UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2020
OR
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _______________ to _______________
Commission file number: 01-32665
BOARDWALK PIPELINE PARTNERS, LP
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of incorporation or organization)
20-3265614
(I.R.S. Employer Identification No.)
9 Greenway Plaza, Suite 2800
Houston, Texas
77046
(866) 913-2122
(Address and Telephone Number of Registrant's Principal Executive Office)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
NONE
Trading Symbol(s)
NONE
Name of each exchange on which registered
NONE
Securities registered pursuant to section 12(g) of the Act: NONE
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes☒ No☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes ☐ No ☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the
past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation
S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging
growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2
of the Exchange Act.
Large accelerated filer ☐ Accelerated filer ☐ Non-accelerated filer ☒ Smaller reporting company ☐
Emerging growth company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or
revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over
financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit
report. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒
Boardwalk Pipeline Partners, LP meets the conditions set forth in General Instructions I(1) (a) and (b) of Form 10-K and is therefore filing this form with
the reduced disclosure format.
Documents incorporated by reference. None.
TABLE OF CONTENTS
2020 FORM 10-K
BOARDWALK PIPELINE PARTNERS, LP
PART I
Item 1. Business
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 2. Properties
Item 3. Legal Proceedings
Item 4. Mine Safety Disclosures
PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Item 6. Selected Financial Data
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8. Financial Statements and Supplementary Data
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information
PART III
Item 10. Directors, Executive Officers and Corporate Governance
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13. Certain Relationships and Related Transactions, and Director Independence
Item 14. Principal Accounting Fees and Services
PART IV
Item 15. Exhibits and Financial Statement Schedules
Item 16. Form 10-K Summary
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PART I
Item 1. Business
Unless the context otherwise requires, references in this Annual Report on Form 10-K to “we,” “our,” “us” or like terms refer to the business of
Boardwalk Pipeline Partners, LP and its consolidated subsidiaries.
Introduction
We are a Delaware limited partnership formed in 2005. Our business, which is conducted by our primary subsidiary, Boardwalk Pipelines, LP (Boardwalk
Pipelines) and its operating subsidiaries (together, the operating subsidiaries), consists of integrated natural gas and natural gas liquids and other hydrocarbons
(herein referred to together as NGLs) pipeline and storage systems. All of our operations are conducted by the operating subsidiaries. As of December 31, 2020,
Boardwalk Pipelines Holding Corp., a wholly-owned subsidiary of Loews Corporation (Loews), owned directly or indirectly, 100% of our capital.
Our Business
We operate in the midstream portion of the natural gas and NGLs industry, providing transportation and storage for those commodities. We own
approximately 14,095 miles of natural gas and NGLs pipelines and underground storage caverns having aggregate capacity of approximately 213.0 billion cubic
feet (Bcf) of working natural gas and 32.1 million barrels (MMBbls) of NGLs. Our natural gas pipeline systems are located in the Gulf Coast region, Oklahoma,
Arkansas and the Midwestern states of Tennessee, Kentucky, Illinois, Indiana and Ohio, and our NGLs pipelines and storage facilities are located in Louisiana and
Texas.
We serve a broad mix of customers, including local distribution companies (LDCs), electric power generators, exporters of liquefied natural gas (LNG),
industrial users, producers and marketers of natural gas, and interstate and intrastate pipelines. We provide a significant portion of our natural gas pipeline
transportation and storage services through firm contracts under which our customers pay monthly capacity reservation fees, which are fixed fees based on the
quantity of capacity reserved, regardless of use. Other fees are based on actual utilization of the capacity under firm contracts and contracts for interruptible
services. Contracts for our NGLs services are generally fee-based or based on minimum volume requirements, while others are dependent on actual volumes
transported or stored. For the year ended December 31, 2020, approximately 90% of our revenues were derived from capacity reservation fees under firm
contracts, approximately 6% of our revenues were derived from fees based on utilization under firm contracts and approximately 4% of our revenues were derived
from interruptible transportation, interruptible storage, parking and lending (PAL) and other services.
The maximum rates we can charge for most of our natural gas transportation services, as well as the general terms and conditions of those services, are
established by, and subject to review and revision by, the Federal Energy Regulatory Commission (FERC). These rates are based upon certain assumptions to
allow us the opportunity to recover the cost of providing these services and earn a reasonable return on equity. However, it is possible that we may not recover all
of our costs or earn a return. We are authorized to charge market-based rates for the majority of our natural gas storage capacity pursuant to authority granted by
the FERC. The Surface Transportation Board (STB) regulates the rates we charge for interstate service on ethylene pipelines. The Louisiana Public Service
Commission (LPSC) regulates the rates we charge for intrastate service within the state of Louisiana on our petrochemical and NGLs pipelines. The STB and
LPSC require that our transportation rates are reasonable and that our practices cannot unreasonably discriminate among our shippers.
Our Pipeline and Storage Systems
We own and operate approximately 13,650 miles of interconnected natural gas pipelines, directly serving customers in thirteen states and indirectly
serving customers throughout the northeastern and southeastern United States (U.S.) through numerous interconnections with unaffiliated pipelines. We also own
and operate approximately 445 miles of NGLs pipelines in Louisiana and Texas. In 2020, our pipeline systems transported approximately 3.2 trillion cubic feet
(Tcf) of natural gas and approximately 80.6 MMBbls of NGLs. Average daily throughput on our natural gas pipeline systems during 2020 was approximately 8.6
Bcf. Our natural gas storage facilities are comprised of fourteen underground storage fields located in four states with aggregate working gas capacity of
approximately 213.0 Bcf and our NGLs storage facilities consist of eleven salt-dome caverns located in Louisiana with an aggregate storage capacity of
approximately 32.1 MMBbls. We also own seven salt-dome caverns and related brine infrastructure for use in providing brine supply services and to support the
NGLs storage operations.
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The principal sources of supply for our natural gas pipeline systems are regional supply hubs and market centers located in the Gulf Coast and Mid-
Continent regions, including offshore Louisiana, the Perryville, Louisiana, area, the Henry Hub in Louisiana and the Carthage, Texas, area. Our pipelines in the
Carthage, Texas, area provide access to natural gas supplies from the Barnett and Haynesville Shales and other natural gas producing regions in eastern Texas and
northern Louisiana. The Henry Hub serves as the designated delivery point for natural gas futures contracts traded on the New York Mercantile Exchange. Our
pipeline systems also have access to supply basins such as the Woodford and Scoop/Stack Shales in Oklahoma, the Fayetteville Shale in Arkansas, the Eagle Ford
Shale in southern Texas and wellhead supplies in northern and southern Louisiana and Mississippi, and we also receive gas in the Lebanon, Ohio, area from the
Marcellus and Utica Shales located in the northeastern U.S. Our NGLs pipeline systems access the Gulf Coast petrochemical industry through our operations at our
Choctaw Hub in the Mississippi River corridor area of Louisiana and the Sulphur Hub in the Lake Charles, Louisiana, area. We also access ethylene supplies at
Port Neches, Texas, which we deliver to petrochemical-industry customers in Louisiana.
The following is a summary of each of our principal operating subsidiaries:
Gulf South Pipeline Company, LLC (Gulf South): Effective January 1, 2020, Gulf South converted from a limited partnership to a limited liability
company. Immediately subsequent to the conversion, our Gulf Crossing Pipeline Company LLC, operating subsidiary was merged into Gulf South. Our merged
Gulf South pipeline system is located along the Gulf Coast in the states of Oklahoma, Texas, Louisiana, Mississippi, Alabama and Florida. The on-system markets
directly served by the Gulf South system are generally located in eastern Texas, Louisiana, southern Mississippi, southern Alabama and the Florida Panhandle.
Gulf South also services the Perryville Exchange. These markets include LNG export markets in the Freeport, Texas, area, power plants, LDCs and municipalities
located across the system, including New Orleans, Louisiana; Jackson, Mississippi; Mobile, Alabama; Houston, Texas; and Pensacola, Florida, and other end-users
located across the system, including the Baton Rouge to New Orleans industrial corridor and Lake Charles, Louisiana. Gulf South also has indirect access to off-
system markets through numerous interconnections with unaffiliated interstate and intrastate pipelines and storage facilities. These pipeline interconnections
provide access to markets throughout the northeastern, midwestern and southeastern U.S.
Gulf South has ten natural gas storage facilities. The two natural gas storage facilities located in Bistineau, Louisiana, and Jackson, Mississippi, have
approximately 91.5 Bcf of working gas storage capacity from which Gulf South offers firm and interruptible storage service, including no-notice service (NNS),
and are used to support pipeline operations. Gulf South also owns and operates eight high deliverability salt-dome natural gas storage caverns in Forrest County,
Mississippi, having approximately 46.0 Bcf of total storage capacity, of which approximately 29.6 Bcf is working gas capacity, and owns undeveloped land which
is suitable for up to five additional storage caverns.
Texas Gas Transmission, LLC (Texas Gas): Our Texas Gas pipeline system is a bi-directional pipeline located in Louisiana, East Texas, Arkansas,
Mississippi, Tennessee, Kentucky, Indiana and Ohio, with smaller diameter lines extending into Illinois. Texas Gas directly serves LDCs, municipalities and power
generators in its market area, which encompasses eight states in the South and Midwest and includes the Memphis, Tennessee; Louisville, Kentucky; Cincinnati
and Dayton, Ohio; and Evansville and Indianapolis, Indiana, metropolitan areas. Texas Gas also has indirect market access to, and receives supply from, the
Northeast through interconnections with unaffiliated pipelines. A large portion of the gas delivered by the Texas Gas system is used for heating during the winter
months, but Texas Gas also supplies gas for cooling needs during the summer months.
Texas Gas owns nine natural gas storage fields, of which it owns the majority of the working and base gas. Texas Gas uses this gas to meet the
operational requirements of its transportation and storage customers and the requirements of its NNS customers. Texas Gas also uses its storage capacity to offer
firm and interruptible storage services.
Boardwalk Louisiana Midstream, LLC and Boardwalk Petrochemical Pipeline, LLC (collectively, Louisiana Midstream): Louisiana Midstream provides
transportation and storage services for natural gas, NGLs and ethylene, fractionation services for NGLs and brine supply services for producers and consumers of
petrochemicals through two hubs in southern Louisiana - the Choctaw Hub in the Mississippi River corridor area and the Sulphur Hub in the Lake Charles area.
These assets provide approximately 48.8 MMBbls of salt-dome storage capacity, including approximately 7.6 Bcf of working natural gas storage capacity;
significant brine supply infrastructure; and approximately 285 miles of pipeline assets, including an extensive ethylene distribution system. Louisiana Midstream
also owns and operates the Evangeline Pipeline, an approximately 175-mile interstate ethylene pipeline that is capable of transporting approximately 4.2 billion
pounds of ethylene per year between Port Neches, Texas, and Baton Rouge, Louisiana, with interconnections with the ethylene distribution system and storage
facilities at the Sulphur and Choctaw Hubs. Throughput for Louisiana Midstream was 80.6 MMBbls for the year ended December 31, 2020.
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Boardwalk Texas Intrastate, LLC (Boardwalk Texas Intrastate): Boardwalk Texas Intrastate provides intrastate natural gas transportation services on
pipelines located in South Texas extending on the west side from Bee County, near the Eagle Ford Shale, and Agua Dulce to the Corpus Christi area and to an
interconnect with Gulf South in Jackson County, Texas. Boardwalk Texas Intrastate is situated to provide access to industrial and power generation markets in the
Corpus Christi area as well as LNG export markets and third-party pipelines for exports to Mexico.
The following table provides information for our pipeline and storage systems as of February 9, 2021:
Pipeline and Storage Systems
Gulf South
Texas Gas
Louisiana Midstream
Boardwalk Texas Intrastate
(1) Bcf per day (Bcf/d)
Current Growth Projects
Miles of
Pipeline
7,415
5,970
460
250
Working Gas
Storage
Capacity (Bcf)
121.1
84.3
7.6
—
Liquids Storage
Capacity
(MMBbls)
Peak-day
Delivery
Capacity
(1)
(Bcf/d)
Average Daily
Throughput (Bcf/d)
(1)
—
—
32.1
—
10.9
5.9
—
—
5.6
3.0
—
—
In 2020, we placed into service approximately $335.0 million of growth projects which represents approximately 1.5 Bcf/d of firm natural gas
transportation capacity and additional NGL infrastructure. Additionally, we expanded our natural gas storage capacity at our Forrest County, Mississippi, storage
facilities. Collectively, these projects were completed on-time and within budget. We expect to spend approximately $380.0 million on our growth projects
currently under construction through 2024. Those projects are expected to serve increased natural gas demand from a power generation plant and liquids demand
from petrochemical facilities. All of our growth projects are secured by long-term firm contracts.
Refer to Liquidity and Capital Resources in Part II, Item 7. of this Annual Report on Form 10-K for further discussion of capital expenditures and
financing.
Nature of Contracts
We contract with our customers to provide transportation and storage services on both a firm and interruptible basis. We also provide bundled firm
transportation and storage services, such as NNS, interruptible PAL services for our customers, brine supply services for certain petrochemical customers and
fractionation services.
Transportation Services: We offer transportation services on both a firm and interruptible basis. Our customers choose, based upon their particular needs,
the applicable mix of services depending upon availability of pipeline capacity, the price of services and the volume and timing of customer requirements. Our firm
transportation customers reserve a specific amount of pipeline capacity at specified receipt and delivery points on our system. The transaction price for firm service
contracts is comprised of a fixed fee based on the quantity of capacity reserved, regardless of use (capacity reservation fee), plus variable fees in the form of a
usage fee paid on the volume of commodity actually transported or injected and withdrawn from storage. Capacity reservation revenues derived from a firm service
contract are generally consistent during the contract term, but can be higher in winter periods than the rest of the year, especially for NNS agreements. Firm
transportation contracts can range from one to twenty years, although we may enter into shorter- or longer-term contracts. In providing interruptible services to
customers, we agree to transport natural gas or NGLs for a customer when capacity is available. Interruptible service customers pay a commodity charge only for
the volume of gas actually transported, plus a fuel charge. Interruptible transportation agreements have terms ranging from day-to-day to multiple years, with rates
that change on a daily, monthly or seasonal basis. Our NGLs transportation services are generally fee-based or based on minimum volume requirements.
Storage and Parking and Lending Services: We offer natural gas and NGLs storage services on both a firm and interruptible basis. Firm storage
customers reserve a specific amount of storage capacity, including injection and withdrawal rights, while interruptible customers receive storage capacity and
injection and withdrawal rights when available. Similar to firm transportation customers, firm storage customers generally pay fees based on the quantity of
capacity reserved plus an injection and withdrawal fee. Firm storage contracts typically range in term from one to ten years. Interruptible storage customers pay for
the volume of gas actually stored plus injection and withdrawal fees. Generally, interruptible storage
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agreements are for monthly terms. We are able to charge market-based rates for the majority of our natural gas storage capacity pursuant to authority granted by
the FERC. Our NGLs storage rates are market-based, and the contracts for NGLs services are typically fixed-price arrangements with escalation clauses. PAL is an
interruptible service offered to customers providing them the ability to park (inject) or borrow (withdraw) natural gas into or out of our pipeline systems at a
specific location for a specific period of time. Customers pay for PAL services in advance or on a monthly basis depending on the terms of the agreement.
No-Notice Services: NNS consist of a combination of firm natural gas transportation and storage services that allow customers to inject or withdraw
natural gas from storage with little or no notice. Customers pay a reservation charge based upon the capacity reserved plus a commodity and a fuel charge based on
the volume of gas actually transported. In accordance with its tariff, Texas Gas loans stored gas to certain of its no-notice customers who are obligated to repay the
gas in-kind.
Customers and Markets Served
We contract directly with end-use customers, including LDCs, electric power generators, exporters of LNG and industrial users, with producers and
marketers of natural gas, and with interstate and intrastate pipelines, who, in turn, provide transportation and storage services for end-users. Based on our 2020
transportation, storage and PAL revenues, net of fuel, our customer mix was as follows: marketers (22%), power generators (22%), natural gas producers (19%),
LDCs (16%), industrial end-users (12%) and exporters of LNG (9%). Based upon our 2020 transportation, storage and PAL revenues, net of fuel, our deliveries
were as follows: pipeline interconnects (32%), LDCs (19%), power generators (16%), industrial end-users (14%), storage activities (9%), exporters of LNG (9%)
and others (1%). One customer comprised approximately 10% of our operating revenues in 2020.
Marketers: Natural gas marketing companies utilize our services to provide services to our other customer groups as well as to customer groups in off-
system markets. The services may include combined gas transportation and storage services to support the needs of the other customer groups. Some of the
marketers are sponsored by LDCs or producers.
Power Generators: Our natural gas pipelines are directly connected to 45 natural-gas-fired power generation facilities in nine states. The demand of the
power generating customers generally peaks during the summer cooling season which is counter to the winter season peak demands of the LDCs, although demand
from power generators remains strong in the winter months as well, due to the overall increase in the use of natural gas over other sources, such as coal, to generate
electricity. Our power generating customers can use a combination of NNS, firm and interruptible transportation services.
Natural Gas Producers: Producers of natural gas use our services to transport gas supplies from producing areas, including shale natural gas production
areas, to supply pools and to other customers on and off of our systems. Producers contract with us for storage services to store excess production and to optimize
the ultimate sales prices for their gas.
Local Distribution Companies: Most of our LDC customers use firm natural gas transportation services, including NNS. We serve approximately 175
LDCs at more than 300 delivery locations across our pipeline systems. The demand of these customers peaks during the winter heating season.
Industrial End-Users: We provide approximately 186 industrial facilities with a combination of firm and interruptible natural gas and NGLs
transportation and storage services. Our pipeline systems are directly connected to industrial facilities in the Baton Rouge to New Orleans industrial corridor; Lake
Charles, Louisiana; Mobile, Alabama; and Pensacola, Florida. We can also access the Houston Ship Channel through third-party natural gas pipelines.
Exporters of LNG: LNG exporters use our firm transportation services to reach LNG liquefaction and export facilities. We provide 1.4 Bcf/d of firm
natural gas transportation service directly to the Freeport LNG liquefaction and export facility in Freeport, Texas.
Our delivery market has diversified over time, with increased deliveries to our end-use customers, whereas historically, our delivery markets were
primarily to other pipelines who then delivered to the end-use customers. As of December 31, 2020, we had approximately $9.5 billion of projected operating
revenues under committed firm transportation agreements, of which our deliveries are expected to be as follows: power generators (30%), exporters of LNG
(22%), pipeline interconnects (21%) industrial end-users (13%), LDCs (8%), storage activities (5%) and others (1%).
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Government Regulation
Federal Energy Regulatory Commission: The FERC regulates our interstate natural gas transmission operating subsidiaries under the Natural Gas Act of
1938 (NGA) and the Natural Gas Policy Act of 1978 (NGPA). The FERC regulates, among other things, the rates and charges for the transportation and storage of
natural gas in interstate commerce and the construction, extension, enlargement or abandonment of facilities under its jurisdiction. Where required, our interstate
natural gas pipeline subsidiaries hold certificates of public convenience and necessity issued by the FERC covering certain of their facilities, activities and services.
The FERC also prescribes accounting treatment for our interstate natural gas pipeline subsidiaries which is separately reported pursuant to forms filed with the
FERC. The regulatory books and records and other activities of our subsidiaries that operate under the FERC's jurisdiction may be periodically audited by the
FERC.
The maximum rates that our FERC-regulated operating subsidiaries may charge for all aspects of the natural gas transportation services they provide are
established through the FERC's cost-based rate-making process. Key determinants in the FERC's cost-based rate-making process are the costs of providing service,
the volumes of gas being transported, the rate design, the allocation of costs between services, the capital structure and the rate of return a pipeline is permitted to
earn. The maximum rates that may be charged by us for storage services on Texas Gas, except for services associated with a portion of the working gas capacity on
that system, are also established through the FERC's cost-based rate-making process. The FERC has authorized us to charge market-based rates for firm and
interruptible storage services for the majority of our other natural gas storage facilities. None of our FERC-regulated entities currently have an obligation to file a
new rate case, and Gulf South is prohibited from filing a rate case until May 1, 2023, subject to certain exceptions.
Boardwalk Texas Intrastate transports natural gas in intrastate commerce under the rules and regulations established by the Texas Railroad Commission
and in interstate commerce that is subject to FERC jurisdiction under Section 311 of the NGPA. The maximum rates for services are established under Section 311
of the NGPA and are generally subject to review every five years by the FERC.
Surface Transportation Board and Louisiana Public Service Commission: The STB regulates the rates we charge for interstate service on our ethylene
pipelines. The LPSC regulates the rates we charge for intrastate service within the state of Louisiana on our petrochemical and NGL pipelines. The STB and LPSC
require that our transportation rates are reasonable and that our practices cannot unreasonably discriminate among our shippers.
U.S. Department of Transportation (DOT): We are regulated by the DOT, through the Pipeline and Hazardous Material Safety Administration (PHMSA),
under the Natural Gas Pipeline Safety Act of 1968, as amended (NGPSA), and the Hazardous Liquids Pipeline Safety Act of 1979, as amended (HLPSA). The
NGPSA and HLPSA govern the design, installation, testing, construction, operation, replacement and management of interstate natural gas and NGLs pipeline
facilities. We have authority from PHMSA to operate certain natural gas pipeline assets under issued permits with specific conditions that allow us to operate those
pipeline assets at higher than normal operating pressures of up to 0.80 of the pipeline's Specified Minimum Yield Strength (SMYS). Operating at these pressures
allows us to transport all the existing natural gas volumes we have contracted for on those facilities with our customers. PHMSA retains discretion whether to grant
or maintain authority for us to operate our natural gas pipeline assets at higher pressures and, in the event that PHMSA should elect not to allow us to operate at
these higher pressures, it could affect our ability to transport all of our contracted quantities of natural gas on these pipeline assets, and we could incur significant
additional costs to reinstate this authority or to develop alternate ways to meet our contractual obligations. PHMSA's regulations also require transportation
pipeline operators to implement integrity management programs to comprehensively evaluate certain high risk areas, known as high consequence areas (HCAs),
high population areas (also known as moderate consequence areas (MCAs)), and Class 3 and Class 4 areas, which are determined by specific population densities
near our pipelines, as well as certain drinking water sources and unusually sensitive ecological areas, along our pipelines, and take additional safety measures to
protect people and property in these areas.
Legislation in the past decade has resulted in more stringent mandates for pipeline safety and has charged PHMSA with developing and adopting
regulations that impose increased pipeline safety requirements on pipeline operators. In particular, the NGPSA and HLPSA were amended by the Pipeline Safety,
Regulatory Certainty, and Job Creation Act of 2011 (2011 Act) and the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (2016 Act).
The 2011 Act increased the penalties for safety violations, established additional safety requirements for newly constructed pipelines and required studies of safety
issues that could result in the adoption of new regulatory requirements by PHMSA for existing pipelines. The 2016 Act, among other things, required PHMSA to
complete its outstanding mandates under the 2011 Act and develop new safety standards for natural gas storage facilities. Pursuant to the 2016 Act, PHMSA
published a final rule in February 2020 that amended the minimum safety issues related to natural gas storage facilities, including wells, wellbore tubing and
casing, which final rule was amended to add applicable reporting requirements and was subsequently published in July 2020. Also, in October 2019, PHMSA
published the first of three expected regulations relating to new or more stringent
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requirements for certain natural gas pipelines, that had originally been proposed in 2016 as part of PHMSA's “gas Mega Rule,” which first final rule became
effective on July 1, 2020. This regulation imposed numerous requirements, including maximum allowable operating pressure (MAOP) reconfirmation through re-
verification of all historical records for pipelines in service, which re-certification process may require natural gas pipelines installed before 1970 (previously
excluded from certain pressure testing obligations) to be pressure tested, the periodic assessment of additional pipeline mileage outside of HCAs (in MCAs as well
as Class 3 and Class 4 areas), the reporting of exceedances of MAOP and the consideration of seismicity as a risk factor in integrity management. Additional
amendments to this October 2019 final rule relating to recordkeeping for gas transmission lines were published by PHMSA in July 2020. We are currently
evaluating the operational and financial impact related to this final rule. The remaining rulemakings comprising the gas Mega Rule have not yet been published,
and we cannot predict when they will be finalized; however, they are expected to include revised pipeline repair criteria as well as more stringent corrosion control
requirements.
Also, in the Fiscal Year 2021 Omnibus Appropriations Bill passed by Congress and made effective December 27, 2020, the Congress reauthorized
PHMSA through fiscal year 2023 and directed the agency to move forward with several regulatory actions, including the “Pipeline Safety: Class Location Change
Requirements” and the “Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines” proposed rulemakings. Congress has also instructed PHMSA to
issue final regulations that will require operators of non-rural gas gathering lines and new and existing transmission and distribution pipeline facilities to conduct
certain leak detection and repair programs and to require facility inspection and maintenance plans to align with those regulations. New regulations adopted by
PHMSA may impose more stringent requirements applicable to integrity management programs and other pipeline safety aspects of our operations, which could
cause us to incur increased capital and operating costs and operational delays.
Other: Our operations are also subject to extensive federal, state and local laws and regulations relating to protection of the environment and occupational
health and safety. Such laws and regulations impose, among other things, restrictions, liabilities and obligations in connection with the generation, handling, use,
storage, transportation, treatment and disposal of various substances, including hazardous substances and waste and in connection with spills, releases, discharges
and emissions of various substances into the environment. Environmental regulations also require that our facilities, sites and other properties be operated,
maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Occupational health and safety regulations establish standards
protective of workers, both generally and within the pipeline industry. These laws, as amended from time to time, that our operations are subject to, include, for
example:
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the Clean Air Act (CAA) and analogous state laws, which regulate air emission pollutants, greenhouse gas (GHG) emissions and reciprocating engines
subject to Maximum Achievable Control Technology standards;
the Federal Water Pollution Control Act, commonly referred to as the Clean Water Act, and analogous state laws, which establish the extent to which
waterways are subject to federal or state jurisdiction and serve to regulate the discharge of wastewater from our facilities into state and federal waters;
the Comprehensive Environmental Response, Compensation and Liability Act, commonly referred to as CERCLA, or the Superfund law, and analogous
state laws, which regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us
or locations to which we have sent hazardous substances for disposal;
the Resource Conservation and Recovery Act (RCRA) and analogous state laws, which impose requirements for the generation, storage, treatment,
transportation and disposal of solid and hazardous wastes at or from our facilities;
the Endangered Species Act (ESA), which restricts activities that may affect federally identified endangered and threatened species or their habitats by the
implementation of operating restrictions or a temporary, seasonal or permanent ban in affected areas;
the National Environmental Policy Act (NEPA), which requires federal agencies to evaluate major agency actions having the potential to impact the
environment and that may require the preparation of environmental assessments and more detailed environmental impact statements that may be made
available for public review and comment; and
the Occupational Safety and Health Act (OSHA) and analogous state laws, which establish workplace standards for the protection of the health and safety
of employees, including the implementation of hazard communications programs designed to inform employees about hazardous substances in the
workplace, potential harmful effects of these substances and appropriate control measures.
Many states where we operate also have, or are developing, similar environmental or occupational health and safety legal requirements governing many
of the same types of activities, and those requirements can be more stringent than those adopted under federal laws and regulations. Failure to comply with these
federal, state and local laws and regulations may result
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in the assessment of administrative, civil and criminal penalties, the imposition of corrective or remedial obligations, the incurrence of capital expenditures, the
occurrence of delays, denials or cancellations in permitting or the development or expansion of projects and the issuance of orders enjoining performance of some
or all of our operations in affected areas.
President Biden has indicated that he intends to pursue additional environmental regulations, whether by new legislation, executive actions or regulatory
initiatives, which may impact our operations. For example, in recent years, there have been conflicting interpretations of what waterways are subject to jurisdiction
under the Clean Water Act, with competing rulemakings being developed, and subsequently challenged in courts, by different presidential administrations. The
incoming Biden Administration may propose another interpretation of the extent of this jurisdiction, though we cannot predict the likelihood or effects of any such
proposal at this time. Similarly, President Biden has announced plans to take action with regards to climate change and signed executive orders to this effect on
January 20, 2021; for more information, see Item 1A. Risk Factors—Business Risks—Legislative and regulatory initiatives related to climate change make our
operations, as well as the operations of our fossil-fuel producer customers, subject to a series of regulatory, political, litigation and financial risks associated with
the production and processing of fossil fuels and emission of GHGs.
Historically, our environmental compliance costs have not had a material adverse effect on our results of operations, but there can be no assurance that
future compliance with existing requirements will not materially affect us or that the current regulatory standards will not become more onerous in the future,
resulting in more significant costs to maintain compliance or increased exposure to significant liabilities. Note 5 in Part II, Item 8. of this Annual Report on Form
10-K contains information regarding environmental compliance.
Human Capital
At December 31, 2020, we had 1,240 employees, approximately 100 of whom were included under collective bargaining agreements. A satisfactory
relationship exists between management and labor.
Hiring and retaining the right people is critical to our long-term strategic success. We have programs in place to help employees build their knowledge,
skills and experience, as well as to guide their career development. A cornerstone of our human capital strategy is our commitment to fostering a diverse and
inclusive work environment, where all people are respected and encouraged to contribute their ideas. Employing individuals with different backgrounds and
experiences helps meet the diverse needs of all our stakeholders.
We are part of a critical infrastructure industry whose customers and communities depend upon us to provide safe and reliable service. Our employees are
essential to ensuring we continue to meet these objectives, and we consider safety in our day-to-day activities to be our primary core value. Our emphasis on safety
extends to our approach to managing the risk of operational disruptions due to coronavirus disease 2019 (COVID-19), and we have maintained full, continuous
operations throughout the pandemic.
Available Information
Our website is located at www.bwpipelines.com. We make available free of charge through our website our Annual Reports on Form 10-K, which include
our audited financial statements, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to
Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (Exchange Act) as soon as we electronically file such material with the Securities and Exchange
Commission (SEC). These documents are also available on the SEC's website at www.sec.gov.
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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 may file with the SEC or make available to the public
should be carefully considered and evaluated before investing in any securities issued by us.
Business Risks
Our natural gas transportation and storage operations are subject to extensive regulation by the FERC, including rules and regulations related to the rates we
can charge for our services and our ability to construct or abandon facilities. We may not be able to recover the full cost of operating our pipelines, including
earning a reasonable return.
Our natural gas transportation and storage operations are subject to extensive regulation by the FERC, including the types, rates and terms of services we
may offer to our customers, construction of new facilities, creation, modification or abandonment of services or facilities and recordkeeping and relationships with
affiliated companies. An adverse FERC action in any of these areas could affect our ability to compete for business, construct new facilities, offer new services or
recover the full cost of operating our pipelines. This regulatory oversight can result in longer lead times to develop and complete any future project than
competitors that are not subject to the FERC's regulations. The FERC can also deny us the right to abandon certain facilities from service.
The FERC also regulates the rates we can charge for our natural gas transportation and storage operations. For our cost-based services, the FERC
establishes both the maximum and minimum rates we can charge. The basic elements that the FERC considers are the costs of providing service, the volumes of
gas being transported, the rate design, the allocation of costs between services, the capital structure and the rate of return a pipeline is permitted to earn. We may
not be able to recover our costs, including certain costs associated with pipeline integrity, through existing or future rates.
The FERC and/or our customers could challenge the maximum applicable rates that any of our regulated pipelines are allowed to charge in accordance
with Section 5 of the NGA. Potential legislation that would amend Section 5 of the NGA to add refund provisions could increase the likelihood of such a
challenge. If such a challenge is successful for any of our pipelines, the revenues associated with transportation and storage services the pipeline provides pursuant
to cost-of-service rates could materially decrease in the future, which would adversely affect the revenues on that pipeline going forward.
Legislative and regulatory initiatives relating to pipeline safety that require the use of new or more prescriptive compliance activities, substantial changes to
existing integrity management programs or withdrawal of regulatory waivers could subject us to increased capital and operating costs and operational delays.
Our interstate pipelines are subject to regulation by PHMSA which is part of the DOT. PHMSA regulates the design, installation, testing, construction,
operation and maintenance of existing interstate natural gas and NGLs pipeline facilities. PHMSA regulation currently requires pipeline operators to implement
integrity management programs, including frequent inspections, correction of certain identified anomalies and other measures to promote pipeline safety in HCAs,
MCAs, and Class 3 and Class 4 areas, as well as in areas unusually sensitive to environmental damage and commercially navigable waterways. States have
jurisdiction over certain of our intrastate pipelines and have adopted regulations similar to existing PHMSA regulations. State regulations may impose more
stringent requirements than found under federal law that affect our intrastate operations. Compliance with these rules over time generally has resulted in an overall
increase in our maintenance costs. The imposition of new or more stringent pipeline safety rules applicable to natural gas or NGL pipelines, or any issuance or
reinterpretation of guidance from PHMSA or any state agencies with respect thereto, could cause us to install new or modified safety controls, pursue additional
capital projects or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in us incurring increased capital and operating
costs, experiencing operational delays and suffering potential adverse impacts to our operations or our ability to reliably serve our customers. Requirements that
are imposed under the 2011 Act or the more recent 2016 Act may also increase our capital and operating costs or impact the operation of our pipelines. In the
Fiscal Year 2021 Omnibus Appropriations Bill, Congress reauthorized PHMSA through fiscal year 2023 and directed the agency to move forward with several
regulatory actions. See Part I, Item 1. Business—Government Regulation—U.S. Department of Transportation of this Annual Report on Form 10-K for further
discussion on pipeline safety matters. Any
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new pipeline safety legislation or implementing regulations could impose more stringent or costly compliance obligations on us and could require us to pursue
additional capital projects or conduct integrity or maintenance programs on an accelerated basis, any or all of which tasks could result in us incurring increased
operating costs that could have a material adverse effect on our costs of providing transportation services.
We have entered into certain firm transportation contracts with shippers on certain of our expansion projects that utilize the design capacity of certain of
our pipeline assets, based upon the authority we received from PHMSA to operate those pipelines at higher than normal operating pressures of up to 0.80 of the
pipeline's SMYS under issued permits with specific conditions. PHMSA retains discretion to withdraw or modify this authority. If PHMSA were to withdraw or
materially modify such authority, it could affect our ability to transport all of our contracted quantities of natural gas on these pipeline assets and we could incur
significant additional costs to reinstate this authority or to develop alternate ways to meet our contractual obligations.
Our actual construction and development costs could exceed our forecasts; our anticipated cash flow from construction and development projects will not be
immediate; and our construction and development projects may not be completed on time or at all.
We are and have been engaged in several construction projects involving our existing assets and the construction of new facilities for which we have
expended or will expend significant capital. We expect to continue to engage in the construction of additional growth projects and modifications of our system.
When we build a new pipeline or expand or modify an existing facility, the design, construction and development occurs over an extended period of time, and we
will not receive any revenue or cash flow from that project until after it is placed into commercial service. On our interstate pipelines, there are several years
between when the project is announced and when customers begin using the new facilities. During this period we spend capital and incur costs without receiving
any of the financial benefits associated with the projects. The construction of new assets involves regulatory (federal, state and local), landowner opposition,
environmental, activist, legal, political, materials and labor costs, as well as operational and other risks that are difficult to predict and some are beyond our control.
A project may not be completed on time or at all due to a variety of factors, may be impacted by significant cost overruns or may be materially changed prior to
completion as a result of developments or circumstances that we are not aware of when we commit to the project. Any of these events could result in material
unexpected costs or have a material adverse effect on our ability to realize the anticipated benefits from our growth projects.
Legislative and regulatory initiatives related to climate change make our operations, as well as the operations of our fossil-fuel producer customers, subject to
a series of regulatory, political, litigation and financial risks associated with the production and processing of fossil fuels and emission of GHGs.
The threat of climate change continues to attract considerable attention in the U.S. and in foreign countries. Numerous proposals have been made and
could continue to be made at the international, national, regional and state levels of government to monitor and limit existing emissions of GHGs as well as to
restrict or eliminate such future emissions, which makes our operations as well as the operations of our fossil fuel producer customers subject to a series of
regulatory, political, litigation and financial risks associated with the production and processing of fossil fuels and emission of GHGs.
In the U.S., no comprehensive climate change legislation has been implemented at the federal level. With the U.S. Supreme Court finding that GHG
emissions constitute a pollutant under the CAA, the Environmental Protection Agency (EPA) has adopted several rules that, among other things, establish
construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions
from certain natural gas system sources in the U.S., implement New Source Performance Standards (NSPS) directing the reduction of methane from certain new,
modified or reconstructed facilities in the natural gas sector, and together with the DOT, implement GHG emissions limits on vehicles manufactured for operation
in the U.S. In recent years, there has been considerable uncertainty surrounding regulation of methane emissions, as the EPA under the Obama Administration
published final regulations under the CAA establishing new performance standards for methane in 2016, but since that time the EPA under the Trump
Administration has undertaken several measures, including publishing in September 2020 final rule policy and technical amendments to the NSPS, for stationary
sources of air emissions. The policy amendments, effective September 14, 2020, notably removed the transmission and storage sector from the regulated source
category and rescinded methane and volatile organic compound (VOC) requirements for the remaining sources that were established by former President Obama’s
Administration; whereas the technical amendments, effective November 16, 2020, included changes to fugitive emissions monitoring and repair schedules for
gathering and boosting compressor stations and low-production wells, and recordkeeping and reporting requirements. Various states and industry and
environmental groups are separately challenging both the original 2016 standards and the EPA's September 2020 final rules, and on January 20, 2021, President
Biden issued an executive order, that directed the EPA to reconsider the technical amendments and issue a proposed rule suspending, revising or rescinding
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those amendments by no later than September 2021. A reconsideration of the September 2020 policy amendments is expected to follow. The January 20, 2021,
executive order also directed the establishment of new methane and VOC standards applicable to existing oil and gas operations, including the production,
transmission, processing and storage segments. Various states and groups of states have adopted or are considering adopting legislation, regulations or other
regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs and restriction of emissions. At
the international level, the non-binding Paris Agreement requests that nations limit their GHG emissions through individually-determined reduction goals every
five years after 2020. Although the U.S. had withdrawn from the Paris Agreement, President Biden has issued executive orders recommitting the U.S. to the Paris
Agreement and calling for the federal government to begin formulating the U.S.’ nationally determined emissions reduction goal under the agreement. With the
U.S. recommitting to the Paris Agreement, additional executive orders may be issued or federal legislation or regulatory initiatives may be adopted to achieve the
Paris Agreement’s goals.
Governmental, scientific and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the
U.S. On January 27, 2021, President Biden issued an executive order that commits to substantial action on climate change, calling for, among other things,
suspending the issuance of new leases for oil and gas development on federal lands, pending completion of a review of leasing and permitting practices and
expanding on the Acting Secretary of the U.S. Department of the Interior's January 20, 2020, order, effective immediately, that suspends new oil and gas leases and
drilling permits on federal lands and waters for a period of 60 days. The executive order also called for the increased use of zero-emissions vehicles by the federal
government, the elimination of subsidies provided to the fossil fuel industry, and an increased emphasis on climate-related risks across government agencies and
economic sectors. Legal challenges to these suspensions are expected, with at least one industry group filing a lawsuit on January 27, 2021, in Wyoming federal
district court and seeking to have the moratorium declared invalid. The new presidential administration could also pursue the imposition of more restrictive
requirements for the establishment of pipeline infrastructure or the permitting of LNG export facilities, as well as more restrictive GHG emissions limitations for
oil and gas facilities. Litigation risks are also increasing, as a number of cities and other local governments have sought to bring suit against fossil fuel producer
companies in state or federal court, alleging, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as
rising sea levels, and are responsible for roadway and infrastructure damages as a result, or alleging that the companies have been aware of the adverse effects of
climate change for some time but defrauded their investors or customers by failing to adequately disclose those impacts.
There are also increasing financial risks for fossil fuel energy companies as investors invested in fossil fuel energy companies become increasingly
concerned about the potential effects of climate change and may elect in the future to shift some or all of their investments into non-energy related sectors.
Institutional lenders who provide financing to fossil fuel energy companies also have become more attentive to sustainable lending practices and some of them may
elect not to provide funding for fossil fuel energy companies. Additionally, there is the possibility that financial institutions will be required to adopt policies that
limit funding for fossil fuel energy companies. Recently, the Federal Reserve announced that it has joined the Network for Greening the Financial System, a
consortium of financial regulators focused on addressing climate-related risks in the financial sector. This could make it more difficult to secure funding for
exploration and production or midstream energy business activities.
The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose
more stringent standards for GHG emissions from the oil and gas sector or otherwise restrict the areas in which this sector may produce fossil fuels or generate
GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for fossil fuels, which could reduce demand for
our transportation and storage services. Political, litigation and financial risks may result in our fossil fuel producer customers restricting or canceling production
activities, incurring liability for infrastructure damages as a result of climatic changes or impairing their ability to continue to operate in an economic manner,
which also could reduce demand for our services. Moreover, the increased competitiveness of alternative energy sources (such as wind, solar, geothermal, tidal and
biofuels) could reduce demand for hydrocarbons, and for our services. Finally, increasing concentrations of GHG in the earth's atmosphere may produce climate
changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods, rising sea levels and other climatic events.
The outbreak of COVID-19 and the measures to mitigate the spread of COVID-19 could materially adversely affect our business, financial condition and
results of operations and those of our customers, suppliers and other business partners.
The global outbreak of COVID-19 has materially negatively impacted worldwide economic and commercial activity and financial markets and has
impacted global demand for oil and petrochemical products. COVID-19 has also resulted in significant business and operational disruptions, including business
closures, supply chain disruptions, travel restrictions, stay-at-home orders and limitations on the availability of workforces. If significant portions of our workforce
are unable to work
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effectively, including because of illness, quarantines, government actions, facility closures or other restrictions in connection with COVID-19, our business could
be materially adversely affected. We may also be unable to perform fully on our contracts, and our costs may increase as a result of the COVID-19 outbreak. These
cost increases may not be fully recoverable. It is possible that the continued spread of COVID-19 could also further cause disruption in our customers' business;
cause delay, or limit the ability of our customers to perform, including in making timely payments to us; and cause other unpredictable events. The impact of
COVID-19 has impacted capital markets, which may impact our customers' financial position, and recoverability of our receivables from our customers may be at
risk. The full impact of COVID-19 is unknown and continues to evolve. The extent to which COVID-19 negatively impacts our business and operations will
depend on the severity, location and duration of the effects and spread of COVID-19, the continued actions undertaken by national, regional and local governments
and health officials to contain the virus or treat its effects, and how quickly and to what extent economic conditions improve and normal business and operating
conditions resume. It might also have the effect of increasing several of the other risk factors contained herein.
Changes in energy prices, including natural gas, oil and NGLs, impact the supply of and demand for those commodities, which impact our business.
Our customers, especially producers and certain plant operators, are directly impacted by changes in commodity prices. The prices of natural gas, oil and
NGLs fluctuate in response to changes in both domestic and worldwide supply and demand, market uncertainty and a variety of additional factors, including for
natural gas the realization of potential LNG exports and demand growth within the power generation market. The recent volatility in the pricing levels of natural
gas, oil and NGLs has adversely affected the businesses of certain of our producer customers and could result in defaults or the non-renewal of our contracted
capacity when existing contracts expire. The current erosion in commodity prices could affect the operations of certain of our industrial customers, including the
temporary closure or reduction of plant operations, resulting in decreased deliveries to those customers. Future increases in the price of natural gas and NGLs could
make alternative energy and feedstock sources more competitive and decrease demand for natural gas and NGLs. A reduced level of demand for natural gas and
NGLs could diminish the utilization of capacity on our systems and reduce the demand for our services.
The price differentials between natural gas supplies and market demand for natural gas have reduced the transportation rates that we can charge on certain
portions of our pipeline systems.
Each year a portion of our firm natural gas transportation contracts expire and need to be replaced or renewed. Over the past several years, as a result of
market conditions, we have renewed some expiring contracts at lower rates or for shorter terms than in the past. The transportation rates we are able to charge
customers are heavily influenced by market trends (both short and longer term), including the available supply, geographical location of natural gas production, the
competition between producing basins, competition with other pipelines for supply and markets, the demand for gas by end-users such as power plants,
petrochemical facilities and LNG export facilities and the price differentials between the gas supplies and the market demand for the gas (basis differentials).
Market conditions have resulted in a sustained narrowing of basis differentials on certain portions of our pipeline system, which has reduced transportation rates
that can be charged in the affected areas and adversely affected the contract terms we can secure from our customers for available transportation capacity and for
contracts being renewed or replaced. We expect these market conditions to continue.
A failure in our computer systems or a cybersecurity attack on any of our facilities, or those of third parties, could cause substantial damage and may affect
adversely our ability to operate our business.
We have become more reliant on technology to help increase efficiency in our business processes. Our businesses are dependent upon our operational and
financial computer systems to process the data necessary to conduct almost all aspects of our business, including the operation of our pipeline and storage facilities
and the recording and reporting of commercial and financial transactions. Any failure of our computer systems, or those of our customers, suppliers or others with
whom we do business, could materially disrupt our ability to operate our business.
At the same time, the U.S. government has issued public warnings that indicate that energy assets might be specific targets of cybersecurity threats. Our
technologies, systems and networks, and those of our vendors, suppliers and other business partners, may become the target of cyberattacks or information security
breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, significant damage to
property, personal injury or loss of life, substantial financial damage or other disruption of operations. In addition, certain cyber-incidents may remain undetected
for an extended period. As cyber-incidents continue to evolve, legislation could be enacted to mitigate cyber-threats. This will likely require us to expend
additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber-incidents at significantly
increased costs. Our insurance coverage for cyberattacks may not be sufficient to cover all the losses we may experience as a result of such cyberattacks. Any
cyberattacks
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that affect our facilities, or those of our customers, suppliers or others with whom we do business could have a material adverse effect on our business, cause us a
financial loss and/or damage our reputation.
We are exposed to credit risk relating to default or bankruptcy by our customers.
Credit risk relates to the risk of loss resulting from the default by a customer of its contractual obligations or the customer filing bankruptcy. We have
credit risk with both our existing customers and those supporting our growth projects. Credit risk exists in relation to our growth projects, both because the
expansion customers make long-term firm capacity commitments to us for such projects and certain of those expansion customers agree to provide credit support
as construction for such projects progresses. If a customer fails to post the required credit support or defaults during the growth project process, overall returns on
the project may be reduced to the extent an adjustment to the scope of the project occurs or we are unable to replace the defaulting customer with a customer
willing to pay similar rates. In 2020 and 2019, two expansion customers declared bankruptcy for which we were able to use the credit support obtained during the
growth project process to cover a portion of their remaining long-term commitment. For more information, refer to Note 5 in Part II, Item 8. of this Annual Report
on Form 10-K.
Our credit exposure also includes receivables for services provided, future performance under firm agreements and volumes of gas owed by customers for
imbalances or gas loaned by us to them under certain NNS and PAL services.
We rely on a limited number of customers for a significant portion of revenues.
For 2020, one customer comprised approximately 10% of our 2020 operating revenues. Additionally, the top ten customers holding firm capacity under
firm agreements comprised approximately 40% of our total projected operating revenues. If any of our significant customers have credit or financial problems
which result in bankruptcy, a delay or failure to pay for services provided by us, to post the required credit support for construction associated with our growth
projects or existing contracts or to repay the gas they owe us, it could have a material adverse effect on our revenues.
Our revolving credit facility contains operating and financial covenants that restrict our business and financing activities.
Our revolving credit facility contains operating and financial covenants that may restrict our ability to finance future operations or capital needs or to
expand or pursue business activities. Our credit agreement limits our ability to make loans or investments, make material changes to the nature of our business,
merge, consolidate or engage in asset sales, or grant liens or make negative pledges. This agreement also requires us to maintain a ratio of consolidated debt to
consolidated EBITDA (as defined in the agreement) of not more than 5.0 to 1.0, or up to 5.5 to 1.0 for the three quarters following a qualified acquisition or series
of acquisitions, where the purchase price exceeds $100.0 million over a rolling 12-month period, which limits the amount of additional indebtedness we can incur
to grow our business, and could require us to reduce indebtedness if our earnings before interest, income taxes, depreciation and amortization (EBITDA) decreases
to a level that would cause us to breach this covenant. Future financing agreements we may enter into could contain similar or more restrictive covenants or may
not be as favorable as those under our existing indebtedness.
Our ability to comply with the covenants and restrictions contained in our credit agreement may be affected by events beyond our control, including
economic, financial and market conditions. If market, economic conditions or our financial performance deteriorate, our ability to comply with these covenants
may be impaired. If we are not able to incur additional indebtedness, we may be required to seek other sources of funding that may be on less favorable terms. If
we default under our credit agreement or another financing agreement, significant additional restrictions may become applicable. In addition, a default could result
in a significant portion of our indebtedness becoming immediately due and payable, and our lenders could terminate their commitment to make further loans to us.
If such event occurs, we would not have, and may not be able to obtain, sufficient funds to make these accelerated payments.
Our substantial indebtedness could affect our ability to meet our obligations and may otherwise restrict our activities.
As of December 31, 2020, we had $3.5 billion in principal amount of long-term debt outstanding, including amounts borrowed under our revolving credit
facility. This level of debt requires significant interest payments. Our inability to generate sufficient cash flow to satisfy our debt obligations, or to refinance our
obligations on commercially reasonable terms, would have a material adverse effect on our business. Our substantial indebtedness could have important
consequences. For example, it could:
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limit our ability to borrow money for our working capital, capital expenditures, debt service requirements or other general partnership purposes;
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impact the ratings received from credit rating agencies;
increase our vulnerability to general adverse economic and industry conditions; and
limit our ability to respond to business opportunities, including growing our business through acquisitions.
We are permitted, under our revolving credit facility and the indentures governing our notes, to incur additional debt, subject to certain limitations under
our revolving credit facility and, in the case of unsecured debt, under the indentures governing the notes. If we incur additional debt, our increased leverage could
also result in the consequences described above.
We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets, which may affect our ability to fulfill
our debt obligations.
We are a partnership holding company and our operating subsidiaries conduct all of our operations and own all of our operating assets. We have no
significant assets other than the ownership interests in our subsidiaries. As a result, our ability to fulfill our debt obligations depends on the performance of our
subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, the
provisions of existing and future indebtedness, applicable state partnership and limited liability company laws and other laws and regulations, including FERC
policies.
Limited access to the debt markets and increases in interest rates could adversely affect our business.
We anticipate funding our capital spending requirements through our available financing options, including cash generated from operations and
borrowings under our revolving credit facility. Changes in the debt markets, including market disruptions, limited liquidity, and an increase in interest rates, may
increase the cost of financing as well as the risks of refinancing maturing debt. This may affect our ability to raise needed financing and reduce the amount of cash
available to fund our operations or growth projects. If the debt markets were not available, it is not certain if other adequate financing options would be available to
us on terms and conditions that we would find acceptable.
Any disruption in the debt markets could require us to take additional measures to conserve cash until the markets stabilize or until we can arrange
alternative credit arrangements or other funding for our business needs. Such measures could include reducing or delaying business activities, reducing our
operations to lower expenses and reducing other discretionary uses of cash. We may be unable to execute our growth strategy or take advantage of certain business
opportunities, any of which could negatively impact our business.
We do not own all of the land on which our pipelines, storage and other facilities are located, which could result in disruptions to our operations.
Substantial portions of our pipelines, storage and other facilities are constructed and maintained on property owned by others pursuant to rights-of-way,
easements, permits, licenses or consents, and we are subject to the possibility of more onerous terms and/or increased costs to retain necessary land use rights if we
do not have valid land use rights or if such land use rights lapse or terminate. Some of the rights to construct and operate our pipelines, storage or other facilities on
land owned by third parties and governmental agencies that we obtain are for specific periods of time. We cannot guarantee that we will always be able to renew,
when necessary, existing land use rights or obtain new land use rights without experiencing significant costs or experiencing landowner opposition. Any loss of
these land use rights with respect to the operation of our pipelines, storage and other facilities, through our inability to renew right-of-way or easement contracts or
permits, licenses, consents or otherwise, could have a material adverse effect on our operations.
Rising sea levels, subsidence and erosion could damage our pipelines and the facilities that serve our customers, particularly along coastal waters and offshore
in the Gulf of Mexico.
Our pipeline operations along coastal waters and offshore in the Gulf of Mexico could be impacted by rising sea levels, subsidence and erosion.
Subsidence issues are also a concern for our pipelines at major river crossings. Rising sea levels, subsidence and erosion could cause serious damage to our
pipelines, which could affect our ability to provide transportation services or result in leakage, migration, releases or spills from our operations to surface or
subsurface soils, surface water, groundwater or offshore waters, which could result in liability, remedial obligations and/or otherwise have a negative impact on
continued operations. Such rising sea levels, subsidence and erosion processes could impact our customers who operate along coastal waters or offshore in the Gulf
of Mexico, and they may be unable to utilize our services. Rising sea levels, subsidence
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and erosion could also expose our operations to increased risks associated with severe weather conditions and other adverse events and conditions, such as
hurricanes and flooding. As a result, we may incur significant costs to repair and preserve our pipeline infrastructure. In recent years, local governments and
landowners have filed lawsuits in Louisiana against energy companies, alleging that their operations contributed to increased coastal rising seas and erosion and
seeking substantial damages.
We may not be successful in executing our strategy to grow and diversify our business.
We rely primarily on the revenues generated from our natural gas transportation and storage services. Negative developments in these services have
significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets. Our ability to grow, diversify and
increase cash flows will depend, in part, on our ability to expand our existing business lines and to close and execute on accretive acquisitions. We may not be
successful in acquiring or developing such assets or may do so on terms that ultimately are not profitable. Any such transactions involve potential risks that may
include, among other things:
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the diversion of management's and employees' attention from other business concerns;
inaccurate assumptions about volume, revenues and project costs, including potential synergies;
a decrease in our liquidity as a result of our using available cash or borrowing capacity to finance the acquisition or project;
a significant increase in our interest expense or financial leverage if we incur additional debt to finance the acquisition or project or if we make inaccurate
assumptions about the overall costs of debt;
an inability to hire, train or retain qualified personnel to manage and operate the acquired business and assets or the developed assets;
unforeseen difficulties operating in new product areas or new geographic areas; and
changes in regulatory requirements or delays of regulatory approvals.
Additionally, acquisitions also contain the following risks:
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an inability to integrate successfully the businesses we acquire;
the assumption of unknown liabilities for which we are not indemnified, for which our indemnity is inadequate or for which our insurance policies may
exclude from coverage;
limitations on rights to indemnity from the seller; and
customer or key employee losses of an acquired business.
Our ability to replace expiring gas storage contracts at attractive rates or on a long-term basis and to sell short-term services at attractive rates or at all are
subject to market conditions.
We own and operate substantial natural gas storage facilities. The market for the storage and PAL services that we offer is impacted by the factors and
market conditions discussed above for our transportation services, and is also impacted by natural gas price differentials between time periods, such as winter to
summer (time period price spreads), and the volatility in time period price spreads. When market conditions cause a narrowing of time period price spreads and a
decline in the price volatility of natural gas, these factors adversely impact the rates we can charge for our storage and PAL services.
Failure to comply with environmental or worker safety laws and regulations or an accidental release of pollutants into the environment may cause us to incur
significant costs and liabilities.
Our operations are subject to federal, state and local laws and regulations relating to protection of worker safety or the environment. These laws include,
for example, the CAA, the Clean Water Act, CERCLA, the RCRA, ESA, NEPA, OSHA and analogous state laws. These laws and regulations may restrict or
impact our business activities, including requiring the acquisition or renewal of permits or other approvals to conduct regulated activities, restricting the manner in
which we handle
16
or dispose of wastes, imposing remedial obligations to remove or mitigate contamination resulting from a spill or other release, requiring capital expenditures to
comply with pollution control requirements and imposing safety and health criteria addressing worker protection. Failure to comply with these laws and regulations
may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial
requirements, the incurrence of capital expenditures, the occurrence of delays, denials or cancellations in the permitting or performance or expansion of projects
and the issuance of orders enjoining future operations in a particular area. Under certain of these environmental laws and regulations, we could be subject to joint
and several or strict liability for the removal or remediation of previously released pollutants or property contamination regardless of whether we were responsible
for the release or contamination or if our operations were not in compliance with all laws. We may not be able to recover some or any of the costs incurred from
insurance. Stricter environmental or worker safety laws, regulations or enforcement policies could significantly increase our operational or compliance costs and
compliance with new or more stringent environmental legal requirements could delay or prohibit our ability to obtain permits for operations or require us to install
additional pollution control equipment. For example, in April 2020, the federal district court for the District of Montana determined that the U.S. Army Corps of
Engineers (the Corps) Clean Water Act Section 404 Nationwide Permit 12 (NWP 12) failed to comply with consultation requirements under the federal ESA. The
district court vacated NWP 12 and enjoined the issuance of new authorizations for oil and gas pipeline projects. While the district court's order has subsequently
been limited pending appeal and NWP 12 authorizations remain available for certain oil and gas pipeline projects, we cannot predict the ultimate outcome of this
case and its impacts to the Nationwide Permit program. Additionally, in response to the vacatur, on January 13, 2021, the Corps published a reissuance of a
restructured NWP 12 for oil and natural gas pipeline activities that separated certain utilities formerly covered under the permit into other NWPs. While the rule is
effective March 15, 2021, the rule may be subject to further revisions or suspension under the Biden Administration. While the full extent and impact of the
vacatur is unclear at this time, any disruption in our ability to obtain coverage under NWP 12 or other general permits may result in increased costs and project
delays if we are forced to seek individual permits from the Corps. See Part I, Item 1. Business—Government Regulation—Other of this Annual Report on Form 10-
K for further discussion on environmental matters.
Our operations are subject to catastrophic losses, operational hazards and unforeseen interruptions for which we may not be adequately insured.
There are a variety of operating risks inherent in transporting and storing natural gas, ethylene and NGLs, such as leaks and other forms of releases,
explosions, fires, cyber-attacks and mechanical problems, which could have catastrophic consequences. Additionally, the nature and location of our business may
make us susceptible to catastrophic losses from hurricanes or other named storms, particularly with regard to our assets in the Gulf Coast region, windstorms,
earthquakes, hail, and other severe weather. Any of these or other similar occurrences could result in the disruption of our operations, substantial repair costs,
personal injury or loss of life, significant damage to property, environmental pollution, impairment of our operations and substantial financial losses. The location
of pipelines in HCAs, which includes populated areas, residential areas, commercial business centers and industrial sites, could significantly increase the level of
damages resulting from some of these risks.
We currently possess property, business interruption, cyber threat and general liability insurance, but proceeds from such insurance coverage may not be
adequate for all liabilities or expenses incurred or revenues lost. Moreover, such insurance may not be available in the future at commercially reasonable costs and
terms. The insurance coverage we do obtain may contain large deductibles or fail to cover certain events, hazards or all potential losses.
Our business requires the retention and recruitment of a skilled workforce and the loss of such workforce could result in the failure to implement our business
plans.
Our operations and management require the retention and recruitment of a skilled executive team and workforce including engineers, technical personnel
and other professionals. In addition, many of our current employees are approaching retirement age and have significant institutional knowledge that must be
transferred to other employees. If we are unable to retain our current employees, successfully complete the knowledge transfer and/or recruit new employees of
comparable knowledge and experience, our business could be negatively impacted.
Our business is highly competitive.
The principal elements of competition among pipeline systems are availability of capacity, rates, terms of service, access to gas supplies, flexibility and
reliability of service. Additionally, the FERC's policies promote competition in natural gas markets by increasing the number of natural gas transportation options
available to our customer base. Increased competition could reduce the volumes of product we transport or store or, in instances where we do not have long-term
contracts with fixed rates, could cause us to decrease the transportation or storage rates we can charge our customers. Competition could intensify
17
the negative impact of factors that adversely affect the demand for our services, such as adverse economic conditions, weather, higher fuel costs and taxes or other
regulatory actions that increase the cost, or limit the use, of products we transport and store.
Possible terrorist activities or military actions could adversely affect our business.
The continued threat of terrorism and the impact of retaliatory military and other action by the U.S. and its allies might lead to increased political,
economic and financial market instability and volatility in prices for natural gas, which could affect the markets for our natural gas transportation and storage
services. While we are taking steps that we believe are appropriate to increase the security of our assets, we may not be able to completely secure our assets or
completely protect them against a terrorist attack.
18
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
We are headquartered in approximately 103,000 square feet of leased office space located in Houston, Texas. We also have approximately 60,000 square
feet of leased office space in Owensboro, Kentucky. Our operating subsidiaries own their respective pipeline and storage systems in fee. However, substantial
portions of these systems are constructed and maintained on property owned by others pursuant to rights-of-way, easements, permits, licenses or consents. Our
Pipeline and Storage Systems, in Part I, Item 1 of this Annual Report on Form 10-K contains additional information regarding our material property, including our
pipelines and storage facilities.
Item 3. Legal Proceedings
Refer to Note 5 in Part II, Item 8. of this Annual Report on Form 10-K for a discussion of our legal proceedings.
Item 4. Mine Safety Disclosures
Not applicable.
PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Not applicable.
Item 6. Selected Financial Data
We are omitting disclosure under this item because we meet the conditions set forth in General Instructions I(1) (a) and (b) of Form 10-K.
19
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A)
Overview
We operate in the midstream portion of the natural gas and NGLs industry, providing transportation and storage for those commodities. Refer to Part I,
Item 1. Business, of this Annual Report on Form 10-K for further discussion of our operations and business. We are not in the business of buying and selling
natural gas and NGLs other than for system management purposes, but changes in natural gas and NGLs prices may impact the volumes of natural gas or NGLs
transported and stored by customers on our systems. We conduct all of our business through our operating subsidiaries as one reportable segment. Due to the
capital-intensive nature of our business, our operating costs and expenses typically do not vary significantly based upon the amount of products transported, with
the exception of fuel consumed at our compressor stations and not included in a fuel tracker, which is netted with fuel retained on our Consolidated Statements of
Income. Please refer to Part I, Item 1. Business, for further discussion of the services that we offer and our customer mix.
Current Events
In 2020, the COVID-19 pandemic and measures to mitigate the spread of COVID-19 significantly impacted the world and the U.S. An excess supply of
energy products also led to disruptions in the energy sector and volatility in energy prices early in 2020, with a partial recovery of prices and demand occurring in
the latter half of 2020. Our operations are considered essential critical infrastructure under current Cybersecurity and Infrastructure Security Agency guidelines,
which allowed us to remain operating during the pandemic. As a result, the impacts from COVID-19 and the volatile energy prices have not been significant to our
business, though some of our customers have been and continue to be directly impacted by COVID-19 and the volatility in commodity prices. In 2020, we
transported approximately 3.2 Tcf of natural gas, or an 8% increase from 2019. Refer to Note 5 in Part II, Item 8. of this Annual Report on Form 10-K for further
information about a producer customer bankruptcy in 2020.
Firm Agreements
A substantial portion of our transportation and storage capacity is contracted for under firm agreements. For the year ended December 31, 2020,
approximately 90% of our revenues were derived from capacity reservation fees under firm contracts. The table below shows a rollforward of operating revenues
under committed firm agreements in place as of December 31, 2019, to December 31, 2020, including agreements for transportation, storage and other services,
over the remaining term of those agreements (in millions):
Total projected operating revenues under committed firm agreements as of December
31, 2019
Adjustments for:
Actual revenues recognized from firm agreements in 2020
Firm agreements entered into in 2020
Total projected operating revenues under committed firm agreements as of December
31, 2020
(1)
$
$
9,329.0
(1,155.5)
1,276.5
9,450.0
(1) As of December 31, 2019, we expected our 2020 revenues from fixed fees under firm agreements to be approximately $1,065.0 million, including
agreements for transportation, storage and other services. Our actual 2020 revenues recognized from fixed fees under firm agreements were $1,155.5
million, an increase of $90.5 million resulting primarily from contract renewals that occurred in 2020 and the receipt of proceeds related to a
customer bankruptcy, as discussed in Note 5 in Part II, Item 8. of this Annual Report on Form 10-K.
During 2020, we entered into approximately $1.3 billion of new firm agreements, of which approximately 55% were from new growth projects executed
in 2020, but will not be placed into commercial service until 2024 or later years. As of December 31, 2020, our top ten customers holding firm capacity under firm
agreements comprised approximately 40% of our total projected operating revenues. Additionally, the credit profile associated with our customers comprising the
total projected operating revenues under firm agreements as of December 31, 2020, was 75% rated as investment grade, 4% rated as non-investment grade and
21% not rated. Note 3 in Part II, Item 8. of this Annual Report on Form 10-K contains more information regarding the revenues we expect to earn from fixed fees
under committed firm agreements.
20
Contract Renewals
Each year a portion of our firm transportation and storage agreements expire. The rates we are able to charge customers are heavily influenced by market
trends (both short and longer term), including the available supply, geographical location of natural gas production, the competition between producing basins,
competition with other pipelines for supply and markets, the demand for gas by end-users such as power plants, petrochemical facilities and LNG export facilities
and the price differentials between the gas supplies and the market demand for the gas (basis differentials). Our storage rates are additionally impacted by natural
gas price differentials between time periods, such as winter to summer (time period price spreads), and the volatility in time period price spreads. Demand for firm
service is primarily based on market conditions which can vary across our pipeline systems. While we did not see a decrease in the demand for our transportation
services as a result of the COVID-19 pandemic or the volatility in energy prices during 2020, if these conditions were to remain for an extended period of time or
worsen, we could see a decline in the demand for our services. We focus our marketing efforts on enhancing the value of the capacity that is up for renewal and
work with customers to match gas supplies from various basins to new and existing customers and markets, including aggregating supplies at key locations along
our pipelines to provide end-use customers with attractive and diverse supply options. If the market perceives the value of our available capacity to be lower than
our long-term view of the capacity, we may seek to shorten contract terms until market perception improves.
Over the past several years, as a result of market conditions, we have renewed some expiring contracts at lower rates or for shorter terms than in the past.
In addition to normal contract expirations, in the 2018 to 2020 timeframe, transportation agreements associated with our significant pipeline expansion projects that
were placed into service in the 2007-2009 timeframe, have expired. A substantial portion of the capacity associated with the pipeline expansion projects was
renewed or the contracts were restructured, usually at lower rates or lower volumes, which has negatively impacted our operating revenues. The last of the contract
expirations associated with the 2007-2009 pipeline expansion projects have occurred and the associated impacts on operating revenues have been, and will
continue to be, realized. Historically, we had delivered the majority of production volumes from these pipeline expansion projects to other pipelines. Over the past
several years, we have focused on diversifying our deliveries to end-use markets through utilizing available capacity from contract expirations and the capacity
created from our growth projects. We have diversified our deliveries such that almost 75% of our projected future firm reservation revenues, from firm agreements
in place as of December 31, 2020, are for deliveries to end-use customers.
Pipeline System Maintenance
We incur substantial costs for ongoing maintenance of our pipeline systems and related facilities, including those incurred for pipeline integrity
management activities, equipment overhauls, general upkeep and repairs. These costs are not dependent on the amount of revenues earned from our transportation
services. PHMSA has developed regulations that require transportation pipeline operators to implement integrity management programs to comprehensively
evaluate certain areas along pipelines and take additional measures to protect pipeline segments located in highly populated areas. These regulations have resulted
in an overall increase in our ongoing maintenance costs, including maintenance capital and maintenance expense. In 2019, PHMSA issued the first part of its gas
Mega Rule, which became effective on July 1, 2020. This regulation imposed numerous requirements, including MAOP reconfirmation through re-verification of
all historical records for pipelines in service, which re-certification process may require natural gas pipelines installed before 1970 (previously excluded from
certain pressure testing obligations) to be pressure tested, the periodic assessment of additional pipeline mileage outside of HCAs (in MCAs as well as Class 3 and
Class 4 areas), the reporting of exceedances of MAOP and the consideration of seismicity as a risk factor in integrity management. The remaining rulemakings
comprising the gas Mega Rule have not been published yet and we cannot predict when they will be finalized; however, they are expected to include revised
pipeline repair criteria as well as more stringent corrosion control requirements. It is expected that these new rules will cause us to incur increased capital and
operating costs, experience operational delays and result in potential adverse impacts to our ability to reliably serve our customers. See Part I, Item 1. Business and
Item 1A. Risk Factors of this Annual Report on Form 10-K for further information.
Maintenance costs may be capitalized or expensed, depending on the nature of the activities. For any given reporting period, the mix of projects that we
undertake will affect the amounts we record as property, plant and equipment on our Consolidated Balance Sheets or recognize as expenses, which impacts our
earnings. In 2021, we expect to spend approximately $370.0 million to maintain our pipeline systems, of which approximately $150.0 million is expected to be
maintenance capital. In 2020, we spent $361.1 million, of which $148.8 million was recorded as maintenance capital. Refer to Capital Expenditures for more
information regarding certain of our maintenance costs.
21
Results of Operations
Note 2 in Part II, Item 8. of this Annual Report on Form 10-K contains a summary of our revenues and the related revenue recognition policies. A
significant portion of our revenues are fee-based, being derived from capacity reservation charges under firm agreements with customers, which do not vary
significantly period to period, but are impacted by longer-term trends in our business such as lower pricing on contract renewals and other factors discussed
elsewhere in this MD&A. Our operating costs and expenses do not vary significantly based upon the amount of products transported, with the exception of costs
recorded in Fuel and transportation expense, which are netted with fuel retained on our Consolidated Statements of Income.
Please refer to the disclosures in this Item 7. of this Annual Report on Form 10-K of items that have impacted, or could impact in the future, our results of
operations.
2020 Compared with 2019
Our net income for the year ended December 31, 2020, decreased $5.2 million, or 2%, to $290.5 million compared to $295.7 million for the year ended
December 31, 2019, primarily due to the factors discussed below. Excluding the impacts from the 2020 and 2019 customer bankruptcies, as discussed in Note 5 in
Part II, Item 8. of this Annual Report on Form 10-K, our net income for the year ended December 31, 2020, would have decreased $13.8 million, or 5%, compared
to the comparative period.
Operating revenues for the year ended December 31, 2020, increased $2.4 million, or less than 1%, to $1,297.6 million, compared to $1,295.2 million for
the year ended December 31, 2019. Including the effect of the items in fuel and transportation expense, and excluding the impact from the customer bankruptcies
as discussed in Note 5 in Part II, Item 8. of this Annual Report on Form 10-K, operating revenues decreased $10.7 million, or 1%. The decrease was driven by
contract expirations that were recontracted at overall lower average rates as discussed above, mostly offset by revenues from our recently completed growth
projects and higher storage and PAL revenues due to favorable market conditions.
Operating costs and expenses for the year ended December 31, 2020, increased $21.5 million, or 3%, to $843.0 million, compared to $821.5 million for
the year ended December 31, 2019. Excluding items offset with operating revenues, operating costs and expenses increased $17.0 million, or 2%, when compared
to 2019. The operating expense increase was primarily due to an increased asset base from recently completed growth projects and the expiration of property tax
abatements, partially offset by lower maintenance project spending and employee-related costs.
Total other deductions for the year ended December 31, 2020, decreased $13.7 million, or 8%, to $163.8 million compared to $177.5 million for 2019
primarily due to lower interest rates and higher allowance for funds used for construction.
Liquidity and Capital Resources
We are a partnership holding company and derive all of our operating cash flow from our operating subsidiaries. Our principal sources of liquidity include
cash generated from operating activities, our revolving credit facility and debt issuances. Our operating subsidiaries use cash from their respective operations to
fund their operating activities and maintenance capital requirements, service their indebtedness and make advances or distributions to Boardwalk Pipelines.
Boardwalk Pipelines uses cash provided from the operating subsidiaries and, as needed, borrowings under our revolving credit facility to service outstanding
indebtedness and make distributions or advances to us. At December 31, 2020, we had no guarantees of off-balance sheet debt or other similar commitments to
third parties, no debt obligations that contain provisions requiring accelerated payment of the related obligations in the event of specified levels of declines in credit
ratings and no other off-balance sheet arrangements.
At December 31, 2020, we had $2.9 million of cash on hand and more than $1.3 billion of available borrowing capacity under our $1.475 billion
revolving credit facility. We anticipate that our existing capital resources, including our revolving credit facility and our cash flows from operating activities, will
be adequate to fund our operations and capital expenditures for 2021. We may seek to access the debt markets to fund some or all capital expenditures for growth
projects, acquisitions or for general partnership purposes. During 2020 we utilized the remaining capacity under our effective shelf registration statement, and we
plan to file with the SEC and expect to have declared effective in the first quarter 2021, a $1.0 billion shelf registration statement under which we may publicly
issue debt securities, warrants or rights from time to time. As of December 31, 2020, we have $4.6 billion of contractual cash payment obligations under firm
agreements, of which $4.4 billion represents principal and interest payments related to our long-term debt. Note 11 in Part II, Item 8. of this Annual Report
22
on Form 10-K contains more information regarding our long-term debt and financing activities and Notes 4 and 5 contain more information about our other
commitments.
Credit Ratings
Most of our senior unsecured debt is rated by independent credit rating agencies. The credit ratings affect our ability to access the public and private debt
markets, as well as the terms and the cost of our borrowings. Our ability to satisfy financing requirements or fund planned growth capital expenditures will depend
upon our future operating performance and our ability to access the capital markets, which are affected by economic factors in our industry as well as other
financial and business factors, some of which are beyond our control. As of February 8, 2021, our credit ratings for our senior unsecured notes and that of our
operating subsidiaries having outstanding rated debt were as follows:
Rating agency
Standard and Poor's
Moody's Investor Services
Fitch Ratings, Inc.
Rating
(Us/Operating
Subsidiaries)
BBB-/BBB-
Baa3/Baa2
BBB-/BBB-
Outlook
(Us/Operating
Subsidiaries)
Stable/Stable
Stable/Stable
Positive/Positive
Credit ratings reflect the view of a rating agency and are not a recommendation to buy, sell or hold any security, and may be revised or withdrawn at any
time by the rating agency if it determines that the facts and circumstances warrant such a change. Each credit agency's rating should be evaluated independently of
any other credit agency's rating.
Guarantee of Securities of Subsidiaries
During the second quarter 2020, we early adopted the SEC's Financial Disclosures about Guarantors and Issuers of Guaranteed Securities and Affiliates
Whose Securities Collateralize a Registrant's Securities rules, which simplify the disclosure requirements under Rule 3-10 of Regulation S-X related to our
registered securities and allow for the simplified disclosure to be included within this MD&A. Accordingly, the required disclosures are provided below.
Our debt is primarily issued at Boardwalk Pipelines, a wholly owned subsidiary of us, although we have historically also issued debt at our operating
subsidiaries. As of December 31, 2020, all of the outstanding notes issued by Boardwalk Pipelines (Subsidiary Issuer) and the full amount of the revolving credit
facility, are guaranteed by us (Parent Guarantor). The purpose of the guarantees is to help simplify our reporting and capital structure.
We guarantee the amounts borrowed under the revolving credit facility, but those amounts are not subject to the reporting requirements of Rule 13-01 of
Regulation S-X. The below table identifies our principal amounts outstanding for the debt that is subject to the disclosure rules of Rule 13-01 of Regulation S-X (in
millions):
Principal amounts guaranteed by Boardwalk Pipeline Partners
Principal amounts not guaranteed
Other
(2)
(3)
Long-term debt and finance lease obligation
(1)
As of December 31,
2020
As of December 31,
2019
$
$
2,950.0
400.0
110.7
3,460.7
$
$
2,450.0
840.0
276.1
3,566.1
(1) This represents principal amounts of all outstanding debt at Boardwalk Pipelines subject to the disclosure rules of Rule 13-01 of Regulation S-X (the
Guaranteed Notes), and as of December 31, 2020, this includes the notes issued by Boardwalk Pipelines in August 2020, as further discussed above
and in Note 11 in Part II, Item 8. of this Annual Report on Form 10-K.
(2) This represents principal amounts of outstanding debt at Gulf South and Texas Gas, excluding any borrowings under the revolving credit facility.
(3) As of December 31, 2020 and 2019, this represents the amounts related to a finance lease, unamortized debt discount and issuance costs and
outstanding borrowings under the revolving credit facility guaranteed by Boardwalk Pipeline Partners.
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The Guaranteed Notes are fully and unconditionally guaranteed by the Parent Guarantor on a senior unsecured basis. The guarantees of the Guaranteed
Notes rank equally with all of our existing and future senior debt, including our guarantee of indebtedness under our revolving credit facility. The guarantees will
be effectively subordinated in right of payment to all of our future secured debt to the extent of the value of the assets securing such debt. There are no restrictions
on the Subsidiary Issuer's ability to pay dividends or make loans to the Parent Guarantor. The guarantee obligations will be terminated with respect to any series of
notes if that series has been discharged or defeased.
Our operating assets, operating liabilities, operating revenues, expenses and other comprehensive income either exist at or are generated by our operating
subsidiaries. The Parent Guarantor and the Subsidiary Issuer have no material assets, liabilities or operations independent of their respective financing activities,
including the Guaranteed Notes and advances to and from each other and the operating subsidiaries as a result of the cash management program described in Note
2 of Part II, Item 8. of this Annual Report on Form 10-K, and their investments in the operating subsidiaries. For these reasons, we meet the criteria in Rule 13-01
of Regulation S-X to omit the summarized financial information from our disclosures.
Capital Expenditures
Maintenance capital expenditures for the years ended December 31, 2020, 2019 and 2018 were $148.8 million, $138.7 million and $108.4 million.
Growth capital expenditures were $270.6 million, $277.7 million and $359.8 million for the years ended December 31, 2020, 2019 and 2018. During the year
ended December 31, 2020, we purchased the remaining undivided interest in the Bistineau storage facility that we did not previously own for $18.8 million. In
2019 and 2018, we purchased $12.6 million and $18.5 million of natural gas to be used as base gas for our integrated natural gas pipeline system.
We expect total capital expenditures to be approximately $340.0 million in 2021, including approximately $150.0 million for maintenance capital and
$190.0 million related to growth projects.
Critical Accounting Estimates and Policies
Our significant accounting policies are described in Note 2 in Part II, Item 8. of this Annual Report on Form 10-K. The preparation of these consolidated
financial statements in accordance with accounting principles generally accepted in the U.S. requires us to make estimates and judgments that affect the reported
amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities. Estimates are based on historical experience and on
various other assumptions that are believed to be reasonable under the circumstances. The result of this process forms the basis for making judgments about the
carrying amount of assets and liabilities that are not readily apparent from other sources. We review our estimates and judgments on a regular, ongoing basis.
Changes in facts and circumstances may result in revised estimates and actual results may differ materially from those estimates. Any effects on our business,
financial position or results of operations resulting from revisions to these estimates are recorded in the periods in which the facts that give rise to the revisions
become known.
The following accounting policies and estimates are considered critical due to the potentially material impact that the estimates, judgments and
uncertainties affecting the application of these policies might have on our reported financial information.
Goodwill
Goodwill represents the excess of the cost of an acquisition over the fair value of the net identifiable assets acquired and liabilities assumed. Goodwill is
tested for impairment at the reporting unit level at least annually or more frequently when events occur and circumstances change that would more likely than not
reduce the fair value of a reporting unit below its carrying amount. Accounting requirements provide that a reporting entity may perform an optional qualitative
assessment on an annual basis to determine whether events occurred or circumstances changed that would more likely than not reduce the fair value of a reporting
unit below its carrying amount. If an initial qualitative assessment identifies that it is more likely than not that the fair value of a reporting unit is less than its
carrying amount, or the optional qualitative assessment is not performed, a quantitative analysis is performed. The quantitative goodwill impairment test is
performed by calculating the fair value of the reporting unit and comparing it to the reporting unit's carrying amount. If the fair value of a reporting unit exceeds its
carrying amount, goodwill of the reporting unit is not impaired. However, if the carrying amount of a reporting unit exceeds its fair value, an impairment loss is
recognized in an amount equal to that excess, limited to the total amount of goodwill recorded on the reporting unit.
As of November 30, 2020, our annual goodwill testing date, we performed a quantitative analysis on our two reporting units to measure whether the fair
value of either of our reporting units was less than their carrying amounts. The fair value
24
measurement of the reporting units was derived based on judgments and assumptions we believe market participants would use in assessing the fair value of the
reporting units. These judgments and assumptions included the valuation premise, use of a discounted cash flow model to estimate fair value under an income
approach and inputs to the valuation model. The inputs included our five-year financial plan operating results, the long-term outlook for growth in natural gas and
NGLs demand, measures of the risk-free rate, equity premium and systematic risk used in the calculation of the applied discount rate under the capital asset pricing
model and views regarding future market conditions, among others. The reasonableness of fair value estimates under the income approach were supported by a
market approach under which we applied EBITDA multiples derived from publicly-available information to each reporting unit's EBITDA. The use of alternate
judgments and assumptions could substantially change the results of our goodwill impairment analysis, including the recognition of an impairment charge in our
Consolidated Financial Statements.
The results of the quantitative goodwill impairment test for 2020 and 2019 indicated that the fair value of our two reporting units exceeded their carrying
amounts and no goodwill impairment charges were recognized. The estimated fair values of our reporting units fluctuate from year to year, and in 2020, the
estimated fair values of the reporting units exceeded their carrying amounts by amounts that were lower than indicated in 2019, with the cushion of a reporting unit
that had goodwill of $73.9 million being approximately 15%. Although the prospects for our reporting units remain positive, including their strong base operating
cash flows and the markets in which they operate, significant changes in future estimated operating revenues or cash flows, or any other changes to the inputs to
the valuation model, such as those previously discussed, could result in the recognition of future impairment charges.
Impairment of Long-Lived Assets (including Tangible and Definite-Lived Intangible Assets)
We evaluate whether the carrying amounts of our long-lived and intangible assets have been impaired when circumstances indicate the carrying amount
of those assets may not be recoverable. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and
eventual disposition of the asset. If the carrying amount is not recoverable, an impairment loss is measured as the excess of the asset's carrying amount over its fair
value. For the years ended December 31, 2020, 2019 and 2018, we recognized immaterial amounts related to asset impairment charges.
Forward-Looking Statements
Certain statements contained in this Annual Report on Form 10-K, as well as some statements in periodic press releases and some oral statements made
by our officials and our subsidiaries during presentations about us, are “forward-looking.” Forward-looking statements include, without limitation, any statement
that may project, indicate or imply future results, events, performance, intentions or achievements, and may contain the words “expect,” “intend,” “plan,”
“anticipate,” “estimate,” “believe,” “will likely result” and similar expressions. In addition, any statement made by our management concerning future financial
performance (including future revenues, earnings or growth rates), ongoing business strategies or prospects and possible actions by us or our subsidiaries, are also
forward-looking statements.
Forward-looking statements are based on current expectations and projections about future events and their potential impact on us. While management
believes that these forward-looking statements are reasonable as and when made, there is no assurance that future events affecting us will be those that we
anticipate. All forward-looking statements are inherently subject to a variety of risks and uncertainties, many of which are beyond our control which could cause
actual results to differ materially from those anticipated or projected. These include, among others, risks and uncertainties related to the impacts of recent volatility
in energy prices and the COVID-19 pandemic, the impacts of changes to laws and regulations or the implementation thereof, the costs of maintaining and ensuring
the integrity and reliability of our pipeline systems, our ability to maintain or replace expiring gas transportation and storage contracts, our ability to complete
projects that we have commenced or will commence, successful negotiation, consummation and completion of contemplated transactions, projects and agreements,
and our ability to contract and sell short-term capacity on our pipelines. Developments in any of these areas could cause our results to differ materially from results
that have been or may be anticipated or projected. Forward-looking statements speak only as of the date they are made and we expressly disclaim any obligation or
undertaking to update these statements to reflect any change in our expectations or beliefs or any change in events, conditions or circumstances on which any
forward-looking statement is based.
Refer to Part I, Item 1A. of this Annual Report on Form 10-K for additional risks and uncertainties regarding our forward-looking statements.
25
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Interest Rate Risk:
With the exception of our revolving credit facility, for which the interest rates are periodically reset, our debt has been issued at fixed rates. For fixed-rate
debt, changes in interest rates affect the fair value of the debt instruments but do not directly affect our earnings or cash flows. The following table presents market
risk associated with our fixed-rate, long-term debt at December 31 (in millions, except interest rates):
Carrying amount of fixed-rate debt
Fair value of fixed-rate debt
100 basis point increase in interest rates and resulting debt decrease
100 basis point decrease in interest rates and resulting debt increase
Weighted-average interest rate
$
$
$
$
2020
2019
3,330.4
3,717.6
182.8
195.7
4.84 %
$
$
$
$
3,270.7
3,503.3
158.6
169.5
5.06 %
At December 31, 2020, we had $130.0 million of variable-rate debt outstanding at a weighted-average interest rate of 1.39%. A 1.00% increase in interest
rates would increase our cash payments for interest on our variable-rate debt by $1.3 million on an annualized basis. At December 31, 2019, we had $295.0 million
outstanding under variable-rate agreements at a weighted-average interest rate of 3.00%.
Commodity Risk:
Our pipelines do not take title to the natural gas and NGLs which they transport and store, therefore, they do not assume the related commodity price risk
associated with the products.
Credit Risk:
Our credit exposure generally relates to receivables for services provided, as well as volumes owed by customers for imbalances or gas lent by us to them,
generally under PAL and certain firm services. Natural gas price volatility can materially increase credit risk related to gas loaned to customers. We also have
credit risk related to customers supporting some of our growth projects. If any significant customer of ours should have credit or financial problems resulting in a
delay or failure to pay for services provided by us or repay gas they owe to us, this could have a material adverse effect on our business, financial condition, results
of operations or cash flows.
As of December 31, 2020, the amount of gas owed to our operating subsidiaries due to gas imbalances and gas loaned under PAL and certain firm service
agreements was approximately 11.2 trillion British thermal units (TBtu). Assuming an average market price during December 2020 of $2.45 per million British
thermal unit (MMBtu), the market value of that gas was approximately $27.4 million. As of December 31, 2019, the amount of gas owed to our operating
subsidiaries due to gas imbalances and gas loaned under PAL and certain firm service agreements was approximately 12.8 TBtu. Assuming an average market
price during December 2019 of $2.08 per MMBtu, the market value of that gas at December 31, 2019, was approximately $26.6 million. As of December 31, 2020
and 2019, there were no outstanding NGL imbalances owed to our operating subsidiaries.
26
Item 8. Financial Statements and Supplementary Data
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Boardwalk GP, LLC and the Partners of Boardwalk Pipeline Partners, LP
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Boardwalk Pipeline Partners, LP and subsidiaries (the "Company") as of December 31,
2020 and 2019, the related consolidated statements of income, comprehensive income, cash flows and changes in partners’ capital, for each of the three years in the
period ended December 31, 2020, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present
fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each
of the three years in the period ended December 31, 2020, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial
statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and
are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the
Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were
we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control
over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting.
Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and
performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the
financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the
overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or
required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our
especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial
statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the
accounts or disclosures to which it relates.
Goodwill – Refer to Notes 2 and 8 to the financial statements
Critical Audit Matter Description
The Company’s evaluation of goodwill for impairment involves a quantitative analysis to measure whether the fair value of either of the reporting units is
less than their carrying amounts, including goodwill. If the carrying amount of a reporting unit exceeds its fair value, an impairment loss shall be recognized in an
amount equal to that excess, limited to the total amount of goodwill recorded on the reporting unit.
The fair value measurement of the reporting units is derived based on judgments and assumptions including the use of a discounted cash flow model to
estimate fair value and inputs to the valuation model. The inputs included the long-term outlook for growth in natural gas and NGLs demand, the applied discount
rate, and the five-year financial plan operating results. The use of alternate judgments and assumptions could substantially change the results of the goodwill
impairment analysis, including the recognition of an impairment charge in the Consolidated Statement of Income. The results of the
27
quantitative goodwill impairment test indicated that the fair value of the Company’s reporting units exceeded their carrying amounts and no goodwill impairment
charges were recognized.
We identified goodwill for Boardwalk Pipeline Partners, LP as a critical audit matter because of the significant judgments made by management to
estimate the fair value of each reporting unit. This required a high degree of auditor judgment and an increased extent of effort, including the need to involve fair
value specialists, when performing audit procedures to evaluate the reasonableness of management’s judgments and assumptions related to the applied discount
rate, the long-term outlook for growth in natural gas and NGLs demand, and the Company’s future estimated operating revenues within the five-year financial plan
operating results.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to management’s assumptions underlying the applied discount rates, the long-term outlook for growth in natural gas and
NGLs demand, and the Company’s future estimated operating revenues within the five-year financial plan operating results included the following, among others:
• We tested the effectiveness of controls over management’s goodwill impairment test, including controls over management’s estimate of the applied
discount rate, the long-term outlook for growth in natural gas and NGLs demand, and the future estimated operating revenues for each reporting unit.
• We evaluated management’s ability to accurately forecast future operating revenues by comparing actual results to management’s historical forecasts for
each reporting unit.
• We evaluated the reasonableness of the future estimated operating revenues within the five-year financial plan operating results by comparing the
forecasts to:
– Historical operating revenues of the Company’s similar or existing contracts with customers and average annual growth rates.
–
Forecasted information in analyst and industry reports for the Company and certain of its peer companies.
• With the assistance of our fair value specialists, we evaluated the reasonableness of the applied discount rate, and the long-term outlook for growth in
natural gas and NGLs demand used as inputs to management’s goodwill impairment test for each reporting unit by:
– Comparing the Company’s estimate of the long-term outlook for growth in natural gas and NGLs demand for each reporting unit to industry
reports and other market data.
– Developing a range of independent estimates of the applied discount rate for each reporting unit and comparing those to the applied discount
rates selected by management for each reporting unit.
/s/ Deloitte & Touche LLP
Houston, Texas
February 9, 2021
We have served as the Company's auditor since 2003.
28
BOARDWALK PIPELINE PARTNERS, LP
CONSOLIDATED BALANCE SHEETS
(Millions)
ASSETS
December 31,
2020
2019
Current Assets:
Cash and cash equivalents
Receivables:
Trade, net
Other
Gas transportation receivables
Prepayments
Other current assets
Total current assets
Property, Plant and Equipment:
Natural gas transmission and other plant
Construction work in progress
Property, plant and equipment, gross
Less—accumulated depreciation and amortization
Property, plant and equipment, net
Other Assets:
Goodwill
Gas stored underground
Other
Total other assets
Total Assets
$
2.9 $
115.1
23.4
6.6
18.5
7.0
173.5
11,964.1
184.2
12,148.3
3,598.5
8,549.8
237.4
101.9
167.3
506.6
3.7
117.2
15.2
7.5
16.0
8.1
167.7
11,489.5
253.9
11,743.4
3,263.7
8,479.7
237.4
97.1
161.2
495.7
$
9,229.9 $
9,143.1
The accompanying notes are an integral part of these consolidated financial statements.
29
BOARDWALK PIPELINE PARTNERS, LP
CONSOLIDATED BALANCE SHEETS
(Millions)
LIABILITIES AND PARTNERS' CAPITAL
December 31,
2020
2019
Current Liabilities:
Payables:
Trade
Affiliates
Other
Gas payables
Accrued taxes, other
Accrued interest
Accrued payroll and employee benefits
Construction retainage
Regulatory liability
Deferred income
Other current liabilities
Total current liabilities
Long-term debt and finance lease obligation
Other Liabilities and Deferred Credits:
Pension liability
Asset retirement obligations
Provision for other asset retirement
Other
Total other liabilities and deferred credits
Commitments and Contingencies
Partners' Capital:
Partners' capital
Accumulated other comprehensive loss
Total partners' capital
Total Liabilities and Partners' Capital
$
$
43.6 $
9.9
9.6
10.9
70.3
33.1
34.5
11.5
14.1
4.9
24.5
266.9
65.8
4.6
11.6
6.4
60.1
35.6
38.1
16.8
9.5
2.2
18.8
269.5
3,460.7
3,566.1
18.0
54.9
81.6
98.7
253.2
5,328.9
(79.8)
5,249.1
9,229.9 $
20.5
56.8
75.1
95.6
248.0
5,140.6
(81.1)
5,059.5
9,143.1
The accompanying notes are an integral part of these consolidated financial statements.
30
BOARDWALK PIPELINE PARTNERS, LP
CONSOLIDATED STATEMENTS OF INCOME
(Millions)
Operating Revenues:
Transportation
Storage, parking and lending
Other
Total operating revenues
Operating Costs and Expenses:
Fuel and transportation
Operation and maintenance
Administrative and general
Depreciation and amortization
Loss (gain) on sale of assets and impairments
Taxes other than income taxes
Total operating costs and expenses
Operating income
Other Deductions (Income):
Interest expense
Interest income
Miscellaneous other income, net
Total other deductions
Income before income taxes
Income taxes
Net income
For the Year Ended December 31,
2019
2020
2018
$
1,117.9 $
110.5
69.2
1,297.6
1,146.2 $
92.0
57.0
1,295.2
1,083.6
90.4
49.7
1,223.7
18.3
212.3
139.9
358.8
0.9
112.8
843.0
454.6
169.7
—
(5.9)
163.8
290.8
0.3
13.8
219.1
141.1
346.1
(3.2)
104.6
821.5
473.7
178.7
(0.3)
(0.9)
177.5
296.2
0.5
$
290.5 $
295.7 $
19.0
205.6
136.3
344.7
(0.2)
103.8
809.2
414.5
175.7
(0.1)
(2.0)
173.6
240.9
0.6
240.3
The accompanying notes are an integral part of these consolidated financial statements.
31
BOARDWALK PIPELINE PARTNERS, LP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Millions)
Net income
Other comprehensive income (loss):
Reclassification adjustment transferred to Net income from cash flow hedges
Pension and other postretirement benefit costs, net of tax
Total Comprehensive Income
$
$
For the Year Ended December 31,
2019
2020
2018
290.5 $
295.7 $
0.8
0.5
291.8 $
0.9
3.2
299.8 $
240.3
1.2
(5.4)
236.1
The accompanying notes are an integral part of these consolidated financial statements.
32
BOARDWALK PIPELINE PARTNERS, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions)
OPERATING ACTIVITIES:
Net income
Adjustments to reconcile net income to cash provided by operations:
Depreciation and amortization
Amortization of deferred costs and other
Loss (gain) on sale of assets and impairments
Changes in operating assets and liabilities:
Trade and other receivables
Gas receivables and storage assets
Other assets
Trade and other payables
Gas payables
Accrued liabilities
Regulatory assets and liabilities
Other liabilities
Net cash provided by operating activities
INVESTING ACTIVITIES:
Capital expenditures
Proceeds from sale of operating assets
Advances to affiliates
Net cash used in investing activities
FINANCING ACTIVITIES:
Proceeds from long-term debt, net of issuance cost
Repayment of borrowings from long-term debt
Proceeds from borrowings on revolving credit agreement
Repayment of borrowings on revolving credit agreement
Principal payment of finance lease obligation
Advances from affiliates
Distributions paid
Net cash used in financing activities
(Decrease) increase in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
For the Year Ended
December 31,
2019
2018
2020
$
290.5 $
295.7 $
240.3
358.8
12.4
0.9
(6.1)
(9.0)
(4.5)
(10.6)
1.4
4.7
4.8
(2.1)
641.2
(438.2)
3.8
—
(434.4)
495.0
(440.0)
687.9
(852.9)
(0.7)
5.3
(102.2)
(207.6)
(0.8)
3.7
2.9 $
346.1
13.1
(3.2)
21.2
(27.6)
0.4
2.9
(0.1)
1.7
20.7
(8.9)
662.0
(429.0)
5.7
—
(423.3)
495.2
(350.0)
660.0
(945.0)
(0.7)
4.1
(102.2)
(238.6)
0.1
3.6
3.7 $
344.7
8.9
(0.2)
(20.4)
12.6
(1.1)
(0.2)
1.2
6.0
(16.0)
(10.2)
565.6
(486.7)
1.0
(0.1)
(485.8)
—
(185.0)
640.0
(445.0)
(0.6)
(1.0)
(102.2)
(93.8)
(14.0)
17.6
3.6
$
The accompanying notes are an integral part of these consolidated financial statements.
33
BOARDWALK PIPELINE PARTNERS, LP
CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL
(Millions)
Balance December 31, 2017
(Deduct) add:
Cumulative effect adjustment from the implementation of
ASC 606
Adjustment related to registration rights agreement
Net income
Distributions paid
Other comprehensive loss, net of tax
General Partner purchase of common units
and conversion to partnership interests
Balance December 31, 2018
Add (deduct):
Net income
Distributions paid
Other comprehensive income, net of tax
Balance December 31, 2019
Add (deduct):
Net income
Distributions paid
Other comprehensive income, net of tax
Balance December 31, 2020
Common
Units
General
Partner
Partners'
Capital
Accumulated
Other
Comprehensive
(Loss) Income
Total
Partners'
Capital
$
4,713.1 $
92.7 $
— $
(81.0)
$
4,724.8
(12.6)
16.0
136.6
(50.1)
—
(0.2)
—
2.8
(1.0)
—
—
—
100.9
(51.1)
—
(4,803.0)
(94.3)
— $
— $
4,897.3
4,947.1 $
—
—
—
— $
—
—
—
— $
—
—
—
— $
—
—
—
— $
295.7
(102.2)
—
5,140.6 $
290.5
(102.2)
—
5,328.9 $
$
$
$
—
—
—
—
(4.2)
—
(85.2)
—
—
4.1
(81.1)
—
—
1.3
(79.8)
$
$
$
(12.8)
16.0
240.3
(102.2)
(4.2)
—
4,861.9
295.7
(102.2)
4.1
5,059.5
290.5
(102.2)
1.3
5,249.1
The accompanying notes are an integral part of these consolidated financial statements.
34
BOARDWALK PIPELINE PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1: Corporate Structure
Boardwalk Pipeline Partners, LP (the Company) is a Delaware limited partnership formed in 2005 to own and operate the business conducted by its
primary subsidiary Boardwalk Pipelines, LP (Boardwalk Pipelines) and its operating subsidiaries, Gulf South Pipeline Company, LLC (Gulf South), Texas Gas
Transmission, LLC (Texas Gas), Boardwalk Louisiana Midstream, LLC (Louisiana Midstream), Boardwalk Petrochemical Pipeline, LLC and Boardwalk Texas
Intrastate, LLC (together, the operating subsidiaries), which consists of integrated natural gas and natural gas liquids and other hydrocarbons (herein referred to
together as NGLs) pipeline and storage systems. All of the Company's operations are conducted by the operating subsidiaries. Effective January 1, 2020, Gulf
South converted from a limited partnership to a limited liability company. Immediately subsequent to the conversion, Gulf Crossing Pipeline Company LLC was
merged into Gulf South.
As of December 31, 2020, Boardwalk Pipelines Holding Corp. (BPHC), a wholly-owned subsidiary of Loews Corporation (Loews), owned directly or
indirectly, 100% of the Company's capital.
Note 2: Basis of Presentation and Accounting Policies
Basis of Presentation
The accompanying consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in
the United States of America (U.S.) (GAAP).
Principles of Consolidation
The consolidated financial statements include the Company's accounts and those of its wholly-owned subsidiaries after elimination of intercompany
transactions.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported
amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities and the fair values of certain items. The Company bases its
estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, which form the basis for making
judgments about the carrying amounts of assets and liabilities that are not readily apparent from other sources. Actual results could differ from such estimates.
Segment Information
The Company operates in one reportable segment - the operation of interstate natural gas and NGLs pipeline systems and integrated storage facilities.
This segment consists of interstate natural gas pipeline systems which are located in the Gulf Coast region, Oklahoma, Arkansas and the Midwestern states of
Tennessee, Kentucky, Illinois, Indiana and Ohio and integrated natural gas storage facilities located in Indiana, Kentucky, Louisiana and Mississippi, and NGL
pipelines and storage facilities in Louisiana and Texas.
Regulatory Accounting
Most of the Company's natural gas pipeline subsidiaries are regulated by the Federal Energy Regulatory Commission (FERC). When certain criteria are
met, GAAP requires that certain rate-regulated entities account for and report assets and liabilities consistent with the economic effect of the manner in which
independent third-party regulators establish rates (regulatory accounting). This basis of accounting is applicable to operations of the Company's Texas Gas
subsidiary, which records certain costs and benefits as regulatory assets and liabilities in order to provide for recovery from or refunds to customers in future
periods, but is not applicable to the operations associated with the Fayetteville and Greenville Laterals due to rates charged under negotiated rate agreements and a
portion of Texas Gas' storage capacity due to the regulatory treatment associated with the rates charged for that capacity.
35
The Company applies regulatory accounting for its fuel trackers on Gulf South, under which the value of fuel received from customers paying the
maximum tariff rate and the related value of fuel used in transportation are recorded to a regulatory asset or liability depending on whether Gulf South uses more
fuel than it collects from customers or collects more fuel than it uses. Other than as described for Texas Gas and for the fuel trackers on Gulf South, regulatory
accounting is not applicable to the Company's other FERC-regulated operations.
The Company monitors the regulatory and competitive environment in which it operates to determine whether its regulatory assets continue to be
probable of recovery. If the Company determines that all or a portion of its regulatory assets no longer meets the criteria for recognition as regulatory assets, that
portion which is not recoverable will be written off, net of any regulatory liabilities.
Note 10 contains more information regarding the Company's regulatory assets and liabilities.
Fair Value Measurements
Fair value refers to an exit price that would be received to sell an asset or paid to transfer a liability in an orderly transaction in the principal market in
which the reporting entity transacts based on the assumptions market participants would use when pricing the asset or liability assuming its highest and best use. A
fair value hierarchy has been established that prioritizes the information used to develop those assumptions giving priority, from highest to lowest, to quoted prices
in active markets for identical assets and liabilities (Level 1); observable inputs not included in Level 1, for example, quoted prices for similar assets and liabilities
(Level 2); and unobservable data (Level 3), for example, a reporting entity's own internal data based on the best information available in the circumstances. The
Company uses fair value measurements to account for asset retirement obligations (ARO) and any impairment charges.
Notes 6 and 12 contain more information regarding fair value measurements.
Cash and Cash Equivalents
Cash equivalents are highly liquid investments with an original maturity of three months or less and are stated at cost plus accrued interest, which
approximates fair value. The Company had no restricted cash at December 31, 2020 and 2019.
Cash Management
The operating subsidiaries participate in an intercompany cash management program, with those that are FERC-regulated participating to the extent they
are permitted under FERC regulations. Under the cash management program, depending on whether a participating subsidiary has short-term cash surpluses or
cash requirements, Boardwalk Pipelines either provides cash to them or they provide cash to Boardwalk Pipelines. The transactions are represented by demand
notes and are stated at historical carrying amounts. Interest income and expense are recognized on an accrual basis when collection is reasonably assured. The
interest rate on intercompany demand notes is London Interbank Offered Rate (LIBOR) plus 1.00% and is adjusted every three months.
Trade and Other Receivables
Trade and other receivables are stated at their historical carrying amount, net of allowances for doubtful accounts. The Company establishes an allowance
for doubtful accounts under an expected credit loss model based on historical credit loss experience and specific facts and circumstances. Uncollectible receivables
are written off when a settlement is reached for an amount that is less than the outstanding historical balance or a receivable amount is deemed otherwise
unrealizable.
Gas Stored Underground and Gas Receivables and Payables
Certain of the Company's operating subsidiaries have underground gas in storage which is utilized for system management and operational balancing, as
well as for services including firm and interruptible storage associated with certain no-notice and parking and lending (PAL) services. Gas stored underground
includes the historical cost of natural gas volumes owned by the operating subsidiaries, at times reduced by certain operational encroachments upon that gas.
The operating subsidiaries provide storage services whereby they store natural gas or NGLs on behalf of customers and also periodically hold customer
gas under PAL services. Since the customers retain title to the gas held by the Company in
36
providing these services, the Company does not record the related gas on its Consolidated Balance Sheets. Certain of the Company's operating subsidiaries also
periodically lend gas and NGLs to customers.
In the course of providing transportation and storage services to customers, the operating subsidiaries may receive different quantities of gas from
shippers and operators than the quantities delivered on behalf of those shippers and operators. This results in transportation and exchange gas receivables and
payables, commonly known as imbalances, which are primarily settled in cash or the receipt or delivery of gas in the future. Settlement of imbalances requires
agreement between the pipelines and shippers or operators as to allocations of volumes to specific transportation contracts and timing of delivery of gas based on
operational conditions. The receivables and payables are valued at market price for operations where regulatory accounting is not applicable and are valued at the
historical value of gas in storage for operations where regulatory accounting is applicable.
Materials and Supplies
Materials and supplies are carried at average cost and are included in Other Assets on the Consolidated Balance Sheets. The Company expects its
materials and supplies to be used for projects related to its property, plant and equipment (PPE) and for future growth projects. At December 31, 2020 and 2019,
the Company held approximately $25.5 million and $21.8 million of materials and supplies.
Property, Plant and Equipment and Repair and Maintenance Costs
PPE is recorded at its original cost of construction or fair value of assets purchased. Construction costs and expenditures for major renewals and
improvements which extend the lives of the respective assets are capitalized. Construction work in progress is included in the financial statements as a component
of PPE. Repair and maintenance costs are expensed as incurred.
Depreciation of PPE related to operations for which regulatory accounting does not apply is provided for using the straight-line method of depreciation
over the estimated useful lives of the assets, which range from 3 to 35 years. The ordinary sale or retirement of PPE for these assets could result in a gain or loss
being recorded in the income statement. Depreciation of PPE related to operations for which regulatory accounting is applicable is provided for primarily on the
straight-line method at FERC-prescribed rates over estimated useful lives of 5 to 62 years. Reflecting the application of composite depreciation, gains and losses
from the ordinary sale or retirement of PPE for these assets are not recognized in earnings and generally do not impact PPE, net.
Note 7 contains more information regarding the Company's PPE.
Goodwill and Intangible Assets
Goodwill represents the excess of the cost of an acquisition over the fair value of the net identifiable assets acquired and liabilities assumed. Goodwill is
tested for impairment at the reporting unit level at least annually, as of November 30, or more frequently when events occur and circumstances change that would
more likely than not reduce the fair value of a reporting unit below its carrying amount. A reporting entity may perform an optional qualitative assessment on an
annual basis to determine whether events occurred or circumstances changed that would more likely than not reduce the fair value of a reporting unit below its
carrying amount. If an initial qualitative assessment identifies that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, or
the optional qualitative assessment is not performed, a quantitative analysis is performed. The quantitative goodwill impairment test is performed by calculating the
fair value of the reporting unit and comparing it to the reporting unit's carrying amount. If the fair value of a reporting unit exceeds its carrying amount, goodwill of
the reporting unit is not impaired. However, if the carrying amount of a reporting unit exceeds its fair value, an impairment loss is recognized in an amount equal to
that excess, limited to the total amount of goodwill recorded on the reporting unit.
Intangible assets are those assets which provide future economic benefit but have no physical substance. The Company recorded intangible assets for
customer relationships obtained through its acquisitions. The customer relationships, which are included in Other Assets on the Consolidated Balance Sheets, have
a finite life and are being amortized over their estimated useful lives.
Note 8 contains more information regarding the Company's goodwill and intangible assets.
37
Impairment of Long-lived Assets (including Tangible and Definite-lived Intangible Assets)
The Company evaluates its long-lived and intangible assets for impairment when, in management's judgment, events or changes in circumstances indicate
that the carrying amount of such assets may not be recoverable. When such a determination has been made, management's estimate of undiscounted future cash
flows attributable to the remaining economic useful life of the asset (or asset group) is compared to the carrying amount of the asset (or asset group) to determine
whether an impairment has occurred. If an impairment of the carrying amount has occurred, the amount of impairment recognized in the financial statements is
determined by estimating the fair value of the assets (or asset group) and recording a loss to the extent that the carrying amount exceeds the estimated fair value.
Capitalized Interest and Allowance for Funds Used During Construction (AFUDC)
The Company records capitalized interest, which represents the cost of borrowed funds used to finance construction activities for operations where
regulatory accounting is not applicable. The Company records AFUDC, which represents the cost of funds, including equity funds, applicable to regulated natural
gas transmission plant under construction as permitted by FERC regulatory practices, in connection with the Company's operations where regulatory accounting is
applicable. Capitalized interest and the allowance for borrowed funds used during construction are recognized as a reduction to Interest expense and the allowance
for equity funds used during construction is included in Miscellaneous other income, net within the Consolidated Statements of Income. The following table
summarizes capitalized interest and the allowance for borrowed funds and allowance for equity funds used during construction (in millions):
Capitalized interest and allowance for borrowed funds used during construction
Allowance for equity funds used during construction
Income Taxes
2020
$
For the Year Ended
December 31,
2019
2018
6.1 $
4.1
5.6 $
1.5
8.5
0.5
The Company is not a taxable entity for federal income tax purposes. As such, it does not directly pay federal income tax. The Company's taxable income
or loss, which may vary substantially from the net income or loss reported in the Consolidated Statements of Income, is includable in the federal income tax returns
of each of its partners. The aggregate difference in the basis of the Company's net assets for financial and income tax purposes is $4.4 billion. The subsidiaries of
the Company directly incur some income-based state taxes which are presented in Income taxes on the Consolidated Statements of Income.
Note 13 contains more information regarding the Company's income taxes.
Asset Retirement Obligations
The accounting requirements for existing legal obligations associated with the future retirement of long-lived assets require entities to record the fair
value of a liability for an ARO in the period during which the liability is incurred. The liability is initially recognized at fair value and is increased with the passage
of time as accretion expense is recorded, until the liability is ultimately settled. The accretion expense is included within Operation and maintenance costs within
the Consolidated Statements of Income. An amount corresponding to the amount of the initial liability is capitalized as part of the carrying amount of the related
long-lived asset and depreciated over the useful life of that asset.
Note 9 contains more information regarding the Company's ARO.
Environmental Liabilities
The Company records environmental liabilities based on management's estimates of the undiscounted future obligation for probable costs associated with
environmental assessment and remediation of operating sites. These estimates are based on evaluations and discussions with counsel and operating personnel and
the current known facts and circumstances related to these environmental matters.
Note 5 contains more information regarding the Company's environmental liabilities.
38
Defined Benefit Plans
The Company maintains postretirement benefit plans for certain employees. The Company funds these plans through periodic contributions which are
invested until the benefits are paid out to the participants, and records an asset or liability based on the overfunded or underfunded status of the plan. The net
benefit costs of the plans are recorded in the Consolidated Statements of Income. Any deferred amounts related to unrecognized gains and losses or changes in
actuarial assumptions are recorded as either a regulatory asset or liability or recorded as a component of accumulated other comprehensive income (AOCI) until
those gains or losses are recognized in the Consolidated Statements of Income.
Note 12 contains more information regarding the Company's pension and postretirement benefit obligations.
Long-Term Compensation
Prior to the purchase of the Company's issued and outstanding publicly-owned common units by the Company's general partner in the third quarter 2018
(Purchase Transaction), the Company provided awards of phantom common units (Phantom Common Units) to certain employees under its Long-Term Incentive
Plan (LTIP). The Company also provides to certain employees awards of long-term cash bonuses (Long-Term Cash Bonuses) under the Boardwalk Pipeline
Partners Unit Appreciation Rights (UAR) and Cash Bonus Plan. Since 2018, the Company has not granted awards in the form of Phantom Common Units and as of
December 31, 2020, all remaining Phantom Common Units had vested and were paid. Beginning in 2019, the Company provided awards of performance awards
(Performance Awards) to certain of its employees under its 2018 Long-Term Incentive Plan (2018 LTIP). A Performance Award is a long-term incentive award
with a stated target amount which is payable in cash, after certain adjustments, upon vesting based on certain specified performance criteria being met.
The Company measures the cost of an award issued in exchange for employee services based on the grant-date fair value of the award in the case of
Phantom Common Units, or the stated amount in the case of Long-Term Cash Bonuses or the stated target amount for Performance Awards. All outstanding
awards are required to be settled in cash and are classified as a liability until settlement. Prior to the Purchase Transaction, unit-based compensation awards were
remeasured each reporting period until the final amount of awards were determined. Outstanding phantom units after the Purchase Transaction were fair valued at
the $12.06 cash purchase price per common unit of the Purchase Transaction plus amounts credited under the distribution equivalent rights (DERs). The related
compensation expense, less forfeitures, is recognized over the period that employees are required to provide services in exchange for the awards, usually the
vesting period.
Note 12 contains more information regarding the Company's long-term compensation.
Partner Capital Accounts
For purposes of maintaining capital accounts prior to the Purchase Transaction, items of income and loss of the Company are allocated among the
partners each period, or portion thereof, in accordance with the partnership agreement, based on their respective ownership interests.
Lease Accounting
Operating lease right-of-use assets and lease liabilities are recognized at the lease commencement date based on the present value of lease payments over
the lease term. The discount rate used to determine the commencement date present value of lease payments is typically the Company's secured borrowing rate, as
most of the Company's leases do not provide an implicit rate.
Revenue Recognition
Nature of Contracts
The Company primarily earns revenues from contracts with customers by providing transportation and storage services for natural gas and NGLs on a
firm and interruptible basis. The Company also provides interruptible natural gas PAL services. The Company's customers choose, based upon their particular
needs, the applicable mix of services depending upon availability of pipeline and storage capacity, the price of services and the volume and timing of customer
requirements. The maximum rates that may be charged by the majority of the Company's operating subsidiaries are established through the FERC's cost-based rate-
making process; however, rates actually charged by those operating subsidiaries may be less than those allowed by the FERC. Under the FERC regulations, certain
revenues that the Company's subsidiaries collect may be subject to possible refunds to customers. Accordingly, during a rate case, estimated refund liabilities are
recorded considering regulatory proceedings,
39
advice of counsel and estimated risk-adjusted total exposure, as well as other factors. The Company's service contracts can range from one to twenty years
although the Company may enter into shorter- or longer-term contracts, and services are invoiced monthly with payment from the customer generally expected
within ten to thirty days, depending on the terms of the contract.
Firm Service Contracts: The Company offers firm services to its customers. The Company's customers can reserve a specific amount of pipeline capacity
at specified receipt and delivery points on the Company's pipeline system (transportation service) or can reserve a specific amount of storage capacity at specified
injection and withdrawal points at the Company's storage facilities (storage service). The Company accounts for firm services as a single promise to stand ready
each month of the contract term to provide the committed capacity for either transportation or storage services when needed by the customer, which represents a
series of distinct monthly services that are substantially the same with the same pattern of transfer to the customer. Although several activities may be required to
provide the firm service, the individual activities do not represent distinct performance obligations because all of the activities must be performed in combination
in order for the Company to provide the firm service.
The transaction price for firm service contracts is comprised of a fixed fee based on the quantity of capacity reserved, regardless of use (capacity
reservation fee), plus variable fees in the form of a usage fee paid on the volume of commodity actually transported or injected and withdrawn from storage. Both
the fixed and usage fees are allocated to the single performance obligation of providing transportation or storage service and recognized over time based upon the
output measure of time as the Company completes its stand-ready obligation to provide contracted capacity and the customer receives and consumes the benefit of
the reserved capacity, which corresponds with the transfer of control to the customer. The fixed fee is recognized ratably over the contract term, representative of
the proportion of the committed stand-ready capacity obligation that has been fulfilled to date, and the usage fee is recognized upon satisfaction of each distinct
monthly performance obligation, consistent with the allocation objective and based upon the level of effort required to satisfy the stand-ready obligation in a given
month. Capacity reservation revenues derived from a firm service contract are generally consistent during the contract term, but can be higher in winter periods
than the rest of the year based upon seasonal rates.
Interruptible Service Contracts: In providing interruptible services to customers, the Company agrees to transport or store natural gas or NGLs for a
customer when capacity is available. The Company does not account for interruptible services with a customer as a contract until the customer nominates for
service and the Company accepts the nomination based upon available pipeline or storage capacity because there are no enforceable rights and obligations until
that time. The nomination and acceptance process is a daily activity and acceptance is granted based upon priority of service and availability of capacity. Upon
acceptance, the Company accounts for interruptible services similarly to its firm services.
The transaction price for interruptible service contracts is comprised of a variable fee in the form of a usage fee paid on the volume of commodity actually
transported or injected and withdrawn from storage. The usage fee is allocated to the single performance obligation of providing interruptible service. Interruptible
service revenues are generally recognized over time based on the output measure of volume transported or stored when services are rendered upon the successful
allocation of the services provided to the customer's account, which best depicts the transfer of control to the customer and satisfaction of the promised service.
Interruptible services are recognized in the month services are provided because the Company has a right to consideration from customers in amounts that
correspond directly to the value that the customer receives from the Company's performance. The rates charged may vary on a daily, monthly or seasonal basis.
Minimum Volume Commitment (MVC) Contracts: Certain of the Company's transportation or storage contracts require customers to transport or store a
minimum volume of commodity over a specified time period. If a customer fails to meet its MVC for the specified time period, the customer is obligated to pay a
contractually-determined deficiency fee based upon the shortfall between the actual volumes transported or stored and the MVC for that period. MVC contracts are
similar in nature to a firm service contract where the performance obligation is a stand-ready obligation that is a series of distinct services that are substantially the
same with the same pattern of transfer to the customer. The transaction price for an MVC is a fee for the volume of commodity actually transported or stored,
which is allocated to each distinct monthly performance obligation, consistent with the allocation objective and based upon the level of effort required to satisfy the
obligation of the transacted service in a given month. Revenues are generally recognized over time based on the output measure of volume transported or stored,
with the recognition of the deficiency fee in the period when it is known the customer cannot make up the deficient volume in the specified period.
Other: Periodically, the Company may enter into contracts with customers for the sale of natural gas or NGLs. The Company recognizes revenues for
these transactions at the point in time of the physical sale of the commodity, which corresponds with the transfer of control of the commodity to the customer and
the consideration is measured as the stated sales price in the contract.
40
Contract Balances
The Company records contract assets primarily related to performance obligations completed but not billed, or partially billed, as of the reporting date.
The Company records contract liabilities, or deferred income, when payment is received in advance of satisfying its performance obligations.
Note 3: Revenues
The Company operates in one reportable segment and contracts directly with end-use customers, including local distribution companies, electric power
generators, exporters of liquefied natural gas and industrial users, with producers and marketers of natural gas, and with interstate and intrastate pipelines, who, in
turn, provide transportation and storage services for end-users. The following table presents the Company's revenues disaggregated by type of service for the years
ended December 31, 2020, 2019 and 2018 (in millions):
Revenues from Contracts with Customers
(1)
Firm Service
Interruptible Service
Other revenues
Total Revenues from Contracts with Customers
Other operating revenues
(2)
Total Operating Revenues
2020
For the Year Ended December 31,
2019
2018
$
$
1,211.7
33.2
18.9
1,263.8
33.8
1,297.6
$
$
1,228.3
29.0
9.1
1,266.4
28.8
1,295.2
$
$
1,161.7
32.2
11.6
1,205.5
18.2
1,223.7
(1) Revenues earned from contracts with MVCs are included in firm service given the stand-ready nature of the performance obligation and the
guaranteed nature of the fees over the contract term. The years ended December 31, 2020 and 2019, contain $34.4 million and $26.2 million of
incremental revenues received related to customer bankruptcies as discussed in Note 5.
(2) Other operating revenues include certain revenues earned from operating leases, pipeline management fees and other activities that are not considered
central and ongoing major business operations of the Company and do not represent revenues earned from contracts with customers.
Contract Balances
As of December 31, 2020 and 2019, the Company had receivables recorded in Trade Receivables from contracts with customers of $115.1 million and
$117.2 million, contract assets recorded in Other Assets from contracts with a customer of $2.9 million and $1.5 million and contract liabilities recorded in
Deferred income (current portion) and Other Liabilities (noncurrent portion) from contracts with customers of $17.2 million and $11.8 million.
As of December 31, 2020, contract liabilities are expected to be recognized through 2040. Significant changes in the contract liabilities balances during
the year ended December 31, 2020, are as follows (in millions):
(1)
Balance as of December 31, 2019
Revenues recognized that were included in the contract liability
balance at the beginning of the period
Increases due to cash received, excluding amounts recognized as
revenues during the period
Balance as of December 31, 2020
(1)
Contract
Liabilities
11.8
(5.1)
10.5
17.2
$
$
41
(1) As of December 31, 2020 and 2019, $4.9 million and $2.2 million were recorded in Deferred income (current portion) and $12.3 million and $9.6
million were recorded in Other Liabilities (noncurrent portion).
Significant changes in the contract liabilities balances during the year ended December 31, 2019, are as follows (in millions):
Contract
Liabilities
(1)
Balance as of December 31, 2018
Revenues recognized that were included in the contract liability
balance at the beginning of the period
Increases due to cash received, excluding amounts recognized as
revenues during the period
Balance as of December 31, 2019
(1)
$
$
9.2
(2.1)
4.7
11.8
(1) As of December 31, 2019 and 2018, $2.2 million and $0.5 million were recorded in Deferred income (current portion) and $9.6 million and $8.7
million were recorded in Other Liabilities (noncurrent portion).
Performance Obligations
The following table includes estimated operating revenues expected to be recognized in the future related to agreements that contain performance
obligations that were unsatisfied as of December 31, 2020. The amounts presented primarily consist of fixed fees or MVCs which are typically recognized over
time as the performance obligation is satisfied, as in accordance with firm service contracts. Additionally, for the Company's customers that are charged maximum
tariff rates related to its FERC-regulated operating subsidiaries, the amounts below reflect the current tariff rate for such services for the term of the agreements;
however, the tariff rates may be subject to future adjustment. The Company has elected to exclude the following from the table: (a) unsatisfied performance
obligations from usage fees associated with its firm services because of the stand-ready nature of such services; (b) consideration in contracts that are recognized in
revenue as invoiced, such as for interruptible services; and (c) consideration that was received prior to December 31, 2020, that will be recognized in future
periods, such as recorded in contract liabilities. The estimated revenues reflected in the table may include estimated revenues that are anticipated under executed
precedent transportation agreements for projects that are subject to regulatory approvals.
2021
2022
Thereafter
Total
In millions
Estimated revenues from contracts with customers from unsatisfied
performance obligations as of December 31, 2020
Operating revenues which are fixed and
determinable (operating leases)
Total projected operating revenues under committed
firm agreements as of December 31, 2020
$
$
1,087.0 $
1,028.5 $
7,092.0 $
9,207.5
23.0
23.0
196.5
242.5
1,110.0 $
1,051.5 $
7,288.5 $
9,450.0
Note 4: Leases
The Company has various operating lease commitments extending through 2050, generally covering office space and equipment rentals, some of which
contain options to renew or extend the lease term. The Company also has a finance lease related to the lease of an office building in Owensboro, Kentucky, that has
a fifteen-year term with two twenty-year renewal options.
42
Operating lease right-of-use assets and lease liabilities are recognized at the lease commencement date based on the present value of lease payments over
the lease term. The discount rate used to determine the commencement date present value of lease payments is typically the Company's secured borrowing rate, as
most of the Company's leases do not provide an implicit rate. The components of lease cost were as follows (in millions):
Operating lease cost
Short-term lease cost
Finance lease cost:
Amortization of right-of-use asset
Interest on lease liabilities
Total lease cost
For the Year Ended December 31,
2019
2020
$
$
4.2 $
3.9
0.7
0.4
9.2 $
The following provides supplemental balance sheet information related to the Company's leases:
Right-of-use assets (in millions)
Operating leases (recorded in Other Assets)
Finance lease (recorded in Property, Plant and Equipment)
$
$
11.8
5.4
As of December 31,
2020
2019
Lease liabilities (in millions)
Operating leases (recorded in Other Liabilities, current and
non-current)
Finance lease
Weighted-average remaining lease term (years)
Operating leases
Finance lease
Weighted-average discount rate
Operating leases
Finance lease
The table below presents the maturities of lease liabilities (in millions):
13.8
6.8
3.8
7.6
4.72 %
5.89 %
4.3
2.6
0.7
0.5
8.1
15.0
6.1
17.5
7.5
4.4
8.6
4.68 %
5.89 %
2021
2022
2023
2024
2025
Thereafter
Total
Less: discount
Total lease liabilities
As of December 31, 2020
Operating
Leases
Finance
Lease
4.5
4.4
3.9
1.3
0.3
0.7
15.1
(1.3)
13.8
$
$
1.1
1.1
1.1
1.1
1.1
2.9
8.4
(1.6)
6.8
$
$
43
Note 5: Commitments and Contingencies
Legal Proceedings and Settlements
The Company and its subsidiaries are parties to various legal actions arising in the normal course of business. Management believes the disposition of
these outstanding legal actions, including the legal actions identified below, will not have a material impact on the Company's financial condition, results of
operations or cash flows.
Mishal and Berger Litigation
On May 25, 2018, plaintiffs Tsemach Mishal and Paul Berger (on behalf of themselves and the purported class, Plaintiffs) initiated a purported class
action in the Court of Chancery of the State of Delaware (the Court) against the following defendants: the Company, Boardwalk GP, LP (Boardwalk GP),
Boardwalk GP, LLC and BPHC (together, Defendants), regarding the potential exercise by Boardwalk GP of its right to purchase the issued and outstanding
common units of the Company not already owned by Boardwalk GP or its affiliates (Purchase Right).
On June 25, 2018, Plaintiffs and Defendants entered into a Stipulation and Agreement of Compromise and Settlement, subject to the approval of the Court
(the Proposed Settlement). Under the terms of the Proposed Settlement, the lawsuit would be dismissed, and related claims against the Defendants would be
released by the Plaintiffs, if BPHC, the sole member of the general partner of Boardwalk GP, elected to cause Boardwalk GP to exercise its Purchase Right for a
cash purchase price, as determined by the Company's Third Amended and Restated Agreement of Limited Partnership, as amended (the Limited Partnership
Agreement), and gave notice of such election as provided in the Limited Partnership Agreement within a period specified by the Proposed Settlement. On June 29,
2018, Boardwalk GP elected to exercise the Purchase Right and gave notice within the period specified by the Proposed Settlement. On July 18, 2018, Boardwalk
GP completed the purchase of the Company's common units pursuant to the Purchase Right.
On September 28, 2018, the Court denied approval of the Proposed Settlement. On February 11, 2019, a substitute verified class action complaint was
filed in this proceeding. The Defendants filed a motion to dismiss, which was heard by the Court in July 2019. In October 2019, the Court ruled on the motion and
granted a partial dismissal, with certain aspects of the case proceeding to trial. The case is set for trial in February 2021.
City of New Orleans Litigation
Gulf South, along with several other energy companies operating in Southern Louisiana, has been named as a defendant in a petition for damages and
injunctive relief in state district court for Orleans Parish, Louisiana, (Case No. 19-3466) by the City of New Orleans. The case was filed on March 29, 2019. The
lawsuit claims include, among other things, negligence, strict liability, nuisance and breach of contract, alleging that the defendants' drilling, dredging, pipeline and
industrial operations since the 1930s have caused increased storm surge risk, increased flood protection costs and unspecified damages to the City of New Orleans.
th
In October 2020, this case was stayed pending the outcome of an appeal to the 5 Circuit Court of Appeals in a similar case.
Letter of Credit Proceeds
In the fourth quarter 2020 and the second quarter 2019, two customers of Texas Gas declared bankruptcy and rejected the transportation agreements they
had with Texas Gas as part of the bankruptcy proceedings. As a result, Texas Gas pursued and received proceeds from existing letters of credit provided to Texas
Gas as credit support of $37.7 million from the 2020 bankruptcy and $27.7 million from the 2019 bankruptcy. In both cases, the bankruptcy courts approved the
rejection of the transportation agreements, which relieved Texas Gas from providing further transportation services to those customers and allowed Texas Gas to
remarket that capacity to other customers. Texas Gas first applied the proceeds from the letters of credit to any outstanding receivables related to the applicable
customers and then recognized as transportation revenues the remaining $34.4 million of proceeds in December 2020 related to the 2020 bankruptcy and
$26.2 million of proceeds in June 2019 related to the 2019 bankruptcy, which represent a portion of the future performance obligations that were eliminated under
the transportation agreements.
Environmental and Safety Matters
The Company's operating subsidiaries are subject to federal, state and local environmental laws and regulations in connection with the operation and
remediation of various operating sites. As of December 31, 2020 and 2019, the Company had an accrued liability of approximately $4.2 million and $3.8 million
related to assessment and/or remediation costs associated
44
with the historical use of polychlorinated biphenyls, petroleum hydrocarbons and mercury. The liability represents management's estimate of the undiscounted
future obligations based on evaluations and discussions with counsel and operating personnel and the current known facts and circumstances related to these
matters. The related expenditures are expected to occur over the next thirty years. As of December 31, 2020 and 2019, approximately $1.0 million was recorded in
Other current liabilities and approximately $3.2 million and $2.8 million were recorded in Other Liabilities and Deferred Credits.
Clean Air Act and Climate Change
The Company's pipelines and associated facilities are subject to the Clean Air Act (CAA) and comparable state laws and regulations, which regulate the
emission of air pollutants from many sources and impose various compliance monitoring and reporting requirements. Under the CAA, the Company may be
required to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions,
obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions. The need to obtain permits has
the potential to delay the development or expansion of the Company's projects. Over the next several years, the Company may be required to incur certain capital
expenditures for air pollution control equipment or other air emissions related issues. For example, in 2015, the Environmental Protection Agency (EPA) issued a
final rule under the CAA, lowering the National Ambient Air Quality Standard (NAAQS) for ground-level ozone to 70 parts per billion under both the primary and
secondary standards to provide requisite protection of public health and welfare, respectively. Since that time, the EPA issued area designations with respect to
ground-level ozone, issued final requirements that apply to state, local and tribal air agencies for implementing the 2015 NAAQS for ground-level ozone and, on
December 31, 2020, published notice of a final action to retain the 2015 ozone NAAQS without revision on a going-forward basis. However, several groups have
filed litigation over this December 2020 final action, and the NAAQS may be subject to further revision under the Biden Administration. States are expected to
implement more stringent regulations that could apply to the Company's operations. Compliance with this final rule could, among other things, require installation
of new emission controls on some of the Company's equipment, result in longer permitting timelines and significantly increase its capital expenditures and
operating costs. Additionally, the threat of climate change continues to attract considerable attention in the U.S. and in foreign countries. Numerous proposals have
been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit existing emissions of
greenhouse gases (GHGs) as well as to restrict or eliminate future emissions through such efforts as GHG cap and trade programs, carbon taxes, reporting and
tracking programs and restriction of emissions, such as methane emissions, from certain sources. The EPA has determined that GHG emissions endanger public
health and the environment and, as a result, has adopted regulations under the CAA related to GHG emissions.
Commitments for Construction
The Company's future capital commitments are comprised of binding commitments under purchase orders for materials ordered but not received and firm
commitments under binding construction service agreements. The commitments as of December 31, 2020, were approximately $128.4 million, all of which are
expected to be settled within the next twelve months.
Pipeline Capacity Agreements
The Company's operating subsidiaries have entered into pipeline capacity agreements with third-party pipelines that allow the operating subsidiaries to
transport gas to off-system markets on behalf of customers. The Company incurred expenses of $4.2 million, $3.8 million and $4.6 million related to pipeline
capacity agreements for the years ended December 31, 2020, 2019 and 2018. The future commitments related to pipeline capacity agreements as of December 31,
2020, were $5.5 million in 2021 and $2.7 million in 2022, with no future commitments after 2022.
Note 6: Other Comprehensive Income and Fair Value Measurements
Other Comprehensive Income
The Company estimates that approximately $0.9 million of net losses reported in AOCI as of December 31, 2020, are expected to be reclassified into
earnings within the next twelve months related to cash flow hedges. The amounts related to cash flow hedges are from treasury rate locks used in hedging interest
payments associated with debt offerings that were settled in previous periods and are being amortized to earnings over the terms of the related interest payments,
generally the terms of the related debt.
45
Financial Assets and Liabilities
As of December 31, 2020 and 2019, the Company had no assets and liabilities which were recorded at fair value on a recurring basis. The following
methods and assumptions were used in estimating the fair value amounts included in the disclosures for financial assets and liabilities:
Cash and Cash Equivalents: For cash and short-term financial assets, the carrying amount is a reasonable estimate of fair value due to the short maturity
of those instruments.
Long-Term Debt: The estimated fair value of the Company's publicly traded debt is based on quoted market prices at December 31, 2020 and 2019. The
fair market value of the debt that is not publicly traded is based on market prices of similar debt at December 31, 2020 and 2019. The carrying amount of the
Company's variable-rate debt at December 31, 2020 and 2019, approximated fair value because the instruments bear a floating market-based interest rate.
The carrying amounts and estimated fair values of the Company's financial assets and liabilities which were not recorded at fair value on the Consolidated
Balance Sheets as of December 31, 2020 and 2019, were as follows (in millions):
As of December 31, 2020
Financial Assets
Cash and cash equivalents
Financial Liabilities
Long-term debt
Carrying Amount
2.9
$
$
3,460.4
(1)
$
$
2.9
—
$
$
—
3,847.6
$
$
Level 1
Level 2
Level 3
Total
Estimated Fair Value
—
—
—
—
$
$
$
$
2.9
3,847.6
Total
3.7
3,798.3
(1) The carrying amount of long-term debt excludes a $6.1 million long-term finance lease obligation and
$5.8 million of unamortized debt issuance costs.
As of December 31, 2019
Financial Assets
Cash and cash equivalents
Financial Liabilities
Long-term debt
Carrying Amount
3.7
$
$
3,565.7
(1)
Level 1
Level 2
Level 3
Estimated Fair Value
$
$
3.7
—
$
$
—
3,798.3
$
$
(1) The carrying amount of long-term debt excludes a $6.8 million long-term finance lease obligation and
$6.4 million of unamortized debt issuance costs.
46
Note 7: Property, Plant and Equipment
The following table presents the Company's PPE as of December 31, 2020 and 2019 (in millions):
Category
Depreciable plant:
Transmission
Storage
Gathering
General
Rights of way and other
Total utility depreciable plant
Non-depreciable:
Construction work in progress
Storage
Land
Total non-depreciable assets
Total PPE
Less: accumulated depreciation
2020
Amount
Weighted-Average
Useful Lives
(Years)
2019
Amount
Weighted-Average
Useful Lives
(Years)
$
10,417.9
863.5
108.0
224.9
153.2
11,767.5
184.2
152.3
44.3
380.8
12,148.3
3,598.5
$
37
38
23
14
33
37
37
38
23
14
34
37
10,025.2
804.2
107.9
219.3
149.2
11,305.8
253.9
139.4
44.3
437.6
11,743.4
3,263.7
Total PPE, net
$
8,549.8
$
8,479.7
The non-depreciable assets were not included in the calculation of the weighted-average useful lives.
The Company holds undivided interests in certain assets, including the Mobile Bay Pipeline of which the Company owns 64% and offshore and other
assets, comprised of pipeline and gathering assets in which the Company holds various ownership interests. In addition, the Company owns 83% of two ethylene
wells and supporting surface facilities in Choctaw, Louisiana, and certain ethylene and propylene pipelines connecting Louisiana Midstream's storage facilities in
Choctaw to chemical manufacturing plants in Geismar, Louisiana.
The proportionate share of investment associated with these interests has been recorded as PPE on the Consolidated Balance Sheets. The Company
records its portion of direct operating expenses associated with the assets in Operation and maintenance expense. The following table presents the gross PPE
investment and related accumulated depreciation for the Company's undivided interests as of December 31, 2020 and 2019 (in millions):
(1)
Bistineau storage
Mobile Bay Pipeline
NGL pipelines and facilities
Offshore and other assets
Total
2020
2019
Gross PPE
Investment
Accumulated
Depreciation
Gross PPE
Investment
Accumulated
Depreciation
$
$
—
14.5
42.5
12.8
69.8
$
$
—
7.1
8.8
10.1
26.0
$
$
89.4 $
14.5
34.8
14.5
153.2 $
29.3
6.7
7.2
11.6
54.8
(1) In 2019, the Company entered into an agreement to purchase the approximately 8% undivided interest that it did not already own in the
Bistineau storage facility in Louisiana for $18.8 million. The FERC approved the purchase in early 2020 and the transaction closed on April 1,
2020. The purchase was recorded in Capital
47
expenditures on the Consolidated Statement of Cash Flows. After this transaction, the Company owns 100% of the Bistineau storage facility.
Note 8: Goodwill and Intangible Assets
Goodwill
As of December 31, 2020 and 2019, the Company had recorded on its Consolidated Balance Sheets $237.4 million of goodwill. The Company performed
its annual goodwill impairment test for its two reporting units as of November 30, 2020 and 2019. The results of the quantitative goodwill impairment test
indicated that the fair value of the Company's reporting units exceeded their carrying amounts and no impairment charges related to goodwill were recorded for
any of the Company's reporting units during 2020, 2019 or 2018. The fair value measurement of the reporting units was derived based on judgments and
assumptions the Company believes market participants would use in assessing the fair value of the reporting units. These judgments and assumptions included the
valuation premise, use of a discounted cash flow model to estimate fair value under an income approach and inputs to the valuation model. The inputs included the
Company’s five-year financial plan operating results, the long-term outlook for growth in natural gas and NGLs demand, measures of the risk-free rate, equity
premium and systematic risk used in the calculation of the applied discount rate under the capital asset pricing model and views regarding future market conditions,
among others. The reasonableness of fair value estimates under the income approach were supported by a market approach under which the Company applied
EBITDA multiples derived from publicly-available information to each reporting unit's EBITDA.
Intangible Assets
The following table contains information regarding the Company's intangible assets, which includes customer relationships acquired as part of its
acquisitions (in millions):
Gross carrying amount
Accumulated amortization
Net carrying amount
December 31,
2020
2019
$
$
59.4
(15.3)
44.1
$
$
59.4
(13.4)
46.0
For each of the years ended December 31, 2020, 2019 and 2018, amortization expense for intangible assets was $1.9 million, $1.9 million and $2.0
million and was recorded in Depreciation and amortization on the Consolidated Statements of Income. Amortization expense for the next five years and in total
thereafter as of December 31, 2020, is expected to be as follows (in millions):
2021
2022
2023
2024
2025
Thereafter
Total
$
$
1.9
1.9
1.9
2.0
2.0
34.4
44.1
The weighted-average remaining useful life of the Company's intangible assets as of December 31, 2020, was 23 years.
48
Note 9: Asset Retirement Obligations
The Company has identified and recorded legal obligations associated with the abandonment of certain pipeline and storage assets, brine ponds, offshore
facilities and the abatement of asbestos consisting of removal, transportation and disposal when removed from certain compressor stations and meter station
buildings. Legal obligations exist for the main pipeline and certain other Company assets; however, the fair value of these obligations cannot be determined
because the lives of the assets are indefinite. As a result, cash flows associated with retirement of the assets cannot be estimated with the degree of accuracy
necessary to establish a liability for the obligations.
The following table summarizes the aggregate carrying amount of the Company's ARO as of December 31, 2020 and 2019 (in millions):
Balance at beginning of year
Liabilities recorded
Liabilities settled
Accretion expense
Balance at end of year
Less: Current portion of ARO
Long-term ARO
2020
2019
60.4 $
1.3
(0.9)
2.3
63.1
(8.2)
54.9 $
62.3
1.0
(5.1)
2.2
60.4
(3.6)
56.8
$
$
For the Company's operations where regulatory accounting is applicable, depreciation rates for PPE are comprised of two components. One component is
based on economic service life (capital recovery) and the other is based on estimated costs of removal (as a component of negative salvage) which is collected in
rates and does not represent an existing legal obligation. The Company has reflected $81.6 million and $75.1 million as of December 31, 2020 and 2019, on the
Consolidated Balance Sheets as Provision for other asset retirement related to the estimated cost of removal collected in rates.
Note 10: Regulatory Assets and Liabilities
The amounts recorded as regulatory assets and liabilities on the Consolidated Balance Sheets as of December 31, 2020 and 2019, are summarized in the
table below. The table also includes amounts related to unamortized debt expense and unamortized discount on long-term debt, which while not regulatory assets
and liabilities, are a critical component of the embedded cost of debt financing utilized in Texas Gas' rate proceedings. The tax effect of the equity component of
AFUDC represents amounts recoverable from rate payers for the tax recorded in regulatory accounting. Certain amounts in the table are reflected as a negative, or
a reduction, to be consistent with the regulatory books of account. The period of recovery for the regulatory assets included in rates varies from one to eighteen
years. The remaining period of recovery for regulatory assets not yet included in rates would be determined in future rate proceedings. None of the regulatory
assets shown below were earning a return as of December 31, 2020 and 2019 (in millions):
Regulatory Assets:
Pension
Tax effect of AFUDC equity
Fuel tracker
Other
Total regulatory assets
49
2020
2019
$
$
10.6 $
0.6
4.2
0.5
15.9 $
10.6
0.8
4.4
0.5
16.3
Regulatory Liabilities:
Cashout and fuel tracker
Provision for other asset retirement
Unamortized debt expense
Unamortized discount on long-term debt
Postretirement benefits other than pension
Total regulatory liabilities
$
$
14.1 $
81.6
(1.8)
(0.2)
63.3
157.0 $
9.5
75.1
(3.1)
(0.4)
56.8
137.9
Note 11: Financing
Long-Term Debt
The following table presents all long-term debt issuances outstanding as of December 31, 2020 and 2019 (in millions):
2020
2019
Notes and Debentures:
Boardwalk Pipelines
3.375% Notes due 2023
4.95% Notes due 2024
5.95% Notes due 2026
4.45% Notes due 2027
4.80% Notes due 2029
3.40% Notes due 2031
Gulf South
4.00% Notes due 2022
Texas Gas
4.50% Notes due 2021 (Texas Gas 2021 Notes)
7.25% Debentures due 2027
Total notes and debentures
Revolving Credit Facility:
Gulf South
Texas Gas
Total revolving credit facility
Finance lease obligation
Less:
Unamortized debt discount
Unamortized debt issuance costs
Total Long-Term Debt and Finance Lease Obligation
50
$
$
300.0 $
600.0
550.0
500.0
500.0
500.0
300.0
—
100.0
3,350.0
30.0
100.0
130.0
6.1
3,486.1
(19.6)
(5.8)
3,460.7 $
300.0
600.0
550.0
500.0
500.0
—
300.0
440.0
100.0
3,290.0
295.0
—
295.0
6.8
3,591.8
(19.3)
(6.4)
3,566.1
Maturities of the Company's long-term debt for the next five years and in total thereafter are as follows (in millions):
2021
2022
2023
2024
2025
Thereafter
Total long-term debt
$
$
—
430.0
300.0
600.0
—
2,150.0
3,480.0
Notes and Debentures
As of December 31, 2020 and 2019, the weighted-average interest rate of the Company's notes and debentures was 4.84% and 5.06%. The Company had
no debt issuances for the year ended December 31, 2018. For the years ended December 31, 2020 and 2019, the Company completed the following debt issuances
(in millions, except interest rates):
Date of
Issuance
August 2020
May 2019
Issuing
Subsidiary
Boardwalk
Pipelines
Boardwalk
Pipelines
Amount of
Issuance
$
$
500.0 $
500.0 $
Purchaser
Discounts
and
Expenses
Net
Proceeds
Interest
Rate
Maturity Date
5.0
4.8
$
$
495.0
(1)
3.40 %
February 15, 2031
495.2
(2)
4.80 %
May 3, 2029
Interest
Payable
February 15 and
August 15
May 3 and November
3
(1) The net proceeds of this offering were used to retire the Texas Gas 2021 Notes on November 3, 2020, to fund growth capital expenditures and for
general partnership purposes. Initially, the Company used the net proceeds to reduce outstanding borrowings under its revolving credit facility.
(2) The net proceeds of this offering were used to retire the outstanding $350.0 million aggregate principal amount of Boardwalk Pipelines 5.75% notes due
2019 at maturity and for general partnership purposes. Initially, the Company used the net proceeds to reduce outstanding borrowings under its
revolving credit facility.
The Company's notes and debentures are redeemable, in whole or in part, at the Company's option at any time, at a redemption price equal to the greater
of 100% of the principal amount of the notes to be redeemed or a “make whole” redemption price based on the remaining scheduled payments of principal and
interest discounted to the date of redemption at a rate equal to the Treasury rate plus 20 to 50 basis points depending upon the particular issue of notes, plus accrued
and unpaid interest, if any. Other customary covenants apply, including those concerning events of default.
The indentures governing the notes and debentures have restrictive covenants which provide that, with certain exceptions, neither the Company nor any of
its subsidiaries may create, assume or suffer to exist any lien upon any property to secure any indebtedness unless the debentures and notes shall be equally and
ratably secured. All of the Company's debt obligations are unsecured. As of December 31, 2020, Boardwalk Pipelines and its operating subsidiaries were in
compliance with their debt covenants.
51
Revolving Credit Facility
The Company has a revolving credit facility that includes Boardwalk Pipelines, Texas Gas and Gulf South as borrowers (Borrowers). Interest is
determined, at the Company's election, by reference to (a) the base rate which is the highest of (1) the prime rate, (2) the federal funds rate plus 0.50% and (3) the
one month Eurodollar Rate plus 1.00%, plus an applicable margin, or (b) the one-month LIBOR plus an applicable margin. The applicable margin ranges from
0.00% to 0.75% for loans bearing interest based on the base rate and ranges from 1.00% to 1.75% for loans bearing interest based on the LIBOR rate, in each case
determined based on the individual Borrower's credit rating from time to time. The Third Amended and Restated Revolving Credit Agreement (amended credit
agreement) provides for a quarterly commitment fee charged on the average daily unused amount of the revolving credit facility ranging from 0.10% to 0.275%
which is determined based on the individual Borrower's credit rating from time to time. The revolving credit facility has a borrowing capacity of $1.475 billion
through May 26, 2022.
The revolving credit facility contains various restrictive covenants and other usual and customary terms and conditions, including restrictions regarding
the incurrence of additional debt, the sale of assets and sale-leaseback transactions. The financial covenants under the revolving credit facility require the Company
and its subsidiaries to maintain, among other things, a ratio of total consolidated debt to consolidated EBITDA (as defined in the amended credit agreement)
measured for the previous twelve months of not more than 5.0 to 1.0, or up to 5.5 to 1.0 for the three quarters following a qualified acquisition or series of
acquisitions, where the purchase price exceeds $100.0 million over a rolling 12-month period. The Company and its subsidiaries were in compliance with all
covenant requirements under the revolving credit facility as of December 31, 2020.
Outstanding borrowings under the Company's revolving credit facility as of December 31, 2020 and 2019, were $130.0 million and $295.0 million, with
weighted-average borrowing rates of 1.39% and 3.00%. As of February 8, 2021, the Company had $170.0 million outstanding borrowings and approximately $1.3
billion of available borrowing capacity under the revolving credit facility.
Cash Distributions
For each of the years ended December 31, 2020, 2019 and 2018, the Company paid cash distributions of $102.2 million to its partners as determined by
Boardwalk GP.
Note 12: Employee Benefits
Retirement Plans
Defined Benefit Retirement Plans (Retirement Plans)
Texas Gas employees hired prior to November 1, 2006, are covered under a non-contributory, defined benefit pension plan (Pension Plan). The Texas Gas
Supplemental Retirement Plan (SRP) provides pension benefits for the portion of an eligible employee's pension benefit under the Pension Plan that becomes
subject to compensation limitations under the Internal Revenue Code. Collectively, the Company refers to the Pension Plan and the SRP as Retirement Plans. The
Company uses a measurement date of December 31 for its Retirement Plans.
As a result of the Texas Gas rate case settlement in 2006, the Company is required to fund the amount of annual net periodic pension cost associated with
the Pension Plan, including a minimum of $3.0 million, which is the amount included in rates. In 2020 and 2019, the Company funded $3.6 million and $4.7
million to the Pension Plan and expects to fund an additional $4.5 million to the plan in 2021. In 2020 and 2019, there were no payments made to the SRP.
The Company recognizes in expense each year the actuarially determined amount of net periodic pension cost associated with the Retirement Plans,
including a minimum amount of $3.0 million related to its Pension Plan, in accordance with the 2006 rate case settlement. Texas Gas is permitted to seek future
rate recovery for amounts of annual Pension Plan costs in excess of $6.0 million and is precluded from seeking future recovery of annual Pension Plan costs
between $3.0 million and $6.0 million. As a result, the Company would recognize a regulatory asset for amounts of annual Pension Plan costs in excess of $6.0
million and would reduce its regulatory asset to the extent that annual Pension Plan costs are less than $3.0 million. Annual Pension Plan costs between $3.0
million and $6.0 million will be charged to expense.
52
Postretirement Benefits Other Than Pension (PBOP)
Texas Gas provides postretirement medical benefits and life insurance to retired employees who were employed full time, hired prior to January 1, 1996,
and have met certain other requirements. In each of 2020 and 2019, the Company contributed $0.1 million to the PBOP plan. The PBOP plan is in an overfunded
status; therefore, the Company does not expect to make any contributions to the plan in 2021. The Company does not anticipate that any plan assets will be
returned to the Company during 2021. The Company uses a measurement date of December 31 for its PBOP plan.
Projected Benefit Obligation, Fair Value of Assets and Funded Status
The projected benefit obligation, fair value of assets, funded status and the amounts not yet recognized as components of net periodic pension and
postretirement benefits cost for the Retirement Plans and PBOP at December 31, 2020 and 2019, were as follows (in millions):
Change in benefit obligation:
Benefit obligation at beginning of period
Service cost
Interest cost
Plan participants' contributions
Actuarial loss (gain)
Benefits paid
Settlement
Benefit obligation at end of period
Change in plan assets:
Fair value of plan assets at beginning of period
Actual return on plan assets
Benefits paid
Settlement
Company contributions
Plan participants' contributions
Fair value of plan assets at end of period
Funded status
Items not recognized as components of net periodic cost:
Net actuarial loss (gain)
Retirement Plans
For the Year Ended
December 31,
PBOP
For the Year Ended
December 31,
2020
2019
2020
2019
122.2 $
2.8
2.7
—
6.0
(0.5)
(12.5)
120.7 $
101.7 $
10.4
(0.5)
(12.5)
3.6
—
102.7 $
125.1 $
3.0
3.9
—
5.9
(0.5)
(15.2)
122.2 $
100.3 $
12.5
(0.5)
(15.2)
4.6
—
101.7 $
36.5 $
0.1
1.1
1.1
(0.3)
(3.3)
—
35.2 $
90.8 $
7.5
(3.3)
—
0.1
1.1
96.2 $
(18.0) $
(20.5) $
61.0 $
35.6
0.1
1.4
1.1
1.9
(3.6)
—
36.5
85.0
8.2
(3.6)
—
0.1
1.1
90.8
54.3
18.2 $
20.6 $
(3.4) $
1.1
$
$
$
$
$
$
At December 31, 2020 and 2019, the following aggregate information relates only to the underfunded plans (in millions):
Retirement Plans
For the Year Ended
December 31,
2020
2019
Projected benefit obligation
Accumulated benefit obligation
Fair value of plan assets
$
120.7 $
113.7
102.7
122.2
115.4
101.7
53
Components of Net Periodic Benefit Cost
Components of net periodic benefit cost for both the Retirement Plans and PBOP for the years ended December 31, 2020, 2019 and 2018, were as follows
(in millions):
Service cost
Interest cost
Expected return on plan assets
Amortization of unrecognized net loss
Settlement charge
Net periodic benefit cost
Retirement Plans
For the Year Ended
December 31,
2019
2020
2018
2020
PBOP
For the Year Ended
December 31,
2019
2018
$
$
2.8 $
2.7
(6.3)
1.9
2.4
3.5 $
3.0 $
3.9
(6.4)
2.2
2.9
5.6 $
3.3 $
4.5
(7.5)
1.4
3.0
4.7 $
0.1 $
1.1
(3.2)
—
—
(2.0) $
0.1 $
1.4
(3.0)
—
—
(1.5) $
0.1
1.5
(4.6)
—
—
(3.0)
Due to the Texas Gas rate case settlement in 2006, Texas Gas is permitted to seek future rate recovery for amounts of annual Pension Plan costs in excess
of $6.0 million.
Estimated Future Benefit Payments
The following table shows benefit payments, which reflect expected future service, as appropriate, which are expected to be paid for both the Retirement
Plans and PBOP (in millions):
2021
2022
2023
2024
2025
2026-2030
PBOP
$
$
Retirement Plans
19.1
13.4
11.4
11.7
13.4
39.2
2.4
2.3
2.3
2.2
2.1
8.9
Weighted-Average Assumptions
Weighted-average assumptions used to determine benefit obligations for the years ended December 31, 2020 and 2019, were as follows:
PBOP
For the Year Ended
December 31,
Retirement Plans
For the Year Ended
December 31,
Discount rate
Expected return on plan assets
Rate of compensation increase
2020
2019
2020
2019
Pension
SRP
Pension
SRP
1.70 %
6.50 %
3.00 %
1.55 %
6.50 %
3.00 %
2.70 %
7.00 %
3.00 %
2.70 %
7.00 %
3.00 %
2.60 %
2.81 %
—
3.30 %
3.61 %
—
54
Weighted-average assumptions used to determine net periodic benefit cost for the periods indicated were as follows:
Retirement Plans
For the Year Ended
December 31,
2019
2020
2018
Pension
SRP
Pension
SRP
Pension
SRP
PBOP
For the Year Ended
December 31,
2019
2020
2018
Discount rate
Expected return on plan assets
Rate of compensation increase
(1)
7.00%
3.00%
2.70 %
7.00 %
3.00 %
(1)
7.00%
3.86%
4.10 %
7.00 %
3.86 %
(1)
7.25%
3.86%
3.40 %
7.25 %
3.86 %
3.30 %
3.61 %
—
4.30 %
3.61 %
—
3.70 %
5.30 %
—
(1) Pension expense was remeasured quarterly in 2020, 2019 and 2018. The quarterly remeasurements for each quarter in 2020, 2019 and 2018 were as
follows: Quarter 1: 2.95%, 3.80% and 3.75%; Quarter 2: 2.20%, 3.25% and 3.85%; Quarter 3: 1.85%, 2.60% and 3.95%; and Quarter 4: 1.70%,
2.70% and 4.00%.
In determining the discount rate assumption, current market and liability information is utilized, including a discounted cash flow analysis of the pension
and postretirement obligations. In particular, the basis for the discount rate selection was the yield on indices of highly rated fixed income debt securities with
durations comparable to that of the Company's plan liabilities. The yield curve was applied to expected future retirement plan payments to adjust the discount rate
to reflect the cash flow characteristics of the plans. The yield curves and indices evaluated in the selection of the discount rate are comprised of high-quality
corporate bonds that are rated AA by an accepted rating agency.
The expected long-term rate of return for plan assets was determined based on widely-accepted capital market principles, long-term return analysis for
global fixed income and equity markets as well as the active total return oriented portfolio management style. Long-term trends are evaluated relative to market
factors such as inflation, interest rates and fiscal and monetary policies, in order to assess the capital market assumptions as applied to the plan. Consideration of
diversification needs and rebalancing is maintained.
Pension Plan and PBOP Asset Allocation and Investment Strategy
Pension Plan
The Pension Plan investments are held in a trust account and consist of an undivided interest in an investment account of the Loews Corporation
Employees Retirement Trust (Master Trust), established by Loews and its participating subsidiaries. Use of the Master Trust permits the co-investing of trust assets
of the Pension Plan with the assets of the Loews Corporation Cash Balance Retirement Plan for investment and administrative purposes. Although assets of all
plans are co-invested in the Master Trust, the custodian maintains supporting records for the purpose of allocating the net gain or loss of the investment account to
the participating plans. The net investment income of the investment assets is allocated by the custodian to each participating plan based on the relationship of the
interest of each plan to the total of the interests of the participating plans. The Master Trust assets are measured at fair value. The fair value of the interest in the
assets of the Master Trust associated with the Pension Plan as of December 31, 2020 and 2019, was $102.7 million (or 43.9%) and $101.7 million (or 48.1%), of
the total Master Trust assets.
Equity securities are publicly traded securities which are valued using quoted market prices and are considered a Level 1 investment under the fair value
hierarchy. Short-term investments that are actively traded or have quoted prices, such as money market funds, are considered Level 1 investments. Fixed income
mutual funds include highly liquid government securities and exchange traded bonds, valued using quoted market prices, and are considered a Level 1 investment.
The limited partnership investments held within the Master Trust are recorded at fair value, which represents the Master Trust's shares of the net asset value of each
partnership, as determined by the general partner. The limited partnership and other invested assets consist primarily of hedge fund strategies that generate returns
through investing in marketable securities in the public fixed income and equity markets.
55
The following table sets forth, by level within the fair value hierarchy, a summary of the Master Trust's investments measured at fair value on a recurring
basis at December 31, 2020 (in millions):
Master Trust Assets
Equity securities
Short-term investments
Fixed income mutual funds
Total assets measured at fair
value
Total limited partnerships
measured at net asset value
Total
Measured under Fair Value Hierarchy
Level 1
Level 2
Level 3
Total
Measured at Net
Asset Value
Total Master
Trust Assets
$
$
59.9 $
3.9
112.5
176.3
—
176.3 $
— $
—
—
—
—
— $
— $
—
—
59.9 $
3.9
112.5
—
176.3
—
— $
—
176.3 $
— $
—
—
—
57.5
57.5 $
59.9
3.9
112.5
176.3
57.5
233.8
The following table sets forth, by level within the fair value hierarchy, a summary of the Master Trust's investments measured at fair value on a recurring
basis at December 31, 2019 (in millions):
Master Trust Assets
Equity securities
Short-term investments
Fixed income mutual funds
Total assets measured at fair
value
Total limited partnerships
measured at net asset value
Total
PBOP
Measured under Fair Value Hierarchy
Level 1
Level 2
Level 3
Total
Measured at Net
Asset Value
Total Master
Trust Assets
$
$
33.3 $
6.6
97.9
137.8
—
137.8 $
— $
—
—
—
—
— $
— $
—
—
33.3 $
6.6
97.9
—
137.8
—
— $
—
137.8 $
— $
—
—
—
73.6
73.6 $
33.3
6.6
97.9
137.8
73.6
211.4
The PBOP plan assets are held in a trust and are measured at fair value. Short-term investments that are actively traded or have quoted prices, such as
money market or mutual funds, are considered Level 1 investments. Fixed income mutual funds are actively traded and valued using quoted market prices and are
considered Level 1 investments. Tax exempt securities, consisting of municipal securities, corporate and other taxable bonds and asset-backed securities are valued
using a methodology based on information generated by market transactions involving identical or comparable assets, a discounted cash flow methodology or a
combination of both when necessary. Common inputs for tax exempt securities include pricing for similar securities, marketplace quotes, benchmark yields,
spreads off benchmark yields, interest rates and U.S. Treasury or swap curves and other pricing models utilizing observable inputs and are considered Level 2
investments. Specifically for asset-backed securities, key inputs include prepayment and default projections based on past performance of the underlying collateral
and current market data.
56
The following table sets forth, by level within the fair value hierarchy, a summary of the PBOP trust investments measured at fair value on a recurring
basis at December 31, 2020 (in millions):
Short-term investments
Fixed income mutual funds
Asset-backed securities
Corporate bonds
Tax exempt securities
Total investments
Level 1
Level 2
Level 3
Total
PBOP Trust Assets
$
$
5.7 $
19.5
—
—
—
25.2 $
— $
—
14.4
23.7
32.9
71.0 $
— $
—
—
—
—
— $
5.7
19.5
14.4
23.7
32.9
96.2
The following table sets forth, by level within the fair value hierarchy, a summary of the PBOP trust investments measured at fair value on a recurring
basis at December 31, 2019 (in millions):
Short-term investments
Fixed income mutual funds
Asset-backed securities
Corporate bonds
Tax exempt securities
Total investments
Investment Strategy
Level 1
Level 2
Level 3
Total
PBOP Trust Assets
$
$
3.4 $
17.6
—
—
—
21.0 $
— $
—
16.4
22.3
31.1
69.8 $
— $
—
—
—
—
— $
3.4
17.6
16.4
22.3
31.1
90.8
Pension Plan: The Company employs a total-return approach using a mix of equities and fixed income securities to maximize the long-term return on plan
assets for a prudent level of risk and generate cash flows adequate to meet plan requirements. The intent of this strategy is to minimize plan expenses by generating
investment returns that exceed the growth of the plan liabilities over the long run. Risk tolerance is established through careful consideration of the plan liabilities,
plan funded status and corporate financial conditions. The target allocation of plan assets is 40% to 60% of the investment portfolio to equity and limited
partnerships, with the remainder primarily invested in fixed income securities. The investment portfolio contains a diversified blend of fixed income, equity and
short-term securities. Alternative investments, including limited partnerships, have been used to enhance risk adjusted long-term returns while improving portfolio
diversification. At December 31, 2020, the pension trust had committed $2.3 million to future capital calls from various third party limited partnership investments
in exchange for an ownership interest in the related partnerships. Investment risk is monitored through annual liability measurements, periodic asset and liability
studies and quarterly investment portfolio reviews.
PBOP: The investment strategy for the PBOP assets is to reduce the volatility of plan investments while protecting the initial investment given the
overfunded status of the plan. At December 31, 2020 and 2019, all of the PBOP investments were in fixed income securities.
Defined Contribution Plan
Texas Gas employees hired on or after November 1, 2006, and all other employees of the Company are provided retirement benefits under a defined
contribution plan, which also provides 401(k) plan benefits to its participants. Costs related to the Company's defined contribution plan were $11.9 million, $11.5
million and $11.1 million for the years ended December 31, 2020, 2019 and 2018.
57
Long-Term Incentive Compensation Plans
The Company grants to selected employees long-term compensation awards under the LTIP (prior to 2019), the UAR and Cash Bonus Plan (prior to
2019) and the 2018 LTIP. These awards are intended to align the interests of the employees with those of the Company, encourage superior performance, attract
and retain employees who are essential for the Company's growth and profitability and to encourage employees to devote their best efforts to advancing the
Company's business over both long and short-term time horizons.
LTIP
Beginning in 2019, as a result of the Purchase Transaction, no further grants of Phantom Common Units have been or will be made under the LTIP. As of
December 31, 2020, all of the remaining Phantom Common Units had vested and were paid. A summary of the status of the outstanding Phantom Common Units
under the Company's LTIP as of December 31, 2020 and 2019, and changes during the years ended December 31, 2020 and 2019, is presented below:
Outstanding at January 1, 2019
Paid
Forfeited
Outstanding at December 31, 2019
Paid
Forfeited
Outstanding at December 31, 2020
Phantom Common
Units
Total Fair Value
(in millions)
Weighted-Average
Vesting Period
(in years)
889,702
(520,753)
(21,493)
347,456
(344,596)
(2,860)
—
$
$
11.2
(6.7)
—
4.5
(4.5)
—
—
1.2
—
—
0.6
—
—
—
Outstanding phantom units after the Purchase Transaction were fair valued at the $12.06 cash purchase price per common unit of the Purchase
Transaction plus amounts credited under the DERs. The fair value of the awards were recognized ratably over the vesting period until settlement in accordance
with the treatment of awards classified as liabilities, and taking into account the payment elections selected by the grantees. The Company recorded $1.1 million,
$4.6 million and $7.3 million in Administrative and general expenses during 2020, 2019 and 2018 for the Phantom Common Unit awards. The total estimated
remaining unrecognized compensation expense related to the Phantom Common Units outstanding at December 31, 2019, was $1.0 million.
UAR and Cash Bonus Plan
The UAR and Cash Bonus Plan provided for grants of UARs and Long-Term Cash Bonuses to select employees of the Company. Beginning in 2019, as a
result of the Purchase Transaction, no further grants of UARs or Long-Term Cash Bonuses have been or will be made under the UAR and Cash Bonus Plan. In
2018, the Company granted to certain employees $2.9 million of Long-Term Cash Bonuses, which vested and were paid to the holders in cash equal to the amount
of the grant in 2020. The Company recorded compensation expense of $0.3 million, $1.6 million and $2.2 million for the years ended December 31, 2020, 2019
and 2018, related to the Long-Term Cash Bonuses. As of December 31, 2020, all of the remaining Long-Term Cash Bonuses had vested and were paid. As of
December 31, 2019, the Company had $0.4 million remaining unrecognized compensation expense related to the Long-Term Cash Bonuses.
2018 LTIP
The 2018 LTIP provides for grants of Performance Awards to selected employees of the Company. A Performance Award is a long-term incentive award
with a stated target amount which is payable in cash, after adjustments, upon vesting based on certain specified performance criteria being met. The stated target
can be adjusted based on the level of achievement of the performance goals for the vesting period, but not to be below 90% or to exceed 110% of the target
amount. In the case of retirement, any outstanding and unvested awards would become fully vested upon retirement and the Performance Awards will be paid at
the original vesting date. In 2020 and 2019, the Company granted to certain employees $12.2 million and $12.0 million of Performance Awards. The Company
recorded compensation expense of $10.9 million and $6.1 million for the years ended December 31, 2020 and 2019, and had $7.0 million and $5.6 million of
remaining unrecognized compensation expense related to the Performance Awards as of December 31, 2020 and 2019.
58
Note 13: Income Taxes
The Company is not a taxable entity for federal income tax purposes. The following is a summary of the provision for income taxes for the years ended
December 31, 2020, 2019 and 2018 (in millions):
Current expense:
State
Deferred provision:
State
Income taxes
For the Year Ended December 31,
2019
2020
2018
$
$
0.1 $
0.2
0.3 $
0.4 $
0.1
0.5 $
0.4
0.2
0.6
The Company's tax years 2017 through 2020 remain subject to examination by the Internal Revenue Service and the states in which it operates. There
were no differences between the provision at the statutory rate to the income tax provision at December 31, 2020, 2019 and 2018. As of December 31, 2020 and
2019, there were no significant deferred income tax assets or liabilities.
Note 14: Credit Risk
Major Customers
For the year ended December 31, 2020, the Company earned $132.5 million of operating revenues from one customer which represented approximately
10% of total operating revenues. For the years ended December 31, 2019 and 2018, no customer comprised 10% or more of the Company's operating revenues.
Gas Loaned to Customers
Natural gas price volatility can cause changes in credit risk related to gas and NGLs loaned to customers. As of December 31, 2020, the amount of gas
owed to the Company's operating subsidiaries due to gas imbalances and gas loaned under PAL and certain firm service agreements was approximately 11.2
trillion British thermal units (TBtu). Assuming an average market price during December 2020 of $2.45 per million British thermal unit (MMBtu), the market
value of that gas was approximately $27.4 million. As of December 31, 2019, the amount of gas owed to the Company's operating subsidiaries due to gas
imbalances and gas loaned under PAL and certain firm service agreements was approximately 12.8 TBtu. Assuming an average market price during December
2019 of $2.08 per MMBtu, the market value of that gas was approximately $26.6 million. As of December 31, 2020 and 2019, there were no outstanding NGL
imbalances owed to the Company's operating subsidiaries. If any significant customer should have credit or financial problems resulting in a delay or failure to
repay the gas owed to the operating subsidiaries, it could have a material adverse effect on the Company's financial condition, results of operations or cash flows.
Note 15: Related Party Transactions
Loews provides a variety of corporate services to the Company under services agreements, including information technology, tax, risk management,
internal audit and corporate development services and also charges the Company for allocated overheads. The Company incurred charges related to these services
of $5.7 million, $5.7 million and $6.2 million for the years ended December 31, 2020, 2019 and 2018, which were recorded in Administrative and general on the
Consolidated Statements of Income.
Total distributions paid to BPHC and Boardwalk GP were $102.2 million, $102.2 million and $77.2 million for each of the years ended December 31,
2020, 2019 and 2018.
59
Note 16: Supplemental Disclosure of Cash Flow Information (in millions):
Cash paid during the period for:
Interest (net of amount capitalized)
Income taxes, net
Non-cash adjustments:
Accounts payable and PPE
Right-of-use assets obtained in exchange for lease obligations
For the Year Ended December 31,
2019
2018
2020
$
162.1 $
0.6
29.2
0.4
171.5 $
0.3
42.7
18.3
166.0
0.8
39.3
—
Note 17: Selected Quarterly Financial Data (Unaudited)
The following tables summarize selected quarterly financial data for 2020 and 2019 for the Company (in millions):
Operating revenues
Operating expenses
Operating income
Interest expense
Other income
Income before income taxes
Income taxes
Net income
Operating revenues
Operating expenses
Operating income
Interest expense, net
Other (income) expense
Income before income taxes
Income taxes
Net income
$
$
$
$
2020
For the Quarter Ended:
December 31
September 30
June 30
March 31
374.8 $
219.8
155.0
42.5
(2.4)
114.9
—
114.9 $
288.0 $
213.1
74.9
43.8
(1.0)
32.1
0.1
32.0 $
295.0 $
202.5
92.5
41.1
(1.3)
52.7
0.1
52.6 $
339.8
207.6
132.2
42.3
(1.2)
91.1
0.1
91.0
2019
For the Quarter Ended:
December 31
September 30
June 30
March 31
294.8 $
207.4
87.4
45.4
(0.6)
42.6
0.1
42.5 $
327.3 $
204.9
122.4
45.5
1.1
75.8
0.1
75.7 $
345.9
192.8
153.1
45.0
(0.2)
108.3
0.2
108.1
327.2 $
216.4
110.8
42.5
(1.2)
69.5
0.1
69.4 $
60
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including
our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in
Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Annual Report on Form 10-K. Our disclosure controls and
procedures are designed to allow timely decisions regarding required disclosure and to provide reasonable assurance that the information required to be disclosed
by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal
financial officer, as appropriate, and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based
upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of
December 31, 2020, at the reasonable assurance level.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred
during the quarter ended December 31, 2020, that have materially affected or that are reasonably likely to materially affect our internal control over financial
reporting.
Management's Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting for us. Our internal control system was
designed to provide reasonable assurance regarding the preparation and fair presentation of our published financial statements.
There are inherent limitations to the effectiveness of any control system, however well designed, including the possibility of human error and the possible
circumvention or overriding of controls. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls
must be considered relative to their costs. Management must make judgments with respect to the relative cost and expected benefits of any specific control
measure. The design of a control system also is based in part upon assumptions and judgments made by management about the likelihood of future events, and
there can be no assurance that a control will be effective under all potential future conditions. As a result, even an effective system of internal control over financial
reporting can provide no more than reasonable assurance with respect to the fair presentation of financial statements and the processes under which they were
prepared.
Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2020. In making this assessment,
management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control – Integrated Framework
(2013). Based on this assessment, our management believes that, as of December 31, 2020, our internal control over financial reporting was effective.
Item 9B. Other Information
Not applicable.
61
PART III
Item 10. Directors, Executive Officers and Corporate Governance
We are omitting disclosure under this item because we meet the conditions set forth in General Instructions I(1) (a) and (b) of Form 10-K.
Item 11. Executive Compensation
We are omitting disclosure under this item because we meet the conditions set forth in General Instructions I(1) (a) and (b) of Form 10-K.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
We are omitting disclosure under this item because we meet the conditions set forth in General Instructions I(1) (a) and (b) of Form 10-K.
Item 13. Certain Relationships and Related Transactions, and Director Independence
We are omitting disclosure under this item because we meet the conditions set forth in General Instructions I(1) (a) and (b) of Form 10-K.
Item 14. Principal Accounting Fees and Services
Audit Fees and Services
Deloitte & Touche LLP (Deloitte & Touche) has served as our auditor since our inception in 2005, and our predecessors since 2003. The following table
presents fees billed by Deloitte & Touche and its affiliates for professional services rendered to us and our subsidiaries in 2020 and 2019 by category as described
in the notes to the table (in millions):
(1)
Audit fees
Audit related fees
(2)
Total
2020
2019
$
$
2.6 $
0.1
2.7 $
2.8
0.1
2.9
(1) Includes the aggregate fees and expenses for annual financial statement audit and quarterly financial statement reviews.
(2) Includes the aggregate fees and expenses for services that were reasonably related to the performance of the financial statement audits or reviews
described above and not included under Audit fees above, mainly including consents, comfort letters and audits of employee benefits plans.
Auditor Engagement Pre-Approval Policy
We are a wholly-owned indirect subsidiary of Loews and the Loews Audit Committee has responsibility for the appointment, compensation and oversight
of the independent external audit firm retained to audit our financial statements and the audit fee negotiations associated with their retention. To assure the
continued independence of our independent auditor, Deloitte & Touche, the Loews Audit Committee has adopted a policy requiring its pre-approval of all audit
and non-audit services performed for us and our subsidiaries by the independent auditor. Under this policy, the Loews Audit Committee annually pre-approved
certain limited, specified recurring services which may be provided by Deloitte & Touche, subject to maximum dollar limitations. All other engagements for
services to be performed by Deloitte & Touche were specifically pre-approved by the Loews Audit Committee, or a designated committee member to whom this
authority had been delegated.
Under that policy, the Loews Audit Committee, or a designated member, pre-approved all engagements by us and our subsidiaries for services of Deloitte
& Touche, including the terms and fees thereof, and the Loews Audit Committee concluded that all such engagements were compatible with the continued
independence of Deloitte & Touche in serving as our independent auditor.
62
PART IV
Item 15. Exhibits and Financial Statement Schedules
(a) 1. Financial Statements
Included in Item 8 of this Annual Report on Form 10-K:
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets at December 31, 2020 and 2019
Consolidated Statements of Income for the years ended December 31, 2020, 2019 and 2018
Consolidated Statements of Comprehensive Income for the years ended December 31, 2020, 2019 and 2018
Consolidated Statements of Cash Flows for the years ended December 31, 2020, 2019 and 2018
Consolidated Statements of Changes in Partners' Capital for the years ended December 31, 2020, 2019 and 2018
Notes to Consolidated Financial Statements
(a) 2. Financial Statement Schedules
Schedule II not material.
(a) 3. Exhibits
The following documents are filed or furnished as exhibits to this report:
Exhibit
Number
Description
3.1
3.2
4.1
4.2
4.3
4.4
4.5
4.6
Certificate of Limited Partnership of Boardwalk Pipeline Partners, LP (Incorporated by reference to Exhibit 3.1 to the Registrant's
Registration Statement on Form S-1, Registration No. 333-127578, filed on August 16, 2005).
Fourth Amended and Restated Agreement of Limited Partnership of Boardwalk Pipeline Partners, LP dated as of July 19, 2018
(Incorporated by reference to Exhibit 3.2 to the Registrant's Annual Report on Form 10-K filed on February 13, 2019).
Indenture dated as of June 12, 2012, between Gulf South Pipeline Company, LP (now known as Gulf South Pipeline Company, LLC)
and The Bank of New York Mellon Trust Company, N.A. (Incorporated by reference to Exhibit 4.1 to the Registrant's Current Report
on Form 8-K filed on June 13, 2012).
First Supplemental Indenture dated as of January 3, 2020, among Gulf South Pipeline Company, LLC, Gulf South Pipeline Company,
LP and The Bank of New York Mellon Trust Company, N.A. (Incorporated by reference to Exhibit 4.2 to the Registrant's Annual
Report on Form 10-K filed on February 11, 2020).
Indenture dated July 15, 1997, between Texas Gas Transmission Corporation (now known as Texas Gas Transmission, LLC) and The
Bank of New York, as Trustee (Incorporated by reference to Exhibit 4.1 to Texas Gas Transmission Corporation's Registration
Statement on Form S-3, Registration No. 333-27359, filed on May 19, 1997).
Indenture dated January 19, 2011, between Texas Gas Transmission, LLC and the Bank of New York Trust Company, N.A.
(Incorporated by reference to Exhibit 4.1 to the Registrant's Current Report on Form 8-K filed on January 19, 2011).
First Supplemental Indenture dated June 7, 2011, between Texas Gas Transmission, LLC and The Bank of New York Mellon Trust
Company, N.A., as Trustee (Incorporated by reference to Exhibit 4.1 to the Registrant's Current report on Form 8-K, filed on June 13,
2011).
Second Supplemental Indenture dated June 16, 2011, between Texas Gas Transmission, LLC and The Bank of New York Mellon Trust
Company, N.A., as Trustee (Incorporated by reference to Exhibit 4.1 to the Registrant's Current report on Form 8-K, filed on June 20,
2011).
63
Exhibit
Number
4.7
4.8
4.9
4.10
4.11
4.12
4.13
4.14
10.1
10.2
10.3
Description
Indenture dated August 21, 2009, by and among Boardwalk Pipelines, LP, as issuer, Boardwalk Pipeline Partners, LP, as guarantor, and
The Bank of New York Mellon Trust Company, N.A., as trustee (Incorporated by reference to Exhibit 4.1 to Boardwalk Pipeline
Partners, LP’s Current Report on Form 8-K, filed on August 21, 2009).
Second Supplemental Indenture dated November 8, 2012, by and among Boardwalk Pipelines, LP, as issuer, Boardwalk Pipeline
Partners, LP, as guarantor, and The Bank of New York Mellon Trust Company, N.A., as trustee (Incorporated by reference to Exhibit
4.1 to Boardwalk Pipeline Partners, LP's Current Report on Form 8-K, filed on November 8, 2012).
Third Supplemental Indenture to the indenture dated August 21, 2009, among Boardwalk Pipelines, LP, as issuer, Boardwalk Pipeline
Partners, LP, as guarantor, and The Bank of New York Mellon Trust Company, N.A., as trustee (Incorporated by reference to Exhibit
4.2 to the Registrant's Current Report on Form 8-K filed on April 23, 2013).
Fourth Supplemental Indenture to the indenture dated August 21, 2009, among Boardwalk Pipelines, LP, as issuer, Boardwalk Pipeline
Partners, LP, as guarantor, and The Bank of New York Mellon Trust Company, N.A., as trustee (Incorporated by reference to Exhibit
4.1 to the Registrant's Current Report on Form 8-K filed on November 26, 2014).
Fifth Supplemental Indenture to the indenture dated August 21, 2009, among Boardwalk Pipelines, LP, as issuer, Boardwalk Pipeline
Partners, LP, as guarantor, and The Bank of New York Mellon Trust Company, N.A., as trustee (Incorporated by reference to Exhibit
4.1 to the Registrant's Current Report on Form 8-K filed on May 20, 2016).
Sixth Supplemental Indenture to the indenture dated August 21, 2009, by and among Boardwalk Pipelines, LP, as issuer, Boardwalk
Pipeline Partners, LP, as guarantor, and The Bank of New York Mellon Trust Company, N.A., as trustee (Incorporated by reference to
Exhibit 4.1 to Boardwalk Pipeline Partners, LP's Current Report on Form 8-K, filed on January 12, 2017).
Seventh Supplemental Indenture to the indenture dated August 21, 2009, by and among Boardwalk Pipelines, LP, as issuer, Boardwalk
Pipeline Partners, LP, as guarantor, and The Bank of New York Mellon Trust Company, N.A., as trustee (Incorporated by reference to
Exhibit 4.1 to Boardwalk Pipeline Partners, LP's Current Report on Form 8-K, filed on May 6, 2019).
Eighth Supplemental Indenture to the indenture dated August 21, 2009, by and among Boardwalk Pipelines, LP, as issuer, Boardwalk
Pipeline Partners, LP, as guarantor, and The Bank of New York Mellon Trust Company, N.A., as trustee (Incorporated by reference to
Exhibit 4.1 to Boardwalk Pipeline Partners, LP's Current Report on Form 8-K, filed on August 12, 2020).
Services Agreement dated as of May 16, 2003, by and between Loews Corporation and Texas Gas Transmission, LLC (Incorporated by
reference to Exhibit 10.8 to Amendment No. 3 to the Registrant's Registration Statement on Form S-1, Registration No. 333-127578,
filed on October 24, 2005).
Third Amended and Restated Revolving Credit Agreement, dated as of May 26, 2015, among Boardwalk Pipelines, LP, Texas Gas
Transmission, LLC, Gulf South Pipeline Company, LP and Gulf Crossing Pipeline Company LLC, as borrowers, Boardwalk Pipeline
Partners, LP, as guarantor, the several lenders and issuers party thereto, Wells Fargo Bank, N.A., as administrative agent, Citibank, N.A.
and JPMorgan Chase Bank, N.A., as co-syndication agents, and Bank of China, New York Branch, Barclays Bank PLC, Deutsche Bank
Securities Inc., Mizuho Bank, Ltd., MUFG Union Bank, N.A., and Royal Bank of Canada, as co-documentation agents, and Wells
Fargo Securities, LLC, Citigroup Global Markets, Inc., J.P. Morgan Securities LLC, Bank of China, New York Branch, Barclays Bank
PLC, Deutsche Bank Securities Inc., Mizuho Bank, Ltd., MUFG Union Bank, N.A., and RBC Capital Markets, as joint lead arrangers
and joint bookrunners (Incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on May 26,
2015).
Amendment No. 1 to the Third Amended and Restated Revolving Credit Agreement, dated as of July 29, 2016, among Boardwalk
Pipelines, LP, Texas Gas Transmission, LLC, Gulf South Pipeline Company, LP and Gulf Crossing Pipeline Company LLC, as
borrowers, Boardwalk Pipeline Partners, LP, as guarantor, the several lenders and issuers party thereto, Wells Fargo Bank, N.A., as
administrative agent, Citibank, N.A. and JPMorgan Chase Bank, N.A., as co-syndication agents, and Bank of China, New York Branch,
Barclays Bank PLC, Deutsche Bank Securities Inc., Mizuho Bank, Ltd., MUFG Union Bank, N.A., and Royal Bank of Canada, as co-
documentation agents, and Wells Fargo Securities, LLC, Citigroup Global Markets, Inc., J.P. Morgan Securities LLC, Bank of China,
New York Branch, Barclays Bank PLC, Deutsche Bank Securities Inc., Mizuho Bank, Ltd., MUFG Union Bank, N.A., and RBC Capital
Markets, as joint lead arrangers and joint bookrunners (Incorporated by reference to Exhibit 10.2 to the Registrant's Quarterly Report on
Form 10-Q filed on August 1, 2016).
(1)
64
Exhibit
Number
10.4
*22.1
*23.1
*31.1
*31.2
**32.1
**32.2
*101.INS
*101.SCH
*101.CAL
*101.DEF
*101.LAB
*101.PRE
*104
* Filed herewith
** Furnished herewith
Description
Amendment No. 2 to the Third Amended and Restated Revolving Credit Agreement, dated as of July 28, 2017, among Boardwalk
Pipelines, LP, Texas Gas Transmission, LLC, Gulf South Pipeline Company, LP and Gulf Crossing Pipeline Company LLC, as
borrowers, Boardwalk Pipeline Partners, LP, as guarantor, the several lenders and issuers party thereto, Wells Fargo Bank, N.A., as
administrative agent, Citibank, N.A. and JPMorgan Chase Bank, N.A., as co-syndication agents, and Bank of China, New York
Branch, Barclays Bank PLC, Deutsche Bank Securities Inc., Mizuho Bank, Ltd., MUFG Union Bank, N.A., and Royal Bank of
Canada, as co-documentation agents, and Wells Fargo Securities, LLC, Citigroup Global Markets, Inc., J.P. Morgan Securities LLC,
Bank of China, New York Branch, Barclays Bank PLC, Deutsche Bank Securities Inc., Mizuho Bank, Ltd., MUFG Union Bank, N.A.,
and RBC Capital Markets, as joint lead arrangers and joint bookrunners (Incorporated by reference to Exhibit 10.1 to the Registrant's
Quarterly Report on Form 10-Q filed on July 31, 2017).
Subsidiary Issuers and Guarantors of Registered Securities.
Consent of Independent Registered Public Accounting Firm.
Certification of Stanley C. Horton, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a).
Certification of Jamie L. Buskill, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a).
Certification of Stanley C. Horton, Chief Executive Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Certification of Jamie L. Buskill, Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded
within the Inline XBRL document.
Inline XBRL Taxonomy Extension Schema Document
Inline XBRL Taxonomy Calculation Linkbase Document
Inline XBRL Taxonomy Extension Definitions Document
Inline XBRL Taxonomy Label Linkbase Document
Inline XBRL Taxonomy Presentation Linkbase Document
Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
(1) The Services Agreements between Gulf South Pipeline Company, LP (now known as Gulf South Pipeline Company, LLC) and Loews Corporation and
between Boardwalk Pipelines, LP (formerly known as Boardwalk Pipelines, LLC) and Loews Corporation are not filed because they are identical to
Exhibit 10.1 except for the identities of Gulf South Pipeline Company, LLC and Boardwalk Pipelines, LLC and the date of the agreement.
Item 16. Form 10-K Summary
We are omitting disclosure under this item as it is provided elsewhere in this Report.
65
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized.
SIGNATURE
Boardwalk Pipeline Partners, LP
By: Boardwalk GP, LP
its general partner
By: Boardwalk GP, LLC
its general partner
Dated:
February 9, 2021
By:
/s/ Jamie L. Buskill
Jamie L. Buskill
Senior Vice President, Chief Financial and Administrative Officer,
Treasurer and Director
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the date indicated.
Dated:
February 9, 2021
Dated:
February 9, 2021
Dated:
February 9, 2021
Dated:
February 9, 2021
Dated:
February 9, 2021
Dated:
February 9, 2021
Dated:
February 9, 2021
/s/ Stanley C. Horton
Stanley C. Horton
President, Chief Executive Officer and Director
(principal executive officer)
/s/ Jamie L. Buskill
Jamie L. Buskill
Senior Vice President, Chief Financial and Administrative Officer, Treasurer and Director
(principal financial officer)
/s/ Steven A. Barkauskas
Steven A. Barkauskas
Senior Vice President, Controller and Chief Accounting and Information Officer
(principal accounting officer)
/s/ Michael E. McMahon
Michael E. McMahon
Senior Vice President, General Counsel, Secretary and Director
/s/ Kenneth I. Siegel
Kenneth I. Siegel
Director, Chairman of the Board
/s/ Andrew H. Tisch
Andrew H. Tisch
Director
/s/ Jane Wang
Jane Wang
Director
66
Subsidiary Issuers and Guarantors of Registered Securities
EXHIBIT 22.1
Subsidiary Issuer
Boardwalk Pipelines, LP 3.375% Notes due 2023
Boardwalk Pipelines, LP 4.95% Notes due 2024
Boardwalk Pipelines, LP 5.95% Notes due 2026
Boardwalk Pipelines, LP 4.45% Notes due 2027
Boardwalk Pipelines, LP 4.80% Notes due 2029
Boardwalk Pipelines, LP 3.40% Notes due 2031
Guarantor
Boardwalk Pipeline Partners, LP
Boardwalk Pipeline Partners, LP
Boardwalk Pipeline Partners, LP
Boardwalk Pipeline Partners, LP
Boardwalk Pipeline Partners, LP
Boardwalk Pipeline Partners, LP
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in Registration Statement No. 333-228714 on Form S-3 of our report dated February 9, 2021, relating to the
consolidated financial statements of Boardwalk Pipeline Partners, LP, and subsidiaries appearing in this Annual Report on Form 10-K of Boardwalk Pipeline
Partners, LP for the year ended December 31, 2020.
EXHIBIT 23.1
/s/ Deloitte & Touche LLP
Houston, Texas
February 9, 2021
I, Stanley C. Horton, certify that:
EXHIBIT 31.1
I have reviewed this Annual Report on Form 10-K of Boardwalk Pipeline Partners, LP;
1)
2) Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3) Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4) The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))
for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to
ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being prepared;
b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our
supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for
external purposes in accordance with generally accepted accounting principles;
c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent
fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant's internal control over financial reporting; and
5) The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the
registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably
likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control
over financial reporting.
Dated:
February 9, 2021
/s/ Stanley C. Horton
Stanley C. Horton
President and Chief Executive Officer
EXHIBIT 31.2
I, Jamie L. Buskill, certify that:
I have reviewed this Annual Report on Form 10-K of Boardwalk Pipeline Partners, LP;
1)
2) Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3) Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4) The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))
for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to
ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being prepared;
b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our
supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for
external purposes in accordance with generally accepted accounting principles;
c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent
fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant's internal control over financial reporting; and
5) The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the
registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably
likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control
over financial reporting.
Dated:
February 9, 2021
/s/ Jamie L. Buskill
Jamie L. Buskill
Senior Vice President, Chief Financial and Administrative Officer and Treasurer
Certification by the Chief Executive Officer
of
Boardwalk GP, LLC
pursuant to 18 U.S.C. Section 1350
(as adopted by Section 906 of the Sarbanes-Oxley Act of 2002)
EXHIBIT 32.1
Pursuant to 18 U.S.C. Section 1350, the undersigned chief executive officer of Boardwalk GP, LLC hereby certifies, to such officer's knowledge, that the annual
report on Form 10-K for the year ended December 31, 2020, (the Report) of Boardwalk Pipeline Partners, LP (the Company) fully complies with the requirements
of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and the information contained in the Report fairly presents, in all material respects, the financial
condition and results of operations of the Company.
February 9, 2021
/s/ Stanley C. Horton
Stanley C. Horton
President and Chief Executive Officer
(principal executive officer)
Certification by the Chief Financial Officer
of
Boardwalk GP, LLC
pursuant to 18 U.S.C. Section 1350
(as adopted by Section 906 of the Sarbanes-Oxley Act of 2002)
EXHIBIT 32.2
Pursuant to 18 U.S.C. Section 1350, the undersigned chief financial officer of Boardwalk GP, LLC hereby certifies, to such officer's knowledge, that the annual
report on Form 10-K for the year ended December 31, 2020, (the Report) of Boardwalk Pipeline Partners, LP (the Company) fully complies with the requirements
of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and the information contained in the Report fairly presents, in all material respects, the financial
condition and results of operations of the Company.
February 9, 2021
/s/ Jamie L. Buskill
Jamie L. Buskill
Senior Vice President, Chief Financial and Administrative Officer and Treasurer
(principal financial officer)