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(Address and Telephone Number of Registrant’s Principal Executive Office)
Securities registered pursuant to Section 12(b) of the Act: 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 ý No o
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 o No ý
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 ýNo o
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 ý No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated
by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý
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. (Check one)
Large accelerated filer ý Accelerated filer o Non-accelerated filer o Smaller
reporting company o
Emerging growth company o
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. Yes o No o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No
ý
The aggregate market value of the common units of the registrant held by non-affiliates as of June 30, 2018, was approximately $i1.4 billion.
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.
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.
In 2018, Boardwalk GP, LP (Boardwalk GP), our general partner, purchased our issued and outstanding common units representing limited partner interests in us not already owned by Boardwalk GP or its affiliates (Transaction Units) and we became a direct or indirect wholly-owned subsidiary of Boardwalk Pipelines Holding Corp. (BPHC), which is a wholly-owned subsidiary of Loews Corporation.
Our Business
We
are a limited partnership operating in the midstream portion of the natural gas and NGLs industry, providing transportation and storage for those commodities. We own approximately 14,230 miles of natural gas and NGLs pipelines and underground storage caverns having aggregate capacity of approximately 205.0 billion cubic feet (Bcf) of working natural gas and 31.8 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 producers of natural gas, local distribution companies
(LDCs), marketers, electric power generators, industrial users 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, 2018, approximately 87% of our revenues, excluding retained fuel, were derived from capacity reservation fees under firm contracts, approximately 9% 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 NGL 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 13,805 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 425 miles of NGLs pipelines in Louisiana and Texas. In 2018, our pipeline systems transported approximately 2.7 trillion cubic feet of natural gas and approximately 70.8
MMBbls of NGLs. Average daily throughput on our natural gas pipeline systems during 2018 was approximately 7.3 Bcf. Our natural gas storage facilities are comprised of fourteen underground storage fields located in four states with aggregate working
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gas capacity of approximately 205.0 Bcf and our NGLs storage facilities consist of eleven salt-dome caverns located in Louisiana with an aggregate storage capacity of approximately 31.8 MMBbls.
We also own five salt-dome caverns and related brine infrastructure for use in providing brine supply services and to support the NGLs storage operations.
The principal sources of supply for our natural gas pipeline systems are regional supply hubs and market centers located in the Gulf Coast and Mid-Continent regions, including offshore Louisiana, the Perryville, Louisiana, area, the Henry Hub in Louisiana and the Carthage, Texas, area. Our pipelines in the Carthage, Texas, area provide access to natural gas supplies from the Barnett and Haynesville Shales and other natural gas producing regions in eastern Texas and northern Louisiana. The Henry Hub serves as the designated delivery point for natural gas futures contracts traded on the New
York Mercantile Exchange. Our pipeline systems also have access to unconventional supplies such as the Woodford Shale in southeastern 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, LP (Gulf South):Our Gulf South pipeline system is located along the Gulf Coast in the states of 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. These markets include LDCs and municipalities located across the system, including New Orleans, Louisiana; Jackson, Mississippi; Mobile, Alabama; 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 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 83.5 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 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.
Gulf Crossing Pipeline Company LLC (Gulf Crossing):Our Gulf Crossing pipeline system is located near Sherman, Texas, and proceeds to the Perryville, Louisiana, area. The market areas are in the Midwest, Northeast and Southeast, including
Florida, through interconnections with Gulf South, Texas Gas and unaffiliated pipelines.
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 49.5 MMBbls of salt-dome storage capacity, including approximately 7.6 Bcf of working natural gas storage capacity; significant
brine supply infrastructure; and approximately 260 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 3.3 billion pounds of ethylene per year between Port Neches, Texas,
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and Baton Rouge, Louisiana, where it interconnects with the ethylene distribution system and storage facilities at the Choctaw Hub. Throughput for Louisiana Midstream was 70.8 MMBbls for the year ended December 31,
2018.
Boardwalk Texas Intrastate, LLC (Texas Intrastate): 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. Texas Intrastate is situated to provide access to industrial and liquefied natural gas (LNG) export markets in the Corpus Christi area, proposed power plants and third-party pipelines for exports to Mexico.
The following table provides information for our pipeline and storage systems as of February 13, 2019:
Pipeline
and Storage Systems
Miles of Pipeline
Working Gas Storage Capacity (Bcf)
Liquids Storage Capacity (MMBbls)
Peak-day Delivery Capacity (Bcf/d) (1)
Average Daily Throughput (Bcf/d) (1)
Gulf
South
7,190
113.1
—
9.7
3.1
Texas
Gas
5,975
84.3
—
5.7
2.8
Gulf
Crossing
375
—
—
1.9
1.4
Louisiana
Midstream
435
7.6
31.8
—
—
Texas
Intrastate
255
—
—
—
—
(1)
Bcf per day (Bcf/d)
Current Growth Projects
In response to changes in the natural gas industry and growth in the petrochemical industry, we have been engaged in several growth projects. Since 2016, we have placed into service several growth projects that represent more than $1.5 billion of total capital expenditures and provide more than 2.9 Bcf of natural gas transportation capacity to producers, power plants and an LNG export facility. These projects include our Northern Supply Access, our Coastal Bend Header, our Sulphur Storage and Pipeline Expansion and a power plant project in Louisiana. We expect to spend approximately $480.0 million on our
growth projects currently under constructionthrough 2022 that are expected to serve increased demand from naturalgas end-users such as power generation plants and industrials, as well as liquids demand frompetrochemical facilities. Collectively, these projectsrepresent more than 1.3 Bcf/d of natural gas transportation to end-users. These growth projects include three projects that will provide firm transportation services to new powerplant customers - one each in Louisiana, Texas and Indiana. We are also progressing with the construction of several NGL growth projects that will provide transportation and storage services and brine supply services to petrochemical and industrial customers
in southern Louisiana. 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.
We contract
with our customers to provide transportation and storage services on a firm and interruptible basis. We also provide bundled firm transportation and storage services, such as NNS, and interruptible PAL services for our customers and 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-
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day to multiple years, with rates that change on a daily, monthly or seasonal basis. Our NGLs transportation services are generally fee-based or based on minimum volume requirements.
Storage and Parking and Lending Services: We offer natural gas and NGLs storage services on both a firm and interruptible basis. Firm storage customers reserve
a specific amount of storage capacity, including injection and withdrawal rights, while interruptible customers receive storage capacity and injection and withdrawal rights when available. Similar to firm transportation customers, firm storage customers generally pay fees based on the quantity of capacity reserved plus an injection and withdrawal fee. Firm storage contracts typically range in term from one to ten years. Interruptible storage customers pay for the volume of gas actually stored plus injection and withdrawal fees. Generally, interruptible storage agreements are for monthly terms. We are able to charge market-based rates for the majority of our natural gas storage capacity pursuant to authority granted by the FERC. Our NGLs storage rates are market-based, and the contracts
for NGLs services are typically fixed-price arrangements with escalation clauses. PAL is an interruptible service offered to customers providing them the ability to park (inject) or borrow (withdraw) natural gas into or out of our pipeline systems at a specific location for a 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 producers of natural gas and with end-use customers, including LDCs, marketers, electric power generators, industrial users and interstate and intrastate pipelines, who, in turn, provide transportation and storage services for end-users. Based on our 2018 transportation, storage and PAL revenues, net of fuel, our customer mix was as follows: natural gas producers (41%), power generators (18%), LDCs (17%), marketers (13%)
and industrial end-users and others (11%). Based upon our 2018 transportation, storage and PAL revenues, net of fuel, our deliveries were as follows: pipeline interconnects (45%), LDCs (19%), industrial end-users (12%), power generators (12%), storage activities (9%) and others (3%). No customer comprises 10% or more of our operating revenues in 2018.
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.
Power Generators: Our natural gas pipelines are directly connected to 42 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 recently we have begun to see an increase in demand from power generators 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.
Local Distribution Companies: Most of our LDC customers use firm natural gas transportation services, including NNS. We serve approximately 172 LDCs at more than 300 delivery locations across our pipeline systems. The demand of these customers peaks during the winter heating season.
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.
Industrial End-Users: We provide approximately 185 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.
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Government
Regulation
Federal Energy Regulatory Commission: The FERC regulates our interstate natural gas 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 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 may be charged by our operating subsidiaries that operate under the FERC's jurisdiction 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, with the exception of 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.
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.
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 of the existing natural gas volumes we have contracted for 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 PHSMA 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), along our pipelines, and take additional safety measures to protect people and property in these highly populated areas. Recent legislation has resulted in more stringent mandates for pipeline safety and has charged PHMSA with developing and adopting regulations that impose increased pipeline safety requirements on pipeline operators. The NGPSA and HLPSA were amended by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (2011 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. In 2016, the NGPSA and HLPSA were amended by the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of
2016 (2016 Act), extending PHMSA’s statutory mandate through 2019 and, among other things, requiring PHMSA to complete certain of its outstanding mandates under the 2011 Act and developing new safety standards for natural gas storage facilities in 2018. Subsequently, in December 2016, PHMSA published an interim final rule that addresses certain safety issues related to natural gas storage facilities, including wells, wellbore tubing and casing. However, in June 2017, PHMSA temporarily suspended specified enforcement actions pertaining to provisions of the December 2016 interim final rule, as PHMSA announced it would reconsider the interim final rule, and subsequently re-opened the rule to public comment in October 2017. The final rule has yet to be finalized. The 2016 Act also empowers PHMSA to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities without prior
notice or an opportunity for a hearing. PHMSA issued interim final regulations in 2016 to implement the agency's expanded authority to address unsafe pipeline conditions or practices that pose an imminent hazard to life, property or the environment. New legislation or any 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. For example, in 2016, PHMSA published a proposed rulemaking that would impose new or more stringent requirements for certain natural gas pipelines including, among other things, expanding certain of PHMSA’s
7
current regulatory
safety programs for natural gas lines in newly defined “moderate consequence areas” that do not qualify as HCAs and requiring maximum allowable operating pressure validation through re-verification of all historical records for pipelines in service, which may require natural gas pipelines installed before 1970 (previously excluded from certain pressure testing obligations) to be pressure tested. PHMSA has split this proposed rule into three separate rulemaking proceedings and expects to publish these proceedings in 2019.
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.
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 hazardous substances and waste and in connection with spills, releases, discharges and emissions of various substances into the environment. Environmental regulations also require that our facilities, sites and other properties be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Occupational health and safety regulations
establish standards protective of workers, both generally and within the pipeline industry. These laws, as amended from time to time, that our operations are subject to, include, for example:
•
the Clean Air Act (CAA) and analogous state laws, which regulate air emission pollutants, greenhouse gas (GHG) emissions and reciprocating engines subject to Maximum Achievable Control Technology standards;
•
the Federal Water Pollution Control Act, commonly referred to as the Clean Water Act, and analogous state laws, which establish the extent to
which waterways are subject to federal or state jurisdiction and serve to regulate the discharge of wastewater from our facilities into state and federal waters;
•
the Comprehensive Environmental Response, Compensation and Liability Act, commonly referred to as CERCLA, or the Superfund law, and analogous state laws, which regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent hazardous substances for disposal;
•
the
Resource Conservation and Recovery Act 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; 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 in the assessment of administrative, civil and criminal penalties, the imposition of corrective or remedial obligations, the incurrence of capital expenditures, the occurrence of delays, denials or cancellations in permitting or the development or expansion of projects and the issuance of orders enjoining performance of some or all of our operations in affected areas. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations, but there can be no assurance that continued 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 4 in Part II, Item 8 of this Annual Report on Form 10-K contains information regarding environmental compliance.
Employee Relations
At December 31, 2018, we had approximately 1,240 employees, approximately 110 of whom are included under collective bargaining agreements. A satisfactory relationship exists between management and labor.
Available
Information
Our website is located at www.bwpmlp.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
8
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. Additionally, copies of these documents, excluding exhibits, may be requested at no cost by contacting Public Relations, Boardwalk Pipeline Partners, LP, 9 Greenway Plaza, Suite 2800, Houston, TX77046.
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Item
1A. Risk Factors
Our business faces many risks and uncertainties. We have described below the most significant 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 significant that may also affect our business.
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
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.
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). Current 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. The prevailing market conditions may also lead some of our customers to seek to renegotiate existing contracts to terms that are less attractive to us; for example, seeking a current price reduction in exchange for an extension of the contract term. We expect these market conditions to continue.
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 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, including the inability of any shipper to provide adequate credit support or to otherwise perform their obligations under any precedent agreements. 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.
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 storageoperations 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.
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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.
The Tax Cuts and Jobs Act of 2017 changed several provisions of the federal tax code, including a reduction in the maximum corporate tax rate. In addition, the FERC issued a series of policies and orders throughout 2018 which addressed the inclusion of federal income tax allowances in interstate pipeline companies’ rates. The FERC issued a Revised Policy Statement on Treatment of Income Taxes (Revised Policy Statement) reversing its long-standing policy by stating that it will no longer permit master limited partnerships to include an income tax allowance in their cost-of-service. The purchase of our outstanding Transaction Units by Boardwalk GP in 2018 and its election
to be treated as a corporation for federal income tax purposes, precluded the impact these policies and orders would have on the ability of our FERC-regulated natural gas pipelines to include an income tax allowance in their cost-of-service.
The FERC also issued an order which required all FERC-regulated natural gas pipelines to make a one-time informational filing reflecting the impacts of the Tax Cuts and Jobs Act of 2017 and the Revised Policy Statement on each individual pipeline’s cost-of-service. Texas Gas filed its informational filing on October 11, 2018, and Gulf South and Gulf Crossing made their filings on December 6, 2018. Customers were provided an opportunity to protest or comment on each pipeline’s informational filing. This procedure could lead to challenges to
a pipeline’s currently effective maximum applicable rates pursuant to Section 5 of the NGA. To date, the FERC has initiated four Section 5 proceedings against non-affiliated interstate natural gas pipelines and has notified other non-affiliated natural gas pipelines that no further action will be taken with respect to their information filings. As of February 13, 2019, Texas Gas, Gulf South and Gulf Crossing’s informational filings remain open.
Even without action on our informational filings, 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. The Tax Cuts and Jobs Act of 2017 and the Revised Policy Statement may 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.
In April 2018, the FERC issued a Notice of Inquiry (Certificate Policy Statement NOI), thereby initiating a review of its policies on certification of natural gas pipelines facilities, including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities, issued in 1999, that is used to determine whether to grant certificates for new pipeline and storage projects and expansions. Comments on the Certificate Policy Statement NOI were due on July 25, 2018, and we are unable to predict what, if any, changes may be proposed that will affect
our natural gas pipeline business or when such proposals, if any, might become effective.
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, replacement and management 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, such as high population areas, 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, experience operational delays, and result in 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. For example, in 2016, PHMSA published a proposed rulemaking that would impose new or more stringent requirements for certain natural gas pipelines including, among other things, expanding certain of PHMSA’s current regulatory safety programs for natural gas lines in newly defined “moderate consequence areas” that do not qualify as HCAs and requiring maximum allowable operating pressure validation through re-verification of all historical records for pipelines in service, which may require natural gas pipelines installed before 1970 (previously
11
excluded
from certain pressure testing obligations) to be pressure tested. See Part I, Item 1, Business - Government Regulation - U.S. Department of Transportation of this Annual Report on Form 10-K for further discussion on pipeline safety matters.
We have entered into certain firm transportation contracts with shippers 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.
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 foundation customers make long-term firm capacity commitments to us for such projects and certain of those foundation customers
agree to provide credit support as construction for such projects progresses. If a customer fails to post the required credit support during the growth project process, overall returns on the project may be reduced to the extent an adjustment to the scope of the project results or we are unable to replace the defaulting customer.
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 may not be able to replace expiring natural gas transportation contracts at attractive rates or on a long-term basis and may not be able to
sell short-term services at attractive rates or at all due to market conditions.
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 current 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 Gulf South, Texas Gas and Gulf Crossing pipeline expansion projects, which were placed into service in 2008
and 2009, will expire or have expired. In late 2017 and throughout 2018, a substantial portion of the capacity becoming available from the 2018 expiring expansion project contracts was renewed or the contracts were restructured, usually at lower rates or lower volumes. As the terms of these remaining expansion contracts expire through 2020, our transportation contract expirations are expected to be at a higher than normal level. If these contracts are renewed at current market rates, the revenues earned from these transportation
contracts would be materially lower than they are today. For a discussion of current developments, refer to Contract Renewals in Part II, Item 7 of this Annual Report on Form 10-K.
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 or 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 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.
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We
rely on a limited number of customers for a significant portion of revenues.
For 2018, while no customer comprised 10% or more of our operating revenues, our top ten customers comprised approximately 40% of our 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.
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, are directly impacted by changes in commodity prices. The prices of natural gas, oil and NGLs fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors. The declines in the levels of natural gas, oil and NGLs prices experienced in recent history have adversely affected the businesses of our producer customers and reduced the demand for our services and could result in defaults or the non-renewal of our contracted capacity when existing contracts expire. Future increases in the price of natural gas and NGLs could make alternative energy and feedstock sources more competitive and reduce demand for natural gas and NGLs. A reduced level of
demand for natural gas and NGLs could reduce the utilization of capacity on our systems and reduce the demand for our services.
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.
We
have a significant amount of indebtedness, which requires significant interest payments. Our inability to generate sufficient cash flow to satisfy our debt obligations, or to refinance our obligations on commercially reasonable terms, would have a material adverse effect on our business. Our substantial indebtedness could have important consequences. For example, it could:
•
limit our ability to borrow money for our working capital, capital expenditures, debt service requirements or other partnership purposes;
•
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.
In addition, the credit agreements governing our current indebtedness contain, and any future debt instruments would likely contain, financial or other restrictive covenants, which impose significant operating and financial restrictions on us. As a result of these covenants, we could be limited in the manner in which we conduct our business and may be unable to engage in favorable business activities or
finance our future operations or capital needs. Furthermore, a failure to comply with these covenants could result in an event of default which, if not cured or waived, could have a material adverse effect on us.
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We will be 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 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 interest rate volatility, 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.
Climate change legislation and regulations restricting emissions of GHGs could result in increased operating and capital costs and reduced demand for our pipeline and storage services.
Climate change continues to attract considerable public and scientific attention. This issue has also become more important in the review of FERC certificate applications. While no comprehensive climate change legislation has been implemented at the federal level, the Environmental Protection Agency (EPA) and states or groupings of states have pursued legal initiatives in recent years that seek to reduce GHG emissions through efforts
that include consideration of cap-and-trade programs, carbon taxes and GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources such as, for example, limitations on emissions of methane through equipment control and leak detection and repair requirements. In November 2018, the current Administration released an updated National Climate Assessment that was issued pursuant to U.S. federal law. The assessment summarizes the impacts of climate change on the U.S., now and in the future. This report could serve as a basis for increasing governmental pursuit of policies to restrict GHG emissions.
In particular, the EPA has adopted rules that, among other things, establish certain permit reviews for GHG emissions from certain large stationary sources, which could require securing permits at covered facilities emitting GHGs and meeting
defined technological standards for those GHG emissions. The EPA has also adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the U.S., including, among others, onshore processing, transmission, storage and distribution facilities as well as gathering, compression and boosting facilities and blowdowns of natural gas transmission pipelines.
Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas operations. In June 2016, the EPA published a final rule requiring certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound emissions. In June 2017, the EPA published a proposed rule to stay certain portions of the 2016 standards for two years but the rule has not been
finalized. In February 2018, the EPA finalized amendments to certain requirements of the 2016 final rule and, in September 2018, the agency proposed additional amendments that included rescission or revision of certain requirements such as fugitive emission monitoring frequency. Additionally, the FERC addresses indirect emissions of GHGs in certain pipeline certificate proceedings. The adoption and implementation of any international, federal or state legislation or regulations that require reporting of GHGs or otherwise restrict emissions of GHGs could result in increased compliance costs or additional operating restrictions.
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Recently, activists concerned about the potential effects of climate change
have directed their attention at sources of funding for companies engaged in business involving fossil fuels, which has resulted in certain financial institutions, investment funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. This could make it more difficult to secure funding for exploration and production or midstream energy business activities.
We do not own all of the land on which our pipelines and facilities are located, which could result in disruptions to our operations.
We do not own all of the land on which our pipelines and facilities have been constructed, and we are subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid
rights-of-way or if such rights-of-way lapse or terminate. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. We cannot guarantee that we will always be able to renew, when necessary, existing rights-of-way or obtain new rights-of-way without experiencing significant costs. Any loss of these land use rights with respect to the operation of our pipelines and facilities, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations and financial position.
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 long-haul 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. We are pursuing a strategy of growing and diversifying our business through acquisition and development of assets in complementary areas of the midstream energy sector. Our ability to grow, diversify and increase cash flows will depend, in part, on our ability to expand our existing business lines and to close and execute on accretive acquisitions. We may not be successful in acquiring or developing such assets or may do so on terms that ultimately are not profitable. Any such transactions involve potential risks that may include, among other things:
•
the
diversion of management's and employees' attention from other business concerns;
•
inaccurate assumptions about volume, revenues and project costs, including potential synergies;
•
a decrease in our liquidity as a result of our using available cash or borrowing capacity to finance the acquisition or project;
•
a
significant increase in our interest expense or financial leverage if we incur additional debt to finance the acquisition or project;
•
inaccurate assumptions about the overall costs of debt;
•
an inability to hire, train or retain qualified personnel to manage and operate the acquired business and assets or the developed assets;
•
unforeseen
difficulties operating in new product areas or new geographic areas; and
•
changes in regulatory requirements or delays of regulatory approvals.
Additionally, acquisitions also contain the following risks:
•
an inability to integrate successfully the businesses we acquire;
•
the
assumption of unknown liabilities for which we are not indemnified, for which our indemnity is inadequate or for which our insurance policies may exclude from coverage;
•
limitations on rights to indemnity from the seller; and
•
customer or key employee losses of an acquired business.
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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 Resource Conservation and Recovery Act, OSHA and analogous state laws. These laws and regulations may restrict or impact our business activities, including requiring the acquisition or renewal of permits or other approvals to conduct regulated activities, restricting the manner in which we handle or dispose of wastes, imposing remedial obligations to remove or mitigate contamination resulting from a spill or other release, requiring capital expenditures to comply with pollution control requirements
and imposing safety and health criteria addressing worker protection. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, the incurrence of capital expenditures, the occurrence of delays, denials or cancellations in the permitting or performance or expansion of projects and the issuance of orders enjoining future operations in a particular area. Under certain of these environmental laws and regulations, we could be subject to joint and several 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. 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.
16
Our business is highly competitive.
The principal elements of competition among pipeline systems are availability of capacity, rates, terms of service, access to gas supplies, flexibility and reliability of service. Additionally, the FERC's policies promote competition in natural
gas markets by increasing the number of natural gas transportation options available to our customer base. Increased competition could reduce the volumes of product we transport or store or, in instances where we do not have long-term contracts with fixed rates, could cause us to decrease the transportation or storage rates we can charge our customers. Competition could intensify the negative impact of factors that adversely affect the demand for our services, such as adverse economic conditions, weather, higher fuel costs and taxes or 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.
17
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 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 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 4 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.
18
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.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A)
Overview
We are a limited partnership operating in the midstream portion of the natural gas and NGLs industry, providing transportation and storage for those commodities. We also provide interruptible natural gas PAL services. 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 beginning in 2018, is netted with fuel retained in Other
revenues 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.
Firm Agreements
A substantial portion of our transportation and storage capacity is contracted for under firm agreements. For the year ended December 31, 2018, approximately 87% of our revenues, excluding retained fuel, were derived from fixed fees under firm agreements. The table below shows a rollforward of operating revenues under committed firm agreements in place as of December 31, 2017 to December 31, 2018, 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, 2017
$
8,870.0
Adjustments for:
Actual
revenues recognized from firm agreements in 2018(1)
(1,087.5
)
Firm agreements entered into in 2018
1,350.0
Total projected operating revenues under committed firm agreements as of December 31, 2018
$
9,132.5
(1)
As of December 31, 2017, we expected our 2018 revenues from fixed fees under firm agreements to be approximately $1,032.5 million, including agreements for transportation, storage and other services. Our actual 2018 revenues recognized from fixed fees under firm agreements were $1,087.5 million, with the increase resulting from contract renewals that occurred in 2018.
During 2018, we entered into approximately $1.4 billion of new firm agreements, of which approximately half of this amount was related to contract renewals and the other half was from new growth projects executed in 2018, but will not be placed into service until 2020 or later years. The
table shown under Performance Obligations in Note 3 to the Financial Statements 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. For our customers that are charged maximum tariff rates related to our FERC-regulated operating subsidiaries, the amounts shown in the Note 3 table 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 amounts shown in the Note 3 table do not include additional revenues we have recognized and may recognize under firm agreements based on actual utilization of
the contracted pipeline or storage capacity, any expected revenues for periods after the expiration dates of the existing agreements, execution of precedent agreements associated with growth projects or other events that occurred or will occur subsequent to December 31, 2018.
Each year a portion of our firm transportation and storage agreements expire. Demand for firm service is primarily based on market conditions which can vary across our pipeline systems.
The amount of change in firm reservation fees under contract reflects the overall market trends, including the impact from our growth projects. 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 current 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 Gulf South, Texas Gas and Gulf Crossing pipeline expansion projects, which were placed into service in 2008 and 2009, will expire or have expired. In late 2017 and throughout 2018, a substantial portion of the capacity becoming available from the 2018 expiring expansion project contracts was renewed or the contracts were restructured, usually at lower rates
or lower volumes, as discussed elsewhere in this document. As the terms of these remaining expansion contracts expire through 2020, our transportation contract expirations are expected to be at a higher than normal level. If these contracts are renewed at current market rates, the revenues earned from these transportation contracts would be materially lower than they are today. For a discussion of recontracting risks associated with our transportation revenues, refer to Part I, Item 1A. Risk Factors - We may not be able to replace expiring natural gas transportation contracts
at attractive rates or on a long-term basis and may not be able to sell short-term services at attractive rates or at all due to market conditions.
FERC Matters
The Tax Cuts and Jobs Act of 2017 changed several provisions of the federal tax code, including a reduction in the maximum corporate tax rate. In addition, the FERC issued a series of policies and orders throughout 2018 which addressed the inclusion of federal income tax allowances in interstate pipeline companies’ rates. In March 2018, the FERC issued a Revised Policy Statement reversing its long-standing policy by stating that it will no longer permit master limited partnerships to include an income tax allowance in their cost-of-service. The purchase of our outstanding Transaction Units by Boardwalk GP in 2018 and its election
to be treated as a corporation for federal income tax purposes, precluded the impact these policies and orders would have on the ability of our FERC-regulated natural gas pipelines to include an income tax allowance in their cost-of-service.
The FERC also issued an order which required all FERC-regulated natural gas pipelines to make a one-time informational filing reflecting the impacts of the Tax Cuts and Jobs Act of 2017 and the Revised Policy Statement on each individual pipeline’s cost-of-service. Texas Gas filed its informational filing on October 11, 2018, and Gulf South and Gulf Crossing made their filings on December 6, 2018, which included an income tax component in each of the pipelines’ cost-of-service. Customers were provided an opportunity to protest or comment on
each pipeline’s informational filing. Through the date of this filing, the protests received on our pipelines were limited in terms of numbers and scope. This procedure could lead to challenges to a pipeline’s currently effective maximum applicable rates pursuant to Section 5 of the NGA. To date, the FERC has initiated four Section 5 proceedings against non-affiliated interstate natural gas pipelines and has notified other non-affiliated natural gas pipelines that no further action will be taken with respect to their information filings. As of February 13, 2019, Texas Gas, Gulf South and Gulf Crossing’s informational filings remain open.
Even without action on our informational filings, 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. The Tax Cuts and Jobs Act of 2017 and the Revised Policy Statement may 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.
On April 19, 2018, the FERC issued a Certificate Policy Statement NOI, thereby initiating a review of its policies on certification of natural gas pipelines facilities, including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities, issued in 1999, that is used to determine whether to grant certificates for new pipeline and storage
projects and expansions. Comments on the Certificate Policy Statement NOI were due on July 25, 2018, and we are unable to predict what, if any, changes may be proposed that will affect our natural gas pipeline business or when such proposals, if any, might become effective. We do not expect that any change in this policy would affect us in a materially different manner than any other natural gas pipeline company operating in the U.S.
20
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 typically offset by revenues from retained fuel included in our Transportation revenues.
Beginning in 2018, these costs are netted with fuel retained in Other revenues on our Consolidated Statements of Income.
Effective January 1, 2018, we implemented the new revenue recognition standard, which did not have a material effect on our net operating revenues or operating or net income. Refer to Note 2 in Part II, Item 8 of this Annual Report on Form 10-K for further information.
In May 2017, we sold our Flag City Processing Partners, LLC subsidiary, which owned the Flag City processing plant and related assets, to a third party for $63.6
million, including customary adjustments. We recognized losses and impairment charges, reported within Total operating costs and expenses, of $47.1 million on the sale.
In 2017, we executed agreements for capacity on our Fayetteville and Greenville Laterals with Southwestern Energy Company. These agreements reduced contracted volumes on our Fayetteville Lateral for the remaining contract term, but also provided longer term revenue generation by adding ten years of firm transportation service commitments and offered potential additional commodity fee revenue from a volume commitment. This contract
restructuring resulted in a reduction of firm transportation reservation revenues of approximately $63.0 million from 2018 to 2020, including a $44.0 million reduction in 2018.
Please refer to Firm Agreements andContract Renewals above for further discussion of items that have impacted, or could impact in the future, our results of operations.
2018 Compared with 2017
Our net income for the year ended December 31,
2018, decreased$56.7 million, or 19%, to $240.3 million compared to $297.0 million for the year ended December 31, 2017, primarily due to the factors discussed below.
Operating revenues for the year ended December 31, 2018, decreased$98.9 million, or 7%, to $1,223.7 million,
compared to $1,322.6 million for the year ended December 31, 2017. Excluding the net effect of the items offset in fuel and transportation expense, primarily retained fuel, operating revenues decreased$63.1 million, or 5%. The decrease was driven by a decrease in transportation revenues of $43.2 million, which resulted primarily from contract expirations and recontracting at overall lower average rates, partially offset by revenues from growth projects placed into service and higher system utilization. Storage, parking and lending revenues decreased by $11.3 million due to unfavorable market conditions.
Operating
costs and expenses for the year ended December 31, 2018, decreased$49.4 million, or 6%, to $809.2 million, compared to $858.6 million for the year ended December 31, 2017. Excluding items offset in operating revenues and the $47.1 million loss on the sale of Flag City assets in 2017, operating costs and expenses increased$33.5 million, or 4%, when compared to the comparable
period in 2017. The operating expense increase was primarily due to higher depreciation expense and property taxes from an increased asset base from recently completed growth projects and increased employee-related costs.
Total other deductions for the year ended December 31, 2018, increased$7.6 million, or 5%, to $173.6 million compared to $166.0 million for the 2017 period primarily due to increased settlement charges related to our pension plan and lower capitalized
interest due to lower capital spending.
21
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, 2018, 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,
2018, we had $3.6 million of cash on hand and more than $900.0 million of available borrowing capacity under our $1.5 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 for 2019. We may seek to access the debt markets to fund some or all capital expenditures for growth projects, acquisitions or for general partnership purposes. As of December 31, 2018, we have $4.7 billion of contractual cash payment obligations under firm agreements, of which $4.6 billion represents principal and interest payments related to our long-term debt. Note 10 in Part II, Item 8 of this Annual Report on Form 10-K contains
more information regarding our long-term debt and financing activities and Note 4 contains 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 11, 2019,
our credit ratings for our senior unsecured notes and that of our operating subsidiaries having outstanding rated debt were as follows:
Credit
ratings reflect the view of a rating agency and are not a recommendation to buy, sell or hold any security, and may be revised or withdrawn at any time by the rating agency if it determines that the facts and circumstances warrant such a change. Each credit agency’s rating should be evaluated independently of any other credit agency’s rating.
Capital Expenditures
Growth capital expenditures were $359.8 million, $570.5 million and $469.1 million for the years ended December 31, 2018, 2017 and 2016.
Maintenance capital expenditures for the years ended December 31, 2018, 2017 and 2016 were $108.4 million, $137.9 million and $121.3 million. In 2018, we purchased $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 $450.0 million in 2019, including approximately $150.0 million
for maintenance capital and $300.0 million related to growth projects.
22
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. of America 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 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 perform a quantitative analysis under a two-step impairment test to measure whether the fair value of the reporting unit is less than its carrying amount. If the fair value of the reporting unit is determined to be less than its carrying
amount, including goodwill, the reporting entity must perform an analysis of the fair value of all of the assets and liabilities of the reporting unit. If the implied fair value of the reporting unit's goodwill is determined to be less than its carrying amount, an impairment loss is recognized for the difference. The implied fair value of goodwill is the excess of the fair value of the reporting unit over the fair value amounts assigned to all of the assets and liabilities of that unit as if the reporting unit was acquired in a business combination and the fair value of the reporting unit represented the purchase price.
We performed a quantitative goodwill impairment test for our reporting units as of November 30, 2018, which corresponds with the preparation of our five-year financial
plan operating results. The fair value measurement of the reporting units was derived based on judgments and assumptions we believe market participants would use in assessing the fair value of the reporting units. These judgments and assumptions included the valuation premise, use of a discounted cash flow model to estimate fair value 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 demand in the U.S. and 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. 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 2018 and 2017 indicated that the fair value of our reporting units significantly exceeded their carrying amounts and no goodwill impairment charges were recognized for the reporting units.
Impairment of Long-Lived Assets (including Tangible and Definite-Lived Intangible Assets)
We evaluate whether the carrying amounts of our long-lived and intangible assets have been impaired when circumstances indicate the carrying amount of those assets may not be recoverable. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the asset. If the carrying amount
is not recoverable, an impairment loss is measured as the excess of the asset’s carrying amount over its fair value. We recognized $0.5 million, $5.8 million and $3.8 million of asset impairment charges for the years ended December 31, 2018, 2017 and 2016.
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 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 our partnership or our subsidiaries, are also forward-looking statements.
23
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 our ability to maintain or replace expiring gas transportation and storage contracts, our ability to complete projects that we have commenced or will commence, the impact of changes to laws and regulations, the costs of maintaining and ensuring the integrity and reliability of our pipeline systems, successful negotiation, consummation and completion of contemplated transactions, projects and agreements, to contract and physically make our systems bi-directional, and to 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.
24
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):
2018
2017
Carrying
amount of fixed-rate debt
$
3,120.9
$
3,302.5
Fair value of fixed-rate debt
$
3,134.6
$
3,504.4
100
basis point increase in interest rates and resulting debt decrease
$
130.9
$
167.5
100 basis point decrease in interest rates and resulting debt increase
$
140.5
$
179.9
Weighted-average
interest rate
5.17
%
5.18
%
At December 31, 2018, we had $580.0 million of variable-rate debt outstanding at a weighted-average interest rate of 3.69%. A 1% increase in interest rates would increase our cash payments for interest on our variable-rate debt by $5.8 million on an annualized basis. At December 31,
2017, we had $385.0 million outstanding under variable-rate agreements at a weighted-average interest rate of 2.72%.
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 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, repay gas they owe to us, or post required credit support, this could have a material adverse effect on our business, financial condition, results of operations or cash flows.
As of December 31, 2018, the amount of gas loaned out by our subsidiaries or owed to our subsidiaries
due to gas imbalances was approximately 13.5 trillion British thermal units (TBtu). Assuming an average market price during December 2018 of $3.68 per million British thermal units (MMBtu), the market value of that gas was approximately $49.7 million. As of December 31, 2017, the amount of gas loaned out by our subsidiaries or owed to our subsidiaries due to gas imbalances was approximately 12.3 TBtu. Assuming an average market price during December
2017 of $2.76 per MMBtu, the market value of that gas at December 31, 2017, was approximately $34.0 million. As of December 31, 2018 and 2017, there were no outstanding NGL imbalances owed to our operating subsidiaries.
25
Item
8. Financial Statements and Supplementary Data
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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 “Partnership”) as of December 31,
2018 and 2017, and 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, 2018 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 Partnership as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31,
2018, in conformity with the accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Partnership's internal control over financial reporting as of December 31, 2018, based on the criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 13, 2019, expressed an unqualified opinion on the Partnership's internal control over financial reporting.
Basis
for Opinion
These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on the Partnership's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership 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. Our audits included performing procedures to assess
the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
The
accompanying notes are an integral part of these consolidated financial statements.
32
BOARDWALK PIPELINE PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1: iCorporate
Structure
Boardwalk Pipeline Partners, LP (the Partnership) 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, LP (Gulf South), Texas Gas Transmission, LLC (Texas Gas), Gulf Crossing Pipeline Company LLC (Gulf Crossing), 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 Partnership’s operations are conducted by the operating subsidiaries.
On June 29, 2018, Boardwalk GP, LP (Boardwalk GP) announced that it elected to exercise its right pursuant to Section 15.1(b) of the Partnership’s Third Amended and Restated Agreement of Limited Partnership, as amended (the Limited Partnership Agreement) to purchase all of the issued and outstanding common units representing limited partner interests in the Partnership not already owned by Boardwalk GP or its affiliates (Transaction Units) for a cash purchase price, determined in accordance with the Limited Partnership Agreement,
of $i12.06 per unit, or approximately $i1.5
billion in the aggregate (Purchase Right). On July 18, 2018, Boardwalk GP purchased the Transaction Units (Purchase Transaction). As a result of this transaction, the Partnership filed a Form 25 with the Securities and Exchange Commission to voluntarily withdraw the common units from listing on the New York Stock Exchange (NYSE) and from registration under Section 12(b) of the Securities Exchange Act of 1934 and also deregistered all of its common units and related equity-like securities which were authorized for sale under its effective registration statements. Subsequently, the Limited Partnership Agreement was amended, which converted the Partnership's common units to common unit equivalents in the form of partnership interests. The Partnership’s common units were traded on the NYSE through July 17, 2018, under the symbol “BWP”.
As of December 31, 2018, Boardwalk Pipelines Holding Corp. (BPHC), a wholly-owned subsidiary of Loews Corporation (Loews), owned directly or indirectly, i100% of the Partnership's capital.
Note
2: iBasis of Presentation and Accounting Policies
iBasis
of Presentation
The accompanying consolidated financial statements of the Partnership were prepared in accordance with accounting principles generally accepted in the United States of America (U.S.) (GAAP).
Certain amounts reported within Total operating revenues for the 2017 and 2016 periods have been reclassified to conform to the current presentation as a result of changes in accounting policies from the implementation of Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers, which was codified in Accounting Standards Codification (ASC) Topic 606 (ASC 606) further described
below. The effect of the reclassifications decreased Transportation revenues and increased Other revenues by $i24.5 million and $i22.1
million for the years ended December 31, 2017 and 2016. Additionally, Storage, parking and lending (PAL) revenues are now reported combined. These reclassifications and combinations had no impact on Total operating revenues, Operating income or Net income.
In March 2017, the FASB issued ASU 2017-07, Retirement Benefits - Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07),
which required entities to retroactively present the service cost component of net periodic postretirement benefit cost with other employee compensation costs in the income statement and present all other net periodic pension costs as a component of non-operating income. Effective January 1, 2018, the Partnership implemented ASU 2017-07 and reclassified $i2.5 million
and $i1.1 million of other components of net periodic benefit cost for the years ended December 31, 2017 and 2016, which resulted in an increase to Miscellaneous
other income, net and Administrative and generalexpensein the Consolidated Statements of Income, with no impact on Net income.
Accounting Pronouncements Adopted in 2018
Revenue Recognition
In May 2014, the Financial Accounting Standards Board (FASB) issued ASU 2014-09, Revenue from Contracts with Customers, which was codified in ASC 606. ASC 606 supersedes the revenue recognition
requirements in ASC Topic 605, Revenue
33
Recognition (ASC 605), and requires the recognition of revenues when promised goods or services are transferred to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services.
Effective January 1, 2018, the Partnership implemented ASC 606 using the modified retrospective method, without adjustment to the comparative period information, which remains reported under ASC 605. Upon implementation, the Partnership recorded a cumulative reduction to partners’ capital of $i12.8
million resulting from two items: (i) contracts which had changes to rates during the service period without corresponding changes in service levels provided by the Partnership, with an offsetting increase to other liabilities of $i6.4
million, and (ii) the de-recognition of excess fuel received from customers which elected to have fuel retained in-kind, with an offsetting decrease to current gas stored underground of $i6.4 million. Upon the implementation of
ASC 606, most retained fuel was not considered additional consideration included in the transaction price. As a result, retained fuel is recorded as a reduction to fuel and transportation expense and will be recognized as Other revenue upon the physical sale of natural gas, when under ASC 605, fuel retained was recognized as part of Transportation revenue. The Partnership elected to apply ASC 606 to contracts with customers, and applicable amendments, which were not completed prior to the implementation date.
iThe
following table summarizes the effect on the Partnership’s consolidated financial statements as of December 31, 2018, and for the year ended December 31, 2018, (in millions) had ASC 606 not been implemented on January 1, 2018:
The
implementation of ASC 606 had no impact on the total operating, financing or investing activities of the Partnership’s Consolidated Statement of Cash Flows for the year ended December 31, 2018.
Retirement Benefits
The Partnership implemented ASU 2017-07 as further described above. Additionally, in 2018, the FASB issued ASU 2018-14, Changes to the Disclosure Requirements for Defined Benefit Plans (ASU 2018-14), which amendment removes, adds and clarifies various disclosures related to post retirement plans. ASU 2018-14 is effective for fiscal years ending after December
15, 2020, though early adoption is permitted. The Partnership implemented the provisions of ASU 2018-14 effective with its Annual Report on Form 10-K for the year ended December 31, 2018 (Annual Report on Form 10-K).
34
iPrinciples of Consolidation
The
consolidated financial statements include the Partnership’s accounts and those of its wholly-owned subsidiaries after elimination of intercompany transactions.
i
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 Partnership 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.
iSegment Information
The
Partnership operates in ione 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 the Partnership's NGLs pipelines and storage facilities in Louisiana and Texas.
iRegulatory
Accounting
Most of the Partnership'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 Partnership’s Texas Gas subsidiary, which records certain costs and benefits as regulatory assets and liabilities in order to provide for recovery from or refund to customers in future periods, but is not applicable to operations associated with the Fayetteville and Greenville Laterals due to rates charged under negotiated rate
agreements and a portion of the storage capacity due to the regulatory treatment associated with the rates charged for that capacity.
The Partnership's Gulf South subsidiary implemented a fuel tracker effective April 1, 2016, and Gulf Crossing implemented a fuel tracker effective April 1, 2018. The Partnership applies regulatory accounting for the fuel trackers, 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 or Gulf Crossing uses more fuel than it collects from customers or collects more fuel than it uses. Prior to the implementation of the fuel trackers and ASC 606 and the application of regulatory accounting,
the value of fuel received from customers was reflected in operating revenues and the value of fuel used was reflected in operating expenses. Other than as described for Texas Gas and for the fuel trackers on Gulf South and Gulf Crossing, regulatory accounting is not applicable to the Partnership’s other FERC-regulated operations.
The Partnership monitors the regulatory and competitive environment in which it operates to determine whether its regulatory assets continue to be probable of recovery. If the Partnership were to determine that all or a portion of its regulatory assets no longer met the criteria for recognition as regulatory assets, that portion which was not recoverable would be written off, net of any regulatory liabilities.
Note 9
contains more information regarding the Partnership’s regulatory assets and liabilities.
iFair 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 Partnership uses fair value measurements to account for asset retirement obligations (ARO) and any impairment charges.
35
Notes 5 and 11
contain more information regarding fair value measurements.
iCash 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 Partnership had no restricted cash at December 31, 2018
and 2017.
iCash 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% and is adjusted every three months.
iTrade
and Other Receivables
Trade and other receivables are stated at their historical carrying amount, net of allowances for doubtful accounts. The Partnership establishes an allowance for doubtful accounts on a case-by-case basis when it believes the required payment of specific amounts owed is unlikely to occur. 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.
iGas
Stored Underground and Gas Receivables and Payables
Certain of the Partnership'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 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 Partnership in providing these services, the Partnership does not record the related gas on its Consolidated Balance Sheets. Certain of the Partnership'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.
iMaterials
and Supplies
Materials and supplies are carried at average cost and are included in Other Assets on the Consolidated Balance Sheets. The Partnership 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, 2018 and 2017, the Partnership held approximately $i21.4
million and $i20.1 million of materials and supplies.
iProperty,
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 i3
to i35 years. The ordinary sale or retirement of PPE for these assets could result in a gain or loss. Depreciation of PPE related to operations for which regulatory
36
accounting is applicable is provided for primarily on the straight-line method at FERC-prescribed rates over estimated useful lives of i5
to i62 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 6 contains more information regarding the Partnership’s PPE.
iGoodwill
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. To test goodwill, a quantitative analysis is performed under a two-step impairment test to measure whether the fair value of the reporting unit is less than its carrying amount. If based upon a quantitative analysis the fair value of the reporting unit is less than its carrying amount, including goodwill, the Partnership performs an analysis of the fair value of all the assets and liabilities of the reporting unit. If the implied fair value of the
reporting unit's goodwill is determined to be less than its carrying amount, an impairment loss is recognized for the difference.
Intangible assets are those assets which provide future economic benefit but have no physical substance. The Partnership 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 7 contains more information regarding the Partnership's goodwill and intangible assets.
iImpairment
of Long-lived Assets (including Tangible and Definite-lived Intangible Assets)
The Partnership 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 is compared to the carrying amount of the asset 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 and recording a loss to the extent that the carrying amount exceeds the estimated fair value.
iCapitalized
Interest and Allowance for Funds Used During Construction (AFUDC)
The Partnership records capitalized interest, which represents the cost of borrowed funds used to finance construction activities for operations where regulatory accounting is not applicable. The Partnership 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 Partnership’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. iThe 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
$
i8.5
$
i19.2
$
i7.4
Allowance
for equity funds used during construction
i0.5
i1.9
i7.9
iIncome
Taxes
The Partnership is not a taxable entity for federal income tax purposes. As such, it does not directly pay federal income tax. The Partnership’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 Partnership's net assets for financial and income tax purposes is $i5.3
billion. The subsidiaries of the Partnership directly incur some income-based state taxes which are presented in Income taxes on the Consolidated Statements of Income.
37
Note 12 contains more information regarding the Partnership’s income taxes.
iAsset
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
8 contains more information regarding the Partnership’s ARO.
iEnvironmental Liabilities
The Partnership 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 4 contains more information regarding the Partnership’s environmental liabilities.
iDefined Benefit Plans
The Partnership maintains postretirement benefit plans for certain
employees. The Partnership 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 11 contains more information regarding the Partnership’s pension and postretirement benefit obligations.
iLong-Term
Compensation
Prior to the Purchase Transaction, the Partnership provided awards of phantom common units (Phantom Common Units) to certain employees under its Long-Term Incentive Plan (LTIP). The Partnership 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.
The Partnership measures the cost of an award issued in exchange for employee services based on the grant-date fair value of the award, or the stated amount in the case of Long-Term Cash Bonuses and amounts under retention payment agreements. 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. Phantom units that remain outstanding after the Purchase Transaction will be valued at the $i12.06 cash purchase price per unit of the Purchase Transaction. The related compensation expense, less an estimate of forfeitures, is recognized over the period that employees are required to provide
services in exchange for the awards, usually the vesting period.
Note 11 contains more information regarding the Partnership’s unit-based and other long-term compensation.
iPartner Capital Accounts
For purposes of maintaining capital accounts, items of income and loss of the
Partnership are allocated among the partners each period, or portion thereof, in accordance with the partnership agreement, based on their respective ownership interests.
The
Partnership 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 Partnership also provides interruptible natural gas PAL services. The Partnership’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 Partnership’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 Partnership's subsidiaries collect may be subject to possible refunds to customers. Accordingly, during a rate case, estimated refund liabilities are recorded considering regulatory proceedings, advice of counsel and estimated risk-adjusted total exposure, as well as other factors. The Partnership's service contracts can range from one to twenty years although the Partnership 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 Partnership offers firm services to its customers. The Partnership’s customers can reserve a specific amount of pipeline capacity at specified receipt and delivery points on the Partnership’s pipeline system (transportation service) or can reserve a specific amount of storage capacity at specified injection and withdrawal points at the Partnership’s storage facilities (storage service). The Partnership 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 Partnership 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 Partnership 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 Partnership agrees to transport or store natural gas or NGLs for a customer when capacity is available. The Partnership does not account for interruptible services with a customer as a contract until the customer nominates for service and the Partnership 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 Partnership 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 Partnership has a right to consideration from customers in amounts that correspond directly to the value that the customer receives from the Partnership's performance. The rates charged may vary on a daily, monthly or seasonal basis.
Minimum Volume Commitment (MVC) Contracts: Certain of the Partnership’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
39
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 Partnership may enter into contracts with customers for the sale of natural gas or NGLs. The Partnership 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.
The Partnership records contract assets primarily related to performance obligations completed but not billed as of the reporting date. The Partnership records contract liabilities, or deferred income, when payment is received in advance of satisfying its performance obligations.
iOtherRecently Issued Accounting Pronouncements
In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) (ASU 2016-02), which will require, among other things, the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under current GAAP. ASU 2016-02 is effective for interim and annual reporting periods beginning after December 15, 2018.
ASU 2016-02 contains several practical expedients. One practical expedient is a practical expedient package, under which all criteria must be applied to all of an entity's leases. The practical expedient package allows an entity to (i) not reassess whether expired or existing
contracts are or contain leases; (ii) not reassess the lease classification for any expired or existing leases; and (iii) not reassess initial direct costs for any existing leases. The Partnership elected to apply this practical expedient package to all of its leases. Another practical expedient allows an entity to use hindsight in determining the lease term (that is, when considering lessee options to extend or terminate the lease and to purchase the underlying asset) and in assessing impairment of the entity’s right-of-use assets. The Partnership has not elected to apply the hindsight practical expedient. In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842), which contains a practical expedient that allows an entity not to assess whether existing or
expired land easements contain a lease under ASU 2016-02 if the land easement had not previously been accounted for as a lease. However, an entity that previously accounted for existing or expired land easements as leases shall not be eligible for this practical expedient for those land easements. The Partnership elected to apply the practical expedient to all its existing and expired land easements that were not previously accounted for as leases. The expedients are to be applied at the beginning of the earliest period presented using a modified retrospective approach, but include an elective transition method that allows entities to initially apply the updated guidance as of the adoption date. The Partnership elected to apply this elective transition method.
The Partnership implemented the provisions of
ASU 2016-02 on January 1, 2019, which did not have a material effect to the Partnership. The majority of the Partnership’s operating leases are for office space and office equipment.
40
Note 3: iRevenues
The Partnership operates in ione reportable segment and contracts directly with producers of natural gas and with end-use customers, including local distribution companies, marketers, electric power generators, industrial users and interstate and intrastate pipelines, who, in turn, provide transportation and storage services for end-users. iThe
following table presents the Partnership's revenues disaggregated by type of service for the year ended December 31, 2018 (in millions):
(1)
Revenues earned from contracts with MVCs are included in firm service given the stand-ready nature of the performance obligation and the guaranteed nature of the fees over the contract term.
(2) Other operating revenues include certain revenues earned from operating leases, pipeline management fees and other activities that are not considered central and ongoing major business operations of the Partnership and do not represent revenues earned from contracts with customers.
As of December 31, 2018, the Partnership had receivables recorded in Trade Receivables and contract liabilities recorded in Other liabilities, from contracts with customers of $i139.2
million and $i9.2 million. The Partnership did not have any outstanding contract assets as of December 31, 2018.
Contract liabilities are expected
to be recognized through 2026. iSignificant changes in the contract liabilities balances during the year ended December 31, 2018, are as follows (in millions):
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, 2018. 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 Partnership’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 Partnership 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
41
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, 2018, that will be recognized in future periods, such as recorded in contract
liabilities.
Total
projected operating revenues under committed
firm agreements
$
i1,084.0
$
i940.0
$
i7,108.5
$
i9,132.5
/
Note
4: iCommitments and Contingencies
Legal Proceedings and Settlements
The Partnership's subsidiaries are parties to various legal actions arising in the normal course of business. Management believes the disposition
of these outstanding legal actions will not have a material impact on the Partnership'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 Partnership, Boardwalk GP, Boardwalk GP, LLC and BPHC (together, Defendants), regarding the potential exercise by Boardwalk GP of its 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 right to purchase the issued and outstanding common units of the Partnership for a cash purchase price, as determined by 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 Transaction Units pursuant to the Purchase Right as further described in Note 1.
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 Partnership is evaluating its response to this new complaint.
Environmental and Safety Matters
The 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, 2018 and 2017, the Partnership had an accrued liability of approximately $i4.5 million and $i5.0
million related to assessment and/or remediation costs associated with the historical use of polychlorinated biphenyls, petroleum hydrocarbons and mercury. The liability represents management’s estimate of the undiscounted future obligations based on evaluations and discussions with counsel and operating personnel and the current known facts and circumstances related to these matters. The related expenditures are expected to occur over the next seven years. As of December 31, 2018 and 2017, approximately $i1.0
million and $i1.2 million were recorded in Other current liabilities and approximately $i3.5
million and $i3.8 million were recorded in Other Liabilities and Deferred Credits.
42
Clean Air Act and Climate Change
The
Partnership’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 Partnership 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 Partnership’s projects. Over the next several years, the Partnership 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. In 2017 and 2018, the EPA issued area designations with respect to ground-level ozone as either "attainment/unclassifiable,""unclassifiable" or "non-attainment." Additionally, in November 2018, the EPA issued final requirements that apply to state, local and tribal air agencies for implementing the 2015 NAAQS for ground-level ozone. States are expected to implement more stringent regulations that could apply to the Partnership's operations. Compliance with this final rule could, among other things, require installation of new emission controls on some of the Partnership's equipment, result in longer permitting timelines and significantly increase its capital expenditures and operating costs. Additionally, climate change
continues to attract considerable public, governmental and scientific attention, and, as a result, numerous proposals and regulatory initiatives have been made and are likely to continue to be made to monitor and limit emissions of greenhouse gases (GHGs) through such efforts as cap-and-trade programs, carbon taxes and GHG reporting and tracking programs, as well as regulations that directly limit GHG 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. Additionally, many states have adopted regulations related to GHG emissions.
Lease Commitments
The Partnership has various operating lease commitments extending through
the year 2028 generally covering office space and equipment rentals. Total lease expense for the years ended December 31, 2018, 2017 and 2016, was approximately $i16.1 million, $i13.8
million and $i13.2 million. iThe following table summarizes
minimum future commitments related to these items at December 31, 2018 (in millions):
2019
$
i4.8
2020
i4.7
2021
i4.6
2022
i4.5
2023
i4.1
Thereafter
i1.9
Total
$
i24.6
Commitments
for Construction
The Partnership’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, 2018, were approximately $i136.6 million, all of which
are expected to be settled within the next twelve months.
43
Pipeline Capacity Agreements
The Partnership’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 Partnership incurred expenses of $i4.6
million, $i6.2 million and $i6.5
million related to pipeline capacity agreements for the years ended December 31, 2018, 2017 and 2016. iThe future commitments related to pipeline capacity agreements as of December 31, 2018, were (in millions):
2019
$
i5.5
2020
i3.0
2021
i1.7
2022
i1.3
2023
i—
Thereafter
i—
Total
$
i11.5
Note
5:iOther Comprehensive Income and Fair Value Measurements
Other Comprehensive Income
The Partnership estimates that approximately $i0.9
million of net losses reported in AOCI as of December 31, 2018, 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.
iFinancial
Assets and Liabilities
As of December 31, 2018 and 2017, the Partnership 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 Partnership's publicly traded debt is based on quoted market prices at December 31, 2018 and 2017. The fair market value of the debt that is not publicly traded is based on market prices of similar debt at December 31, 2018 and 2017. The carrying amount of the Partnership's variable-rate debt approximates fair value because the instruments bear a floating market-based interest rate.
iThe
carrying amounts and estimated fair values of the Partnership's financial assets and liabilities which were not recorded at fair value on the Consolidated Balance Sheets as of December 31, 2018 and 2017, were as follows (in millions):
(1)
The carrying amount of long-term debt excludes an $i8.1 million long-term capital lease obligation and
$i8.8 million
of unamortized debt issuance costs.
Note 6: iProperty, Plant and Equipment
iThe
following table presents the Partnership’s PPE as of December 31, 2018 and 2017 (in millions):
Category
2018 Amount
Weighted-Average
Useful
Lives
(Years)
2017 Amount
Weighted-Average
Useful Lives
(Years)
Depreciable plant:
Transmission
$
i9,719.3
i37
$
i9,115.4
i38
Storage
i818.0
i38
i776.7
i38
Gathering
i109.9
i23
i109.2
i23
General
i212.4
i14
i196.7
i13
Rights
of way and other
i146.1
i35
i127.6
i36
Total
utility depreciable plant
i11,005.7
i37
i10,325.6
i37
Non-depreciable:
Construction
work in progress
i150.2
i416.5
Storage
i126.7
i105.5
Land
i43.0
i36.0
Total
non-depreciable assets
i319.9
i558.0
Total
PPE
i11,325.6
i10,883.6
Less: accumulated
depreciation
i2,939.8
i2,621.1
Total
PPE, net
$
i8,385.8
$
i8,262.5
The
non-depreciable assets were not included in the calculation of the weighted-average useful lives.
The Partnership holds undivided interests in certain assets, including the Bistineau storage facility of which the Partnership owns i92%, the Mobile Bay Pipeline of which the Partnership owns i64%
and offshore and other assets, comprised of pipeline and gathering assets in which the Partnership holds various ownership interests. In addition, the Partnership owns i83% 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.
45
The
proportionate share of investment associated with these interests has been recorded as PPE on the Consolidated Balance Sheets. The Partnership records its portion of direct operating expenses associated with the assets in Operation and maintenance expense. iThe following table presents the gross PPE investment and related accumulated depreciation for the Partnership’s undivided interests as of December 31, 2018
and 2017 (in millions):
2018
2017
Gross
PPE
Investment
Accumulated Depreciation
Gross PPE
Investment
Accumulated Depreciation
Bistineau storage
$
i84.5
$
i26.6
$
i75.5
$
i24.0
Mobile
Bay Pipeline
i14.0
i6.3
i13.2
i5.8
NGL
pipelines and facilities
i34.8
i6.2
i34.8
i5.2
Offshore
and other assets
i14.6
i11.4
i16.2
i12.7
Total
$
i147.9
$
i50.5
$
i139.7
$
i47.7
Asset
Disposition and Impairments
In May 2017, the Partnership sold its Flag City Processing Partners, LLC subsidiary, which owned the Flag City processing plant and related assets, to a third party for $i63.6 million, including customary adjustments. The Partnership recognized losses and impairment charges, reported within Total operating costs and expenses,
of $i47.1 million on the sale.
The Partnership recognized $i0.5
million, $i5.8 million and $i3.8 million of asset impairment charges for the years ended
December 31, 2018, 2017 and 2016. A portion of the asset impairment charges recorded in 2017 were related to the sale of the Flag City processing plant and related assets, a portion of the charges in 2017 and the charges in 2018 and 2016 were primarily due to materials and supplies inventory that were determined to be obsolete and the remainder of the charges in 2017 were primarily due to an increase in the estimate of ARO related to assets having no carrying amount.
Note 7: iGoodwill
and Intangible Assets
Goodwill
As of December 31, 2018 and 2017, the Partnership had recorded in its Consolidated Balance Sheets $i237.4 million of goodwill. The Partnership performed its
annual goodwill impairment test for its reporting units as of November 30, 2018. The results of the quantitative goodwill impairment test indicated that the fair value of the Partnership’s reporting units significantly exceeded their carrying amounts. No impairment charge related to goodwill was recorded for any of the Partnership’s reporting units during 2018, 2017 or 2016.
Intangible Assets
iThe
following table contains information regarding the Partnership's intangible assets, which includes customer relationships acquired as part of its acquisitions (in millions):
For
each of the years ended December 31, 2018, 2017 and 2016, amortization expense for intangible assets was $i2.0 million and was recorded in Depreciation and amortization on the Consolidated Statements of Income. iAmortization
expense for the next five years and in total thereafter as of December 31, 2018, is expected to be as follows (in millions):
2019
$
i2.0
2020
i1.9
2021
i1.9
2022
i1.9
2023
i1.9
Thereafter
i38.3
Total
$
i47.9
The
weighted-average remaining useful life of the Partnership's intangible assets as of December 31, 2018, was i25 years.
Note 8: iAsset
Retirement Obligations
The Partnership 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 Partnership assets; however, the fair value of the obligations cannot be determined because the lives of the assets are indefinite, therefore cash flows associated with retirement of the assets cannot be estimated with the degree of accuracy necessary to establish a liability for the obligations.
iThe
following table summarizes the aggregate carrying amount of the Partnership’s ARO as of December 31, 2018 and 2017 (in millions):
2018
2017
Balance at beginning of year
$
i55.1
$
i51.9
Liabilities
recorded
i10.3
i5.3
Liabilities
settled
(i5.0
)
(i3.7
)
Accretion
expense
i1.9
i1.6
Balance
at end of year
i62.3
i55.1
Less: Current
portion of ARO
(i5.9
)
(i9.1
)
Long-term
ARO
$
i56.4
$
i46.0
For
the Partnership’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 Partnership has reflected $i68.5 million and $i65.8
million as of December 31, 2018 and 2017, in the accompanying Consolidated Balance Sheets as Provision for other asset retirement related to the estimated cost of removal collected in rates.
47
Note 9: iRegulatory
Assets and Liabilities
iThe amounts recorded as regulatory assets and liabilities in the Consolidated Balance Sheets as of December 31, 2018 and 2017, 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, 2018 and 2017
(in millions):
2018
2017
Regulatory Assets:
Pension
$
i10.6
$
i10.6
Tax
effect of AFUDC equity
i1.0
i2.3
Fuel
tracker
i23.6
i—
Total
regulatory assets
$
i35.2
$
i12.9
i
Regulatory
Liabilities:
Cashout and fuel tracker
$
i8.0
$
i0.4
Provision
for other asset retirement
i68.5
i65.8
Unamortized
debt expense and premium on reacquired debt
(i4.3
)
(i5.6
)
Unamortized
discount on long-term debt
(i0.6
)
(i0.8
)
Postretirement
benefits other than pension
i51.6
i48.9
Total
regulatory liabilities
$
i123.2
$
i108.7
/
48
Note
10: iFinancing
Long-Term Debt
The following table presents all long-term debt issuances outstanding as of December 31, 2018 and 2017 (in millions):
2018
2017
Notes
and Debentures:
Boardwalk Pipelines
5.20% Notes due 2018
$
i—
$
i185.0
5.75%
Notes due 2019
i350.0
i350.0
3.375%
Notes due 2023
i300.0
i300.0
4.95%
Notes due 2024
i600.0
i600.0
5.95%
Notes due 2026
i550.0
i550.0
4.45%
Notes due 2027
i500.0
i500.0
Gulf
South
4.00% Notes due 2022
i300.0
i300.0
Texas
Gas
4.50% Notes due 2021
i440.0
i440.0
7.25%
Debentures due 2027
i100.0
i100.0
Total
notes and debentures
i3,140.0
i3,325.0
Revolving
Credit Facility:
Gulf Crossing
i285.0
i285.0
Gulf
South
i295.0
i100.0
Total
revolving credit facility
i580.0
i385.0
Capital
lease obligation
i7.5
i8.1
i3,727.5
i3,718.1
Less:
Unamortized
debt discount
(i19.1
)
(i22.5
)
Unamortized
debt issuance costs
(i7.1
)
(i8.8
)
Total
Long-Term Debt and Capital Lease Obligation
$
i3,701.3
$
i3,686.8
iMaturities
of the Partnership’s long-term debt for the next five years and in total thereafter are as follows (in millions):
2019
$
i350.0
2020
i—
2021
i440.0
2022
i880.0
2023
i300.0
Thereafter
i1,750.0
Total
long-term debt
$
i3,720.0
The Partnership has included $i350.0
million of notes which mature in less than one year as long-term debt on its Consolidated Balance Sheets as of December 31, 2018. The Partnership has the intent and the ability to refinance the notes through the available borrowing capacity under its revolving credit facility as of December 31, 2018. The Partnership expects to retire these notes at their maturity.
49
Notes and Debentures
As of
December 31, 2018 and 2017, the weighted-average interest rate of the Partnership's notes and debentures was i5.17% and i5.18%.
iThe Partnership did not have any debt issuances for the year ended December 31, 2018, however, for the years ended December 31, 2017 and 2016, the Partnership completed the following debt issuances (in millions, except interest rates):
The net proceeds of this offering were used to retire the outstanding $i275.0
million aggregate principal amount of Gulf South's i6.30% notes due 2017 at maturity and to fund growth capital expenditures.
(2)
The
net proceeds of this offering were used to retire the outstanding $i250.0 million aggregate principal amount of the Boardwalk Pipelines i5.875%
notes due 2016 and the outstanding $i300.0 million aggregate principal amount of the Boardwalk Pipelines i5.50%
notes due 2017 at their maturity.
The Partnership’s notes and debentures are redeemable, in whole or in part, at the Partnership’s option at any time, at a redemption price equal to the greater of i100% 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 Partnership 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 Partnership's debt obligations are unsecured. At December 31,
2018, Boardwalk Pipelines and its operating subsidiaries were in compliance with their debt covenants.
Revolving Credit Facility
The Partnership has a revolving credit facility that includes Boardwalk Pipelines, Texas Gas, Gulf South and Gulf Crossing as borrowers (Borrowers). Interest is determined, at the Partnership's election, by reference to (a) the ibase
rate which is the highest of (1) the iprime rate, (2) the ifederal
funds rate plus i0.50% and (3) the ione
month Eurodollar Rate plus i1.00%, plus an applicable margin, or (b) the one-month iLIBOR
plus an applicable margin. The applicable margin ranges from i0.00% to i0.75%
for loans bearing interest based on the base rate and ranges from i1.00% to i1.75%
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 i0.10% to i0.275%
which is determined based on the individual Borrower's credit rating from time to time. The revolving credit facility has a borrowing capacity of $i1.5 billion through May 26, 2020, and a borrowing capacity of $i1.475
billion from May 27, 2020, to 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 Partnership 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 i5.0
to 1.0, or up to i5.5 to 1.0 for the three quarters following a qualified acquisition or series of acquisitions, where the purchase price exceeds $i100.0
million over a rolling 12-month period. The Partnership and its subsidiaries were in compliance with all covenant requirements under the revolving credit facility as of December 31, 2018.
50
Outstanding borrowings under the Partnership's revolving credit facility as of December 31, 2018 and 2017, were
$i580.0 million and $i385.0 million with a weighted-average borrowing rate
of i3.69% and i2.72%.
As of February 11, 2019, the Partnership had $i630.0 million outstanding borrowings and approximately $i870.0
million of available borrowing capacity under the revolving credit facility.
Subordinated Loan Agreement with Affiliate
The Partnership had in place a Subordinated Loan Agreement with BPHC (Subordinated Loan Agreement) under which the Partnership could borrow up to $i300.0
million through December 31, 2018. The Partnership did not borrow any amounts under the Subordinated Loan Agreement by December 31, 2018, and the borrowing period and related agreement has expired.
Capital Lease
The Partnership recorded a capital lease obligation of $i10.5
million in 2013 related to the lease of an office building in Owensboro, Kentucky. The office building lease has a term of fifteen years with two twenty-year renewal options. Future commitments under the capital lease are $i1.1 million for each year 2019 through 2023 and $i5.1
million thereafter. After deducting $i2.5 million for amounts representing interest, the present value of the capital lease obligation at December 31, 2018, was $i8.1
million, of which $i0.6 million was recorded in Other current liabilities and $i7.5
million was recorded in Long–term debt and capital lease obligation.
Amortization of the office building under the capital lease for each of the years ended December 31, 2018, 2017 and 2016, was $i0.7
million was included in Depreciation and amortization. As of December 31, 2018 and 2017, assets recorded in Natural gas transmission and other plant under the capital lease were $i10.5 million
and the accumulated amortization was $i3.8 million and $i3.1
million.
Summary of Changes in Outstanding Units
As a result of the Purchase Transaction and amendments made to the Limited Partnership Agreement described elsewhere in this Annual Report on Form 10-K, the Partnership no longer has outstanding common units as of December 31, 2018. The Partnership had ino
common unit issuances for the years ended December 31, 2017 and 2016.
The Partnership had previously entered into an Amended and Restated Registration Rights Agreement with BPHC under which the Partnership agreed to register the resale of up to i27.9
million common units by BPHC and to reimburse BPHC up to a maximum amount of $i0.914 per common unit for underwriting discounts and commissions. As of December 31, 2017, the Partnership had a $i16.0
million accrued liability for future underwriting discounts and commissions that would be reimbursed to BPHC. However, due to the Purchase Transaction described in Note 1, the $i16.0 million liability was reversed in the second quarter 2018, with an offsetting adjustment to partners' capital.
Cash Distributions
For
the six months ended December 31, 2018, the Partnership paid distributions of $i51.1 million to its partners in proportion to their respective partnership interests as determined by Boardwalk GP. For the six months ended June 30, 2018, and for the years ended December 31,
2017 and 2016, the Partnership declared a quarterly distribution of $i0.10 per unit with respect to its common units, resulting in quarterly payments of $i25.1
million to its common unitholders and $i0.5 million to its general partner. For 2018, 2017 and 2016, the Partnership paid no amounts with respect to the incentive distribution rights (IDRs) because the quarterly target distribution levels for IDR payout were not met.
51
Note
11: iEmployee Benefits
Retirement Plans
Defined Benefit 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 Partnership refers to the Pension Plan and the SRP as Retirement Plans. The Partnership uses a measurement date of December 31 for its Retirement Plans.
As a result of the Texas Gas rate case settlement in 2006, the Partnership is required to fund the amount of annual net periodic pension cost associated with the Pension Plan, including a minimum of $i3.0
million, which is the amount included in rates. In each of 2018 and 2017, the Partnership funded $i3.0 million to the Pension Plan and expects to fund an additional $i3.0
million to the plan in 2019. In 2018, the Partnership funded $i0.8 million to the SRP. In 2017, there were ino
payments made under the SRP.
The Partnership recognizes in expense each year the actuarially determined amount of net periodic pension cost associated with the Retirement Plans, including a minimum amount of $i3.0 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 iin excess of $6.0 million and is precluded from seeking future recovery of annual Pension Plan costs between $i3.0
million and $i6.0 million. As a result, the Partnership would recognize a regulatory asset for amounts of annual Pension Plan costs iin
excess of $6.0 million and would reduce its regulatory asset to the extent that annual Pension Plan costs are iless than $3.0 million. Annual Pension Plan costs between $i3.0
million and $i6.0 million will be charged to expense.
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 2018 and 2017, the Partnership contributed $i0.2 million and $i0.1
million to the PBOP plan. The PBOP plan is in an overfunded status; therefore, the Partnership does not expect to make any contributions to the plan in 2019. The Partnership does not anticipate that any plan assets will be returned to the Partnership during 2019. The Partnership uses a measurement date of December 31 for its PBOP plan.
52
iProjected
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, 2018 and 2017, were as follows (in millions):
Components of net periodic benefit cost for both the Retirement Plans and PBOP for the years ended December 31, 2018, 2017 and 2016, were as follows (in millions):
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 iin excess of $6.0 million.
iEstimated
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):
RetirementPlans
PBOP
2019
$
i21.2
$
i2.5
2020
i13.0
i2.6
2021
i12.2
i2.7
2022
i13.4
i2.5
2023
i12.5
i2.5
2024-2028
i54.0
i11.2
iWeighted–Average
Assumptions
Weighted-average assumptions used to determine benefit obligations for the years ended December 31, 2018 and 2017, were as follows:
Pension
expense was remeasured quarterly in 2018, 2017 and 2016. The quarterly remeasurements for each quarter in 2018, 2017 and 2016 were as follows: Quarter 1: i3.75%, i3.45%
and i3.45%; Quarter 2: i3.85%,
i3.30% and i3.00%;
Quarter 3: i3.95%, i3.20%
and i2.85%; and Quarter 4: i4.00%,
i3.25% and i3.60%.
The 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, 2018 and 2017, was $i100.3 million (or i48.2%)
and $i118.9 million (or i50.8%),
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 and exchange traded bonds and redeemable preferred stock, valued using quoted market prices, and are considered a Level 1 investment. Asset-backed securities are valued using pricing for similar securities, recently executed transactions, cash flow models with yield curves, broker/dealer quotes and other pricing models utilizing observable inputs, which include prepayment and default projections based on past performance of the underlying collateral and current market data, and are considered Level 2
investments. 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.
iThe
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, 2018 (in millions):
55
Master
Trust Assets
Measured under Fair Value Hierarchy
Measured at Net Asset Value
Total Master Trust Assets
Level 1
Level 2
Level
3
Total
Equity securities
$
i34.1
$
i—
$
i—
$
i34.1
$
—
$
34.1
Short-term
investments
i8.8
i—
i—
i8.8
—
8.8
Fixed
income mutual funds
i90.3
i—
i—
i90.3
—
90.3
Total
assets measured at fair
value
i133.2
i—
i—
i133.2
—
i133.2
Total
limited partnerships
measured at net asset value
—
—
—
—
74.8
i74.8
Total
$
133.2
$
—
$
—
$
133.2
$
74.8
$
i208.0
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, 2017 (in millions):
Master
Trust Assets
Measured under Fair Value Hierarchy
Measured at Net Asset Value
Total Master Trust Assets
Level 1
Level 2
Level
3
Total
Equity securities
$
i44.0
$
i—
$
i—
$
i44.0
$
—
$
44.0
Short-term
investments
i6.2
i—
i—
i6.2
—
6.2
Fixed
income mutual funds
i96.2
i—
i—
i96.2
—
96.2
Asset-backed
securities
i—
i1.5
i—
i1.5
—
1.5
Total
assets measured at fair value
i146.4
i1.5
i—
i147.9
—
i147.9
Total
limited partnerships measured at net asset value
—
—
—
—
86.3
i86.3
Total
$
146.4
$
1.5
$
—
$
147.9
$
86.3
$
i234.2
PBOP
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
iThe 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, 2018 (in millions):
PBOP Trust Assets
Level 1
Level
2
Level 3
Total
Short-term investments
$
i4.0
$
i—
$
i—
$
i4.0
Fixed
income mutual funds
i15.8
i—
i—
i15.8
Asset-backed
securities
i—
i11.1
i—
i11.1
Corporate
bonds
i—
i23.6
i—
i23.6
Tax
exempt securities
i—
i30.5
i—
i30.5
Total
investments
$
i19.8
$
i65.2
$
i—
$
i85.0
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, 2017 (in millions):
PBOP Trust Assets
Level
1
Level 2
Level 3
Total
Short-term investments
$
i2.2
$
i—
$
i—
$
i2.2
Fixed
income mutual funds
i13.9
i—
i—
i13.9
Asset-backed
securities
i—
i11.5
i—
i11.5
Corporate
bonds
i—
i18.1
i—
i18.1
Tax
exempt securities
i—
i42.5
i—
i42.5
Total
investments
$
i16.1
$
i72.1
$
i—
$
i88.2
Investment
strategy
Pension Plan: The Partnership 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 i40%
to i60% of the investment portfolio to equity and alternative investments, including 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, 2018, the pension trust had committed $i6.0 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, 2018 and 2017, 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 Partnership are provided retirement benefits under a defined contribution plan, which also provides 401(k) plan benefits to its employees. Costs related to the Partnership’s defined contribution plan were $i11.1 million, $i11.0
million and $i10.7 million for the years ended December 31, 2018, 2017 and 2016.
57
Long-Term
Incentive Compensation Plans
The Partnership grants to selected employees long-term compensation awards under the LTIP and the UAR and Cash Bonus Plan. These awards are intended to align the interests of the employees with those of the Partnership, encourage superior performance, attract and retain employees who are essential for the Partnership’s growth and profitability and to encourage employees to devote their best efforts to advancing the Partnership’s business over both long and short-term time horizons. The Partnership also made annual grants of common units to certain of its directors under the LTIP prior to the Purchase Transaction.
LTIP
Prior to the Purchase Transaction, the Partnership
had reserved i3,525,000 common units for grants of units, restricted units, unit options and UARs to officers and directors of the Partnership’s general partner and for selected employees under the LTIP. The Partnership has outstanding Phantom Common Units which were granted under the plan. Each outstanding Phantom
Common Unit includes a tandem grant of Distribution Equivalent Rights (DERs). The grantee selected one of two irrevocable payment elections shortly after the award was granted. If the first payment election was selected, an amount equal to the fair market value of the vested portion of the Phantom Common Units (as defined in the plan) and associated DERs will become payable to the grantee in cash on each of the two vesting dates. If the second payment election option was selected, the Phantom Common Units and associated DERs will become payable in cash on the second vesting date. Prior to the Purchase Transaction, the economic value of the Phantom Common Units was directly tied to the value of the Partnership’s common units, but these awards did not confer any rights of ownership to the grantee. The fair value of the awards was recognized ratably over the vesting period and prior to the Purchase Transaction, was remeasured each quarter until settlement, based on the
market price of the Partnership’s common units and amounts credited under the DERs. Phantom units that remain outstanding after the Purchase Transaction will be valued at the $i12.06 cash purchase price per unit of the Purchase Transaction plus amounts credited under the DERs and will be settled based on the payment election made by the grantee shortly after the award was granted. Except for
the annual grants of common units to certain of its directors, the Partnership did not make any grants of units, restricted units or unit options under the plan. As a result of the Purchase Transaction, no further grants of Phantom Common Units or common units will be made under the LTIP.
iA summary of the status of the Phantom Common Units granted under the Partnership’s LTIP as of December 31,
2018 and 2017, and changes during the years ended December 31, 2018 and 2017, is presented below:
Represents
fair value and remaining weighted-average vesting period of outstanding awards at the end of the period.
The fair value of the awards at the date of grant was based on the closing market price of the Partnership’s common units on or directly preceding the date of grant. Phantom units that remain outstanding after the Purchase Transaction will be fair valued at the $i12.06
cash purchase price per common unit of the Purchase Transaction plus amounts credited under the DERs. The fair value of the awards at December 31, 2017, was based on the closing market price of the common units on December 31, 2017, of $i12.91
plus the accumulated value of the DERs. The fair value of the awards will be 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 Partnership recorded $i7.3 million, $i7.8
million and $i11.6 million in Administrative and general expenses during 2018, 2017 and 2016 for the Phantom Common Unit awards. The total estimated remaining unrecognized
58
compensation
expense related to the Phantom Common Units outstanding at December 31, 2018 and 2017, was $i5.6
million and $i6.0 million.
In 2018 and 2017,
the general partner purchased i17,980 and i10,812
of the Partnership’s common units in the open market at a price of $i11.15 and $i18.50
per unit. These units were granted under the LTIP to the independent directors as part of their director compensation. Any outstanding common units owned by the independent directors were acquired by Boardwalk GP as part of the Purchase Transaction.
UAR and Cash Bonus Plan
The UAR and Cash Bonus Plan provides for grants of UARs and Long-Term Cash Bonuses to selected employees of the Partnership. In 2018 and 2017, the Partnership granted to certain employees $i2.9
million and $i2.7 million of Long-Term Cash Bonuses, which will vest and become payable to the holders in cash equal to the amount of the grant after the vesting dates and in 2014, granted $i9.2
million of Long-Term Cash Bonuses, which vested and were paid in 2016. The Partnership recorded compensation expense of $i2.2 million, $i1.1
million and $i3.5 million for the years ended December 31, 2018, 2017 and 2016, related to the Long-Term Cash Bonuses. As of December 31,
2018, the Partnership had $i2.1 million remaining unrecognized compensation expense related to the Long-Term Cash Bonuses.
Note
12: iIncome Taxes
The Partnership is not a taxable entity for federal income tax purposes. As such, it does not directly pay federal income tax. The Partnership’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 Partnership's
net assets for financial and income tax purposes is $i5.3 billion. The subsidiaries of the Partnership directly incur some income-based state taxes which are presented in Income taxes on the Consolidated Statements of Income.
iFollowing
is a summary of the provision for income taxes for the periods ended December 31, 2018, 2017 and 2016 (in millions):
The
Partnership’s tax years 2015 through 2018 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, 2018, 2017 and 2016. As of December 31, 2018 and 2017, there were no significant deferred income tax assets or liabilities.
Note
13: iCredit Risk
Major Customers
For the years ended December 31, 2018, 2017 and 2016, no customer comprised 10%
or more of the Partnership’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, 2018, the amount of gas owed to the operating subsidiaries due to gas imbalances and gas loaned under PAL and
59
certain firm service agreements was approximately i13.5
trillion British thermal units (TBtu). Assuming an average market price during December 2018 of $i3.68 per million British thermal units (MMBtu), the market value of that gas was approximately $i49.7
million. As of December 31, 2017, the amount of gas owed to the operating subsidiaries due to gas imbalances and gas loaned under PAL and certain firm agreements was approximately i12.3 TBtu. Assuming an average market price during December 2017 of $i2.76
per MMBtu, the market value of that gas at December 31, 2017, would have been approximately $i34.0 million. As of December 31, 2018 and 2017, there were ino
outstanding NGL imbalances owed to the 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 Partnership’s financial condition, results of operations or cash flows.
Note 14: iRelated
Party Transactions
Loews provides a variety of corporate services to the Partnership under services agreements, including but not limited to, information technology, tax, risk management, internal audit and corporate development services and also charges the Partnership for allocated overheads. The Partnership incurred charges related to these services of $i6.2 million,
$i6.6 million and $i7.1
million for the years ended December 31, 2018, 2017 and 2016.
As described in Note 1, Boardwalk GP purchased the Partnership’s Transaction Units on July 18, 2018. As a result of this transaction, the Partnership became an indirect and direct wholly-owned subsidiary of BPHC as of July 18, 2018.
Distributions paid to BPHC and Boardwalk GP were $i77.2
million, $i52.2 million and $i52.2
million for each of the years ended December 31, 2018, 2017 and 2016. The distribution paid to BPHC and Boardwalk GP was impacted by the increase in ownership by Boardwalk GP in the third quarter 2018 as described above and in Note 1.
In 2014, the Partnership and BPHC entered into a Subordinated Loan Agreement whereby the Partnership could borrow up to $i300.0
million by December 31, 2018. The Partnership did not borrow any amounts under the Subordinated Loan Agreement by December 31, 2018, and the borrowing period and related agreement has expired.
Note 15: iiSupplemental
Disclosure of Cash Flow Information(in millions):/
Note
16: iSelected Quarterly Financial Data (Unaudited)
iThe
following tables summarize selected quarterly financial data for 2018 and 2017 for the Partnership (in millions):
2018
For the Quarter Ended:
December
31
September 30
June 30
March 31
Operating revenues
$
i325.1
$
i277.9
$
i285.3
$
i335.4
Operating
expenses
i217.8
i197.1
i199.6
i194.7
Operating
income
i107.3
i80.8
i85.7
i140.7
Interest
expense, net
i44.8
i43.5
i43.2
i44.1
Other
(income) expense
(i0.7
)
(i0.7
)
i0.2
(i0.8
)
Income
before income taxes
i63.2
i38.0
i42.3
i97.4
Income
taxes
i0.2
i0.1
i0.1
i0.2
Net
income
$
i63.0
$
i37.9
$
i42.2
$
i97.2
2017
For
the Quarter Ended:
December 31
September 30
June 30
March 31
Operating revenues
$
i337.5
$
i300.5
$
i317.6
$
i367.0
Operating
expenses
i214.5
i190.5
i250.9
i202.7
Operating
income
i123.0
i110.0
i66.7
i164.3
Interest
expense, net
i39.8
i41.0
i43.7
i46.1
Other
income
(i1.1
)
(i1.1
)
(i1.1
)
(i1.3
)
Income
before income taxes
i84.3
i70.1
i24.1
i119.5
Income
taxes
i0.1
i0.3
i0.4
i0.2
Net
income
$
i84.2
$
i69.8
$
i23.7
$
i119.3
Effective
January 1, 2018, the Partnership implemented ASU 2017-07 and reclassified $i2.5 million (Quarter 1: $i0.5
million; Quarter 2: $i0.5 million; Quarter 3: $i0.8
million; and Quarter 4: $i0.7 million) of other components of net periodic benefit cost for the year ended December 31, 2017, which resulted in an increase to Otherincome
and Operating expensesin the Selected Quarterly Financial Data, with no impact on Net income.
Boardwalk Pipelines (Subsidiary Issuer) has issued securities which have been fully and unconditionally guaranteed by the Partnership (Parent Guarantor). The Subsidiary Issuer is i100% owned by the Parent Guarantor. The Partnership's subsidiaries
had no significant restrictions on their ability to pay distributions or make loans to the Partnership except as noted in the debt covenants and had no restricted assets at December 31, 2018 and 2017. Note 10 contains additional information regarding the Partnership's debt and related covenants.
Proceeds
from long-term debt, net of issuance cost
i—
i539.1
i—
i—
i539.1
Repayment
of borrowings from long-term
debt
i—
(i250.0
)
i—
i—
(i250.0
)
Proceeds
from borrowings on revolving
credit agreement
i—
i—
i490.0
i—
i490.0
Repayment
of borrowings on revolving
credit agreement, including financing
fees
i—
(i0.8
)
(i685.0
)
i—
(i685.8
)
Principal
payment of capital lease
obligation
i—
i—
(i0.5
)
i—
(i0.5
)
Advances
from affiliates, net
i0.3
(i104.3
)
i20.6
i83.7
i0.3
Distributions
paid
(i102.2
)
i—
i—
i—
(i102.2
)
Net cash
(used in) provided by
financing activities
(i101.9
)
i184.0
(i174.9
)
i83.7
(i9.1
)
Increase
(decrease) in cash and cash
equivalents
i0.6
i1.5
(i0.6
)
i—
i1.5
Cash and cash equivalents at
beginning of period
i—
i0.3
i2.8
i—
i3.1
Cash and cash equivalents at
end of period
$
i0.6
$
i1.8
$
i2.2
$
i—
$
i4.6
72
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, 2018, 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, 2018, 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, 2018. 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, 2018, our internal control over financial reporting was effective. Deloitte
& Touche LLP, the independent registered public accounting firm that audited our financial statements included in Item 8 of this Annual Report on Form 10-K, has issued a report on our internal control over financial reporting.
73
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
and the Partners of Boardwalk Pipeline Partners, LP
Opinion
on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of Boardwalk Pipeline Partners, LP and subsidiaries (the “Partnership”) as of December 31, 2018, based on criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on the criteria established in
Internal Control-Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2018, of the Partnership and our report dated February 13, 2019 expressed an unqualified opinion on those financial statements.
Basis for Opinion
The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness
of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership 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 audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material
weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed 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. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the
company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
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 2018 and 2017 by category as described in the notes to the table (in millions):
2018
2017
Audit
fees (1)
$
2.7
$
2.5
Audit related fees (2)
—
0.1
Total
$
2.7
$
2.6
(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
Before we became a wholly-owned subsidiary of BPHC, we had an Audit Committee comprised of independent directors
which satisfied the additional independence and other requirements for Audit Committee members provided for in the listing standards of the NYSE. For the 2018 audit engagement, in order to assure the continued independence of our independent auditor, Deloitte & Touche, the Audit Committee 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 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 Audit Committee, or a designated committee member to whom this authority had been delegated.
75
Under
that policy, the 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 Audit Committee concluded that all such engagements were compatible with the continued independence of Deloitte & Touche in serving as our independent auditor.
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
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.
(1) The Services Agreements between Gulf South Pipeline Company, LP 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, LP 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.
79
SIGNATURE
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.
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.
