen the industry's overall cybersecurity posture in light of the
evolving threat landscape and its potential impacts to U.S. critical infrastructure. The security directives require, among other things, that pipeline owners and operators
designate a cybersecurity coordinator; establish and implement a Cybersecurity Implementation Plan; develop, maintain and test no less than annually through tabletop
exercises a Cybersecurity Incident Response Plan; and establish a Cybersecurity Assessment Plan (CAP) including a schedule for assessing and auditing the CAP. The
directives also contain requirements for
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reporting cybersecurity incidents and the results of certain assessments and audits. We have implemented tools, policies and practices designed to comply with the
security directives. Other regulators, such as PHMSA and the Securities and Exchange Commission (SEC), have also established requirements for reporting certain
cybersecurity incidents.
Other: Our operations are also subject to extensive federal, state, and local laws and regulations relating to the protection of the environment and occupational
health and safety. Such laws and regulations impose, among other things, restrictions, liabilities and obligations in connection with the generation, handling, use,
storage, transportation, treatment and disposal of various substances, including hazardous substances and waste, and in connection with spills, releases, discharges and
emissions of various substances into the environment. Environmental regulations also require that our facilities, sites and other properties be operated, maintained,
abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Occupational health and safety regulations establish standards protective of workers,
both generally and within the pipeline industry. These laws, as amended from time to time, that our operations are subject to, include, for example:
•
the Clean Air Act (CAA) and analogous state laws, which regulate air emission pollutants, greenhouse gas (GHG) emissions and reciprocating engines subject
to Maximum Achievable Control Technology standards;
•
the Federal Water Pollution Control Act, commonly referred to as the Clean Water Act, and analogous state laws, which establish the extent to which
waterways are subject to federal or state jurisdiction and serve to regulate the discharge of wastewater from our facilities into state and federal waters;
•
the Comprehensive Environmental Response, Compensation, and Liability Act, commonly referred to as CERCLA, or the Superfund law, and analogous state
laws, which regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or
locations to which we have sent hazardous substances for disposal;
•
the Resource Conservation and Recovery Act (RCRA) and analogous state laws, which impose requirements for the generation, storage, treatment,
transportation and disposal of solid and hazardous wastes at or from our facilities;
•
the Endangered Species Act (ESA), which restricts activities that may affect federally identified endangered and threatened species or their habitats by the
implementation of operating restrictions or a temporary, seasonal or permanent ban in affected areas;
•
the National Environmental Policy Act (NEPA), which requires federal agencies to evaluate major agency actions having the potential to impact the
environment and that may require the preparation of environmental assessments and more detailed environmental impact statements that may be made
available for public review and comment; and
•
the Occupational Safety and Health Act (OSHA) and analogous state laws, which establish workplace standards for the protection of the health and safety of
employees, including the implementation of hazard communications programs designed to inform employees about hazardous substances in the workplace,
potential harmful effects of these substances and appropriate control measures.
Many states and local governments 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.
While the Biden Administration attempted to pursue additional actions to bolster environmental regulations, the future of these actions is uncertain. For
example, the Biden Administration revised various rules to be more stringent, repealed various rules issued by the first Trump Administration, imposed restrictions on
methane emissions from oil and gas operations and ground level ozone emission standards and took other actions to mitigate climate change and further limit GHG
emissions. In addition, in January 2023, the White House's Council on Environmental Quality (CEQ) released guidance to assist federal agencies in assessing the GHG
emissions and climate change effects of their proposed actions under the NEPA. In May 2024, the CEQ published a final rule that, in the second and final "phase" of
updates, revised the implementing regulations of the procedural provisions of NEPA and implemented amendments to NEPA included in the Fiscal Responsibility Act of
2023. The final rule was challenged by various states and the litigation remains ongoing. More recently, in November 2024, a panel of three judges on the U.S. Court of
Appeals for the D.C. Circuit held that the CEQ lacks authority to issue NEPA regulations and followed with a statement by a majority of the judges suggesting that in
future cases they may not rule similarly that the CEQ lacks rulemaking authority. In February 2025, the District Court for North Dakota also held that the CEQ lacks
authority to issue NEPA regulations and vacated the CEQ's 2024 "Phase 2" rule. Additionally, President Trump signed an energy-related
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Executive Order which included ordering the CEQ to propose rescinding its NEPA regulations. As a result, there is significant uncertainty with respect to current and
future NEPA regulations. While we cannot predict the full impact of these developments, any legal challenges to NEPA reviews performed in connection with our
projects may 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."
Environmental laws and regulations generally become stricter over time; however, we cannot predict how the recent change in presidential administrations will
impact our regulatory obligations. 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. 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 Nationwide Permit (NWP) 12, which was issued in January 2021 and subsequently challenged by various environmental groups. We rely
on NWP 12, alongside other NWPs, as blanket authority for construction, maintenance, repair and removal of pipelines. If NWP 12 is amended or revoked, we may be
required to apply for one or more Individual Permits, which would require additional time and resources to obtain. The NWP process relies upon the Clean Water Act
Section 401 certification process, which is also subject to ongoing litigation. In September 2023, the Environmental Protection Agency (EPA) finalized its Clean Water
Act Section 401 Water Quality Certification Improvement Rule, effective in November 2023, which expanded the scope of certification authority. While the litigation is
ongoing and the full extent and impact of these actions is unclear at this time, any disruption in our ability to obtain coverage under NWP 12 or other 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" (WOTUS), 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. Most recently, in September 2023, the EPA issued a
version of the WOTUS rule that, due to injunctions in certain states, is being implemented in only 24 states. Thus, the operative definition of WOTUS varies by state.
However, we cannot predict what actions the Trump Administration may take with respect to any of these regulations and the timing with respect to the same. As a
result, there is significant uncertainty with respect to wetlands regulation under the Clean Water Act at this time. 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."
Historically, our environmental compliance costs have not had a material adverse effect on our results of operations, but there can be no assurance that future
compliance with existing requirements will not materially affect us or that the current regulatory standards will not become more onerous in the future, resulting in more
significant costs to maintain compliance and increased exposure to significant liabilities. Note 6 in Part II, Item 8. of this Annual Report on Form 10-K contains
information regarding environmental compliance.
Climate Change
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. While we are seeking to reduce our GHG emissions, we cannot predict all risks that may be associated
with climate change or other environmental, 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 matters and conservation measures may adversely impact our business."
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Human Capital
As of December 31, 2024, we had approximately 1,290 employees, approximately 100 of whom were included under collective bargaining agreements. A
satisfactory relationship exists between management and our employees.
Hiring and retaining qualified people is critical to our long-term strategic success. We have programs in place that seek to help employees build their
knowledge, skills and experience, as well as to guide their career development. We believe that employing individuals with different backgrounds and experiences helps
meet the diverse needs of our stakeholders.
We are part of a critical infrastructure industry whose customers and communities depend upon us to provide safe and reliable service. Our employees are
essential to ensuring we continue to meet these objectives, and we consider safety in our day-to-day activities to be a primary core value.
Available Information
Our website is located at www.bwpipelines.com. We make available free of charge through our website our Annual Reports on Form 10-K, which include our
audited financial statements, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a)
or 15(d) of the Securities Exchange Act of 1934 (Exchange Act) as soon as reasonably practical after we electronically file such material with the SEC. These
documents are also available on the SEC's website at www.sec.gov.
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Item 1A. Risk Factors
Our business faces many risks and uncertainties. We have described below the material risks facing us. These risks and uncertainties could lead to events or
circumstances that may have a material adverse effect on our business, financial condition, results of operations or cash flows. There may be additional risks that we do
not yet know of or that we do not currently perceive to be as material that may also materially adversely affect our business, financial condition, results of operations or
cash flows.
All of the information included in this Annual Report on Form 10-K and any subsequent reports we file with the SEC or make available to the public should be
carefully considered and evaluated before investing in any securities issued by us.
Business Risks
Our natural gas transportation and storage operations and ethane transportation services are subject to extensive regulation by the FERC, including rules and
regulations related to the rates we can charge for our services and our ability to construct or abandon facilities. We may not be able to recover the full cost of
operating our pipelines or storage operations, including earning a reasonable return.
Our natural gas transportation and storage operations are subject to extensive regulation by the FERC, including with respect to 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 or storage operations, including earning a reasonable return. 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 regulates the rates we can charge for our natural gas transportation and storage and interstate ethane transportation operations. For our cost-based
services, the FERC establishes both the maximum and minimum rates we can charge. The basic elements that the FERC considers are the costs of providing service, the
volumes of gas being transported, the rate design, the allocation of costs between services, the capital structure and the rate of return a pipeline is permitted to earn. We
may not be able to recover our costs, including certain costs associated with pipeline integrity, through existing or future rates.
The FERC and/or our customers could challenge the maximum applicable rates that any of our regulated pipelines can charge in accordance with Section 5 of
the NGA. The adoption of potential legislation that would amend Section 5 of the NGA to add refund provisions could increase the likelihood of such a challenge. If
such a challenge is successful for any of our pipelines or if our rates are found not to be just and reasonable, then the revenues associated with transportation and storage
services the pipeline provides pursuant to cost-of-service rates could materially decrease in the future, which would adversely affect, perhaps substantially, the revenues
on that pipeline going forward.
Over time, the FERC may change, amend or announce that it will undertake a review of its existing policies. There were no major policy changes announced
by the FERC during 2024.
The FERC has authority to impose civil penalties for violations of the NGA and NGPA, and the implementing regulations thereunder, up to a maximum
amount that is adjusted annually for inflation, which for 2025 is approximately $1.6 million per day per violation. Should we fail to comply with applicable statutes,
rules, regulations and orders administered by the FERC, we could be subject to substantial penalties and fines, in addition to reputational damage.
Our operations, and those of our customers, are subject to a series of risks regarding climate change.
The threat of climate change continues to attract considerable attention in the U.S. and in other countries. Numerous proposals have been made and could
continue to be made at the international, national, regional, state and local levels of government to monitor, limit and eliminate both existing and future emissions of
GHGs. These proposals expose our operations, as well as the operations of our fossil fuel producer customers, to a series of regulatory, political, litigation and financial
risks.
In the U.S., no comprehensive climate change legislation has been implemented at the federal level. Although the Biden Administration has taken legislative,
regulatory and executive action to address climate change, policy priorities, such as climate change, are likely to change with the new presidential administration. For
example, in August 2022, the Inflation
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Reduction Act of 2022 (IRA) passed, which advanced numerous climate-related objectives, including a methane emissions fee that applies to excess methane emissions
from certain facilities that 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. In November 2024,
the EPA issued a final rule implementing the methane emissions fee; however, we cannot predict if Congress may take action to repeal or revise the IRA, with respect to
the methane emissions fee.
Additionally, the EPA regulates GHGs, including methane and carbon dioxide, under the CAA and has implemented various permitting, reporting and
technology-based requirements to reduce GHG emissions by the oil and gas sectors. In December 2023, the EPA finalized its methane rules for new, modified, and
reconstructed facilities, known as OOOOb, as well as standards for existing sources for the first time ever, known as OOOOc. Under the final rules, states have two
years to prepare and submit their plans to impose methane emission controls on existing sources. The presumptive standards established under the final rules include
advanced monitoring to encourage the deployment of innovative technologies to detect and reduce methane emissions, reduction of emissions by 95% through capture
and control systems, zero-emission requirements for certain devices, and the establishment of the "super emitter" response program that would allow third parties to
make reports to the EPA of large methane emission events. Fines and penalties for violations of these rules can be substantial and compliance with the new rules may
affect the amount we owe under the IRA. The EPA's final methane rules are currently being challenged by 23 states and a coalition of industry groups in the U.S. Circuit
Court of Appeals for the D.C. Circuit. To the extent not timely repealed or modified by the Trump Administration, the requirements of the EPA's final methane rules
could increase our operating costs and the costs of our customers, 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 2021, the U.S. rejoined the Paris
Agreement, which requires member nations to submit non-binding GHG emissions reduction goals every five years, and President Biden announced a new target for the
U.S. to reduce GHG emissions 50%-52% from 2005 levels by 2030. However, on January 20, 2025, President Trump signed an Executive Order once again
withdrawing the U.S. from the Paris Agreement and from any other commitments made under the United Nations Framework Convention on Climate Change.
Additionally, President Trump revoked any purported financial commitment made by the U.S. pursuant to the same. The full impact these actions may have upon our
business or financial condition is uncertain at this time.
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.
and the federal government has and could in the future take various actions to seek 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. However, on his first day in office, President Trump signed several Executive Orders rescinding many of the previous
administration’s climate-related initiatives, that included many of the actions noted above. We cannot predict what additional actions the Trump Administration may take
with respect to these matters or the timing for such actions. Litigation risks are also increasing, as a number of cities and other governmental entities have brought suit
alleging that fossil fuel producers created public nuisances by producing fuels that contributed to global warming effects such as rising sea levels, are responsible for
associated roadway and infrastructure damage, or defrauded investors or customers by failing to timely and adequately disclose adverse effects of climate change.
There have also been increasing financial risks for fossil fuel energy companies as certain investors become increasingly concerned about the potential effects
of climate change and may elect in the future to shift some or all of their investments into non-fossil fuel energy related sectors. 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. While we
cannot predict how or to what extent sustainable lending and investment practices may impact us, 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 2024, the SEC released a final rule that establishes a framework for the reporting of climate risks, targets and metrics. However, the
future of the SEC climate change rule is uncertain given that its implementation has been stayed pending the outcome of legal challenges; moreover, the SEC under the
Trump Administration may seek to repeal or revoke the rule, though we cannot predict whether such action will occur or its timing. As a result, the ultimate impact of
the SEC rule, or any similar climate-related disclosure requirements imposed in the future, on our business is uncertain and may result in increased compliance costs and
increased costs of and restrictions on access to capital. These agency actions also could increase the potential for litigation.
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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, result in litigation and 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."
Increased attention to climate change, environmental, social and governance matters and conservation measures may adversely impact our business.
Increasing attention to climate change, societal expectations on companies to address climate change, investor and societal expectations regarding ESG matters
and disclosures, and consumer demand for alternative forms of energy may result in increased costs, reduced demand for our services, reduced profits, increased
investigations and litigation, and negative impacts on our access to capital markets. Increasing attention to climate change and environmental conservation, for example,
may result in demand shifts for oil and natural gas products, additional governmental investigations, governmental and private litigation and other liabilities imposed
against us or our customers. It is possible that such liability could be imposed without regard to our causation of or contribution to the asserted damage or to other
mitigating factors.
While we may publish voluntary disclosures regarding ESG matters from time to time, many of the statements in those disclosures may not be material and
may be based on expectations and assumptions that may not be representative of actual risks or events or forecasts of expected risks or events. Such expectations and
assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single
approach to identifying, measuring and reporting on many ESG matters.
Organizations that provide information to investors on corporate governance and related matters have developed rating 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.
In addition, other stakeholders, including customers, employees, regulators, credit rating agencies and suppliers, have also been focused on ESG matters.
Companies that do not adapt to or comply with investor or other stakeholder expectations and standards, which are evolving, or that are perceived to have not responded
appropriately to the growing concern regarding ESG issues, regardless of whether there is a legal requirement to do so, may suffer from reputational damage and other
adverse consequences. Additionally, to the extent ESG matters negatively impact our reputation, we may not be able to compete as effectively to recruit or retain
employees, which may adversely affect our operations.
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. 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 conditions and events could adversely impact our operations, pipelines and facilities, or those of our customers or suppliers.
Climatic events can cause disruptions to, delays in or suspension of our services by interrupting our operations, causing loss of or damage to our facilities or
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
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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 climatic 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.
We are subject to reputational risks and risks related to public opinion.
Our business, operations and financial condition may be adversely impacted as a result of negative public opinion. We operate in an industry that 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 could also be impacted by
negative publicity related to pipeline incidents, unpopular expansion projects and opposition to the 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.
Failure to comply with environmental or worker safety laws and regulations or an accidental release of pollutants into the environment may cause us to incur
significant costs and liabilities.
Our operations are subject to extensive federal, state, and local laws and regulations relating to protection of the environment and occupational health and
safety. Such laws and regulations impose, among other things, restrictions, liabilities and obligations in connection with the generation, handling, use, storage,
transportation, treatment and disposal of various substances, including hazardous substances and waste, and in connection with spills, releases, discharges and emissions
of various substances into the environment. These laws include, for example, the CAA, the Clean Water Act, CERCLA, the RCRA, ESA, NEPA, OSHA and analogous
state laws. These laws and regulations may restrict or impact our business activities, including requiring the acquisition or renewal of permits or other approvals to
conduct regulated activities, restricting the manner in which we handle or dispose of wastes, imposing remedial obligations to remove or mitigate contamination
resulting from a spill or other release, requiring capital expenditures to comply with pollution control requirements and imposing safety and health criteria addressing
worker protection. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the
assessment of monetary penalties, the imposition of remedial requirements, the incurrence of capital expenditures, the occurrence of delays, denials or cancellations in
the permitting or performance or expansion of projects and the issuance of orders enjoining future operations in a particular area. Under certain of these environmental
laws and regulations, we could be subject to joint and several strict liability for the removal or remediation of previously released pollutants or property contamination,
regardless of whether we were responsible for the release or contamination or if our operations were not in compliance with applicable laws. We may not be able to
recover some or any of the costs incurred from insurance.
Stricter environmental or worker safety laws, regulations or enforcement policies could significantly increase our operational or compliance costs and
compliance with new or more stringent environmental legal requirements could delay or prohibit our ability to obtain permits for operations or require us to install
additional pollution control equipment. For instance, the construction or expansion of pipelines often requires authorizations under the Clean Water Act, which may be
subject to challenge. There is ongoing litigation with respect to the status and use of the Corps' Clean Water Act Section 404 NWP 12, which was issued in January 2021
and subsequently challenged by various environmental groups. We rely on NWP 12, alongside other NWPs, as blanket authority for construction, maintenance, repair
and removal of pipelines. If NWP 12 is amended or revoked, we may be required to apply for one or more Individual Permits, which would require additional time and
resources to obtain. The NWP process relies upon the Clean Water Act Section 401 certification process, which is also subject to ongoing litigation. In September 2023,
the EPA finalized its Clean Water Act Section 401 Water Quality Certification Improvement Rule, effective in November 2023, which expanded the scope of
certification authority. While the litigation is ongoing and the full extent and impact of these actions are unclear, any disruption in our ability to obtain coverage under
NWP 12 or other 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
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over WOTUS, as the EPA and the Corps have pursued multiple rulemakings under different administrations since 2015 to determine the scope of such reach. Most
recently, in September 2023, the EPA issued a version of the WOTUS rule that, due to injunctions in certain states, is being implemented in only 24 states. Thus, the
operative definition of WOTUS varies by state. We cannot predict what actions, if any, or the timing of any such actions the Trump Administration may take with
respect to these regulations. See Part I, Item 1. Business—Government Regulation—Other of this Annual Report on Form 10-K for further discussion on environmental
matters.
Legislative and regulatory initiatives relating to new or more stringent pipeline safety requirements or substantial changes to existing integrity management
programs or withdrawal of regulatory waivers could subject us to increased capital and operating costs and operational delays.
Our interstate pipelines are subject to regulation by PHMSA, which is part of the DOT. PHMSA regulates the design, installation, testing, construction,
operation and maintenance of existing interstate natural gas and NGLs pipeline facilities. PHMSA regulation currently requires pipeline operators to implement integrity
management programs, including frequent inspections, 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 and recently issued a series of significant rulemakings for onshore gas
distribution, transmission and gathering pipelines (e.g., relating to MAOP reconfirmation and exceedance reporting, the integrity assessment of additional pipeline
mileage and the consideration of seismicity as a risk factor in integrity management), and hazardous liquid transmission and gathering pipelines (e.g., expanding the
reach of certain of PHMSA's integrity management requirements, requiring the accommodation of in-line inspection tools by 2039 for certain pipelines, increasing
annual, accident and safety-related conditional reporting requirements, and expanding the use of leak detection systems beyond HCAs). PHMSA also regulates safety
requirements applicable to natural gas storage facilities, including wells, wellbore tubing and casing. In August 2022, PHMSA published a final rule that attempted to
expand the Management of Change process and corrosion control requirements for gas transmission pipelines and add requirements that operators ensure no conditions
exist following an extreme weather event that could adversely affect the safe operation of the pipeline and repair criteria for non-HCAs. Five safety standards included
in that rule were challenged by industry trade groups, and in August 2024, the U.S. Court of Appeals for the D.C. Circuit struck down four of the five challenged safety
standards. In September 2023, PHMSA published a proposed rule that, if finalized, would enhance the safety requirements for gas distribution pipelines and require
updates to distribution integrity management programs, emergency response plans, operations and maintenance manuals and other safety practices. 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 operations or 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 those 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 NGLs 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 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, 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.
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Our actual construction and development costs could exceed our forecasts; our anticipated cash flow from construction and development projects will not be
immediate and can take several years; and our construction and development projects may not be completed on time or at all.
We are and have been engaged in several construction projects involving our existing assets and the construction of new facilities for which we have expended
or will expend significant capital. We expect to continue to engage in the construction of additional growth projects and modifications of our system. When we build a
new pipeline or expand or modify an existing facility, the design, construction and development occurs over an extended period of time, and we will not receive any
revenue or cash flow from that project until after it is placed into commercial service. On our interstate pipelines, there are several years between when the project is
announced and when customers begin using the new facilities. During this period, we spend capital and incur costs without receiving any of the financial benefits
associated with the projects. The construction of new assets involves a number of risks, including risks related to regulations (federal, state, and local), landowner
opposition, environmental matters, activists, legal compliance, political matters and materials and labor costs, as well as operational and other risks that are difficult to
predict and some of which are beyond our control. Additionally, the possibility of implementing trade tariffs under the Trump Administration could impact some of our
pricing and availability of materials with some of our suppliers. 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.
A failure in our computer systems or a cybersecurity attack on any of our computer systems, devices or telecommunications networks or those of certain third
parties could cause substantial and catastrophic damage and may materially adversely affect our cash flows, financial condition and ability to operate our business.
Our business is dependent upon our computer systems, devices and networks (operational and information technology), and those of our customers, suppliers
and others with whom we do business, to collect, process and store the data necessary to conduct almost all aspects of our business, including the operation of our
pipeline and storage facilities and the recording and reporting of commercial and financial information. Despite our security measures, the information and operational
technology and infrastructure we rely on may be vulnerable to attacks by third parties, such as hackers, cybercriminals, nation-states, insiders or other third parties, or
breached due to human error, malfeasance or other disruptions. Through government intelligence reports, we are aware of credible global threats to third-party, U.S.
critical infrastructure sectors on which we depend, such as the telecommunications sector.
Cybersecurity threat actors have attacked and continue to threaten energy infrastructure. The U.S. government has issued public and industry-directed warnings
that indicate that energy assets might be specific targets of cybersecurity attacks, which are increasing in sophistication, magnitude and frequency. Vulnerabilities in one
environment may affect other interconnected systems. A cybersecurity incident that impacts a third party with whom we do business may impact us.
Some cyber incidents, such as surveillance, may go unnoticed for a long period of time. Any investigation of a cybersecurity attack or other security incident
will be inherently unpredictable and complex, and it may take significant time before the completion of any investigation and availability of full and reliable
information. During such time, we may not know the extent of the harm or how best to remediate it, and certain errors or actions could be repeated or compounded
before they are discovered and remediated, any or all of which could further increase the costs and consequences of a cybersecurity attack or other security incident, and
our remediation efforts may not be successful.
As the cybersecurity threat landscape continues to evolve, we may be required to expend significant additional resources to continue to modify or enhance our
protective measures or to investigate and remediate any information security vulnerabilities. Advances in computer capabilities, discoveries in the field of artificial
intelligence, cryptography, inadequate facility security or other developments may result in a compromise or breach of the technology we use to safeguard our
operational and information technology systems and confidential, personal, or otherwise protected information. As the breadth and complexity of the technologies we
use continue to grow, including as a result of the use of mobile devices, cloud services, artificial intelligence, open-source software, social media and the increased
reliance on devices connected to the internet, the potential risk of cyberattacks and cybersecurity incidents also increases. No security measure is infallible. Despite
ongoing efforts to improve our ability to protect our systems from compromise, we may not be able to protect all of our diverse systems. Our efforts to improve security
and protect data and our systems may also identify previously undiscovered instances of security breaches or other cyber incidents.
TSA has issued a series of security directives applicable to pipeline owners and operators, which require the implementation of a variety of cybersecurity
measures and reporting. Other regulators, such as PHMSA and the SEC, have also
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established requirements for reporting certain cybersecurity incidents. As cybersecurity incidents continue to evolve, more legislation could be enacted to seek to
mitigate cybersecurity threats. This may require us to expend additional resources to continue to modify or enhance our protective measures or to investigate and
remediate vulnerabilities to cybersecurity incidents at significantly increased costs. We cannot predict the potential impact to our business of potential future legislation,
regulations or orders relating to cybersecurity.
A failure, security breach, disruption or degradation impacting our operational or information technology systems or those of third parties with whom we do
business could negatively affect our ability to safely and reliably operate our assets and/or result in delays in providing services for our customers, contamination or
degradation of the products we transport and store, damage to or destruction of our or third-party pipelines, property or facilities, catastrophic events, injury or death to
our employees or other persons, the inadvertent release of hydrocarbons or the release or destruction of confidential, proprietary or business-critical information or
intellectual property, which could result in outages, reduced revenue, unexpected costs and expenses, litigation and reputational damage, any or all of which may be
irreversible and may materially adversely affect our results of operations, cash flows, financial condition and ability to operate our business.
In addition, access, disclosure or other loss of information or other consequences could result in legal claims or proceedings, liability under laws that protect
the privacy of personal information or personally identifiable information, regulatory penalties for divulging or failing to adequately protect such information, disruption
of our operations, incident response and remediation costs, damage to our reputation, and loss of confidence in our services.
We may face opposition to the operation of our pipelines and facilities, construction or expansion of facilities and new pipeline projects from various groups.
We may face opposition to the operation of our pipelines and facilities, construction or expansion of our facilities and 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, and 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 or death to people, property or the environment and lead to extended interruptions of our operations and material damages and
costs.
Market conditions, including available supply, demand and the price differentials between natural gas supplies and market locations for natural gas, may affect the
transportation rates that we can charge on certain portions of our pipeline systems.
Each year, a portion of our firm natural gas transportation contracts expire and need to be replaced or renewed. As a result of 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 continued availability of supply from key supply basins, the competition between producing basins, competition with
other pipelines for supply and markets, the demand for gas by end-users such as electric power generators, petrochemical facilities and LNG export facilities and the
price differentials between the gas supplies and the market demand for the gas (basis differentials).
Changes in energy prices, including natural gas, oil and NGLs, impact the supply of and demand for those commodities, which impact our business.
Our customers, especially producers and certain plant operators, are directly impacted by changes in commodity prices. The prices of natural gas, oil and NGLs
fluctuate in response to changes in both domestic and worldwide supply and demand, market uncertainty and a variety of additional factors, including for natural gas,
the realization of potential LNG exports and demand growth within the power generation market. Volatility in the pricing levels of natural gas, oil and NGLs could
adversely affect the businesses of certain of our producer customers and could result in defaults or the non-renewal of our contracted capacity when existing contracts
expire. Commodity prices could affect the operations of certain of our industrial customers, including the temporary closure or reduction of plant operations, resulting in
decreased deliveries to those customers. Future increases in the price of natural gas and NGLs could make alternative energy and feedstock sources more competitive
and decrease demand for natural gas and NGLs. A reduced level of demand for natural gas and NGLs could diminish the utilization of capacity on our systems and
reduce the demand for our services.
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We are exposed to credit risk relating to default or bankruptcy by our customers.
Credit risk relates to the risk of loss resulting from the default by a customer of its contractual obligations or the customer filing bankruptcy. We have credit risk
with both our existing customers and those supporting our growth projects. Credit risk exists in relation to our growth projects because the expansion customers make
long-term firm capacity commitments to us for such projects and certain of those expansion customers agree to provide credit support as construction for such projects
progresses. If a customer fails to post the required credit support or defaults during the growth project process, overall returns on the project may be reduced to the
extent an adjustment to the scope of the project occurs, or we are unable to replace the defaulting customer with a customer willing to pay similar rates.
Our credit exposure also includes receivables for services provided, future performance under firm agreements and volumes of gas owed by customers for
imbalances or gas loaned by us to them under certain NNS and PAL services.
We rely on a limited number of customers for a significant portion of our revenues.
For 2024, no customer comprised 10% or more of our operating revenues. However, the top ten customers under committed firm agreements comprised
approximately 62% of our total projected operating revenues as of December 31, 2024. If any of our significant customers have credit or financial problems that result
in bankruptcy, a delay or failure to pay for services provided by us, to post the required credit support for construction associated with our growth projects or existing
contracts or to repay the gas they owe us, it could have a material adverse effect on our revenues.
Our revolving credit facility contains operating and financial covenants that may restrict our business and financing activities.
Our revolving credit facility contains operating and financial covenants that may restrict our ability to finance future operations or capital needs or to expand or
pursue business activities. Our credit agreement limits our ability to make loans or investments, make material changes to the nature of our business, merge, consolidate
or engage in asset sales, or grant liens or make negative pledges. This agreement also requires us to maintain a ratio of total consolidated debt to consolidated EBITDA
(as defined in the credit agreement) of not more than 5.0 to 1.0, or up to 5.5 to 1.0 for the three quarters following a qualified acquisition or series of acquisitions, where
the purchase price exceeds $100.0 million over a rolling 12-month period, which limits the amount of additional indebtedness we can incur to grow our business, and
could require us to reduce indebtedness if our earnings before interest, income taxes, depreciation and amortization (EBITDA) decreases to a level that would cause us
to breach this covenant. Future financing agreements we may enter into could contain similar or more restrictive covenants or may not be as favorable as those under
our existing indebtedness.
Our ability to comply with the covenants and restrictions contained in our credit agreement may be affected by events beyond our control, including economic,
financial and market conditions. If market 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 an event occurs, we
may not be able to obtain sufficient funds to make these accelerated payments.
Our indebtedness could affect our ability to meet our obligations and may otherwise restrict our activities.
As of December 31, 2024, we had $3.3 billion in principal amount of long-term debt outstanding. This level of debt requires significant interest payments. Our
inability to generate sufficient cash flow to satisfy our debt obligations, or to refinance our obligations on commercially reasonable terms, would have a material adverse
effect on our business. Our indebtedness could have important consequences. For example, it could:
•
limit our ability to borrow money for our working capital, capital expenditures, debt service requirements or other general partnership purposes;
•
impact our ratings received from credit rating agencies;
•
increase our vulnerability to general adverse economic and industry conditions; and
•
limit our ability to respond to business opportunities, including growing our business through acquisitions.
    
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We are permitted, under our revolving credit facility and the indentures governing our notes, to incur additional debt, subject to certain limitations under our
revolving credit facility and the indentures governing the notes. If we incur additional debt, our increased leverage could also result in or exacerbate the consequences
described above.
We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets, which may affect our ability to fulfill our
debt obligations.
We are a partnership holding company, and our operating subsidiaries conduct all of our operations and own all of our operating assets. We have no significant
assets other than the ownership interests in our subsidiaries. As a result, our ability to fulfill our debt obligations depends on the performance of our subsidiaries and
their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, the provisions of existing and
future indebtedness, applicable state partnership and limited liability company laws and other laws and regulations, including FERC policies.
Changes in the debt markets and increases in interest rates could adversely affect our business.
We anticipate funding our capital and other spending requirements through our available financing options, including cash generated from operations,
borrowings under our revolving credit facility and issuances of additional debt. Changes in the debt markets, including market disruptions, limited liquidity, and an
increase in interest rates, may increase the cost of financing as well as the risks of refinancing maturing debt. This may affect our ability to raise needed financing and
reduce the amount of cash available to fund our operations or growth projects or refinance maturing debt. If the debt markets were not available, it is not certain if other
adequate financing options would be available to us on terms and conditions that we would find acceptable.
Any disruption in the debt markets could require us to take additional measures to conserve cash until the markets stabilize or until we can arrange alternative
credit arrangements or other funding for our business needs. Such measures could include reducing or delaying business activities, reducing our operations to lower
expenses and reducing other discretionary uses of cash. We may be unable to execute our growth strategy or take advantage of certain business opportunities, any of
which could negatively impact our business.
Pandemics or other outbreaks of contagious diseases and the measures to mitigate their spread could materially adversely affect our business, financial condition
and results of operations and those of our customers, suppliers and other business partners.
The global outbreak of the COVID-19 pandemic and measures to mitigate the spread of COVID-19 caused unprecedented disruptions to the global and U.S.
economies and impacted global demand for oil and petrochemical products. Future pandemics or 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. Although our operations are considered essential critical infrastructure under current Cybersecurity and Infrastructure
Security Agency guidelines, 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 or 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 any potential future pandemics or other outbreaks of contagious diseases. These cost increases may not be
fully recoverable. It is possible that future pandemics or other outbreaks of contagious diseases could cause disruption in our customers' businesses, cause delays, or
limit the ability of our customers to perform, including in making timely payments to us. Future pandemics or other outbreaks of contagious diseases could impact
capital markets, which may impact our customers' financial position. Future pandemics or other outbreaks of contagious diseases may also have the effect of
exacerbating several of the other risk factors contained herein.
We do not own all of the land on which our pipelines, storage and other facilities are located, which could result in disruptions to our operations.
Substantial portions of our pipelines, storage and other facilities are constructed and maintained on property owned by others pursuant to rights-of-way,
easements, permits, licenses or consents, and we are subject to the possibility of more onerous terms and/or increased costs to retain necessary land use rights if we do
not have valid land use rights or if such land use rights lapse or terminate. Some of the rights we obtain to construct and operate our pipelines, storage or other facilities
on land owned by third parties and governmental agencies 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 (or
increased costs to renew) 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
22

permits, licenses, consents or otherwise (or increased costs in connection with the renewal thereof), could have a material adverse effect on our operations.
We may not be successful in executing our strategy to grow and diversify our business.
We rely primarily on the revenues generated from our natural gas transportation and storage services. Negative developments in these services have a
significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets. Our ability to grow, diversify and increase
cash flows will depend, in part, on our ability to expand our existing business lines and to close and execute on accretive acquisitions. We may not be successful in
acquiring or developing such assets or may do so on terms that ultimately are not profitable.
Our ability to replace expiring gas storage contracts at attractive rates or on a long-term basis and to sell short-term services at attractive rates or at all are subject
to market conditions.
We own and operate substantial natural gas storage facilities. The market for the storage and PAL services that we offer is impacted by the factors and market
conditions discussed above for our transportation services and is also impacted by natural gas price differentials between time periods, such as winter to summer (time
period price spreads), and the volatility in time period price spreads. When market conditions cause a narrowing of time period price spreads and a decline in the price
volatility of natural gas, these factors adversely impact the rates we can charge for our storage and PAL services.
Our operations are subject to catastrophic losses, operational hazards and unforeseen interruptions for which we may not be adequately insured.
There are a variety of operating risks inherent in transporting and storing natural gas, ethylene and NGLs, such as leaks and other forms of releases, explosions,
fires, cybersecurity 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, cold freezes, snowstorms,
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 and
reputational damage. The location of pipelines in HCAs, which includes populated areas, residential areas, commercial business centers and industrial sites, could
significantly increase the level of damages resulting from some of these risks.
We currently possess property, business interruption, cybersecurity and general liability insurance, but proceeds from such insurance coverage may not be
adequate for all liabilities or expenses incurred or revenues lost. Moreover, such insurance may not be available in the future at commercially reasonable costs and
terms. The insurance coverage we do obtain may contain large deductibles or fail to cover certain events, hazards or potential losses.
Our business requires the retention and recruitment of a skilled workforce and the loss of such workforce could result in the failure to implement our business
plans.
Our operations and management require the retention and recruitment of a skilled executive team and workforce, including engineers, technical personnel and
other professionals. In addition, many of our current employees are approaching retirement age and have significant institutional knowledge that must be transferred to
other employees. If we are unable to retain our current employees, successfully complete the knowledge transfer and/or recruit new employees of comparable
knowledge and experience, our business could be negatively impacted.
Our business is highly competitive.
The principal elements of competition among pipeline systems are the 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 exacerbate 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 our facilities or products we transport and store.
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Possible terrorist activities or military actions could adversely affect our business.
The continued threat of terrorism and the impact of military and other action by the U.S. and its allies or other countries might lead to increased political,
economic and financial market instability and volatility in prices for natural gas, which could affect the markets for our natural gas transportation and storage services.
While we are taking steps that we believe are appropriate to increase the security of our assets, we may not be able to completely secure our assets or completely protect
them against a terrorist attack.
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Item 1B. Unresolved Staff Comments
None.
Item 1C. Cybersecurity
Risk Management and Strategy
Our business is dependent upon our computer systems, devices and networks (operational and information technology), and those of third parties with whom
we do business, to collect, process and store the data necessary to conduct almost all aspects of our business, including the operation of our pipeline and storage
facilities and the recording and reporting of commercial and financial information. We maintain a cybersecurity program, which includes people, processes, and
technology aimed at defending our computer systems, devices and networks (operational and information technology) against increasingly sophisticated threats.
We recognize the importance of protecting both our information and operational control systems from threats that could disrupt our business, put our assets at
risk or compromise our customer and employee data, including personally identifiable information. The effective protection of our assets and technology infrastructure
is crucial to the reliability of our operations, our ability to serve our customers, the nation's energy needs and the security of our assets and data. We developed a
comprehensive strategy designed to address both physical and cybersecurity threats. Additionally, as further described in Item 1. Business—Government Regulation—
Transportation Safety Administration, TSA has issued a series of security directives that all pipeline owners and operators must include in their cybersecurity planning,
testing and in their reporting of any incidents.
Our cybersecurity program is encapsulated in our Cybersecurity Implementation Plan, Cybersecurity Incident Response Plan and CAP. Our cybersecurity
program is implemented and maintained using information security tools, policies and a dedicated team responsible for monitoring our networks, providing training to
our employees, analyzing the evolution of new threats and strategies for mitigating such threats and seeking to continually harden our cybersecurity posture. The
program is periodically exercised, reviewed, updated, and vetted through third-party audits, assessments, and tests with the goal of validating its effectiveness in
reducing risk, as well as evaluating its compliance with legal and regulatory requirements. To assess, identify and manage our material risks from cybersecurity threats,
we endeavor to employ the following:
a.
Identification of critical systems – we seek to identify which operational or information technology, if compromised or exploited, would result in operational
disruption or harm or data compromise. We aim to protect the entire environment at an enterprise level where practical, combined with additional layered, risk-
based controls designed to safeguard against cybersecurity threats where risk is higher. This strategic, defense-in-depth, and risk-based approach to
cybersecurity provides a methodology designed to identify, protect, detect, respond, and recover from cybersecurity incidents.
b.
Network segmentation – we use a combination of firewalls, routers and switches in an effort to provide network segmentation aimed at providing network zone
protection.
c.
Access controls – we leverage several security capabilities to attempt to enforce access, authorization and authentication to relevant systems, technology, and
controls. A least-privilege methodology is applied for localized client workstations, servers, and applications. Security capabilities for access control include
physical, administrative, and technical controls that combine to seek to provide a defense-in-depth approach designed to protect our cyber assets from
unauthorized use.
d.
Continuous monitoring, detection, and auditing – we employ various technologies, tactics, and procedures aimed to continuously monitor, baseline, and detect
threats, and audit our network and systems. In addition, we use a combination of technology tools with outside managed security service providers designed to
capture, analyze and respond to security anomalies.
e.
Patch management – network vulnerability scanning tools are deployed that seek to continually scan, identify and report on asset vulnerabilities. Vulnerability
scanner reports are used to drive patching and remediation efforts and are also used as a tool to evaluate the effectiveness and timeliness of patching efforts.
Application and infrastructure subject matter experts subscribe to various third-party vendor security notifications to receive proactive notifications on, among
other things, bugs, security flaws and mitigations, related to operational and information systems.
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The above cybersecurity risk management processes are integrated into our overall risk management program. Cybersecurity threats are understood to be wide-
reaching and to intersect with various other enterprise risks. In addition to assessing our own cybersecurity preparedness, we also consider cybersecurity risks associated
with our use of third-party service providers based on the potential impact of a disruption of the services to our operations and the sensitivity of data shared with the
service providers. We have established separate processes and procedures to oversee and identify cybersecurity risks associated with third parties.
We regularly engage independent third parties to periodically assess our cybersecurity posture. These assessments include penetration tests, purple team
activities, health checks and point-specific technical cybersecurity assessments of key systems. Some of these assessments are performed independently with internal
audit oversight. Certain processes are part of our CAP and are required to be tested at regular intervals, and test results may be required to be reported to TSA as
requested and during inspections. We interface with industry peers, participate in information sharing and analysis centers and partner with federal, state, and local law
enforcement and regulatory agencies with the goal of forming a cybersecurity threat feedback loop. Threat and mitigation information, techniques, tactics and
procedures are often shared via this loop.
Impact of Risks from Cybersecurity Threats
As of the date of this Annual Report, though the Company and third parties with whom we do business have experienced certain cybersecurity incidents, we
are not aware of any previous cybersecurity threats or incidents that have materially affected or are reasonably likely to materially affect us. We acknowledge that
cybersecurity threats are continually evolving, and the possibility of future cybersecurity incidents remains. Despite the implementation of our cybersecurity processes,
our security measures cannot guarantee that a significant cybersecurity attack will not occur. While we devote resources to our security measures designed to protect our
systems and information, no security measure is infallible. See Item 1A. Risk Factors for additional information about the risks to our business associated with a breach
or other compromise to our information and operational technology systems.
Governance
Our board of directors oversees the execution of our cybersecurity strategy. Our Chief Information Security Officer (CISO) oversees our cybersecurity
activities and leads our team of cybersecurity professionals responsible for our cybersecurity program and is informed about and monitors the prevention, detection,
mitigation and remediation of cybersecurity incidents as part of our cybersecurity programs. Our CISO and other cybersecurity professionals provide updates regarding
cybersecurity risks to our executive team and board of directors at least quarterly, with more frequent updates regarding cybersecurity-related situations, such as relevant
intelligence indicators, as appropriate. Our Chief Information Officer and CISO also attend weekly executive leadership meetings to give updates on any immediate
cybersecurity threats, risks and regulatory changes, as well as any improvements or impediments to our cybersecurity posture. Our CISO has over thirty years of
experience involving technology in the energy sector, with a focus over the last twenty years on helping companies, including us, improve their technology
infrastructure and cybersecurity programs.
Item 2. Properties
We are headquartered in approximately 98,600 square feet of leased office space located in Houston, Texas. We also have approximately 60,000 square feet of
leased office space in Owensboro, Kentucky. Our operating subsidiaries own their respective pipeline and storage systems in fee. However, substantial portions of these
systems are constructed and maintained on property owned by others pursuant to rights-of-way, easements, permits, licenses or consents. Natural Gas and Natural Gas
Liquids, in Part I, Item 1 of this Annual Report on Form 10-K, contains additional information regarding our material property, including our pipelines and storage
facilities.
Item 3. Legal Proceedings
Refer to Note 6 in Part II, Item 8. of this Annual Report on Form 10-K for a discussion of our legal proceedings.
Item 4. Mine Safety Disclosures
Not applicable.
26

PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Not applicable.
Item 6. [Reserved]
27

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Overview
We operate in the midstream portion of the natural gas and NGLs industry, providing transportation and storage for those commodities. We also provide ethane
supply and transportation services for industrial customers in Louisiana and Texas. 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 and to
facilitate our ethane supply operations, but changes in natural gas and NGLs prices may impact the volumes of natural gas or NGLs transported and stored by our
customers or the ethane supply requirements on our systems. The pricing contained in the purchase and sales agreements associated with our ethane supply services is
generally based on the same ethane commodity index, plus a fixed delivery fee. As a result, except for possible timing differences that may occur when volumes are
purchased in one month and sold in another month, our ethane supply services, like our other businesses, have little to no direct commodity price exposure. Due to the
capital-intensive nature of our business, our operating costs and expenses typically do not vary significantly based upon the volume of products transported, with the
exception of fuel consumed at our compressor stations and not included in a fuel tracker. Refer to Part I, Item 1. Business, for further discussion of the services that we
offer and our customer mix. As further discussed below, our operations are now reported under two business segments: Natural Gas and Natural Gas Liquids.
Firm Agreements
A substantial portion of our transportation and storage capacity is contracted for under firm agreements. For the year ended December 31, 2024, approximately
86% of our revenues were derived from capacity reservation fees under firm contracts or from contracts with MVCs. The table below shows a rollforward of projected
operating revenues under committed firm agreements in place as of December 31, 2023, to December 31, 2024, including agreements for transportation, storage, ethane
supply and other services, over the remaining term of those agreements (in millions):
Total projected operating revenues under committed firm
    agreements as of December 31, 2023
$
9,671.5 
Adjustments for:
Actual revenues recognized from firm agreements in 2024
(1,504.0)
Firm agreements entered into in 2024
6,016.5 
Total projected operating revenues under committed firm
    agreements as of December 31, 2024
$
14,184.0 
(1) As of December 31, 2023, we expected our 2024 revenues from fixed fees under firm agreements to be approximately $1,390.0 million, including agreements
for transportation, storage and other services. Our actual 2024 revenues recognized from fixed fees under firm agreements were approximately $1,504.0
million, an increase of $114.0 million from 2023, primarily resulting from contract renewals at higher rates that occurred in 2024.
(2) During 2024, we entered into approximately $6.0 billion of new firm agreements, of which approximately 78% were associated with new growth projects
executed in 2024.
For firm agreements associated with new growth projects, the associated assets may not be placed into commercial service until sometime in the future.
Further, the table above includes $3.8 billion of estimated revenues that are anticipated under executed precedent transportation agreements for growth projects that are
subject to regulatory approvals. 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 electric power generators, 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, 2024, our top ten customers under committed firm
agreements comprised approximately 62% of our total projected operating revenues and the credit profile associated with our customers comprising the total projected
operating revenues under committed firm agreements was 82% rated as investment grade, 3% rated as non-investment grade and 15% not rated. Note 4 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.
(1)
(2)
28

Pipeline System Maintenance and GHG Emission Reduction Initiatives
We incur substantial costs for ongoing maintenance of our pipeline systems and related facilities, including those incurred for pipeline integrity management
activities, equipment overhauls, general upkeep and repairs. These costs are not dependent on the amount of revenues earned from our transportation services. PHMSA
has developed regulations that require transportation pipeline operators to implement integrity management programs to comprehensively evaluate certain high-risk
areas, known as HCAs, and MCAs, along pipelines and take additional safety measures to protect people and property in these 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 2 areas), whereas HCAs along our NGLs 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. PHMSA has issued a series of significant rulemakings for onshore gas transmission pipelines (e.g., relating to MAOP reconfirmation and
exceedance reporting, the integrity assessment of additional pipeline mileage and the consideration of seismicity as a risk factor in integrity management). In August
2022, PHMSA published a final rule that attempted to expand the Management of Change process, corrosion control requirements for gas transmission pipelines,
requirements that operators ensure no conditions exist following an extreme weather event that could adversely affect the safe operation of the pipeline, and repair
criteria for non-HCAs. Five safety standards included in that rule were challenged by industry trade groups, and in August 2024, the U.S. Court of Appeals for the D.C.
Circuit struck down four of the five challenged safety standards. In September 2023, PHMSA published a proposed rule that, if finalized, would enhance the safety
requirements for gas distribution pipelines and would require updates to distribution integrity management programs, emergency response plans, operations and
maintenance manuals and other safety practices.
Due to the nature of our business, our operations emit various types of GHGs. We seek to 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.
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, when
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 on equipment with emissions performance that exceeds applicable federal standards. Several of our reliability projects over the
last few years have resulted in the replacement of older, higher-emitting compressor drivers with units equipped with advanced emission control systems. As a result,
these projects have resulted in decreases in emissions of nitrogen oxides and other air pollutants.
We have identified the reduction of GHG emissions as an area of focus and look for opportunities to reduce emissions using a variety of strategies, including
the following:
•
evaluating replacing older compression equipment with electric drive compression or new low emission, fuel efficient units when practical;
•
modifying fuel systems on certain reciprocating compression equipment to lower fuel consumption and emissions;
•
conducting emissions surveys and performing maintenance and repairs on identified component leaks;
•
performing annual leak surveys along our pipelines with the aid of helicopters and fixed-wing planes and analytical field surveys when appropriate;
•
performing measurement surveys on all of our compressor stations at least twice a year, exceeding EPA requirements;
•
using optical gas imaging cameras to scan natural gas piping and components at our compressor stations to visualize any leaks in real time;
•
installing continuous monitoring emission detection equipment at certain compression stations;
•
employing experts in air emissions to develop and monitor efforts in reducing emissions;
•
reducing methane emissions vented to the atmosphere from transmission pipeline blowdowns by using existing and portable compression and flaring when
feasible;
29

•
installing repair sleeves and composite wraps where appropriate and practical to avoid pipeline blowdowns;
•
evaluating software tools to optimize our GHG emissions management system;
•
exploring options to replace high-bleed natural gas pneumatic devices with low or zero flow bleed devices; and
•
reducing methane emissions from rod packing seals on reciprocating compressors, where appropriate and practical.
However, we cannot guarantee that we will be able to implement any of the opportunities we may review or explore, or, for any opportunities we do choose to
implement, to implement them in their intended manner or within a specific timeframe or across all operational assets.
These new and any future regulations adopted by PHMSA and efforts to reduce GHG emissions are expected to cause our capital and operating costs to
increase in 2025 and in future years, may cause us to experience operational delays and may result in potential adverse impacts to our ability to reliably serve our
customers. See Part I, Item 1. Business and Item 1A. Risk Factors of this Annual Report on Form 10-K for further information.
Maintenance costs may be capitalized or expensed, depending on the nature of the activities. For any given reporting period, the mix of projects that we
undertake will affect the amounts we record as property, plant and equipment on our Consolidated Balance Sheets or recognize as expenses, which impact our earnings.
We began incurring costs to implement the Mega Rule's requirements in 2021, and based on our current projections, believe that these costs have stabilized. In 2025, we
expect to spend approximately $504.0 million to maintain our pipeline systems, comply with regulations and monitor, control and reduce our GHG emissions, of which
approximately $203.0 million is expected to be maintenance capital. In 2024, we spent $512.7 million on these matters, of which $202.4 million was recorded as
maintenance capital. Refer to Capital Expenditures for more information regarding certain of our maintenance costs.
Consolidated Results of Operations
   
Note 2 in Part II, Item 8. of this Annual Report on Form 10-K contains a summary of our revenue 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 changes in pricing on contract renewals and other factors discussed
elsewhere in this Annual Report on Form 10-K. We acquired Bayou Ethane in September 2023 and began providing ethane supply and transportation services in
connection with that acquisition. As a result of the acquisition, beginning with the fourth quarter 2023, our product sales and product costs were reported separately on
our Consolidated Statements of Income. The pricing contained in the purchase and sales agreements associated with our ethane supply services is generally based on the
same ethane commodity index, plus a fixed delivery fee. As a result, except for possible timing differences that may occur when volumes are purchased in one month
and sold in another month, our ethane supply services, like our other businesses, have little to no direct commodity price exposure. Our operating costs and expenses do
not vary significantly based upon the volume of products transported, with the exception of costs recorded in Costs associated with service revenues. 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.
We use earnings before interest, taxes, depreciation and amortization (EBITDA), a measure not included in accounting principles generally accepted in the U.S.
(GAAP), as a financial measure to assess our operating and financial performance and return on invested capital. We believe that some investors may find this measure
useful in evaluating our performance as EBITDA is a commonly used metric within the midstream industry.
The following table presents a reconciliation of net income to EBITDA (in millions):
 
For the Year Ended December 31,
 
2024
2023
2022
Net income
$
510.9 
$
386.0 
$
342.2 
Income taxes
1.1 
0.8 
0.8 
Depreciation and amortization
424.8 
408.7 
392.3 
Interest expense
182.9 
155.6 
165.9 
Interest income
(31.1)
(12.1)
(3.3)
EBITDA
$
1,088.6 
$
939.0 
$
897.9 
30

Please refer to the disclosures in this Item 7. and Item 1A. Risk Factors of this Annual Report on Form 10-K of items that have impacted, or could impact in the
future, our results of operations.
2024 Compared with 2023
Our net income for the year ended December 31, 2024, increased $124.9 million, or 32%, to $510.9 million compared to $386.0 million for the year ended
December 31, 2023. Our EBITDA increased $149.6 million, or 16%, to $1,088.6 million for the same period. Our net income and EBITDA increased primarily due to
the factors discussed below and included increases in 2024 of $15.0 million and $23.5 million from the acquisition of Bayou Ethane in September 2023.
Operating revenues for the year ended December 31, 2024, increased $410.4 million, or 25%, to $2,028.1 million, compared to $1,617.7 million for the year
ended December 31, 2023. During the fourth quarter 2023, a customer released its NNS into separate transportation and storage services, which resulted in an increase
of storage revenues and a reduction in transportation revenues of $19.1 million for both services for the year ended December 31, 2024, compared to the comparable
period in 2023. Excluding the $19.1 million from the NNS contract, our transportation revenues increased $93.0 million, primarily due to re-contracting at higher rates
and recently completed growth projects; our storage and PAL revenues increased $31.0 million due to favorable market conditions which allowed for contracting at
higher rates; our product sales revenues from the sale of natural gas, ethylene and propane increased by $22.6 million due to opportunistic market conditions; and the
Bayou Ethane acquisition contributed $261.5 million of incremental operating revenues, primarily resulting from ethane product sales.
Operating costs and expenses for the year ended December 31, 2024, increased $278.9 million, or 26%, to $1,370.4 million, compared to $1,091.5 million for
the year ended December 31, 2023. Our operating expenses in 2024 were primarily impacted by the following items:
•
increased expenses from the Bayou Ethane acquisition, which incurred incremental costs of $246.4 million for the year, including $215.5 million of
incremental costs associated with product sales and $8.4 million of incremental depreciation and amortization expense;
•
increased operation and maintenance expenses of $18.4 million primarily due to higher maintenance projects associated with compliance activities; and
•
increased administrative and general costs of $10.0 million from higher employee-related costs.
Our depreciation and amortization expense and interest income and expense in 2024 were impacted by the following items:
•
increased depreciation and amortization expense of $16.1 million from an increased asset base from recently completed growth projects and the Bayou Ethane
acquisition; and
•
increased interest expense of $27.3 million due to the pre-financing of the $600.0 million of debt that matured on December 15, 2024, and increased interest
income of $19.0 million primarily due to income earned from cash invested in short-term investments.
2023 Compared with 2022
Our net income for the year ended December 31, 2023, increased $43.8 million, or 13%, to $386.0 million compared to $342.2 million for the year ended
December 31, 2022. Our EBITDA increased $41.1 million, or 5%, to $939.0 million for the same period. Our net income and EBITDA increased due to the other factors
discussed below, and also included increases of $5.5 million and $8.2 million from the Bayou Ethane acquisition.
Operating revenues for the year ended December 31, 2023, increased $185.7 million, or 13%, to $1,617.7 million, compared to $1,432.0 million for the year
ended December 31, 2022. During the fourth quarter 2023, a customer released its NNS into separate transportation and storage services, which resulted in an increase
of storage revenues and a reduction in transportation revenues of $6.4 million in 2023 compared to 2022. Excluding the $6.4 million from the NNS contract, our
transportation revenues increased $64.7 million, primarily due to re-contracting at higher rates and recently completed growth projects; our storage and PAL revenues
increased $25.3 million due to favorable market conditions; the Bayou Ethane acquisition contributed $101.5 million, primarily resulting from product sales of $99.4
million; and other increases of $4.3 million. These increases were partially offset by $10.1 million from lower sales of our other NGL products.
31

Operating costs and expenses for the year ended December 31, 2023, increased $158.7 million, or 17%, to $1,091.5 million, compared to $932.8 million for the
year ended December 31, 2022. Our operating expenses in 2023 were impacted by the following items:
•
increased expenses of $96.0 million from the Bayou Ethane acquisition, including $88.0 million of costs associated with product sales and $2.7 million from
depreciation and amortization expense;
•
increased operation and maintenance expenses of $28.2 million primarily due to higher maintenance projects associated with the requirements of the Mega
Rule and higher materials and supplies and outside services costs; and
•
increased administrative and general expenses of $23.2 million primarily due to higher employee-related and outside services costs.
Our depreciation and amortization expense and interest income and expense in 2023 were impacted by the following items:
•
increased depreciation and amortization expense of $16.4 million from an increased asset base from recently completed growth projects, the Bayou Ethane
acquisition and a change in the estimated life of certain of our assets; and
•
decreased interest expense of $10.3 million due to lower average outstanding long-term debt and increased interest income of $8.8 million due to income
earned from cash invested in money market funds.
Segment Results
Prior to the fourth quarter 2024, we reported in one single operating and reportable segment – the operation of interstate natural gas and NGLs pipeline systems
and integrated storage facilities in the U.S. In 2024, our previous Chief Executive Officer (CEO) retired and a new CEO was appointed. In the fourth quarter 2024, new
internal reports and information began to be provided to and evaluated by the Chief Operating Decision Maker, our CEO, to reflect the CEO’s method of viewing
information to manage the business, assess performance and allocate resources. As such, our operations are now reported under two business segments: Natural Gas and
Natural Gas Liquids. While our segments provide similar services, their results of operations are primarily organized and managed according to product lines – that of
Natural Gas and that of Natural Gas Liquids. Management uses Segment EBITDA as a basis to assess segment financial performance and allocate resources, which
financial information is contained in Note 18 in Part II, Item 8. of this Annual Report on Form 10-K.
The following table provides our Total Segment EBITDA and a reconciliation to EBITDA (in millions):
 
For the Year Ended December 31,
 
2024
2023
2022
Natural Gas
$
874.7 
$
794.4 
$
752.2 
Natural Gas Liquids
213.9 
144.6 
145.7 
Total Segment EBITDA
$
1,088.6 
$
939.0 
$
897.9 
EBITDA 
$
1,088.6 
$
939.0 
$
897.9 
(1) Refer to the reconciliation of net income to EBITDA in the table under Consolidated Results of Operations.
2024 Compared with 2023
Natural Gas
The Natural Gas segment operating revenues for the year ended December 31, 2024, increased $127.4 million, or 10%, to $1,442.1 million, compared to
$1,314.7 million for the year ended December 31, 2023. EBITDA operating costs and expenses increased $49.2 million in 2024, or 9%, to $573.5 million, compared to
$524.3 million in 2023. EBITDA increased by $80.3 million to $874.7 million in 2024, compared to 2023. Operating revenues in 2024 were impacted by the NNS
contract that was separated into separate transportation and storage agreements discussed above, which resulted in an increase of storage revenues of $19.1 million and a
decrease in transportation revenues by the same amount. Additionally, the Natural Gas segment had intrasegment revenues of $49.4 million and $30.0 million for the
years ended December 31, 2024 and 2023, for which
(1)
32

$31.0 million and $26.1 million of expenses were recognized in Costs associated with service revenues associated with an intrasegment transportation contract and
$18.4 million and $3.9 million were recognized in Administrative and general expenses related to an intrasegment licensing agreement for the same periods. EBITDA
was also impacted by the following items in 2024:
•
increased transportation revenues of $82.8 million primarily due to re-contracting at higher rates and recently completed growth projects;
•
increased storage and PAL revenues of $21.1 million due to favorable market conditions which allowed for re-contracting at higher rates;
•
increased product sales revenues from the sale of natural gas of $5.9 million due to opportunistic market conditions;
•
increased operation and maintenance expenses of $24.0 million related to increased maintenance projects associated with compliance activities; and
•
increased administrative and general expenses of $10.6 million primarily due to higher employee-related and outside services costs.
Natural Gas Liquids
The Natural Gas Liquids segment operating revenues for the year ended December 31, 2024, increased $302.4 million, or 91%, to $635.4 million compared to
$333.0 million for the year ended December 31, 2023. EBITDA operating costs and expenses increased $233.0 million in 2024, or 124%, to $421.5 million, compared
to $188.5 million in 2023. EBITDA increased by $69.3 million to $213.9 million in 2024, compared to 2023. The Natural Gas Liquids segment acquired Bayou Ethane
on September 29, 2023. Bayou Ethane contributed an incremental $23.5 million to EBITDA in 2024, which consisted of $261.5 million of incremental operating
revenues, primarily resulting from ethane product sales, and $238.0  million of incremental EBITDA operating costs and expenses, including $215.5  million of
incremental costs associated with product sales and $22.5 million of other EBITDA operating costs and expenses. In addition to the Bayou Ethane acquisition, EBITDA
was also impacted by the following items in 2024:
•
increased ethylene and propane product sales of $16.7 million due to opportunistic market conditions;
•
increased transportation revenues of $10.2 million due to higher volumes;
•
increased storage of $9.9 million due to re-contracting at higher rates; and
•
decreased operation and maintenance expenses of $5.6 million due to lower maintenance project costs.
2023 Compared with 2022
Natural Gas
The Natural Gas segment operating revenues for the year ended December 31, 2023, increased $84.0 million, or 7%, to $1,314.7 million, compared to $1,230.7
million for the year ended December 31, 2022. EBITDA operating costs and expenses increased $39.5 million in 2023, or 8%, to $524.3 million, compared to $484.8
million in 2022. EBITDA increased by $42.2 million to $794.4 million in 2023, compared to 2022. Operating revenues in 2023 were impacted by the NNS contract that
was separated into separate transportation and storage agreements that was discussed above, which resulted in an increase of storage revenues of $6.4 million and a
decrease in transportation revenues by the same amount. Additionally, the Natural Gas segment had intrasegment revenues of $30.0 million and $24.9 million for the
years ended December 31, 2023 and 2022, for which $26.1 million and $24.9 million of expenses were recognized in Costs associated with service revenues associated
with an intrasegment transportation contract for the same periods. An additional $3.9 million was recognized in Administrative and general expenses related to an
intrasegment licensing agreement for the year ended December 31, 2023. EBITDA was also impacted by the following items in 2023:
•
increased transportation revenues of $59.3 million primarily due to re-contracting at higher rates and recently completed growth projects;
•
increased storage and PAL revenues of $19.5 million due to favorable market conditions, which allowed for re-contracting at higher rates;
•
increased operation and maintenance expenses of $20.5 million primarily due to higher maintenance projects associated with the requirements of the Mega
Rule and higher materials and supplies and outside services costs; and
33

•
increased administrative and general expenses of $18.9 million primarily due to higher employee-related and outside services costs.
Natural Gas Liquids
The Natural Gas Liquids segment operating revenues for the year ended December 31, 2023, increased $106.8 million, or 47%, to $333.0 million, compared to
$226.2 million for the year ended December 31, 2022. EBITDA operating costs and expenses increased $107.9 million in 2023, or 134%, to $188.5 million, compared
to $80.6 million in 2022. EBITDA decreased by $1.1 million to $144.6 million in 2023, compared to 2022. The Bayou Ethane acquisition contributed $8.2 million to
EBITDA in 2023, which primarily consisted of $101.5 million of operating revenues, primarily resulting from ethane product sales, and $93.3 million of EBITDA
operating costs and expenses, including $88.0 million of incremental costs associated with product sales and $5.3  million of other EBITDA operating costs and
expenses. In addition to the Bayou Ethane acquisition, EBITDA was also impacted by the following items in 2023:
•
decreased ethylene and propane product sales of $10.1 million;
•
increased transportation and storage revenues of $11.2 million primarily due to higher rates;
•
increased other revenues from brine supply revenues of $2.9 million due to higher volumes;
•
increased operation and maintenance costs of $7.7 million primarily due to increased outside services and utility costs; and
•
increased administrative and general expenses of $4.3 million primarily due to higher employee-related and outside services costs.
Liquidity and Capital Resources
We are a partnership holding company and derive all of our operating cash flow from our operating subsidiaries. Our principal sources of liquidity include cash
generated from operating activities, our revolving credit facility and debt issuances. Our operating subsidiaries use cash from their respective operations to fund their
operating activities and maintenance capital requirements, service their indebtedness and make advances or distributions to Boardwalk Pipelines. Boardwalk Pipelines
uses cash provided from the operating subsidiaries and, as needed, borrowings under our revolving credit facility to service outstanding indebtedness and make
distributions or advances to us.
At December 31, 2024, we had $117.9 million of cash on hand, no outstanding borrowings under our revolving credit facility, and the full borrowing capacity
of $1.0 billion available to us. In February 2024, we issued $600.0 million aggregate principal amount of Boardwalk Pipelines 5.625% notes due August 2034. The net
proceeds from this offering were used to retire $600.0 million of Boardwalk Pipelines 4.95% notes at their maturity in December 2024. We anticipate that our existing
capital resources, including our cash and cash equivalents, revolving credit facility and our cash flows from operating activities, will be adequate to fund our operations
and capital expenditures for 2025. We may seek to access the debt markets to fund some or all capital expenditures for growth projects or acquisitions, to refinance
maturing debt or for general partnership purposes. As of February 7, 2025, we also have an effective shelf registration statement on file with the SEC under which we
may publicly issue $900.0 million of debt securities, warrants or rights from time to time. In 2024, we paid $400.0 million of distributions to BPHC and Boardwalk GP,
LP. As of December 31, 2024, we have $4.2 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 12 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 5 and 6 contain more information about our other commitments.
34

Credit Ratings
Most of our senior unsecured debt is rated by independent credit rating agencies. The credit ratings affect our ability to access the public and private debt
markets, as well as the terms and the cost of our borrowings. Our ability to satisfy financing requirements or fund planned growth capital expenditures will depend upon
our future operating performance and our ability to access the capital markets, which are affected by economic factors in our industry as well as other general economic,
financial and business factors, some of which are beyond our control. As of February 7, 2025, our credit ratings for our senior unsecured notes (including those issued
by Boardwalk Pipelines) and that of our operating subsidiary having outstanding rated debt were as follows:    
Rating agency
Rating
(Us/Operating
 Subsidiary)
Outlook
(Us/Operating
Subsidiary)
Standard and Poor's
BBB/BBB
Stable/Stable
Moody's Investor Services
Baa2/Baa1
Stable/Stable
Fitch Ratings, Inc.
BBB/BBB
Stable/Stable
Credit ratings reflect the view of a rating agency and are not a recommendation to buy, sell or hold any security, and may be revised or withdrawn at any time
by the rating agency if it determines that the facts and circumstances warrant such a change. Each credit agency's rating should be evaluated independently of any other
credit agency's rating.
Guarantee of Securities of Subsidiaries
Our debt is primarily issued at Boardwalk Pipelines, our wholly owned subsidiary, although we have historically also issued debt at our operating subsidiaries.
As of December 31, 2024, all of the outstanding notes issued by Boardwalk Pipelines (Subsidiary Issuer) and the full amount of the revolving credit facility were
guaranteed by us (Parent Guarantor). The purpose of the guarantees is to help simplify our reporting and capital structure.
We guarantee amounts borrowed under the revolving credit facility, but any amounts borrowed are not subject to the reporting requirements of Rule 13-01 of
Regulation S-X (Rule 13-01). As of December 31, 2024, there were no outstanding borrowings under the revolving credit facility. The following table identifies our
principal amounts outstanding for the debt that is subject to the disclosure rules of Rule 13-01 (in millions):
As of December 31, 2024
Principal amounts guaranteed by Boardwalk Pipeline Partners
    and subject to Rule 13-01 
$
3,150.0 
Principal amounts not guaranteed 
100.0 
Other 
(15.6)
Total debt and finance lease obligation
$
3,234.4 
(1) This represents principal amounts of all outstanding debt at Boardwalk Pipelines subject to the disclosure rules of Rule 13-01 (the Guaranteed Notes).
(2) This represents principal amounts of outstanding debt at Texas Gas.
(3) This represents amounts related to a finance lease and unamortized debt discount and issuance costs.
The Guaranteed Notes are fully and unconditionally guaranteed by the Parent Guarantor on a senior unsecured basis. The guarantees of the Guaranteed Notes
rank equally with all of our existing and future senior debt, including our guarantee of indebtedness under our revolving credit facility. The guarantees will be
effectively subordinated in right of payment to all of our future secured debt to the extent of the value of the assets securing such debt. There are no restrictions on the
Subsidiary Issuer's ability to pay dividends or make loans to the Parent Guarantor. The guaranteed obligations will be terminated with respect to any series of notes if
that series has been discharged or defeased.
Our operating assets, operating liabilities, operating revenues, expenses and other comprehensive income either exist at or are generated by our operating
subsidiaries. The Parent Guarantor and the Subsidiary Issuer have no material assets,
(1)
(2)
(3)
35

liabilities or operations independent of their respective financing activities, which includes the Guaranteed Notes and interest expense of $176.7 million, and includes
advances to and from each other, and their investments in the operating subsidiaries. For these reasons, we meet the criteria in Rule 13-01 to omit the summarized
financial information from our disclosures.
Capital Expenditures
Maintenance capital expenditures for the years ended December 31, 2024, 2023 and 2022, were $202.4 million, $164.5 million and $157.4 million. Refer to
Pipeline System Maintenance and GHG Emission Reduction Initiatives for further information about factors impacting our maintenance capital spending.
Growth capital expenditures for the years ended December 31, 2024, 2023 and 2022, were $190.0 million, $217.9 million and $180.2 million. During the year
ended December 31, 2023, we acquired Bayou Ethane for $355.0 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.
We expect total capital expenditures to be approximately $269.0 million in 2025, including approximately $203.0 million for maintenance capital and $66.0
million related to growth projects. We expect to spend a total of approximately $1.6 billion on our ongoing and announced growth projects, with expected in-service
dates for these projects ranging from 2025 to 2029. Refer to Current Growth Projects in Part I, Item 1. Business of this Annual Report on Form 10-K for further
information on our growth projects.
Critical Accounting Estimates and Policies
Our significant accounting policies are described in Note 2 in Part II, Item 8. of this Annual Report on Form 10-K. The preparation of these consolidated
financial statements in conformity with accounting principles generally accepted in the U.S. requires us to make estimates and assumptions 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
amounts of assets and liabilities and related disclosures of contingent assets and liabilities that are not readily apparent from other sources. We review our estimates and
assumptions on a regular, ongoing basis. Changes in facts and circumstances may result in revised estimates and actual results may differ materially from those
estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the periods in which the facts
that give rise to the revisions become known.
The following accounting policies and estimates are considered critical due to the potentially material impact that the estimates, judgments and uncertainties
affecting the application of these policies might have on our reported financial information.
Goodwill
Goodwill represents the excess of the cost of an acquisition over the fair value of the net identifiable assets acquired and liabilities assumed. Goodwill is tested
for impairment at the reporting unit level at least annually, 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, 2024, our annual goodwill testing date, we elected to perform a qualitative assessment on our two reporting units. The qualitative
assessment included our consideration of, among other things, overall macroeconomic conditions, industry and market considerations, current discount rates and
valuation multiples, overall financial performance, including operating revenues, and other relevant company specific events. Based on the assessment of these items,
we concluded that it is more likely than not that the fair value of our two reporting units exceeded their respective carrying amounts. Accordingly, there were no
indicators of impairment and the quantitative impairment test was not performed.
36

The estimated fair values of our reporting units fluctuate from year to year, and the use of alternate judgments and assumptions could substantially change the
results of our goodwill impairment analysis, including the recognition of an impairment charge in our Consolidated Financial Statements. The quantitative goodwill tests
for 2023 and 2022 did not result in any goodwill impairment charges. 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 could result in the recognition of future impairment charges.
Impairment of Long-Lived Assets (including Tangible and Definite-Lived Intangible Assets)
We evaluate whether the carrying amounts of our long-lived and intangible assets have been impaired when circumstances indicate the carrying amount of
those assets may not be recoverable. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and
eventual disposition of the asset. If the carrying amount is not recoverable, an impairment loss is measured as the excess of the asset's carrying amount over its fair
value. We recognized asset impairment charges of $2.4 million, $0.4 million and $7.5 million for the years ended December 31, 2024, 2023 and 2022.
Forward-Looking Statements
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 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 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 these statements to reflect any change in our expectations or beliefs or any change in events, conditions or circumstances on
which any forward-looking statement is based.
Refer to Part I, Item 1A. of this Annual Report on Form 10-K for additional risks and uncertainties regarding our forward-looking statements.
37

Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Interest Rate Risk
With the exception of our revolving credit facility, for which the interest rates are periodically reset, our debt has been issued at fixed rates. For fixed-rate debt,
changes in interest rates affect the fair value of the debt instruments but do not directly affect our earnings or cash flows. The following table presents market risk
associated with our fixed-rate, long-term debt at December 31, 2024 and 2023 (in millions, except interest rates):
 
2024
2023
Carrying amount of fixed-rate debt
$
3,236.5 
$
3,237.4 
Fair value of fixed-rate debt
$
3,129.7 
$
3,130.3 
100 basis point increase in interest rates and resulting
    fair value of debt decrease
$
133.0 
$
116.4 
100 basis point decrease in interest rates and resulting
    fair value of debt increase
$
141.9 
$
123.7 
Weighted-average interest rate
4.95 %
4.84 %
At December 31, 2024, we had no outstanding debt under variable-rate agreements. At December 31, 2023, we had $25.0 million of outstanding debt under
variable-rate agreements at a weighted-average interest rate of 6.71%.
   
Commodity Risk
For the natural gas and NGLs (other than ethane supply services) that our pipelines transport and store, we do not take title to these products; therefore, we do
not assume the related commodity price risk associated with these products. For our ethane supply services, which require us to enter into ethane sales and purchase
agreements and take title to those products, the pricing contained in those purchase and sales agreements is generally based on the same ethane commodity index, plus a
fixed delivery fee. As a result, except for possible timing differences that may occur when volumes are purchased in one month and sold in another month, our ethane
supply services, like our other businesses, have little to no direct commodity price exposure.
Credit Risk
Our credit exposure generally relates to receivables for services provided, as well as volumes owed by customers for imbalances or gas lent by us to them,
generally under PAL and certain firm services. Natural gas price volatility can materially increase credit risk related to gas loaned to customers. We also have credit risk
related to customers supporting some of our growth projects. If any significant customer of ours should have credit or financial problems resulting in a delay or failure
to pay for services provided by us or repay gas they owe to us, this could have a material adverse effect on our business, financial condition, results of operations and
cash flows.
As of December 31, 2024, 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 9.8 trillion British thermal units (TBtu). Assuming an average market price during December 2024 of $2.98 per million British thermal
unit (MMBtu), the market value of that gas was approximately $29.2 million. As of December 31, 2024, the amount of NGLs owed to our operating subsidiaries due to
imbalances was less than 0.1 million barrels, which had a market value of approximately $0.3 million. As of December 31, 2023, 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 2023 of $2.33 per MMBtu, the market value of that gas was approximately $26.1 million. As of December 31, 2023, there were no outstanding
NGLs imbalances owed to our operating subsidiaries. As of December 31, 2024 and 2023, there were no amounts of ethylene owed to our operating subsidiaries under
exchange agreements.
38

Item 8. Financial Statements and Supplementary Data
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Boardwalk GP, LLC and the Partners of Boardwalk Pipeline Partners, LP
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Boardwalk Pipeline Partners, LP and subsidiaries (the "Company") as of December 31, 2024
and December 31, 2023, the related consolidated statements of income, comprehensive income, changes in partners' capital and cash flows, for each of the three years in
the period ended December 31, 2024, 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, 2024 and 2023, and the results of its operations and its cash flows for each of the three
years in the period ended December 31, 2024, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial
statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are
required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and
Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we
engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over
financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we
express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and
performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial
statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall
presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to
be communicated to the audit council and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially
challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a
whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to
which it relates.
Goodwill — Refer to Notes 2 and 9 to the financial statements
Critical Audit Matter Description
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, 2024, the Company performed a
qualitative assessment for its annual goodwill impairment test of its two reporting units. The qualitative assessment included the Company’s consideration of, among
other things, the overall macroeconomic conditions, industry and market considerations, current discount rates and valuation multiples, overall financial performance,
including operating revenue, and other relevant company specific events. Based on the assessment of these items, the Company concluded that it is more likely than not
that the fair value of the two reporting units exceeded their respective carrying amounts. As of December 31, 2024, the Company had recorded on its Consolidated
Balance Sheets $237.4 million of goodwill.
39

We identified goodwill for Boardwalk Pipeline Partners, LP as a critical audit matter because of the high degree of auditor judgment and an increased extent of
effort when performing audit procedures to evaluate the reasonableness of management’s judgments and assumptions related to its assessment of the impact of
macroeconomic conditions, operating revenues, valuation multiples, and current discount rates, including the need to involve fair value specialists, in determining
whether it was more likely than not that the fair value of the Company’s reporting units was less than their respective carrying amounts.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to management’s consideration of current discount rates, valuation multiples, impact of macroeconomic conditions, and the Company’s
future estimated operating revenues in its qualitative assessment of the fair value of the Company’s two reporting units included the following, among others:
•
We tested the effectiveness of controls over management’s goodwill impairment qualitative assessment, which included management’s review of qualitative
factors affecting each reporting unit.
•
We evaluated management’s ability to accurately forecast future operating revenues by comparing, for each reporting unit, management’s historical forecasts of
operating revenue to (a) actual operating revenues and to (b) current-period forecasts of future operating revenues.
•
We performed breakeven sensitivity analyses over management’s projections to evaluate sensitivity of key assumptions and their effect on fair value.
•
We considered the completeness of management’s identification of qualitative factors as per ASC 350, affecting each reporting unit by considering other
information obtained in our review of board minutes, inquiries with management, substantive testing around operating revenues, and results from our search for
external evidence with respect to the impact of macroeconomic conditions.
•
With the assistance of our fair value specialists, we evaluated the reasonableness of management’s consideration of current discount rates by developing a
range of independent estimates of current discount rates for each reporting unit as of November 30, 2024, and comparing those to current discount rates
selected by management within the qualitative assessment for each reporting unit.
•
With the assistance of our fair value specialists, we evaluated the reasonableness of management’s consideration of valuation multiples by developing
independent valuation multiples using guideline public companies in a similar industry for each of the reporting units.
/s/ Deloitte & Touche LLP
Houston, Texas
February 11, 2025
We have served as the Company's auditor since 2003.
40

BOARDWALK PIPELINE PARTNERS, LP
CONSOLIDATED BALANCE SHEETS
(Millions)
 
December 31,
ASSETS
2024
2023
Current Assets:
 
 
Cash and cash equivalents
$
117.9 
$
20.1 
Receivables:
 
 
Trade, net
210.7 
204.6 
Other
21.4 
24.9 
Gas transportation receivables
7.4 
7.0 
Prepayments
25.2 
24.3 
Other current assets
18.5 
7.8 
Total current assets
401.1 
288.7 
Property, Plant and Equipment:
 
 
Pipelines, storage and other plant
13,667.7 
13,242.3 
Construction work in progress
190.1 
287.2 
Property, plant and equipment, gross
13,857.8 
13,529.5 
Less—accumulated depreciation and amortization
5,045.1 
4,672.9 
Property, plant and equipment, net
8,812.7 
8,856.6 
Other Assets:
 
 
Goodwill
237.4 
237.4 
Gas stored underground
98.3 
99.3 
Other
229.9 
214.4 
Total other assets
565.6 
551.1 
Total Assets
$
9,779.4 
$
9,696.4 
The accompanying notes are an integral part of these consolidated financial statements.
41

BOARDWALK PIPELINE PARTNERS, LP
CONSOLIDATED BALANCE SHEETS
(Millions)
 
December 31,
LIABILITIES AND PARTNERS' CAPITAL
2024
2023
Current Liabilities:
 
 
Payables:
 
 
Trade
$
100.9 
$
113.2 
Affiliates
0.5 
3.4 
Other
21.7 
16.4 
Gas transportation payables
11.7 
7.8 
Accrued taxes, other
67.0 
67.9 
Accrued interest
46.7 
34.2 
Accrued payroll and employee benefits
48.6 
44.0 
Regulatory liabilities
18.3 
15.1 
Other current liabilities
30.2 
60.3 
Total current liabilities
345.6 
362.3 
Long-term debt and finance lease obligation
3,234.4 
3,261.9 
Other Liabilities and Deferred Credits:
 
 
Asset retirement obligations
70.0 
59.2 
Provision for other asset retirement
103.6 
98.1 
Payable to affiliate
4.8 
— 
Other
115.0 
123.8 
Total other liabilities and deferred credits
293.4 
281.1 
Commitments and Contingencies
Partners' Capital:
 
 
Partners' capital
5,978.6 
5,867.7 
Accumulated other comprehensive loss
(72.6)
(76.6)
Total partners' capital
5,906.0 
5,791.1 
Total Liabilities and Partners' Capital
$
9,779.4 
$
9,696.4 
The accompanying notes are an integral part of these consolidated financial statements.
42

BOARDWALK PIPELINE PARTNERS, LP
CONSOLIDATED STATEMENTS OF INCOME
(Millions)
 
For the Year Ended December 31,
 
2024
2023
2022
Operating Revenues:
 
 
 
Transportation
$
1,361.3 
$
1,287.0 
$
1,228.8 
Storage, parking and lending
211.0 
160.9 
129.2 
Product sales
378.7 
100.3 
11.1 
Other
77.1 
69.5 
62.9 
Total operating revenues
2,028.1 
1,617.7 
1,432.0 
Operating Costs and Expenses:
 
 
 
Costs associated with service revenues
29.1 
26.3 
22.4 
Costs associated with product sales
303.5 
87.8 
1.0 
Operation and maintenance
310.3 
281.0 
250.9 
Administrative and general
186.1 
171.9 
147.7 
Depreciation and amortization
424.8 
408.7 
392.3 
(Gain) loss on sale of assets, impairments and other
(5.5)
0.3 
4.0 
Taxes other than income taxes
122.1 
115.5 
114.5 
Total operating costs and expenses
1,370.4 
1,091.5 
932.8 
Operating income
657.7 
526.2 
499.2 
Other Deductions (Income):
 
 
 
Interest expense
182.9 
155.6 
165.9 
Interest income
(31.1)
(12.1)
(3.3)
Miscellaneous other income, net
(6.1)
(4.1)
(6.4)
Total other deductions
145.7 
139.4 
156.2 
Income before income taxes
512.0 
386.8 
343.0 
Income taxes
1.1 
0.8 
0.8 
Net income
$
510.9 
$
386.0 
$
342.2 
The accompanying notes are an integral part of these consolidated financial statements.
43

BOARDWALK PIPELINE PARTNERS, LP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Millions)
 
For the Year Ended December 31,
 
2024
2023
2022
Net income
$
510.9 
$
386.0 
$
342.2 
Other comprehensive income (loss):
 
 
 
Reclassification adjustment transferred to Net income from cash flow hedges
0.1 
0.1 
0.5 
Pension and other postretirement benefit costs, net of tax
3.9 
2.8 
(7.4)
Total Comprehensive Income
$
514.9 
$
388.9 
$
335.3 
The accompanying notes are an integral part of these consolidated financial statements.
44

BOARDWALK PIPELINE PARTNERS, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions)
 
For the Year Ended December 31,
2024
2023
2022
OPERATING ACTIVITIES:
Net income
$
510.9 
$
386.0 
$
342.2 
Adjustments to reconcile net income to cash provided by operations:
 
Depreciation and amortization
424.8 
408.7 
392.3 
Amortization of deferred costs and other
13.8 
18.5 
4.0 
(Gain) loss on sale of assets, impairments and other
(5.5)
0.3 
4.0 
Interest income from short-term investments
(19.8)
— 
— 
Changes in operating assets and liabilities:
 
Trade and other receivables
(2.8)
(7.8)
(16.7)
Gas transportation receivables, storage assets and other product
    inventory
(15.2)
70.6 
(63.4)
Prepayments and other assets
(7.7)
3.1 
(9.8)
Trade and other payables
11.9 
11.5 
15.6 
Other payables, affiliates
0.1 
0.1 
(0.2)
Gas transportation payables
(8.6)
(20.8)
21.0 
Accrued liabilities
17.1 
7.4 
(0.9)
Regulatory assets and liabilities
2.7 
(40.3)
49.3 
Other liabilities
(21.2)
(19.9)
(10.6)
Net cash provided by operating activities
900.5 
817.4 
726.8 
INVESTING ACTIVITIES:
 
 
 
Capital expenditures
(392.4)
(382.4)
(344.3)
Proceeds from sale of operating assets
0.5 
0.3 
1.5 
Acquisition of business
— 
(355.0)
— 
Purchases of short-term investments
(1,102.2)
— 
— 
Proceeds from the maturity of short-term investments
1,122.0 
— 
— 
Net cash used in investing activities
(372.1)
(737.1)
(342.8)
FINANCING ACTIVITIES:
 
 
 
Proceeds from long-term debt, net of issuance cost
593.5 
— 
495.0 
Repayment of borrowings from long-term debt
(600.0)
— 
(600.0)
Proceeds from borrowings on revolving credit facility
170.0 
155.0 
— 
Repayments of borrowings on revolving credit facility,
    including financing fees
(195.0)
(130.6)
(0.6)
Principal payment of finance lease obligation
(0.9)
(0.9)
(0.8)
Advances from affiliates
1.8 
0.7 
1.1 
Distributions paid
(400.0)
(300.0)
(102.2)
Net cash used in financing activities
(430.6)
(275.8)
(207.5)
Increase (decrease) in cash and cash equivalents
97.8 
(195.5)
176.5 
Cash and cash equivalents at beginning of period
20.1 
215.6 
39.1 
Cash and cash equivalents at end of period
$
117.9 
$
20.1 
$
215.6 
The accompanying notes are an integral part of these consolidated financial statements.
45

BOARDWALK PIPELINE PARTNERS, LP
CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL
(Millions)
 
Partners'
Capital
Accumulated Other
Comprehensive (Loss)
Income
Total Partners'
Capital
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 
Add (deduct):
 
 
Net income
386.0 
— 
386.0 
Distributions paid
(300.0)
— 
(300.0)
Other comprehensive income, net of tax
— 
2.9 
2.9 
Balance December 31, 2023
$
5,867.7 
$
(76.6)
$
5,791.1 
Add (deduct):
 
 
Net income
510.9 
— 
510.9 
Distributions paid
(400.0)
— 
(400.0)
Other comprehensive income, net of tax
— 
4.0 
4.0 
Balance December 31, 2024
$
5,978.6 
$
(72.6)
$
5,906.0 
The accompanying notes are an integral part of these consolidated financial statements.
46

BOARDWALK PIPELINE PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1: Corporate Structure
Boardwalk Pipeline Partners, LP (the Company) is a Delaware limited partnership formed in 2005 to own and operate the business conducted by its primary
subsidiary Boardwalk Pipelines, LP (Boardwalk Pipelines) and its operating subsidiaries, Gulf South Pipeline Company, LLC (Gulf South), Texas Gas Transmission,
LLC (Texas Gas), Boardwalk Louisiana Midstream, LLC (Louisiana Midstream), Boardwalk Louisiana Gas Transmission, LLC, Boardwalk Texas Intrastate, LLC,
Boardwalk Petrochemical Pipeline, LLC (Boardwalk Petrochemical), and Boardwalk Ethane Pipeline Company, LLC (together, the operating subsidiaries), which
consists of integrated pipeline and storage systems for natural gas and natural gas liquids, olefins and other hydrocarbons (herein referred to together as NGLs). All of
the Company's operations are conducted by the operating subsidiaries.
As of December 31, 2024, Boardwalk Pipelines Holding Corp. (BPHC), a wholly owned subsidiary of Loews Corporation (Loews), owned directly or
indirectly, 100% of the Company's capital.
Note 2: Basis of Presentation and Significant Accounting Policies
Basis of Presentation
The accompanying consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the
United States of America (U.S.) (GAAP).
Principles of Consolidation
The consolidated financial statements include the Company's accounts and those of its wholly owned subsidiaries after elimination of intercompany
transactions.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of
assets, liabilities, revenues and expenses, disclosure of contingent assets and liabilities and the fair values of certain items. The Company bases its estimates on historical
experience and on various other assumptions that are believed to be reasonable under the circumstances, which form the basis for making judgments about the carrying
amounts of assets and liabilities that are not readily apparent from other sources. Actual results could differ from such estimates.
Segment Information
The Company determines its operating and reportable segments based on how the Chief Operating Decision Maker (CODM), who is the Chief Executive
Officer (CEO), reviews and manages the business, including determining how to allocate resources and assess performance. Historically, the Company concluded that it
had a single operating and reportable segment. Due to changes in its internal reporting and the information evaluated by the CODM, the Company concluded that it
operated in three operating segments as of December 31, 2024. The Company reported the financial results in two reportable segments because two operating segments
met the aggregation criteria to be reported as one reportable segment. The Company’s two reportable segments are Natural Gas and Natural Gas Liquids.
Note 18 contains more information about the Company’s segment information, including the 2023 and 2022 financial information presented under the 2024
reportable segment presentation.
Regulatory Accounting
Most of the Company's natural gas pipeline subsidiaries and its interstate ethane transportation pipeline are regulated by the Federal Energy Regulatory
Commission (FERC). When certain criteria are met, GAAP requires that certain rate-regulated entities account for and report assets and liabilities consistent with the
economic effect of the manner in which independent third-party regulators establish rates (regulatory accounting). This basis of accounting is applicable to operations of
47

the Company's Texas Gas subsidiary, which records certain costs and benefits as regulatory assets and liabilities in order to provide for recovery from or refunds to
customers in future periods, but is not applicable to the operations associated with the Fayetteville and Greenville Laterals due to rates charged under negotiated rate
agreements and a portion of Texas Gas' storage capacity due to the regulatory treatment associated with the rates charged for that capacity.
The Company also applies regulatory accounting for its fuel trackers on Gulf South, under which the value of fuel received from customers paying the
maximum tariff rate and the related value of fuel used in transportation are recorded to a regulatory asset or liability depending on whether Gulf South uses more fuel
than it collects from customers or collects more fuel than it uses. Other than as described for Texas Gas and for the fuel trackers on Gulf South, regulatory accounting is
not applicable to the Company's other FERC-regulated operations.
The Company monitors the regulatory and competitive environment in which it operates to determine whether its regulatory assets continue to be probable of
recovery. If the Company determines that all or a portion of its regulatory assets no longer meets the criteria for recognition as regulatory assets, that portion which is
not recoverable will be written off, net of any regulatory liabilities.
Note 11 contains more information regarding the Company's regulatory assets and liabilities.
Fair Value Measurements
Fair value refers to an exit price that would be received to sell an asset or paid to transfer a liability in an orderly transaction in the principal market in which
the reporting entity transacts based on the assumptions market participants would use when pricing the asset or liability assuming its highest and best use. A fair value
hierarchy has been established that prioritizes the information used to develop those assumptions giving priority, from highest to lowest, to quoted prices in active
markets for identical assets and liabilities (Level 1); observable inputs not included in Level 1, for example, quoted prices for similar assets and liabilities (Level 2); and
unobservable data (Level 3), for example, a reporting entity's own internal data based on the best information available in the circumstances. The Company uses fair
value measurements to account for equity securities, asset retirement obligations (ARO), pension and postretirement benefits other than pension (PBOP) assets and any
impairment charges.
Notes 7 and 13 contain more information regarding fair value measurements.
Cash and Cash Equivalents
Cash equivalents are highly liquid investments with an original maturity of three months or less and are stated at cost plus accrued interest, which approximates
fair value. The Company had no restricted cash at December 31, 2024 and 2023.
Short-Term Investments
During 2024, the Company invested in U.S. treasury bills that were classified as held-to-maturity short-term investments and matured in December 2024.
Income related to the U.S. treasury bills was recorded in Interest Income on the Consolidated Statements of Income. The Company had no outstanding short-term
investments as of December 31, 2024 and 2023.
Trade and Other Receivables
Trade and other receivables are stated at their historical carrying amount, net of allowances for doubtful accounts. The Company establishes an allowance for
doubtful accounts under an expected credit loss model based on historical credit loss experience and specific facts and circumstances. Uncollectible receivables are
written off when a settlement is reached for an amount that is less than the outstanding historical balance or a receivable amount is deemed otherwise unrealizable.
Gas Stored Underground and Gas Receivables and Payables
Certain of the Company's operating subsidiaries have underground gas in storage which is utilized for system management and operational balancing, as well
as for services including firm and interruptible storage associated with certain no-notice and parking and lending (PAL) services. Gas stored underground includes the
historical cost of natural gas volumes owned by the operating subsidiaries, at times reduced by certain operational encroachments upon that gas.
48

The operating subsidiaries provide storage services whereby they store natural gas or NGLs on behalf of customers and also periodically hold customer gas
under PAL services. Since the customers retain title to the gas held by the Company in providing these services, the Company does not record the related gas on the
Consolidated Balance Sheets. Certain of the Company's operating subsidiaries also periodically lend gas and NGLs to customers.
In the course of providing transportation and storage services to customers, the operating subsidiaries may receive different quantities of gas from shippers and
operators than the quantities delivered on behalf of those shippers and operators. This results in transportation and exchange gas receivables and payables, commonly
known as imbalances, which are primarily settled in cash or the receipt or delivery of gas in the future. Settlement of imbalances requires agreement between the
pipelines and shippers or operators as to allocations of volumes to specific transportation contracts and timing of delivery of gas based on operational conditions. The
receivables and payables are valued at market price for operations where regulatory accounting is not applicable and are valued at the historical value of gas in storage
for operations where regulatory accounting is applicable.
Product Inventory
Product inventory, primarily ethane used in the Company’s ethane supply services, is included in Other Current Assets on the Consolidated Balance Sheets.
Product inventory is recorded at the lower of weighted-average cost or net realizable value. At December 31, 2024 and 2023, the Company held $12.7 million and $2.4
million of product inventory.
Materials and Supplies
Materials and supplies are carried at average cost and are included in Other Assets on the Consolidated Balance Sheets. The Company expects its materials and
supplies to be used for projects related to its property, plant and equipment (PPE) and for future growth projects. At December 31, 2024 and 2023, the Company held
approximately $42.4 million and $38.1 million of materials and supplies.
Property, Plant and Equipment and Repair and Maintenance Costs
PPE is recorded at its original cost of construction or fair value of assets purchased. Construction costs and expenditures for major renewals and improvements
which extend the lives of the respective assets are capitalized. Construction work in progress is included in the financial statements as a component of PPE. Repair and
maintenance costs are expensed as incurred.
Depreciation of PPE related to operations for which regulatory accounting does not apply is provided for using the straight-line method of depreciation over the
estimated useful lives of the assets, which range from 3 to 35 years. The ordinary sale or retirement of PPE for these assets could result in a gain or loss being recorded
in the income statement. Depreciation of PPE related to operations for which regulatory accounting is applicable is provided for primarily on the straight-line method at
FERC-prescribed rates over estimated useful lives of 5 to 62 years. Reflecting the application of composite depreciation, gains and losses from the ordinary sale or
retirement of PPE for these assets are not recognized in earnings and generally do not impact PPE, net.
    
Note 8 contains more information regarding the Company's PPE.
Goodwill and Intangible Assets
Goodwill represents the excess of the cost of an acquisition over the fair value of the net identifiable assets acquired and liabilities assumed. Goodwill is tested
for impairment at the reporting unit level at least annually, as of November 30, or more frequently when events occur and circumstances change that would more likely
than not reduce the fair value of a reporting unit below its carrying amount. A reporting entity may perform an optional qualitative assessment on an annual basis to
determine whether events occurred or circumstances changed that would more likely than not reduce the fair value of a reporting unit below its carrying amount. If an
initial qualitative assessment identifies that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, or the optional qualitative
assessment is not performed, a quantitative analysis is performed. The quantitative goodwill impairment test is performed by calculating the fair value of the reporting
unit and comparing it to the reporting unit's carrying amount. If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is not
impaired. However, if the carrying amount of a reporting unit exceeds its fair value, an impairment loss is recognized in an amount equal to that excess, limited to the
total amount of goodwill recorded on the reporting unit.
49

Intangible assets are those assets which provide future economic benefit but have no physical substance. The Company recorded intangible assets for customer
relationships obtained through its acquisitions. The customer relationships, which are included in Other Assets on the Consolidated Balance Sheets, have a finite life and
are being amortized over their estimated useful lives, which is generally 35 years.
Note 9 contains more information regarding the Company's goodwill and intangible assets.
Impairment of Long-lived Assets (including Tangible and Definite-lived Intangible Assets)
The Company evaluates its long-lived and intangible assets for impairment when, in management's judgment, events or changes in circumstances indicate that
the carrying amount of such assets may not be recoverable. When such a determination has been made, management's estimate of undiscounted future cash flows
attributable to the remaining economic useful life of the asset (or asset group) is compared to the carrying amount of the asset (or asset group) to determine whether an
impairment has occurred. If an impairment of the carrying amount has occurred, the amount of impairment recognized in the financial statements is determined by
estimating the fair value of the assets (or asset group) and recording a loss to the extent that the carrying amount exceeds the estimated fair value.
Capitalized Interest and Allowance for Funds Used During Construction (AFUDC)
The Company records capitalized interest, which represents the cost of borrowed funds used to finance construction activities for operations where regulatory
accounting is not applicable. The Company records AFUDC, which represents the cost of funds, including equity funds, applicable to regulated natural gas transmission
plant under construction as permitted by FERC regulatory practices, in connection with the Company's operations where regulatory accounting is applicable.
Capitalized interest and the allowance for borrowed funds used during construction are recognized as a reduction to Interest expense and the allowance for equity funds
used during construction is included in Miscellaneous other income, net on the Consolidated Statements of Income. The following table summarizes capitalized interest
and the allowance for borrowed funds and allowance for equity funds used during construction (in millions):
 
For the Year Ended
December 31,
 
2024
2023
2022
Capitalized interest and allowance for borrowed funds used during construction
$
5.5 
$
3.6 
$
2.2 
Allowance for equity funds used during construction
4.5 
5.7 
6.2 
Income Taxes
The Company is not a taxable entity for federal income tax purposes. As such, it does not directly pay federal income tax. The Company's taxable income or
loss, which may vary substantially from the net income or loss reported on the Consolidated Statements of Income, is includable in the federal income tax returns of
each of its partners. The aggregate difference in the basis of the Company's net assets for financial and income tax purposes is $5.7 billion. The subsidiaries of the
Company directly incur some income-based state taxes which are presented in Income taxes on the Consolidated Statements of Income.
Note 14 contains more information regarding the Company's income taxes.
Asset Retirement Obligations
The accounting requirements for existing legal obligations associated with the future retirement of long-lived assets require entities to record the fair value of a
liability for an ARO in the period during which the liability is incurred. The liability is initially recognized at fair value and is increased with the passage of time as
accretion expense is recorded, until the liability is ultimately settled. The accretion expense is included within Operation and maintenance costs on the Consolidated
Statements of Income. An amount corresponding to the amount of the initial liability is capitalized as part of the carrying amount of the related long-lived asset and
depreciated over the useful life of that asset.
Note 10 contains more information regarding the Company's ARO.
50

Environmental Liabilities
The Company records environmental liabilities based on management's estimates of the undiscounted future obligation for probable costs associated with
environmental assessment and remediation of operating sites. These estimates are based on evaluations and discussions with counsel and operating personnel and the
current known facts and circumstances related to these environmental matters.
Note 6 contains more information regarding the Company's environmental liabilities.
Defined Benefit Plans
The Company maintains postretirement benefit plans for certain employees. The Company funds these plans through periodic contributions which are invested
until the benefits are paid out to the participants, and records an asset or liability based on the overfunded or underfunded status of the plan. The net benefit costs of the
plans are recorded on the Consolidated Statements of Income. Any deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions are
recorded as either a regulatory asset or liability or recorded as a component of accumulated other comprehensive income until those gains or losses are recognized on
the Consolidated Statements of Income.
Note 13 contains more information regarding the Company's pension and other postretirement benefit obligations.
Long-Term Compensation
The Company provides performance awards (Performance Awards) to certain of its employees under its 2018 Long-Term Incentive Plan (2018 LTIP). A
Performance Award is a long-term incentive award with a stated target amount which is payable in cash, after certain adjustments, upon vesting based on certain
specified performance criteria being met.
The Company measures the cost of an award issued in exchange for employee services based on the stated target amount for Performance Awards. All
outstanding awards are required to be settled in cash and are classified as a liability until settlement. The related compensation expense, less forfeitures, is recognized
over the period that employees are required to provide services in exchange for the awards, usually the vesting period.
Note 13 contains more information regarding the Company's long-term compensation.
Partner Capital Accounts
For purposes of maintaining capital accounts, items of income and loss of the Company are allocated among the partners each period, or portion thereof, in
accordance with the partnership agreement, based on their respective ownership interests.
Leases
Operating lease right-of-use assets and lease liabilities are recognized at the lease commencement date based on the present value of lease payments over the
lease term. The discount rate used to determine the commencement date present value of lease payments is typically the Company's secured borrowing rate, as the
implicit rate of most of the Company's leases is not readily determinable. The Company has elected not to record any leases with terms of twelve months or less on the
Consolidated Balance Sheets.
Note 5 contains more information regarding the Company's leases.
Revenue Recognition
Nature of Contracts
The Company primarily earns revenues from contracts with customers by providing transportation and storage services for natural gas and NGLs on a firm and
interruptible basis and providing ethane supply and transportation services for industrial customers in Louisiana and Texas. The Company also provides interruptible
natural gas PAL services. The Company's customers choose, based upon their particular needs, the applicable mix of services depending upon availability of pipeline
and storage capacity, the price of services and the volume and timing of customer requirements. The maximum applicable rates that the majority of the Company's
operating subsidiaries may charge for their services are established through the FERC's cost-
51

based rate-making process; however, the FERC also allows for discounted or negotiated rates as an alternative to cost-based rates. Under the FERC regulations, certain
revenues that the Company's subsidiaries collect may be subject to possible refunds to customers. Accordingly, during a rate case, estimated refund liabilities are
recorded considering regulatory proceedings, advice of counsel and estimated risk-adjusted total exposure, as well as other factors. The Company's service contracts can
range from one to twenty years although the Company may enter into shorter- or longer-term contracts, and services are invoiced monthly with payment from the
customer generally expected within ten to thirty days, depending on the terms of the contract. For the ethane supply contracts, the purchases and sales are with different
counterparties and control transfers at different receipt and delivery points, resulting in the purchases and sales being presented on a gross basis in the Consolidated
Statements of Income.
   
Firm Service Contracts: The Company offers firm services to its customers. The Company's customers can reserve a specific amount of pipeline capacity at
specified receipt and delivery points on the Company's pipeline system (transportation service) or can reserve a specific amount of storage capacity at specified injection
and withdrawal points at the Company's storage facilities (storage service). The Company accounts for firm services as a single promise to stand ready each month of
the contract term to provide the committed capacity for either transportation or storage services when needed by the customer, which represents a series of distinct
monthly services that are substantially the same with the same pattern of transfer to the customer. Although several activities may be required to provide the firm
service, the individual activities do not represent distinct performance obligations because all of the activities must be performed in combination in order for the
Company to provide the firm service.
The transaction price for firm service contracts is comprised of a fixed fee based on the quantity of capacity reserved, regardless of use (capacity reservation
fee), plus variable fees in the form of a usage fee paid on the volume of commodity actually transported or injected and withdrawn from storage. Both the fixed and
usage fees are allocated to the single performance obligation of providing transportation or storage service and recognized over time based upon the output measure of
time as the Company completes its stand-ready obligation to provide contracted capacity and the customer receives and consumes the benefit of the reserved capacity,
which corresponds with the transfer of control to the customer. The fixed fee is recognized ratably over the contract term, representative of the proportion of the
committed stand-ready capacity obligation that has been fulfilled to date, and the usage fee is recognized upon satisfaction of each distinct monthly performance
obligation, consistent with the allocation objective and based upon the level of effort required to satisfy the stand-ready obligation in a given month. Capacity
reservation revenues derived from a firm service contract are generally consistent during the contract term, but can be higher in winter periods than the rest of the year
based upon seasonal rates.
Interruptible Service Contracts: In providing interruptible services to customers, the Company agrees to transport or store natural gas or NGLs for a customer
when capacity is available. The Company does not account for interruptible services with a customer as a contract until the customer nominates for service and the
Company accepts the nomination based upon available pipeline or storage capacity or product availability because there are no enforceable rights and obligations until
that time. The nomination and acceptance process is a daily activity and acceptance is granted based upon priority of service and availability of capacity and products.
Upon acceptance, the Company accounts for interruptible services similarly to its firm services.
The transaction price for interruptible service contracts is comprised of a variable fee in the form of a usage fee paid on the volume of commodity actually
transported or injected and withdrawn from storage. The transaction price is allocated to the single performance obligation of providing interruptible service.
Interruptible service revenues for natural gas transportation and storage are generally recognized over time based on the output measure of volume transported or stored
when services are rendered upon the successful allocation of the services provided to the customer's account, which best depicts the transfer of control to the customer
and satisfaction of the promised service. Interruptible services are recognized in the month services are provided because the Company has a right to consideration from
customers in amounts that correspond directly to the value that the customer receives from the Company's performance. The rates charged may vary on a daily, monthly
or seasonal basis.
Minimum Volume Commitment (MVC) Contracts: Certain of the Company's transportation, storage or ethane supply contracts require customers to transport,
store or purchase a minimum volume of commodity over a specified time period. If a customer fails to meet its MVC for the specified time period, the customer is
obligated to pay a contractually-determined deficiency fee based upon the shortfall between the actual volumes transported, stored or purchased and the MVC for that
period. MVC contracts are generally similar in nature to a firm service contract where the performance obligation is a stand-ready obligation that is a series of distinct
services that are substantially the same with the same pattern of transfer to the customer. The transaction price for a MVC is a fee for the volume of commodity actually
transported, stored or delivered, which is allocated to each distinct monthly performance obligation, consistent with the allocation objective and based upon the level of
effort required to satisfy the obligation of the transacted activities in a given month. Revenues associated with transportation and storage services are generally
recognized over time based on the output measure of volume transported or
52

stored and revenues associated with ethane supply are generally recognized at a point in time based on barrels delivered, with the recognition of the deficiency fee in the
period when it is known the customer cannot make up the deficient volume in the specified period.
   
Other: Certain ethane supply contracts include a stated volume that the Company supplies to customers, and any volume requested above the stated volume is
based on product availability. Revenues for these ethane supply contracts are generally recognized at a point in time when each barrel is transferred to the customer
because the customer is able to direct the use of, and obtain substantially all of the remaining benefits from, the product at that time. Periodically, the Company may also
enter into contracts with customers for the sale of natural gas or NGLs. The Company recognizes revenues for these transactions at the point in time of the physical sale
of the commodity, which corresponds with the transfer of control of the commodity to the customer and the consideration is measured as the stated sales price in the
contract.
Contract Balances
The Company records contract assets primarily related to performance obligations completed but not billed, or partially billed, as of the reporting date. The
Company records contract liabilities, or deferred revenue, when payment is received in advance of satisfying its performance obligations.
Note 3: Acquisition
On September 29, 2023, Boardwalk Resources Company, LLC, a wholly owned subsidiary of the Company, acquired 100% of the equity interests of Williams
Olefins Pipeline Holdco LLC, renamed Boardwalk Ethane Pipeline Holdco, LLC (Bayou Ethane) after the acquisition, from Williams Field Services Group, LLC for
$355.0 million in cash. The acquisition was accounted for as a business combination. For the year ended December 31, 2023, the acquisition contributed $101.5 million
to the Company's operating revenues and $5.5 million to net income.
Pro Forma Financial Information (unaudited)
The following unaudited pro forma results of operations of the Company are presented as if the acquisition occurred on January 1, 2022. Such results are not
necessarily indicative of future results. These pro forma results also do not reflect any cost savings, operating synergies or revenue enhancements that the Company may
achieve or the costs necessary to achieve those objectives (in millions):
Pro Forma
For the Year Ended December 31,
2023
2022
Operating revenue
$
1,962.8 
$
2,253.4 
Net income
393.8 
357.4 
The pro forma information was adjusted for the following items:
•
Operating revenues and expenses were based on actual results for the periods indicated. Acquisition costs were not material and were excluded; and
•
Depreciation and amortization expense was calculated using PPE and intangible asset amounts as determined by the purchase price allocation and estimated
useful lives.
Note 4: Revenues
The Company contracts directly with end-use customers, including electric power generators, local distribution companies, industrial users and exporters of
liquefied natural gas. The Company also contracts with other customers, including producers and marketers of natural gas and interstate and intrastate pipelines, who, in
turn, provide transportation and storage services for end-users. The following table presents the Company's revenues disaggregated by type of service by segment (in
millions):
53

For the Year Ended December 31, 2024
Natural Gas
Natural Gas
Liquids
Eliminations
Total
Revenues from Contracts with Customers
Firm Service 
$
1,353.9 
$
452.6 
$
(31.0)
$
1,775.5 
Interruptible Service
59.1 
0.1 
— 
59.2 
Other revenues 
7.6 
144.9 
— 
152.5 
Total Revenues from Contracts with Customers
1,420.6 
597.6 
(31.0)
1,987.2 
Other operating revenues 
21.5 
37.8 
(18.4)
40.9 
Total Operating Revenues
$
1,442.1 
$
635.4 
$
(49.4)
$
2,028.1 
(1) Revenues earned from contracts with MVCs are included in firm service given the stand-ready nature of the performance obligation and the guaranteed
nature of the fees over the contract term.
(2) For the year ended December 31, 2024, revenues attributable to Bayou Ethane within the Natural Gas Liquids segment were $243.6 million included in firm
service from product sales earned from contracts with MVCs; $114.4 million included in other revenues from product sales earned from contracts with no
MVCs; and $4.9 million included in other operating revenues.
(3) Other operating revenues include certain revenues earned from operating leases, pipeline management fees, intrasegment licensing fees and other activities
that are not considered central and ongoing major business operations of the Company and do not represent revenues earned from contracts with customers.
For the Year Ended December 31, 2023
Natural Gas
Natural Gas
Liquids
Eliminations
Total
Revenues from Contracts with Customers
Firm Service 
$
1,253.1 
$
262.7 
$
(26.1)
$
1,489.7 
Interruptible Service
51.6 
— 
— 
51.6 
Other revenues 
3.4 
36.8 
— 
40.2 
Total Revenues from Contracts with Customers
1,308.1 
299.5 
(26.1)
1,581.5 
Other operating revenues 
6.6 
33.5 
(3.9)
36.2 
Total Operating Revenues
$
1,314.7 
$
333.0 
$
(30.0)
$
1,617.7 
(1) Revenues earned from contracts with MVCs are included in firm service given the stand-ready nature of the performance obligation and the guaranteed
nature of the fees over the contract term.
(2) For the year ended December 31, 2023, revenues attributable to Bayou Ethane within the Natural Gas Liquids segment were $74.9 million included in firm
service from product sales earned from contracts with MVCs; $25.4 million included in other revenues from product sales earned from contracts with no
MVCs; and $1.2 million included in other operating revenues.
(3) Other operating revenues include certain revenues earned from operating leases, pipeline management fees, intrasegment licensing fees and other activities
that are not considered central and ongoing major business operations of the Company and do not represent revenues earned from contracts with customers.
(1)(2)
(2)
(2)(3)
(1)(2)
(2)
(2)(3)
54

For the Year Ended December 31, 2022
Natural Gas
Natural Gas
Liquids
Eliminations
Total
Revenues from Contracts with Customers
Firm Service 
$
1,157.8 
$
174.0 
$
(19.9)
$
1,311.9 
Interruptible Service
61.2 
— 
(5.0)
56.2 
Other revenues
9.4 
20.5 
— 
29.9 
Total Revenues from Contracts with Customers
1,228.4 
194.5 
(24.9)
1,398.0 
Other operating revenues 
2.3 
31.7 
— 
34.0 
Total Operating Revenues
$
1,230.7 
$
226.2 
$
(24.9)
$
1,432.0 
(1) Revenues earned from contracts with MVCs are included in firm service given the stand-ready nature of the performance obligation and the guaranteed
nature of the fees over the contract term.
(2) Other operating revenues include certain revenues earned from operating leases, pipeline management fees and other activities that are not considered central
and ongoing major business operations of the Company and do not represent revenues earned from contracts with customers.
Contract Balances
As of December 31, 2024 and 2023, the Company had receivables recorded in Trade Receivables, net from contracts with customers of $210.7 million and
$204.6 million, contract assets recorded in Other Assets from contracts with a customer of $11.9 million and $6.2 million, and contract liabilities recorded in Other
Current Liabilities (current portion) and Other Liabilities (noncurrent portion) from contracts with customers of $17.9 million and $21.4 million.
As of December 31, 2024, contract liabilities are expected to be recognized through 2040. Significant changes in the contract liability balances during the year
ended December 31, 2024, were as follows (in millions):
Contract Liabilities
Balance as of December 31, 2023
$
21.4 
Revenues recognized that were included in the contract liability
    balances at the beginning of the period
(4.1)
Increases due to cash received, excluding amounts recognized as
    revenues during the period
0.6 
Balance as of December 31, 2024
$
17.9 
(1) As of December 31, 2024 and 2023, $1.8 million and $3.5 million were recorded in Other Current Liabilities (current portion), and $16.1 million and $17.9
million were recorded in Other Liabilities (noncurrent portion).
(1)
(2)
(1)
(1)
55

Significant changes in the contract liability balances during the year ended December 31, 2023, were as follows (in millions):
Contract Liabilities
Balance as of December 31, 2022
$
23.0 
Revenues recognized that were included in the contract liability
    balances at the beginning of the period
(3.9)
Increases due to cash received, excluding amounts recognized as
    revenues during the period
1.8 
Other
0.5 
Balance as of December 31, 2023
$
21.4 
(1) As of December 31, 2023 and 2022, $3.5 million and $3.6 million was recorded in Other Current Liabilities (current portion) and $17.9 million and $19.4
million were recorded in Other Liabilities (noncurrent portion).
Performance Obligations
The following table includes estimated operating revenues expected to be recognized in the future related to agreements that contain performance obligations
that were unsatisfied as of December  31, 2024. The amounts presented primarily consist of fixed fees or MVCs which are typically recognized over time as the
performance obligation is satisfied, in accordance with firm service contracts, or at a point in time as guaranteed minimum fees associated with the performance
obligation are satisfied under certain ethane supply contracts. For the Company's customers that are charged maximum tariff rates related to its FERC-regulated
operating subsidiaries, the amounts below reflect the current tariff rate for such services for the term of the agreements; however, the tariff rates may be subject to future
adjustment. The Company has elected to exclude the following from the table: (a) unsatisfied performance obligations from usage fees associated with its firm services
because of the variable nature of such services; (b) unsatisfied performance obligations from the ethane commodity indexed portion of ethane supply contracts because
of the variable nature of ethane prices, and (c) consideration in contracts that is recognized in revenue as invoiced, such as for interruptible services. The estimated
revenues reflected in the table include estimated revenues that are anticipated under executed precedent transportation agreements for projects that are subject to
regulatory approvals.
In millions
2025
2026
Thereafter
Total
Estimated revenues from contracts with customers
    from unsatisfied performance obligations as of
    December 31, 2024
$
1,484.5 
$
1,294.5 
$
11,214.0 
$
13,993.0 
Operating revenues which are fixed and
    determinable (operating leases)
27.5 
27.5 
136.0 
191.0 
Total projected operating revenues under committed
    firm agreements as of December 31, 2024
$
1,512.0 
$
1,322.0 
$
11,350.0 
$
14,184.0 
(1) In March 2024, the Company executed a 108-year firm storage agreement with a customer. The estimated annual revenue from this contract is $3.1 million
with $328.5 million of unsatisfied performance obligations included in the "Thereafter" column. Per the tariff provisions, this customer was required to
provide 90 days of collateral and the Company can suspend services due to non-payment.
(2) The estimated revenues from contracts with customers from unsatisfied performance obligations as of December 31, 2024, that are anticipated under executed
precedent transportation agreements associated with the Company's growth projects are $3.8 billion.
(1)
(1)
(1)(2)
56

Note 5: Leases
The Company has various operating lease commitments extending through 2058, generally covering office space and equipment rentals, some of which contain
options to renew or extend the lease term. The Company also has a finance lease related to the lease of an office building in Owensboro, Kentucky, entered into in 2013,
that has a fifteen-year term with two renewal options for up to twenty additional years in total.
The components of lease cost were as follows (in millions):
For the Year Ended December 31,
2024
2023
2022
Operating lease cost
$
4.1 
$
3.8 
$
3.8 
Short-term lease cost
5.4 
4.7 
3.1 
Finance lease cost:
      Amortization of right-of-use asset
0.7 
0.7 
0.7 
      Interest on lease liability
0.3 
0.3 
0.3 
        Total lease cost
$
10.5 
$
9.5 
$
7.9 
The following provides supplemental balance sheet information related to the Company's leases:
As of December 31,
2024
2023
Right-of-use assets (in millions)
Operating leases (recorded in Other Assets)
$
24.9
$
18.9
Finance lease (recorded in Property, Plant and Equipment)
2.5
3.2
Lease liabilities (in millions)
Operating leases (recorded in Other Liabilities, current and
    non-current)
25.3
19.6
Finance lease (recorded in Other Current Liabilities and
    Long-term debt and finance lease obligation)
3.6
4.5
Weighted-average remaining lease term (years)
Operating leases
13.6
9.9
Finance lease
3.6
4.6
Weighted-average discount rate
Operating leases
3.95 %
3.20 %
Finance lease
5.89 %
5.89 %
57

The table below presents the maturities of lease liabilities (in millions):
As of December 31, 2024
Operating
Leases
Finance
Lease
2025
$
2.6 
$
1.1 
2026
2.6 
1.1 
2027
2.2 
1.1 
2028
0.8 
0.7 
2029
2.1 
— 
Thereafter
24.4 
— 
Total
34.7 
4.0 
Less: discount
(9.4)
(0.4)
Total lease liabilities
$
25.3 
$
3.6 
Note 6: Commitments and Contingencies
Legal Proceedings and Settlements
The Company and its subsidiaries are parties to various legal actions arising in the normal course of business. Management believes the disposition of these
outstanding legal actions, including the legal actions identified below, will not have a material impact on the Company's financial condition, results of operations or cash
flows.
Mishal and Berger Litigation
On May 25, 2018, plaintiffs Tsemach Mishal and Paul Berger (on behalf of themselves and the purported class, Plaintiffs) initiated a purported class action in
the Court of Chancery of the State of Delaware (the Trial Court) against the following defendants: the Company, Boardwalk GP, LP (Boardwalk GP), Boardwalk GP,
LLC and BPHC (together, Defendants), regarding the potential exercise by Boardwalk GP of its right to purchase the issued and outstanding common units of the
Company not already owned by Boardwalk GP or its affiliates (Purchase Right).
On June 25, 2018, Plaintiffs and Defendants entered into a Stipulation and Agreement of Compromise and Settlement, subject to the approval of the Trial Court
(the Proposed Settlement). Under the terms of the Proposed Settlement, the lawsuit would be dismissed, and related claims against the Defendants would be released by
the Plaintiffs, if BPHC, the sole member of the general partner of Boardwalk GP, elected to cause Boardwalk GP to exercise its Purchase Right for a cash purchase
price, as determined by the Company's Third Amended and Restated Agreement of Limited Partnership, as amended (the Limited Partnership Agreement), and gave
notice of such election as provided in the Limited Partnership Agreement within a period specified by the Proposed Settlement. On June 29, 2018, Boardwalk GP
elected to exercise the Purchase Right and gave notice within the period specified by the Proposed Settlement. On July 18, 2018, Boardwalk GP completed the purchase
of the Company's common units pursuant to the Purchase Right.
On September 28, 2018, the Trial Court denied approval of the Proposed Settlement. On February 11, 2019, a substitute verified class action complaint was
filed in this proceeding, which, among other things, added Loews as a Defendant. The Defendants filed a motion to dismiss, which was heard by the Trial Court in July
2019. In October 2019, the Trial Court ruled on the motion and granted a partial dismissal, with certain aspects of the case proceeding to trial. A trial was held the week
of February 22, 2021, and post-trial oral arguments were held on July 14, 2021.
On November 12, 2021, the Trial Court issued a ruling in the case. The Trial Court held that Boardwalk GP breached the Limited Partnership Agreement and
found that Boardwalk GP was liable to the Plaintiffs for approximately $690.0 million in damages, plus pre-judgment interest (approximately $166.0 million), post-
judgment interest and attorneys' fees. The Trial Court's ruling and damages award was against Boardwalk GP, and not the Company or its subsidiaries.
The Defendants believed that the Trial Court ruling included factual and legal errors. Therefore, on January 3, 2022, the Defendants appealed the Trial Court's
ruling to the Supreme Court of the State of Delaware (the Supreme Court). On January 17, 2022, the Plaintiffs filed a cross-appeal to the Supreme Court contesting the
calculation of damages by the Trial Court. Oral arguments were held on September 14, 2022, and on December 19, 2022, the Supreme Court reversed the Trial
58

Court's ruling and remanded the case to the Trial Court for further proceedings related to claims not decided by the Trial Court's ruling. Briefing by the parties at the
Trial Court on the remanded issues was completed in September 2023. A hearing on the remanded issues was held at the Trial Court in April 2024. In September 2024,
the Trial Court ruled in favor of the Defendants on all of the remanded issues. On October 21, 2024, the Plaintiffs appealed the Trial Court's ruling on the remanded
issues to the Supreme Court. Briefing on the appeal is ongoing and is expected to be completed in March 2025.
City of New Orleans Litigation
Gulf South, along with several other energy companies operating in Southern Louisiana, has been named as a defendant in a petition for damages and
injunctive relief in state district court for Orleans Parish, Louisiana, (Case No. 19-3466) by the City of New Orleans. The case was filed on March 29, 2019. The lawsuit
claims include, among other things, negligence, strict liability, nuisance and breach of contract, alleging that the defendants' drilling, dredging, pipeline and industrial
operations since the 1930s have caused increased storm surge risk, increased flood protection costs and unspecified damages to the City of New Orleans. In October
2020, this case was stayed pending the outcome of a consolidated appeal to the Fifth Circuit Court of Appeals in a similar case. On August 5, 2021, the Fifth Circuit
Court of Appeals ruled in favor of the oil-and-gas defendants in that consolidated appeal, finding that the two cases being appealed should be re-examined in federal
district court since they involve operations that were federally overseen at the time. The ruling reverses a previous decision that allowed the cases to be heard in state
court, which the plaintiffs had sought. As a result of the Fifth Circuit Court of Appeals' decision, it is anticipated that this case will be reviewed in federal district court
to determine whether the case should be heard in that court. Discovery has been initiated.
Gulf South and Texas Gas have been named as defendants in several suits in the State of Louisiana that are similar in nature to the City of New Orleans
Litigation discussed above. These cases were filed in Louisiana state courts and discovery is ongoing. Two of these cases were settled in 2024, which did not have a
material impact to the Company's results of operations or equity.
Environmental and Safety Matters
The Company's operating subsidiaries are subject to federal, state, and local environmental laws and regulations in connection with the operation and
remediation of various operating sites. As of December 31, 2024 and 2023, the Company had an accrued liability of approximately $7.0 million and $10.1 million
related to assessment and/or remediation costs associated with the historical use of polychlorinated biphenyls, petroleum hydrocarbons and mercury. The liability
represents management's estimate of the undiscounted future obligations based on evaluations and discussions with counsel and operating personnel and the current
known facts and circumstances related to these matters. The related expenditures are expected to occur over the next twenty years. As of December 31, 2024 and 2023,
approximately $3.4 million and $6.7 million were recorded in Other Current Liabilities and approximately $3.6 million and $3.4 million were recorded in Other
Liabilities and Deferred Credits.
Clean Air Act and Climate Change
The Company's pipelines and associated facilities are subject to the Clean Air Act (CAA) and comparable state laws and regulations, which regulate the
emission of air pollutants from many sources and impose various compliance monitoring and reporting requirements. Under the CAA, the Company may be required to
obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly
comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions. The need to obtain permits has the potential to delay
the development or expansion of the Company's projects. Over the next several years, the Company may be required to incur certain capital expenditures for air
pollution control equipment or other air emissions related issues. For example, in 2015, the Environmental Protection Agency (EPA) issued a final rule under the CAA,
lowering the National Ambient Air Quality Standard (NAAQS) for ground-level ozone to 70 parts per billion under both the primary and secondary standards to provide
requisite protection of public health and welfare. Since that time, the EPA issued area designations with respect to ground-level ozone, issued final requirements that
apply to state, local and tribal air agencies for implementing the 2015 NAAQS for ground-level ozone and, on December 31, 2020, published notice of a final action to
retain the 2015 ozone NAAQS without revision on a going-forward basis. However, several groups filed litigation over the December 2020 final action and in October
2021, the EPA announced that it would reconsider the December 2020 determination to maintain the November 2015 NAAQS. In August 2023, the EPA announced a
new review of the ozone NAAQS to ensure the standards protect people’s health and reflect the most current, relevant science. The new review will incorporate the
reconsideration of the December 2020 final action. Until a final decision following the review is released, the full extent of the impacts of any new standards are not
clear. Additionally, it is not clear what actions the Trump Administration may take with respect to the review. States are also expected to implement more stringent
regulations that could apply to the Company's
59

operations. Compliance with any final decision could, among other things, require installation of new emission controls on some of the Company's equipment, result in
longer permitting timelines and significantly increase its capital expenditures and operating costs. Additionally, the threat of climate change continues to attract
considerable public, governmental and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international,
national, regional, state and local levels of government to monitor and limit emissions of greenhouse gases (GHGs). These efforts have included consideration of cap-
and-trade programs, carbon taxes, and GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. The EPA has
determined that GHG emissions endanger public health and the environment and, as a result, has adopted regulations under the CAA related to GHG emissions.
Commitments for Construction
The Company's future capital commitments are comprised of binding commitments under purchase orders for materials ordered but not received and firm
commitments under binding construction service agreements. As of December 31, 2024, the commitments were approximately $112.1 million, all of which are expected
to be settled within the next twelve months.
Pipeline Capacity and Storage Agreements
The Company's operating subsidiaries have entered into pipeline capacity and storage agreements with third-party pipelines that allow the operating
subsidiaries to transport gas to off-system markets on behalf of customers or store natural gas. Additionally, in connection with the Bayou Ethane acquisition, the
Company has assumed a pipeline capacity agreement with a third party to facilitate the transportation of ethane and an ethane storage agreement. The Company incurred
expenses of $11.2 million, $5.8 million and $3.2 million related to pipeline capacity and storage agreements for the years ended December 31, 2024, 2023 and 2022.
The table below presents the future commitments related to these agreements as of December 31, 2024 (in millions):
2025
$
8.0 
2026
8.1 
2027
3.0 
2028
0.2 
2029
— 
Thereafter
— 
Total
$
19.3 
Note 7: Fair Value Measurements
Financial Assets and Liabilities
The Company had equity securities recorded at fair value on a recurring basis in Other Current Assets of $1.8 million and $2.3 million as of December 31,
2024 and 2023. The equity securities were received as part of a settlement of a bankruptcy claim. The equity securities were valued based on quoted market prices at
December 31, 2024 and 2023, and were considered Level 1 investments. The Company had no liabilities recorded at fair value on a recurring basis as of December 31,
2024 and 2023.
Financial Assets and Liabilities Not Measured at Fair Value
The following methods and assumptions were used in estimating the fair value amounts included in the disclosures for financial assets and liabilities:
Cash and Cash Equivalents: For cash and short-term financial assets, the carrying amount is a reasonable estimate of fair value due to the short maturity of
those instruments.
Long-Term Debt: The estimated fair value of the Company's publicly traded debt is based on quoted market prices at December 31, 2024 and 2023. The fair
market value of the debt that is not publicly traded is based on market prices of similar
60

debt at December 31, 2024 and 2023. The carrying amount of the Company's variable-rate debt at December 31, 2023, approximated fair value because the instruments
bear a floating market-based interest rate.
   
The carrying amounts and estimated fair values of the Company's financial assets and liabilities which were not recorded at fair value on the Consolidated
Balance Sheets as of December 31, 2024 and 2023, were as follows (in millions):
As of December 31, 2024
 
Estimated Fair Value
Financial Assets
Carrying Amount
Level 1
Level 2
Level 3
Total
   Cash and cash equivalents
$
117.9 
$
117.9 
$
— 
$
— 
$
117.9 
Financial Liabilities
 
 
 
 
 
   Long-term debt
$
3,236.5 
$
— 
$
3,129.7 
$
— 
$
3,129.7 
(1) The carrying amount of long-term debt excluded a $2.7 million long-term finance lease obligation and
$4.8 million of unamortized debt issuance costs.
As of December 31, 2023
Estimated Fair Value
Financial Assets
Carrying Amount
Level 1
Level 2
Level 3
Total
   Cash and cash equivalents
$
20.1 
$
20.1 
$
— 
$
— 
$
20.1 
Financial Liabilities
 
   Long-term debt
$
3,262.4 
$
— 
$
3,155.3 
$
— 
$
3,155.3 
(1) The carrying amount of long-term debt excluded a $3.6 million long-term finance lease obligation and
$4.1 million of unamortized debt issuance costs.
(1)
(1)
61

Note 8: Property, Plant and Equipment
The following table presents the Company's PPE as of December 31, 2024 and 2023 (in millions):
Category
2024
Amount
2024
Weighted-Average
Useful Lives
(Years)
2023
Amount
2023
Weighted-Average
Useful Lives
 (Years)
Depreciable plant:
 
 
 
 
Transmission
$
11,750.7 
38
$
11,405.4 
38
Storage
1,002.1 
39
951.3 
39
Gathering
108.8 
25
106.1 
24
General, intangibles and other
557.7 
20
535.4 
20
Total utility depreciable plant
13,419.3 
38
12,998.2 
37
Non-depreciable:
 
 
 
Construction work in progress
190.1 
 
287.2 
 
Storage
196.8 
 
197.5 
 
Land
51.6 
 
46.6 
 
Total non-depreciable assets
438.5 
 
531.3 
 
Total PPE, gross
13,857.8 
 
13,529.5 
 
Less:  accumulated depreciation and amortization
5,045.1 
 
4,672.9 
 
Total PPE, net
$
8,812.7 
 
$
8,856.6 
 
 
The non-depreciable assets were not included in the calculation of the weighted-average useful lives. 
    
For the years ended December  31, 2024, 2023 and 2022, depreciation expense for PPE was $421.9 million, $406.5 million and $390.4 million and was
recorded in Depreciation and amortization on the Consolidated Statements of Income.
The Company holds undivided interests in certain assets, including the Mobile Bay Pipeline, of which the Company owns 64%, and offshore and other assets,
comprised of pipeline and gathering assets in which the Company holds various ownership interests. In addition, the Company owns 83% of two ethylene wells and
supporting surface facilities in Choctaw, Louisiana, and certain ethylene and propylene pipelines connecting Louisiana Midstream's storage facilities in Choctaw to
chemical manufacturing plants in Geismar, Louisiana.
The proportionate share of investment associated with these interests has been recorded as PPE on the Consolidated Balance Sheets. The Company records its
portion of direct operating expenses associated with the assets in Operation and maintenance expense. The following table presents the gross PPE investment and
related accumulated depreciation for the Company's undivided interests as of December 31, 2024 and 2023 (in millions):
 
2024
2023
 
Gross PPE
Investment
Accumulated
Depreciation
Gross PPE
Investment
Accumulated
Depreciation
Mobile Bay Pipeline
$
15.4 
$
8.8 
$
15.4 
$
8.3 
NGLs pipelines and facilities
55.1 
15.1 
54.6 
13.5 
Offshore and other assets
7.5 
5.7 
13.0 
10.9 
Total
$
78.0 
$
29.6 
$
83.0 
$
32.7 
62

Asset Impairments
The Company recognized asset impairment charges of $2.4 million, $0.4 million and $7.5 million for the years ended December 31, 2024, 2023 and 2022.
Note 9: Goodwill and Intangible Assets
Goodwill
As of December 31, 2024 and 2023, goodwill of $237.4 million was recorded on the Consolidated Balance Sheets, with $163.5 million being attributable to the
Natural Gas reportable segment and $73.9 million to the Natural Gas Liquids reportable segment.
As of November 30, 2024, the Company elected to perform a qualitative assessment for its annual goodwill impairment test of its two reporting units. The
qualitative assessment included the Company’s consideration of, among other things, the overall macroeconomic conditions, industry and market considerations, current
discount rates and valuation multiples, overall financial performance and other relevant company specific events. Based on the assessment of these items, the Company
concluded that it is more likely than not that the fair value of the two reporting units exceeded their respective carrying amounts. Accordingly, there were no indicators
of impairment and quantitative impairment tests were not performed for its two reporting units.
As of November 30, 2023, the Company performed a quantitative annual goodwill impairment test for its two reporting units. The results of the quantitative
goodwill impairment test indicated that the fair value of the Company's reporting units exceeded their carrying amounts. The fair value measurement of the reporting
units was derived based on judgments and assumptions the Company believes market participants would use in assessing the fair value of the reporting units. These
judgments and assumptions included the valuation premise, use of a discounted cash flow model to estimate fair value under an income approach and inputs to the
valuation model. The inputs included the Company's five-year financial plan operating results, including operating revenues, the long-term outlook for growth in natural
gas and NGLs demand, measures of the risk-free rate, equity premium and systematic risk used in the calculation of the applied discount rate under the capital asset
pricing model and views regarding future market conditions, among others. The reasonableness of fair value estimates under the income approach were supported by a
market approach under which the Company applied earnings before interest, income taxes, depreciation and amortization (EBITDA) multiples derived from publicly
available information to each reporting unit's EBITDA.
No impairment charges related to goodwill were recorded for any of the Company's reporting units during 2024, 2023 or 2022.
Intangible Assets
The following table contains information regarding the Company's intangible assets, which includes customer relationships acquired as part of its acquisitions
(in millions):
As of December 31,
2024
2023
Gross carrying amount
$
92.9 
$
93.3 
Accumulated amortization
(24.2)
(21.3)
Net carrying amount
$
68.7 
$
72.0 
63

For the years ended December 31, 2024, 2023 and 2022, amortization expense for intangible assets was $2.9 million, $2.2 million and $1.9 million, and was
recorded in Depreciation and amortization on the Consolidated Statements of Income. Amortization expense for the next five years and in total thereafter as of
December 31, 2024, is expected to be as follows (in millions):
2025
$
3.0 
2026
2.9 
2027
2.9 
2028
2.9 
2029
2.9 
Thereafter
54.1 
Total
$
68.7 
The weighted-average remaining useful life of the Company's intangible assets as of December 31, 2024, was 25 years.
Note 10: Asset Retirement Obligations
The Company has identified and recorded legal obligations associated with the abandonment of certain pipeline and storage assets, brine ponds, offshore
facilities and the abatement of asbestos, consisting of removal, transportation and disposal when removed from certain compressor stations and meter station buildings.
Legal obligations exist for the main pipeline and certain other Company assets; however, the fair value of these obligations cannot be determined because the lives of
the assets are indefinite. As a result, cash flows associated with retirement of the assets cannot be estimated with the degree of accuracy necessary to establish a liability
for the obligations.
The following table summarizes the aggregate carrying amount of the Company's ARO (in millions):
As of December 31,
 
2024
2023
Balance at beginning of year 
$
74.1 
$
71.1 
Liabilities recorded
5.0 
8.4 
Liabilities settled
(9.9)
(10.0)
Accretion expense
2.1 
2.1 
Revision of estimates
0.9 
2.5 
Balance at end of year
72.2 
74.1 
Less:  Current portion of ARO
(2.2)
(14.9)
Long-term ARO
$
70.0 
$
59.2 
For the Company's operations where regulatory accounting is applicable, depreciation rates for PPE are comprised of two components. One component is
based on economic service life (capital recovery) and the other is based on estimated costs of removal (as a component of negative salvage) which is collected in rates
and does not represent an existing legal obligation. The Company has reflected $103.6 million and $98.1 million as of December  31, 2024 and 2023, on the
Consolidated Balance Sheets as Provision for other asset retirement related to the estimated cost of removal collected in rates.
64

Note 11: Regulatory Assets and Liabilities
The amounts recorded as regulatory assets and liabilities on the Consolidated Balance Sheets as of December 31, 2024 and 2023, are summarized in the table
below. The table also includes amounts related to unamortized debt issuance costs and unamortized discount on long-term debt, which while not regulatory assets and
liabilities, are a component of the embedded cost of debt financing utilized in Texas Gas' rate proceedings. The tax effect of the equity component of AFUDC represents
amounts recoverable from rate payers for the tax recorded in regulatory accounting. Certain amounts in the table are reflected as a negative, or a reduction, to be
consistent with the regulatory books of account. The period of recovery for the regulatory assets included in rates varies from one to eighteen years. The remaining
period of recovery for regulatory assets not yet included in rates would be determined in future rate proceedings. None of the regulatory assets shown below were
earning a return as of December 31, 2024 and 2023 (in millions):
As of December 31,
 
2024
2023
Regulatory Assets:
 
 
Pension
$
8.0 
$
8.1 
Tax effect of AFUDC equity
0.1 
0.1 
Other
0.5 
0.5 
Total regulatory assets
$
8.6 
$
8.7 
Regulatory Liabilities:
Cashout and fuel tracker
$
18.3 
$
15.1 
Provision for other asset retirement
103.6 
98.1 
Unamortized debt issuance costs
(0.7)
(1.0)
Unamortized discount on long-term debt
(0.1)
(0.1)
Postretirement benefits other than pension
62.8 
60.6 
Total regulatory liabilities
$
183.9 
$
172.7 
65

Note 12: Financing
Long-Term Debt
The following table presents all long-term debt issuances outstanding as of December 31, 2024 and 2023 (in millions):
 
2024
2023
Notes and Debentures:
 
 
Boardwalk Pipelines
 
 
4.95% Notes due 2024 (Boardwalk Pipelines 2024 Notes)
$
— 
$
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 
500.0 
5.625% Notes due 2034
600.0 
— 
Texas Gas
 
 
7.25% Debentures due 2027
100.0 
100.0 
Total notes and debentures
3,250.0 
3,250.0 
Revolving Credit Facility:
 
 
Boardwalk Pipelines
— 
25.0 
Total revolving credit facility
— 
25.0 
Finance lease obligation
2.7 
3.6 
 
3,252.7 
3,278.6 
Less:
Unamortized debt discount
(13.5)
(12.6)
Unamortized debt issuance costs
(4.8)
(4.1)
Total Long-Term Debt and Finance Lease Obligation
$
3,234.4 
$
3,261.9 
Maturities of the Company's long-term debt for the next five years and in total thereafter are as follows (in millions):
 
2025
$
— 
2026
550.0 
2027
600.0 
2028
— 
2029
500.0 
Thereafter
1,600.0 
Total long-term debt
$
3,250.0 
66

Notes and Debentures
As of December 31, 2024 and 2023, the weighted-average interest rates of the Company's notes and debentures were 4.95% and 4.84%.
For the twelve months ended December 31, 2024, the Company completed the following debt issuance (in millions, except interest rates):
Date of
Issuance
Issuing
Subsidiary
Amount of
 Issuance
Purchaser
Discounts
and
Expenses
Net
Proceeds
 
Interest
Rate
Maturity Date
Interest
 Payable
February 2024
Boardwalk
Pipelines
$
600.0 
$
6.5 
$
593.5 
5.625 %
August 1, 2034
February 1 and
August 1
(1) The net proceeds of this offering were initially invested in U.S. treasury bills and used to retire the Boardwalk Pipelines 2024 Notes due December 2024 at
maturity.
The Company's notes and debentures are redeemable, in whole or in part, at the Company's option at any time, at a redemption price equal to the greater of
100% of the principal amount of the notes to be redeemed or a "make whole" redemption price based on the remaining scheduled payments of principal and interest
discounted to the date of redemption at a rate equal to the U.S. Treasury rate plus 20 to 50 basis points depending upon the particular issue of notes, plus accrued and
unpaid interest, if any. Other customary covenants apply, including those concerning events of default.
The indentures governing the notes and debentures have restrictive covenants which provide that, with certain exceptions, neither the Company nor any of its
subsidiaries may create, assume or suffer to exist any lien upon any property to secure any indebtedness unless the debentures and notes shall be equally and ratably
secured. All of the Company's debt obligations are unsecured. As of December 31, 2024, the Company and its subsidiaries were in compliance with their covenants
under the indentures.
Revolving Credit Facility
The Company has a revolving credit facility that includes Boardwalk Pipelines, Texas Gas and Gulf South as borrowers (Borrowers) that is evidenced by a
credit agreement. Interest is determined, at the Company's election, by reference to (a) the base rate which is the highest of (1) the prime rate, (2) the federal funds rate
plus 0.50% and (3) the one month term Secured Overnight Financing Rate plus 1.00%, or (b) the term Secured Overnight Financing Rate plus a flat 10 basis point credit
spread adjustment across all available interest periods. The credit agreement provides for a quarterly commitment fee charged on the average daily unused amount of the
revolving credit facility ranging from 0.10% to 0.275% which is determined based on the individual Borrower's credit rating from time to time. The revolving credit
facility has a borrowing capacity of $1.0 billion through May 27, 2027, and a borrowing capacity of $912.2 million from May 28, 2027, to May 26, 2028.
The credit agreement contains various restrictive covenants and other usual and customary terms and conditions, including restrictions regarding the incurrence
of additional debt, the sale of assets and sale-leaseback transactions. The financial covenants under the credit agreement require the Company and its subsidiaries to
maintain, among other things, a ratio of total consolidated debt to consolidated EBITDA (as defined in the credit agreement) measured for the previous twelve months
of not more than 5.0 to 1.0, or up to 5.5 to 1.0 for (i) the quarter in which the consummation of a qualified acquisition or series of acquisitions, where the purchase price
exceeds $100.0 million over a rolling 12-month period and (ii) the three quarters following the qualified acquisition quarter. The Company and its subsidiaries were in
compliance with all covenant requirements under the credit agreement as of December 31, 2024.
As of December 31, 2024, the Company had no outstanding borrowings under its revolving credit facility and had the full borrowing capacity of $1.0 billion
available. As of December 31, 2023, outstanding borrowings under the Company's revolving credit facility were $25.0 million, with a weighted-average interest rate of
6.71%. As of February 7, 2025, the Company had no outstanding borrowings and $1.0 billion of available borrowing capacity under its revolving credit facility.
(1)
67

Cash Distributions    
Cash distributions the Company paid to BPHC and Boardwalk GP were $400.0 million, $300.0 million and $102.2 million for the years ended December 31,
2024, 2023 and 2022.
Note 13: Employee Benefits
Retirement Plans
Defined Benefit Retirement Plans (Retirement Plans)
Texas Gas employees hired prior to November 1, 2006, are covered under a non-contributory, defined benefit pension plan (Pension Plan). The Texas Gas
Supplemental Retirement Plan (SRP) provides pension benefits for the portion of an eligible employee's pension benefit under the Pension Plan that becomes subject to
compensation limitations under the Internal Revenue Code. Collectively, the Company refers to the Pension Plan and the SRP as Retirement Plans. The Company uses a
measurement date of December 31 for the Retirement Plans.
As a result of the Texas Gas rate case settlement in 2006, the Company is required to fund the amount of annual net periodic pension cost associated with the
Pension Plan, including a minimum of $3.0 million, which is the amount included in rates. In 2024 and 2023, the Company funded $3.2 million and $4.9 million to the
Pension Plan and expects to fund an additional $3.0 million to the plan in 2025. In 2024 and 2023, no SRP payments were made.
The Company recognizes in expense each year the actuarially determined amount of net periodic pension cost associated with the Retirement Plans, including a
minimum amount of $3.0 million related to its Pension Plan, in accordance with the 2006 rate case settlement. Texas Gas is permitted to seek future rate recovery for
amounts of annual Pension Plan costs in excess of $6.0 million and is precluded from seeking future recovery of annual Pension Plan costs between $3.0 million and
$6.0 million. As a result, the Company would recognize a regulatory asset for amounts of annual Pension Plan costs in excess of $6.0 million and would reduce its
regulatory asset to the extent that annual Pension Plan costs are less than $3.0 million. Annual Pension Plan costs between $3.0 million and $6.0 million will be charged
to expense.
Postretirement Benefits Other Than Pension
Texas Gas provides postretirement medical benefits and life insurance to retired employees who were employed full time, hired prior to January 1, 1996, and
have met certain other requirements. In 2024 and 2023, the Company contributed $0.2 million and $0.1 million to the PBOP plan. The PBOP plan is in an overfunded
status; therefore, the Company does not expect to make any contributions to the plan in 2025. The Company does not anticipate that any plan assets will be returned to
the Company during 2025. The Company uses a measurement date of December 31 for its PBOP plan.
68

Projected Benefit Obligation, Fair Value of Assets and Funded Status
The projected benefit obligation, fair value of assets, funded status and the amounts not yet recognized as components of net periodic pension and
postretirement benefits cost for the Retirement Plans and PBOP at December 31, 2024 and 2023, were as follows (in millions):
 
Retirement Plans
PBOP
 
For the Year Ended
December 31,
For the Year Ended December 31,
 
2024
2023
2024
2023
Change in benefit obligation:
 
 
 
 
Benefit obligation at beginning of period
$
88.0 
$
86.4 
$
23.4 
$
23.7 
Service cost
1.9 
1.9 
— 
— 
Interest cost
4.0 
4.1 
1.1 
1.2 
Plan participants' contributions
— 
— 
1.0 
1.0 
Actuarial (gain) loss
(2.1)
4.0 
(0.1)
2.3 
Benefits paid
(0.5)
(0.5)
(4.1)
(4.8)
Settlements
(8.2)
(7.9)
— 
— 
Benefit obligation at end of period
$
83.1 
$
88.0 
$
21.3 
$
23.4 
Change in plan assets:
 
 
 
 
Fair value of plan assets at beginning of period
$
83.3 
$
77.6 
$
82.3 
$
81.2 
Actual return on plan assets
6.6 
9.2 
3.1 
4.8 
Company's contribution
3.2 
4.9 
0.2 
0.1 
Plan participants' contributions
— 
— 
1.0 
1.0 
Benefits paid
(0.5)
(0.5)
(4.1)
(4.8)
Settlements
(8.2)
(7.9)
— 
— 
Fair value of plan assets at end of period
$
84.4 
$
83.3 
$
82.5 
$
82.3 
Funded status
$
1.3 
$
(4.7)
$
61.2 
$
58.9 
Items not recognized as components of net periodic cost:
 
 
 
Net actuarial loss
$
6.8 
$
12.7 
$
2.5 
$
3.0 
As of December 31, 2024, the Retirement Plans and PBOP were in an overfunded status. The following aggregate information relates only to the underfunded
plans as of December 31, 2023 (in millions):
Retirement Plans
 
For the Year Ended
December 31,
 
2023
Projected benefit obligation
$
88.0 
Accumulated benefit obligation
84.6 
Fair value of plan assets
83.3 
69

Components of Net Periodic Benefit Cost
Components of net periodic benefit cost for both the Retirement Plans and PBOP for the years ended December 31, 2024, 2023 and 2022, were as follows (in
millions):
 
Retirement Plans
PBOP
 
For the Year Ended
December 31,
For the Year Ended
December 31,
 
2024
2023
2022
2024
2023
2022
Service cost
$
1.9 
$
1.9 
$
2.2 
$
— 
$
— 
$
— 
Interest cost
4.0 
4.1 
3.1 
1.1 
1.2 
0.8 
Expected return on plan assets
(3.9)
(3.6)
(5.3)
(2.6)
(2.4)
(1.8)
Amortization of prior service cost
0.1 
0.1 
0.1 
— 
— 
— 
Amortization of unrecognized net loss
0.3 
1.2 
0.7 
— 
— 
— 
Settlement charge
0.7 
1.3 
2.9 
— 
— 
— 
Regulatory asset decrease
0.1 
— 
— 
— 
— 
— 
Net periodic benefit cost (credit)
$
3.2 
$
5.0 
$
3.7 
$
(1.5)
$
(1.2)
$
(1.0)
Due to the Texas Gas rate case settlement in 2006, Texas Gas is permitted to seek future rate recovery for amounts of annual Pension Plan costs in excess of
$6.0 million.
Estimated Future Benefit Payments
The following table shows benefit payments, which reflect expected future service, as appropriate, which are expected to be paid for both the Retirement Plans
and PBOP (in millions):
 
Retirement Plans
PBOP
2025
$
19.6 
$
2.0 
2026
11.4 
1.9 
2027
10.8 
1.8 
2028
8.3 
1.7 
2029
6.9 
1.6 
2030-2034
17.8 
6.9 
Weighted-Average Assumptions
Weighted-average assumptions used to determine benefit obligations for the years ended December 31, 2024 and 2023, were as follows:
 
Retirement Plans
PBOP
For the Year Ended
December 31,
For the Year Ended
December 31,
 
2024
2023
2024
2023
 
Pension
SRP
Pension
SRP
Discount rate
5.35 %
5.25 %
4.90 %
4.90 %
5.60 %
5.10 %
Expected return on plan assets
5.50 %
5.50 %
5.00 %
5.00 %
3.37 %
3.25 %
Rate of compensation increase
4.00%-4.50%
4.00%-4.50%
3.00%-3.50%
3.00%-3.50%
— %
— %
70

Weighted-average assumptions used to determine net periodic benefit cost for the periods indicated were as follows:
 
Retirement Plans
PBOP
For the Year Ended
December 31,
For the Year Ended
December 31,
 
2024
2023
2022
2024
2023
2022
Pension
SRP
Pension
SRP
Pension
SRP
Discount rate
(1)
5.25 %
(1)
4.90 %
(1)
(2)
5.10 %
5.40 %
2.90 %
Expected return on plan assets
5.00%
5.00 %
5.00%
5.00 %
6.25%
6.25 %
3.25 %
2.99 %
2.01 %
Rate of compensation increase
3.00% -
3.50%
3.00% -
3.50%
3.00% -
4.50%
3.00% -
4.50%
3.00%
3.00 %
— %
— %
— %
(1) Pension expense was remeasured quarterly in 2024, 2023 and 2022. The quarterly remeasurements for each quarter in 2024, 2023 and 2022 were as
follows: Quarter 1: 5.25%, 5.35% and 3.00%; Quarter 2: 5.40%, 5.15% and 4.10%; Quarter 3: 4.80%, 5.45% and 4.65%; and Quarter 4: 5.35%, 4.90%
and 5.30%.
(2) SRP expense was remeasured with discount rates of 4.15% at June 30, 2022, and 5.30% at December 31, 2022, to reflect settlements.
In determining the discount rate assumption, current market and liability information is utilized, including a discounted cash flow analysis of the pension and
postretirement obligations. In particular, the basis for the discount rate selection was the yield on indices of highly rated fixed income debt securities with durations
comparable to that of the Company's plan liabilities. The yield curve was applied to expected future retirement plan payments to adjust the discount rate to reflect the
cash flow characteristics of the plans. The yield curves and indices evaluated in the selection of the discount rate were comprised of high-quality corporate bonds that
are rated AA by an accepted rating agency.
The expected long-term rate of return for plan assets is determined based on widely-accepted capital market principles, long-term return analysis for global
fixed income and equity markets as well as the active total return oriented portfolio management style. Long-term trends are evaluated relative to market factors such as
inflation, interest rates and fiscal and monetary policies, in order to assess the capital market assumptions as applied to the plan. Consideration of diversification needs
and rebalancing is maintained.
Pension Plan and PBOP Asset Allocation and Investment Strategy
Pension Plan
The Pension Plan assets are held in the Texas Gas Trust, established by Texas Gas, which manages and administers the Pension Plan. The Texas Gas Trust
assets are measured at fair value. Equity securities are publicly traded securities which are valued using quoted market prices and are considered Level 1 investments
under the fair value hierarchy. Short-term investments that are actively traded or have quoted prices, such as money market funds or treasury bills, are considered Level
1 investments. Fixed income mutual funds include highly liquid government securities and exchange traded bonds, valued using quoted market prices, and are
considered Level 1 investments. Tax-exempt securities are valued using a methodology based on information generated by market transactions involving identical or
comparable assets, a discounted cash flow methodology or a combination of both when necessary. Common inputs for these securities, which are considered Level 2
investments, include pricing for similar securities, marketplace quotes, benchmark yields, spreads off benchmark yields, interest rates, U.S. Treasury or swap curves and
other pricing models utilizing observable inputs.
71

The following table sets forth, by level within the fair value hierarchy, a summary of the Texas Gas Trust's assets measured at fair value on a recurring basis at
December 31, 2024 (in millions):
 
Pension Plan Trust Assets
 
Level 1
Level 2
Level 3
Total
Equity securities
$
35.9 
$
— 
$
— 
$
35.9 
Short-term investments
8.4 
— 
— 
8.4 
Fixed income mutual funds
40.1 
— 
— 
40.1 
Total assets
$
84.4 
$
— 
$
— 
$
84.4 
The following table sets forth, by level within the fair value hierarchy, a summary of the Texas Gas Trust's assets measured at fair value on a recurring basis at
December 31, 2023 (in millions):
 
Pension Plan Trust Assets
 
Level 1
Level 2
Level 3
Total
Equity securities
$
34.6 
$
— 
$
— 
$
34.6 
Short-term investments
17.3 
— 
— 
17.3 
Fixed income mutual funds
26.3 
— 
— 
26.3 
Tax-exempt securities
— 
5.1
— 
5.1 
Total assets
$
78.2 
$
5.1 
$
— 
$
83.3 
PBOP
The PBOP plan assets are held in a trust and are measured at fair value. Short-term investments and other assets that are actively traded or have quoted prices,
such as money market or mutual funds, are considered Level 1 investments. Fixed income securities, such as tax-exempt securities and corporate bonds, and asset-
backed securities are valued using a methodology based on information generated by market transactions involving identical or comparable assets, a discounted cash
flow methodology or a combination of both when necessary. Common inputs for these securities, which are considered Level 2 investments, include pricing for similar
securities, marketplace quotes, benchmark yields, spreads off benchmark yields, interest rates, U.S. Treasury or swap curves and other pricing models utilizing
observable inputs. Other assets and other liabilities are primarily pending sale and purchase transactions for certain investments that were executed on the last day of the
year and not settled until the following year.
The following table sets forth, by level within the fair value hierarchy, a summary of the PBOP trust investments measured at fair value on a recurring basis at
December 31, 2024 (in millions):
 
PBOP Trust Assets
 
Level 1
Level 2
Level 3
Total
Short-term investments
$
1.6 
$
— 
$
— 
$
1.6 
Other assets
15.7 
— 
— 
15.7 
Asset-backed securities
— 
0.5 
— 
0.5 
Corporate bonds
— 
47.8 
— 
47.8 
Tax-exempt securities
— 
34.9 
— 
34.9 
Total assets
$
17.3 
$
83.2 
$
— 
$
100.5 
Other liabilities
(18.0)
— 
— 
(18.0)
Total liabilities
$
(18.0)
$
— 
$
— 
$
(18.0)
72

The following table sets forth, by level within the fair value hierarchy, a summary of the PBOP trust investments measured at fair value on a recurring basis at
December 31, 2023 (in millions):
 
PBOP Trust Assets
 
Level 1
Level 2
Level 3
Total
Short-term investments
$
12.8 
$
— 
$
— 
$
12.8 
Other assets
2.1 
— 
— 
2.1 
Asset-backed securities
— 
0.8 
— 
0.8 
Corporate bonds
— 
67.0 
— 
67.0 
Tax-exempt securities
— 
38.9 
— 
38.9 
Total assets
$
14.9 
$
106.7 
$
— 
$
121.6 
Other liabilities
(39.3)
— 
— 
(39.3)
Total liabilities
$
(39.3)
$
— 
$
— 
$
(39.3)
    
Investment Strategy
Pension Plan: The Company employs a total-return approach using a mix of equities and fixed income securities designed to maximize the long-term return on
plan assets for a prudent level of risk and generate cash flows adequate to meet plan requirements. The intent of this strategy is to minimize plan expenses by generating
investment returns that exceed the growth of the plan liabilities over the long run. Risk tolerance is established through careful consideration of the plan liabilities, plan
funded status and corporate financial conditions. The target allocation of plan assets is 85% of the investment portfolio to equity and fixed income securities, with the
remainder primarily invested in cash. Investment risk is monitored through annual liability measurements, periodic asset and liability studies and quarterly investment
portfolio reviews.
PBOP: The investment strategy for the PBOP assets is to reduce the volatility of plan investments while protecting the initial investment given the overfunded
status of the plan. The Company uses a broad array of public and private assets and investment vehicles to achieve a return that is targeted to meet or exceed the plan
blended benchmark indices. At December 31, 2024 and 2023, the investment portfolio contained a diversified blend of fixed income securities, such as tax-exempt
securities and corporate bonds, asset-backed securities, short-term securities and other assets.
Defined Contribution Plan
Texas Gas employees hired on or after November 1, 2006, and all other employees of the Company are provided retirement benefits under a defined
contribution plan, which also provides 401(k) plan benefits to its participants. Costs related to the Company's defined contribution plan were $14.7 million, $14.0
million and $12.7 million for the years ended December 31, 2024, 2023 and 2022.
Long-Term Incentive Compensation Plans
The 2018 LTIP provides for grants of Performance Awards to selected employees of the Company. A Performance Award is a long-term incentive award with a
stated target amount which is payable in cash, after adjustments, upon vesting based on certain specified performance criteria being met. In the case of retirement, any
outstanding and unvested awards would become fully vested upon retirement and the Performance Awards will be paid at the original vesting date. In 2024 and 2023,
the Company granted to certain employees $17.2 million and $16.3 million of Performance Awards. The Company recorded compensation expense of $17.1 million,
$14.2 million and $12.3 million related to Performance Awards for the years ended December 31, 2024, 2023 and 2022, and had $10.5 million and $9.8 million of
remaining unrecognized compensation expense related to Performance Awards as of December 31, 2024 and 2023.
73

Note 14: Income Taxes
The Company is not a taxable entity for federal income tax purposes. The following is a summary of the provision for income taxes for the years ended
December 31, 2024, 2023 and 2022 (in millions):
 
For the Year Ended December 31,
 
2024
2023
2022
Current expense:
 
 
 
State
$
0.8 
$
0.8 
$
0.8 
Deferred provision:
 
 
 
State
0.3 
— 
— 
Income taxes
$
1.1 
$
0.8 
$
0.8 
The Company's tax years 2021 through 2024 remain subject to examination by the Internal Revenue Service and the states in which it operates. There were no
differences between the provision at the statutory rate to the income tax provision at December 31, 2024, 2023 and 2022. As of December 31, 2024 and 2023, there were
no significant deferred income tax assets or liabilities.
Note 15: Credit Risk
Major Customers
For the years ended December 31, 2024, 2023 and 2022, no customer comprised 10% or more of the Company's operating revenues.
Gas Loaned to Customers
Natural gas price volatility can cause changes in credit risk related to gas and NGLs loaned to customers. As of December 31, 2024, the amount of gas owed to
the Company's operating subsidiaries due to gas imbalances and gas loaned under PAL and certain firm service agreements was approximately 9.8 trillion British
thermal units (TBtu). Assuming an average market price during December 2024 of $2.98 per million British thermal unit (MMBtu), the market value of that gas was
approximately $29.2 million. As of December 31, 2024, the amount of NGLs owed to the Company's operating subsidiaries due to imbalances was less than 0.1 million
barrels, which had a market value of approximately $0.3 million. As of December 31, 2023, the amount of gas owed to the Company's operating subsidiaries due to gas
imbalances and gas loaned under PAL and certain firm service agreements was approximately 11.2 TBtu. Assuming an average market price during December 2023 of
$2.33 per MMBtu, the market value of that gas was approximately $26.1 million. As of December 31, 2023, there were no outstanding NGLs imbalances owed to the
Company's operating subsidiaries. As of December 31, 2024 and 2023, there were no amounts of ethylene owed to the Company's operating subsidiaries under
exchange agreements. If any significant customer should have credit or financial problems resulting in a delay or failure to pay for services provided or repay the gas
owed to the operating subsidiaries, it could have a material adverse effect on the Company's financial condition, results of operations and cash flows.
Note 16: Related Party Transactions
Loews provides a variety of corporate services to the Company under services agreements, including risk management, finance and accounting, legal, tax and
corporate development services, and charges the Company for allocated overheads. The Company incurred charges related to these services of $5.4 million, $4.3 million
and $3.7 million for the years ended December 31, 2024, 2023 and 2022, which were recorded in Administrative and general on the Consolidated Statements of
Income.
   
Total distributions paid to BPHC and Boardwalk GP were $400.0 million, $300.0 million and $102.2 million for the years ended December 31, 2024, 2023 and
2022.
       
74

Note 17: Supplemental Disclosure of Cash Flow Information (in millions):
 
For the Year Ended December 31,
 
2024
2023
2022
Cash paid during the period for:
 
 
 
Amounts included in the measurement of operating lease liabilities
$
4.2 
$
4.9 
$
3.7 
Amounts included in the measurement of finance lease liability
1.1 
1.1 
1.1 
Interest (net of amount capitalized)
162.1 
147.3 
156.3 
Income taxes, net
0.8 
0.7 
0.6 
Non-cash investing activities:
 
 
 
Accounts payable and PPE
30.4 
47.7 
44.4 
Right-of-use asset obtained in exchange for lease obligations
9.9 
3.4 
0.2 
Gas stored underground and PPE
— 
47.8 
— 
Note 18: Reportable Segments
Identification of Segments
Prior to the fourth quarter 2024, the Company reported in one single operating and reportable segment – the operation of interstate natural gas and NGLs
pipeline systems and integrated storage facilities in the U.S. In 2024, the Company’s previous CEO retired and a new CEO was appointed. In the fourth quarter 2024,
new internal reports and information began to be provided to and evaluated by the CODM, the CEO, to reflect the CEO’s method of viewing information to manage the
business, assess performance, and allocate resources. This change in financial information provided to the CEO required the Company to reassess its operating and
reportable segments.
At the end of the fourth quarter 2024, the Company completed the reassessment of its segment reporting. Based on the reassessment, the Company identified
three operating segments in accordance with ASC 280, Segment Reporting (ASC 280). They are: (1) Texas Gas; (2) Gulf South and the Company’s other natural gas
businesses; and (3) Louisiana Midstream, Boardwalk Petrochemical and Bayou Ethane (collectively, Natural Gas Liquids).
The Company aggregated the Texas Gas operating segment and the Gulf South and the Company’s other natural gas businesses operating segment into one
reportable segment in accordance with ASC 280, because the Company concluded that: (1) both operating segments had similar economic characteristics; (2) both
operating segments had similar product and service lines, customer base, production processes, distribution methods, and regulatory environments; and (3) aggregation
would be consistent with the objectives and basic principles of ASC 280.
Accordingly, as of December 31, 2024, the Company has the following two reportable segments, which comprise 100% of the Company’s operating revenues.
The segments are generally organized and managed according to products.
•
Natural Gas (Texas Gas, Gulf South and the Company’s other natural gas businesses): This segment consists of the ownership and operation of the Company’s
interstate and intrastate natural gas pipelines and storage facilities. This segment earns revenues from contracts with customers by providing transportation and
storage services for natural gas on a firm and interruptible basis.
•
Natural Gas Liquids: This segment consists of the ownership and operation of the Company’s interstate and intrastate NGLs pipelines and storage facilities and
the operations of brine supply services and NGL marketing activities, which primarily consist of purchases and sales of ethane under supply service
agreements. This segment earns revenues from contracts with customers by providing transportation and storage services for NGLs on a firm basis as well as
providing brine and ethane supply services. Through Louisiana Midstream’s ownership of Boardwalk Storage Company, LLC, it also contains the results for
one natural gas storage cavern.
Measures of Segment Profit or Loss Used
The CODM uses EBITDA to assess each of the Company’s segments performance and to determine how to allocate resources. The CODM uses EBITDA in
the annual budget process and considers budget-to-actual variances of the segments,
75

which is reviewed at least quarterly, when making decisions about the allocation of operating and capital resources for the segments of the Company. The CODM uses
this measure, together with other non-financial measures, such as safety, emissions and reliability initiatives, commercial opportunities and compliance with the
Company’s rules and regulations, when assessing performance of the Company and establishing management’s compensation.
Segment Expenses and Other Segment Items
The Company provides segment expenses to its CODM on the same basis as the expenses are provided in the Company’s income statement and used to
calculate EBITDA. The Company accounts for intrasegment sales and transfers as if the sales or transfers were to third parties, or at fair market value.
Information about Reportable Segments
The below tables provide information about the Company’s reportable segments as provided to the CODM, including information about segment operating
revenues; EBITDA, the performance measure of the Company’s segments; significant segment expenses; segment asset information and segment capital expenditures.
Interest expense and interest income are not allocated to nor used in the performance measures of the Company’s reportable segments. The Company’s segments
pipeline, storage and other fixed assets are all operated and located within the U.S. and follow the accounting policies as described in Note 2.
Financial information by segment follows (in millions):
For the year ended December 31, 2024
Natural Gas
Natural Gas Liquids
Total
Revenues
Revenue from external customers
$
1,392.7 
$
635.4 
$
2,028.1 
Intrasegment revenues
49.4 
— 
49.4 
$
1,442.1 
$
635.4 
$
2,077.5 
Reconciliation of revenues:
Elimination of intrasegment revenues
(49.4)
Total consolidated revenues
$
2,028.1 
Less:
Costs associated with service revenues
$
41.1 
$
19.0 
Costs associated with product sales
— 
303.5 
Operation and maintenance
253.1 
57.2 
Administrative and general
176.9 
27.6 
Taxes other than income taxes
109.0 
13.1 
(Gain) loss on sale of assets, impairments and other
(6.6)
1.1 
Miscellaneous other income, net
(6.1)
— 
Segment EBITDA
$
874.7 
$
213.9 
$
1,088.6 
Reconciliation of profit or loss:
Depreciation and amortization
$
424.8 
Interest expense
182.9 
Interest income
(31.1)
Consolidated income before income taxes
$
512.0 
76

For the year ended December 31, 2023
Natural Gas
Natural Gas Liquids
Total
Revenues
Revenue from external customers
$
1,284.7 
$
333.0 
$
1,617.7 
Intrasegment revenues
30.0 
— 
30.0 
$
1,314.7 
$
333.0 
$
1,647.7 
Reconciliation of revenues:
Elimination of intrasegment revenues
(30.0)
Total consolidated revenues
$
1,617.7 
Less:
Costs associated with service revenues
$
37.1 
$
15.3 
Costs associated with product sales
— 
87.8 
Operation and maintenance
229.1 
51.9 
Administrative and general
151.7 
24.1 
Taxes other than income taxes
106.1 
9.4 
Loss on sale of assets, impairments and other
0.3 
— 
Miscellaneous other income, net
(4.0)
(0.1)
Segment EBITDA
$
794.4 
$
144.6 
$
939.0 
Reconciliation of profit or loss:
Depreciation and amortization
$
408.7 
Interest expense
155.6 
Interest income
(12.1)
Consolidated income before income taxes
$
386.8 
77

For the year ended December 31, 2022
Natural Gas
Natural Gas Liquids
Total
Revenues
Revenue from external customers
$
1,205.8 
$
226.2 
$
1,432.0 
Intrasegment revenues
24.9 
— 
24.9 
$
1,230.7 
$
226.2 
$
1,456.9 
Reconciliation of revenues:
Elimination of intrasegment revenues
(24.9)
Total consolidated revenues
$
1,432.0 
Less:
Costs associated with service revenues
$
37.1 
$
10.2 
Costs associated with product sales
— 
1.0 
Operation and maintenance
208.6 
42.3 
Administrative and general
129.0 
18.7 
Taxes other than income taxes
106.1 
8.4 
Loss on sale of assets, impairments and other
4.0 
— 
Miscellaneous other income, net
(6.3)
(0.1)
Segment EBITDA
$
752.2 
$
145.7 
$
897.9 
Reconciliation of profit or loss:
Depreciation and amortization
$
392.3 
Interest expense
165.9 
Interest income
(3.3)
Consolidated income before income taxes
$
343.0 
Segment assets include Property, plant, and equipment – net, Intangible assets – net of accumulated amortization and Goodwill. The following table reflects
segment assets and a reconciliation to Total Assets (in millions):
Segment Assets
As of December 31,
2024
2023
Natural Gas
$
7,490.1 
$
7,515.2 
Natural Gas Liquids
1,628.7 
1,650.8 
Total Segment Assets
9,118.8 
9,166.0 
Total current assets
401.1 
288.7 
Gas stored underground and Other assets
259.5 
241.7 
Total Assets
$
9,779.4 
$
9,696.4 
The following table reflects capital expenditures by segment (in millions):
Capital Expenditures
For the year ended
 December 31,
2024
2023
2022
Natural Gas
$
340.6 
$
321.5 
$
291.3 
Natural Gas Liquids
51.8 
60.9 
53.0 
Total
$
392.4 
$
382.4 
$
344.3 
78

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our
principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules
13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Annual Report on Form 10-K. Our disclosure controls and procedures are
designed to allow timely decisions regarding required disclosure and to provide reasonable assurance that the information required to be disclosed by us in reports that
we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as
appropriate, and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our
principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of December 31, 2024, at the
reasonable assurance level.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred
during the quarter ended December 31, 2024, that have materially affected or that are reasonably likely to materially affect our internal control over financial reporting. 
Management's Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting for us. Our internal control system was
designed to provide reasonable assurance regarding the preparation and fair presentation of our published financial statements.
There are inherent limitations to the effectiveness of any control system, however well designed, including the possibility of human error and the possible
circumvention or overriding of controls. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must
be considered relative to their costs. Management must make judgments with respect to the relative cost and expected benefits of any specific control measure. The
design of a control system is also based in part upon assumptions and judgments made by management about the likelihood of future events, and there can be no
assurance that a control will be effective under all potential future conditions. As a result, even an effective system of internal control over financial reporting can
provide no more than reasonable assurance with respect to the fair presentation of financial statements and the processes under which they were prepared.
Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2024. In making this assessment, management
used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control – Integrated Framework (2013). Based on
this assessment, our management believes that, as of December 31, 2024, our internal control over financial reporting was effective.
Item 9B. Other Information
Not applicable.
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
Not applicable.
79

PART III
Item 10. Directors, Executive Officers and Corporate Governance
We are omitting disclosure under this item because we meet the conditions set forth in General Instructions I(1) (a) and (b) of Form 10-K.
Item 11. Executive Compensation
We are omitting disclosure under this item because we meet the conditions set forth in General Instructions I(1) (a) and (b) of Form 10-K.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
We are omitting disclosure under this item because we meet the conditions set forth in General Instructions I(1) (a) and (b) of Form 10-K.
Item 13. Certain Relationships and Related Transactions, and Director Independence
We are omitting disclosure under this item because we meet the conditions set forth in General Instructions I(1) (a) and (b) of Form 10-K.
Item 14. Principal Accountant Fees and Services
Audit Fees and Services
Deloitte & Touche LLP (Deloitte & Touche) (PCAOB ID No. 34) has served as our auditor since our inception in 2005 and our predecessors' auditor from 2003
to 2005. The following table presents fees billed by Deloitte & Touche and its affiliates for professional services rendered to us and our subsidiaries in 2024 and 2023 by
category as described in the notes to the table (in millions):
2024
2023
Audit fees 
$
3.0 
$
3.2 
Audit related fees
0.1 
0.1 
Total
$
3.1 
$
3.3 
(1) Includes the aggregate fees and expenses for annual financial statement audit and quarterly financial statement reviews.
(2) Includes the aggregate fees and expenses for services that were reasonably related to the performance of the financial statement audits or reviews
described above and not included under Audit fees above, mainly including consents, comfort letters and audits of employee benefits plans.
Auditor Engagement Pre-Approval Policy
We are a wholly owned indirect subsidiary of Loews, and the Loews Audit Committee has responsibility for the appointment, compensation and oversight of
the independent external audit firm retained to audit our financial statements and the audit fee negotiations associated with their retention. To assure the continued
independence of our independent auditor, Deloitte & Touche, the Loews Audit Committee has adopted a policy requiring its pre-approval of all audit and non-audit
services performed for us and our subsidiaries by the independent auditor. Under this policy, the Loews Audit Committee annually pre-approves certain limited,
specified recurring services that may be provided by Deloitte & Touche, subject to maximum dollar limitations. All other engagements for services to be performed by
Deloitte & Touche are specifically pre-approved by the Loews Audit Committee or a designated committee member to whom this authority had been delegated.
Under that policy, the Loews Audit Committee, or a designated member, pre-approved all engagements by us and our subsidiaries for services of Deloitte &
Touche during 2024, including the terms and fees thereof, and the Loews Audit Committee concluded that all such engagements were compatible with the continued
independence of Deloitte & Touche in serving as our independent auditor.
(1)
 (2)
80

PART IV
Item 15. Exhibit and Financial Statement Schedules
(a) 1. Financial Statements
Included in Item 8 of this Annual Report on Form 10-K:
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets at December 31, 2024 and 2023
Consolidated Statements of Income for the years ended December 31, 2024, 2023 and 2022
Consolidated Statements of Comprehensive Income for the years ended December 31, 2024, 2023 and 2022
Consolidated Statements of Cash Flows for the years ended December 31, 2024, 2023 and 2022
Consolidated Statements of Changes in Partners' Capital for the years ended December 31, 2024, 2023 and 2022
Notes to Consolidated Financial Statements
(a) 2. Financial Statement Schedules
Schedule II not material.
81

(a) 3. Exhibits
The following documents are filed or furnished as exhibits to this report:
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 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).
4.2
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).
4.3
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).
4.4
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).
4.5
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).
4.6
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).
4.7
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).
4.8
Tenth Supplemental Indenture, dated February 15, 2024, 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 16, 2024).
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)
82

Exhibit
Number
Description
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).
10.7
Agreement and Amendment No. 5 to Third Amended and Restated Revolving Credit Agreement, dated as of June 30, 2023, 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 3, 2023).
*22.1
Subsidiary Issuers and Guarantors of Registered Securities.
*23.1
Consent of Independent Registered Public Accounting Firm.
*31.1
Certification of Scott A. Hallam, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities and Exchange Act of
1934, as amended.
83

Exhibit
Number
Description
*31.2
Certification of Steven A. Barkauskas, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities and Exchange
Act of 1934, as amended.
**32.1
Certification of Scott A. Hallam, 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
(1)  The Services Agreements between Gulf South Pipeline Company, LP (now known as Gulf South Pipeline Company, LLC) and Loews Corporation and between
Boardwalk Pipelines, LP (formerly known as Boardwalk Pipelines, LLC) and Loews Corporation are not filed because they are identical to Exhibit 10.1 except
for the identities of Gulf South Pipeline Company, LLC and Boardwalk Pipelines, LLC and the date of the agreement.
Item 16. Form 10-K Summary
We are omitting disclosure under this item as it is provided elsewhere in this Report.
84

SIGNATURES
   Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
 
Boardwalk Pipeline Partners, LP
 
By: Boardwalk GP, LP
 
its general partner
 
By: Boardwalk GP, LLC
 
its general partner
Dated:
February 11, 2025
By:
/s/  Steven A. Barkauskas
 
 
Steven A. Barkauskas
 
 
Senior Vice President and Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant
and in the capacities and on the date indicated.
Dated:
February 11, 2025
/s/  Scott A. Hallam                                    
 
Scott A. Hallam
President, Chief Executive Officer and Director
(principal executive officer)
Dated:
February 11, 2025
/s/  Steven A. Barkauskas                      
 
Steven A. Barkauskas
Senior Vice President, Chief Financial Officer and Director
(principal financial officer)
Dated:
February 11, 2025
/s/  Christine Fernandez
 
Christine Fernandez
Vice President, Controller and Chief Accounting Officer
(principal accounting officer)
Dated:
February 11, 2025
/s/  Michael E. McMahon                                
 
Michael E. McMahon
Senior Vice President, General Counsel, Secretary and Director
Dated:
February 11, 2025
/s/  Kenneth I. Siegel
 
Kenneth I. Siegel
Director, Chairman of the Board
Dated:
February 11, 2025
/s/  Marc A. Alpert
Marc A. Alpert
Director
Dated:
February 11, 2025
/s/  Stanley C. Horton
Stanley C. Horton
Director
Dated:
February 11, 2025
/s/  Benjamin J. Tisch
 
Benjamin J. Tisch
Director
Dated:
February 11, 2025
/s/  Jane Wang
 
Jane Wang
Director
85

EXHIBIT 22.1
Subsidiary Issuers and Guarantors of Registered Securities
Subsidiary Issuer
Guarantor
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
Boardwalk Pipelines, LP 5.625% Notes due 2034
Boardwalk Pipeline Partners, LP

EXHIBIT 23.1
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
   We consent to the incorporation by reference in Registration Statement No. 333-274067 on Form S-3 of our report dated February 11, 2025, relating to the financial
statements of Boardwalk Pipeline Partners, LP appearing in this Annual Report on Form 10-K for the year ended December 31, 2024.
/s/ Deloitte & Touche LLP
Houston, Texas
February 11, 2025
 

EXHIBIT 31.1
I, Scott A. Hallam, certify that:
1)
I have reviewed this Annual Report on Form 10-K of Boardwalk Pipeline Partners, LP;
2)
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements
made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3)
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial
condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4)
The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act
Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and
have:
a.
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities,
particularly during the period in which this report is being prepared;
b.
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision,
to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles;
c.
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal
quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the
registrant's internal control over financial reporting; and
5)
The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the
registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
a.
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely
to adversely affect the registrant's ability to record, process, summarize and report financial information; and
b.
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over
financial reporting.
Dated:
February 11, 2025
/s/ Scott A. Hallam
 
 
Scott A. Hallam
 
 
President and Chief Executive Officer

EXHIBIT 31.2
I, Steven A. Barkauskas, certify that:
1)
I have reviewed this Annual Report on Form 10-K of Boardwalk Pipeline Partners, LP;
2)
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements
made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3)
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial
condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4)
The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act
Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and
have:
a.
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities,
particularly during the period in which this report is being prepared;
b.
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision,
to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles;
c.
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal
quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the
registrant's internal control over financial reporting; and
5)
The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the
registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
a.
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely
to adversely affect the registrant's ability to record, process, summarize and report financial information; and
b.
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over
financial reporting.
Dated:
February 11, 2025
/s/ Steven A. Barkauskas
 
 
Steven A. Barkauskas
 
 
Senior Vice President and Chief Financial Officer

EXHIBIT 32.1
Certification by the Chief Executive Officer
of
Boardwalk GP, LLC
pursuant to 18 U.S.C. Section 1350
(as adopted by Section 906 of the Sarbanes-Oxley Act of 2002)
   Pursuant to 18 U.S.C. Section 1350, the undersigned chief executive officer of Boardwalk GP, LLC hereby certifies, to such officer's knowledge, that the annual
report on Form 10-K for the year ended December 31, 2024, (the Report) of Boardwalk Pipeline Partners, LP (the Company) fully complies with the requirements of
Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and the information contained in the Report fairly presents, in all material respects, the financial condition
and results of operations of the Company.
February 11, 2025
/s/ Scott A. Hallam                                  
Scott A. Hallam
President and Chief Executive Officer
(principal executive officer)

EXHIBIT 32.2
Certification by the Chief Financial Officer
of
Boardwalk GP, LLC
pursuant to 18 U.S.C. Section 1350
(as adopted by Section 906 of the Sarbanes-Oxley Act of 2002)
   Pursuant to 18 U.S.C. Section 1350, the undersigned chief financial officer of Boardwalk GP, LLC hereby certifies, to such officer's knowledge, that the annual report
on Form 10-K for the year ended December 31, 2024, (the Report) of Boardwalk Pipeline Partners, LP (the Company) fully complies with the requirements of Section
13(a) or 15(d) of the Securities Exchange Act of 1934 and the information contained in the Report fairly presents, in all material respects, the financial condition and
results of operations of the Company.
February 11, 2025
/s/ Steven A. Barkauskas                                  
Steven A. Barkauskas
Senior Vice President and Chief Financial Officer
(principal financial officer)