None.
Item 4. Mine Safety Disclosures
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A)
Overview
We are a master limited partnership operatingoperate in the midstream portion of the natural gas and NGLs industry, providing transportation and storage for those commodities. We also provide ethane supply and transportation services for industrial customers in Louisiana and Texas. Refer to Part I, Item 1,1. Business, of this Annual Report on Form 10-K for further discussion of our operations and business. We are not in the business of buying and selling natural gas and NGLs other than for system management purposes and to facilitate our ethane supply operations, but changes in natural gas and NGLsNGL prices may impact the volumes of natural gas or NGLs transported and stored by customers or the ethane supply requirements on our systems. The pricing contained in the purchase and sales agreements associated with our ethane supply services is generally based on the same ethane commodity index, plus a fixed delivery fee. As a result, except for possible timing differences that may occur when volumes are purchased in one month and sold in another month, our ethane supply services, like our other businesses, result in us having little to no direct commodity price exposure. We conduct all of our business through our operating subsidiaries as one reportable segment.
Our transportation services consist of firm natural gas transportation, whereby the customer pays a capacity reservation charge to reserve pipeline capacity at receipt and delivery points along our pipeline systems, plus a commodity and fuel charge on the volume of natural gas actually transported, and interruptible natural gas transportation, under which the customer pays to transport gas only when capacity is available and used. The transportation rates we are able to charge customers are heavily influenced by market trends (both short and longer term), including the available natural gas supplies, geographical location of natural gas production, 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). Rates for short-term firm and interruptible transportation services are influenced by shorter-term market conditions such as current and forecasted weather.
We offer firm natural gas storage services in which the customer reserves and pays for a specific amount of storage capacity, including injection and withdrawal rights, and interruptible storage and PAL services where the customer receives and pays for capacity only when it is available and used. The value of our storage and PAL services (comprised of parking gas for customers and/or lending gas to customers) is affected by natural gas price differentials between time periods, such as between winter and summer (time period price spreads), price volatility of natural gas and other factors. Our storage and parking services have greater value when the natural gas futures market is in contango (a positive time period price spread, meaning that current price quotes for delivery of natural gas further in the future are higher than in the nearer term), while our lending service has greater value when the futures market is backwardated (a negative time period price spread, meaning that current price quotes for delivery of natural gas in the nearer term are higher than further in the future). The value of both storage and PAL services may also be favorably impacted by increased volatility in the price of natural gas, which allows us to optimize the value of our storage and PAL capacity.
We also transport and store NGLs. Contracts for our NGLs services are generally fee-based or based on minimum volume requirements, while others are dependent on actual volumes transported. Our NGLs storage rates are market-based and contracts are typically fixed-price arrangements with escalation clauses.
Due to the capital-intensive nature of our business, our operating costs and expenses typically do not vary significantly based upon the amount of products transported, with the exception of fuel consumed at our compressor stations and not included in a fuel tracker, which is included in Fuel and transportation expensesnetted with fuel retained on our Consolidated Statements of Income. Please refer to Part I, Item 1. Business, for further discussion of the services that we offer and our customer mix.
Acquisition
On September 29, 2023, Boardwalk Resources Company, LLC, a wholly owned subsidiary of ours, acquired 100% of the equity interests of Bayou Ethane from Williams Field Services Group, LLC for $355.0 million in cash. Bayou Ethane owns an approximately 380-mile pipeline system that transports ethane from Mont Belvieu, Texas, to the Mississippi River corridor in Louisiana and two 15-mile pipelines in the Houston Ship Channel area that carry ammonia and hydrogen chloride. Bayou Ethane provides ethane supply and transportation services for industrial customers in Louisiana and Texas. In providing supply services, Bayou Ethane purchases ethane at Mont Belvieu, Texas, and various locations in Louisiana and utilizes its pipeline to deliver ethane supply to its customers. The acquisition allows us to extend our assets, diversify our customer base and service offerings and to complement our existing NGLs operations. The purchase price was funded with available cash on hand.
Firm Transportation Agreements
A substantial portion of our transportation and storage capacity is contracted for under firm transportation agreements. For the year ended December 31, 2023, approximately 89% of our revenues were derived from capacity reservation fees under firm contracts or from contracts with MVCs. The table below sets forth the approximate expectedshows a rollforward of projected operating revenues from capacity reservation and minimum bill charges under committed firm transportation agreements in place as of December 31, 2017,2022, to December 31, 2023, including agreements for 2018transportation, storage, ethane supply and 2019, as well asother services, over the actual comparative amountremaining term of those agreements (in millions):
| | | | | | | | |
| | |
Total projected operating revenues under committed firm agreements as of December 31, 2022 | | $ | 9,124.5 | |
Adjustments for: | | |
Actual revenues recognized from firm agreements in 2023(1) | | (1,355.5) | |
Firm agreements entered into or acquired in 2023(2) | | 1,902.5 | |
Total projected operating revenues under committed firm agreements as of December 31, 2023 | | $ | 9,671.5 | |
(1)As of December 31, 2022, we expected our 2023 revenues for 2017. The table does not include additional revenues we have recognized and may receivefrom fixed fees under firm agreements to be approximately $1,280.0 million, including agreements for transportation, storage and other services. Our actual 2023 revenues recognized from fixed fees under firm agreements based on actual utilizationwere approximately $1,355.5 million, an increase of $75.5 million over 2022, primarily resulting from contract renewals at higher rates that occurred in 2023. The Bayou Ethane acquisition also contributed $14.3 million to the increase.
(2)During 2023, we entered into approximately $1.9 billion of new firm agreements, of which approximately 16% were from new growth projects executed in 2023 and 9%, or $178.0 million, were from the agreements assumed as part of the contracted pipeline capacity, any expected revenues for periods after the expiration dates of the existing agreements, execution of precedentBayou Ethane acquisition.
For firm agreements associated with new growth projects, orthe associated assets may not be placed into commercial service until sometime in the future. Each year a portion of our firm transportation and storage agreements expire. The rates we are able to charge customers are heavily influenced by market trends (both short and longer term), including the available supply, geographical location of natural gas production, the competition between producing basins, competition with other events that occurred or will occur subsequent to December 31, 2017.
|
| | | | |
As of |
December 31, 2017 (1) |
(in millions) |
2017 | | $ | 1,070.0 |
|
2018 | | | 970.0 |
|
2019 | | | 950.0 |
|
(1) For a discussion of recontracting risks associated with our transportation revenuespipelines for supply and risks associated with construction,markets, the receipt of regulatorydemand for gas by end-users such as power plants, petrochemical facilities and other approvalsLNG export facilities and the nonperformance of our customers, referprice differentials between the gas supplies and the market demand for the gas (basis differentials). Refer to Part I, Item 1. Business and Item 1A. Risk Factors - We may not be able to replace expiring natural gas transportation contracts at attractive rates orof this Annual Report on a long-term basis and may not be able to sell short-term services at attractive rates or at all due to market conditionsForm 10-K and 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.
In the third quarter 2017, we executed an agreement regarding capacity on our Fayetteville and Greenville Laterals with Southwestern Energy Company (Southwestern), the largest firm transportation customer on those laterals. The agreement, which was approved by the FERC, but is subject to a rehearing request filed with the FERC by Fayetteville Express Pipeline LLC, reduces contracted volumes (or the amountfor further information. As of capacity under contract) on our Fayetteville Lateral for the remaining contract term and commits Southwestern to new firm transportation agreements on our Fayetteville and Greenville Laterals that begin January 1, 2021, and expire on December 31, 2030, and to an interim agreement on the Greenville Lateral from April 2019 through 2020. The agreement also provides us the opportunity to transport natural gas produced from committed properties in the Fayetteville and Moorefield shales that are connected to2023, our Fayetteville Lateral through 2030. Although the transaction will result in a reduction of firm transportation reservation revenues of approximately $70.0 million from 2017 to 2020, including reductions in 2018 and 2019 of approximately $44.0 million and $15.0 million, it provides longer-term revenue generation by addingtop ten years of firm transportation service commitments on both laterals and offers potential additional commodity fee revenue from Southwestern’s volume commitment.
The table below shows a reconciliation of the actualcustomers under committed firm transportationagreements comprised approximately 53% of our total projected operating revenues for 2017 and expectedthe credit profile associated with our customers comprising the total projected operating revenues under committed firm transportation agreements for 2018 from the table shown above to the amounts shownwas 77% rated as investment grade, 7% rated as non-investment grade and 16% not rated. Note 4 in our 2016Part II, Item 8. of this Annual Report on Form 10-K taking into accountcontains more information regarding the Southwestern transaction discussed above, the second quarter 2017 sale of our Flag City processing plant and related assets discussed below and contracts entered into since December 31, 2016. The table does not include additional revenues we have recognized and may receive under firm transportation agreements based on actual utilization of the contracted pipeline 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 subsequentexpect to December 31, 2017.
|
| | | | | | | | |
| | As of December 31, 2017 |
| | (in millions) |
| | 2017 | | 2018 |
Expected revenues under committed firm transportation agreements as reported in our 2016 Annual Report on Form 10-K | | $ | 1,055.0 |
| | $ | 975.0 |
|
Adjustments for: | | | | | | |
Southwestern contract restructuring | | | (7.0 | ) | | | (44.0 | ) |
Sale of Flag City processing plant and related assets | | | (5.0 | ) | | | (8.0 | ) |
Firm transportation agreements entered into in 2017 | | | 27.0 |
| | | 47.0 |
|
Actual/expected revenues under committed firm transportation agreements as of December 31, 2017 | | $ | 1,070.0 |
| | $ | 970.0 |
|
In the 2018 to 2020 timeframe, the agreements associated with our East Texas to Mississippi Pipeline, Southeast Expansion, Gulf Crossing Pipeline and Fayetteville and Greenville Laterals, which were placed into service in 2008 and 2009, will expire. These projects were large, new pipeline expansions, developed to serve growing production in Texas, Oklahoma, Arkansas and Louisiana and anchored primarily by ten-year firm transportation agreements with producers. Since our expansion projects went into service, gas productionearn from the Utica and Marcellus area in the Northeast has grown significantly and has altered the flow patterns of natural gas in North America. Over the last few years, gas production from other basins such as Barnett and Fayetteville, which primarily supported two of our expansions, has declined because the production economics in those basins are not as competitive as other production basins. These market dynamics have resulted in less production from certain basins tied to our system and a narrowing of basis differentials across portions of our pipeline systems, primarily for capacity associated with natural gas flows from west to east. Total revenues generated from the expansion project capacity will be materially lower when these contracts expire. For example, as shown directly above, revenuesfixed fees under committed firm transportation agreements for 2018 are expected to be approximately $100.0 million lower than the actual amount for 2017. This reduction is mainly a result of: (i) expansion contracts on our Gulf South system that expired in early 2018, which comprises approximately 60% of the $100.0 million reduction of revenues; and (ii) the Southwestern contract restructuring, which is responsible for the remaining 40% reduction. While some of the Gulf South capacity has been remarketed at lower rates and for shorter terms, we believe that the
current market rates are not indicative of the long-term value of that capacity. We continue to focus our marketing efforts on enhancing the value of the remaining expansion capacity and we are working 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.
agreements.
Partly as a result of the increase in overall gas supplies, demand markets, primarily in the Gulf Coast area, are growing due to new natural gas export facilities, power plants, petrochemical facilities and increased exports to Mexico. These developments have resulted in significant growth projects for us, as discussed under
Growth Projects. As of December 31, 2017, we have placed several growth projects into service since 2016 and have additional growth projects under development that are expected to be fully placed into service through the end of 2020. These projects have lengthy planning and construction periods. As a result, these projects will not contribute to our earnings and cash flows until they are fully placed into service. The revenues that are expected to be realized in 2018 and 2019 from these growth projects are included in the estimates of expected revenues from capacity reservation and minimum bill charges under committed firm transportation agreements shown above.
Pipeline System Maintenance
and GHG Emission Reduction Initiatives
We incur substantial costs for ongoing maintenance of our pipeline systems and related facilities, including those incurred for pipeline integrity management activities, equipment overhauls, general upkeep and repairs. These costs are not dependent on the amount of revenues earned from our transportation services. PHMSA has developed regulations that require transportation pipeline operators to implement integrity management programs to comprehensively evaluate certain high risk areas, known as HCAs, and MCAs, along pipelines and take additional safety measures to protect pipeline segments locatedpeople and property in highly populatedthese areas. The HCAs for natural gas pipelines are predicated on high-population density areas (which, for natural gas transmission lines, include Class 3 and 4 areas and, depending on the potential impacts of a risk event, may include Class 1 and 2 areas) whereas HCAs along our NGL pipelines are based on high-population density areas, areas near certain drinking water sources and unusually sensitive ecological areas. These regulations have resulted in an overall increase in our ongoing maintenance costs, including maintenance capital and maintenance expense. In 2019, PHMSA has proposed more prescriptiveissued the first part of its gas Mega Rule, which became effective on July 1, 2020. This regulation imposed numerous requirements, including MAOP reconfirmation through re-verification of all historical records for pipelines in service, which re-certification process may require natural gas pipelines installed before 1970 (previously excluded from certain pressure testing obligations) to be pressure tested, the periodic assessment of additional pipeline mileage outside of HCAs (in MCAs as well as Class 3 and Class 4 areas), the reporting of exceedances of MAOP and the consideration of seismicity as a risk factor in integrity management. In 2021, PHMSA issued a final rule that will impose safety regulations related to onshore gas gathering lines and in June 2021, PHMSA issued an Advisory Bulletin advising pipeline and pipeline facility operators of applicable requirements to update their inspection and maintenance plans for the elimination of hazardous leaks and minimization of natural gas released from pipeline facilities. PHMSA and state regulators reportedly began their review of these plans in 2022, and in May 2023, PHMSA published a proposed rule that would enhance requirements for detecting and repairing leaks on new and existing natural gas distribution, gas transmission and gas gathering pipelines. In August 2022, PHMSA published another final rule expanding the Management of Change process, extending corrosion control requirements for gas transmission pipelines, adding requirements that operators ensure no conditions exist following an extreme weather event that could adversely affect the safe operation of the pipeline, and adopting repair criteria for non-HCAs similar to those applicable to HCAs. In September 2023, PHMSA published a proposed rule that would enhance the safety requirements for gas distribution pipelines and would require updates to distribution integrity management programs, emergency response plans, operations and maintenance manuals and other safety practices.
Due to the nature of our interstatebusiness, our operations emit various types of GHGs. We seek to carefully monitor our emissions and expect to incur additional costs to mitigate emissions. New legislation or regulations could increase the costs related to operating and maintaining our facilities. Depending on the particular law, regulation or program, we could be required to incur capital expenditures for installing new monitoring equipment or emission controls on our facilities, acquire and surrender allowances for GHG emissions, pay taxes or fees related to GHG emissions and/or administer and manage a more comprehensive GHG emissions program.
We have been focused on seeking to meet and, in certain instances, pursuing projects aimed at exceeding, regulatory obligations (such as those found in the CAA) by working to reduce emissions of regulated air pollutants, including methane, associated with our pipeline transportation and storage assets. For example, in selecting new compression equipment for growth or asset reliability projects, we consider air emissions as a component in the decision-making process and, when appropriate, place increased emphasis in the selection process on equipment with emissions performance that exceeds applicable federal standards. Several of our reliability projects over the last few years have resulted in replacement of older, higher-emitting compressor drivers with units equipped with advanced emission control systems. As a result, these projects have resulted in decreases in emissions of nitrogen oxides and other air pollutants.
We have identified the reduction of GHG emissions as an area of focus and look for opportunities to reduce emissions using a variety of strategies, including the following:
•evaluating replacing older compression equipment with electric drive compression or new low emission, fuel efficient units when practical;
•modifying fuel systems on certain reciprocating compression equipment to lower fuel consumption and emissions;
•conducting emissions surveys and performing maintenance and repairs on identified component leaks;
•performing annual leak surveys along our pipelines with the aid of helicopters and fixed-wing planes, and analytical field surveys when appropriate;
•performing measurement surveys on all of our compressor stations at least twice a year, exceeding EPA requirements;
•using optical gas imaging cameras to scan natural gas piping and NGLs pipelines which, ifcomponents at our compressor stations to visualize any leaks in real time;
•installing continuous monitoring emission detection equipment at three compression stations;
•employing experts in air emissions to develop and monitor efforts in reducing emissions;
•reducing methane emissions vented to the atmosphere from transmission pipeline blowdowns by using existing and portable compression and flaring when feasible;
•installing repair sleeves and composite wraps where appropriate to avoid pipeline blowdowns;
•exploring options to replace high-bleed natural gas pneumatic devices with low or zero flow bleed devices; and
•reducing methane emissions from rod packing seals on reciprocating compressors, where appropriate.
However, we cannot guarantee that we will be able to implement any of the opportunities we may review or explore, or, for any opportunities we do choose to implement, to implement them in their intended manner or within a specific timeframe or across all operational assets.
These new and any future regulations adopted as proposed, willby PHMSA and efforts to reduce GHG emissions are expected to cause us to incur increased capital and operating costs, may cause us to experience operational delays and may result in potential adverse impacts to our ability to reliably serve our customers. While these proposed regulations have not yet been finalized, they are representative of the types of regulatory changes that can be enacted which would affect our operations and the cost of operating our facilities. See Part I, Item 1. Business and Item 1A. Risk Factors of this Annual Report on Form 10-K for further information.
Maintenance costs may be capitalized or expensed, depending on the nature of the activities. For any given reporting period, the mix of projects that we undertake will affect the amounts we record as property, plant and equipment (PPE) on our balance sheetConsolidated Balance Sheets or recognize as expenses, which impacts our earnings. In 2018,2024, we expect to spend approximately $320.0$505.0 million to maintain our pipeline systems, comply with regulations and monitor, control and reduce our GHG emissions, of which approximately $120.0$215.0 million is expected to be maintenance capital. In 2017,2023, we spent $342.1$445.5 million on these matters, of which $137.9$164.5 million was recorded as maintenance capital. In 2017, the maintenance capital amounts include pipeline integrity upgrades associated with certain segments of our natural gas pipelines. Refer to Capital Expenditures for more information regarding certain of our maintenance costs and additional pipeline integrity upgrades.costs.
Results of Operations
The Overview section in this Item 7, and Note 2 in Part II, Item 8. of Item 8, contain summariesthis Annual Report on Form 10-K contains a summary of our revenuesrevenue contracts and the related revenue recognition policies. A significant portion of our revenues are fee-based, being derived from capacity reservation charges under firm transportation agreements with customers, which do not vary significantly period to period, but are impacted by longer-term trends in our business such as lowerchanges in pricing on contract renewals and other factors discussed elsewhere in this MD&A.Annual Report on Form 10-K. As discussed above, we recently acquired Bayou Ethane. As a result of the acquisition, beginning in the fourth quarter 2023, we have separately reported product sales and product costs on our Consolidated Statements of Income. The pricing contained in the purchase and sales agreements associated with our ethane supply services is generally based on the same ethane commodity index, plus a fixed delivery fee. As a result, except for possible timing differences that may occur when volumes are purchased in one month and sold in another month, our ethane supply services, like our other businesses, result in us having little to no direct commodity price exposure. 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 offsetnetted with fuel retained on our Consolidated Statements of Income. Our operations and maintenance expenses are impacted by revenues from retained fuel includedour compliance with the requirements of, among other regulations, the Mega Rule and our efforts to monitor, control and reduce emissions, as further discussed in our Transportation revenues. Because we are a partnership, we are not a taxable entity for federal income tax purposes and we do not directly pay federal income tax.this Annual Report on Form 10-K.
On May 9, 2017, we sold
We use EBITDA, a non-GAAP measure, as a financial measure to assess our Flag City Processing Partners, LLC subsidiary, which ownedoperating and financial performance and return on invested capital. We believe that some investors may find this measure useful in evaluating our performance.
The following table presents a reconciliation of net income to EBITDA for the Flag City processing plantyears ended December 31, 2023 and related assets, to a third party for $63.6 million, including customary adjustments. We recognized losses and impairment charges of $47.1 million on the sale, reported within 2022 (in millions):
| | | | | | | | | | | | | | |
| | For the Year Ended December 31, |
| | 2023 | | 2022 |
Net income | | $ | 386.0 | | | $ | 342.2 | |
Income taxes | | 0.8 | | | 0.8 | |
Depreciation and amortization | | 408.7 | | | 392.3 | |
Interest expense | | 155.6 | | | 165.9 | |
Interest income | | (12.1) | | | (3.3) | |
EBITDA | | $ | 939.0 | | | $ | 897.9 | |
Total operating costs and expenses.
Please refer to Firm Transportation Agreements the disclosures in this Item 7. and Pipeline System Maintenance above for further discussion Item 1A. Risk Factors of this Annual Report on Form 10-K of items that have impacted, or could impact in the future, our results of operations, including material trends in our operating revenues and expenses.operations.
20172023 Compared with 20162022
Our net income for the year ended December 31, 2017, decreased $5.22023, increased $43.8 million, or 2%13%, to $297.0$386.0 million compared to $302.2$342.2 million for the year ended December 31, 2016, primarily2022. Our EBITDA for the year ended December 31, 2023, increased $41.1 million, or 5%, to $939.0 million as compared to the comparable 2022 period. Our net income and EBITDA increased due to the loss on the saleother factors discussed below, and also included increases of the Flag City processing plant$5.5 million and related assets in 2017 and $12.7$8.2 million of income from the settlement of a legal claim in 2016, mostly offset by the increase in net operating revenues discussed below.Bayou Ethane acquisition.
Operating revenues for the year ended December 31, 2017,2023, increased $15.4$185.7 million, or 1%13%, to $1,322.6$1,617.7 million, compared to $1,307.2$1,432.0 million for the year ended December 31, 2016. Excluding the net effect of $12.7 million of proceeds received from the settlement of a legal matter in 2016 and items offset in2022. Including fuel and transportation expense, primarily retained fuel,expenses and product costs, operating revenues increased $44.1$95.0 million, or 4%7%. TheDuring the fourth quarter 2023, a customer released its no-notice service into separate transportation and storage services, which resulted in an increase was driven byof storage revenues and a reduction in transportation revenues of $6.4 million in 2023 compared to 2022. Excluding the $6.4 million from the no-notice service contract, our transportation revenues increased $70.9 million, primarily due to re-contracting at higher rates and recently completed growth projects recently placed into service, partially offset by a decrease inprojects; our storage and PAL revenues primarily from the effects of unfavorableincreased $23.1 million due to favorable market conditions on time period price spreads and a decrease in revenues associated with the Flag City saleconditions; and the Southwestern contract restructuring discussed above.Bayou Ethane acquisition contributed $11.4 million, resulting from product sales of $99.4 million and product costs of $88.0 million. These increases were partially offset by $9.0 million from lower sales of our other NGL products and other reductions of $1.4 million.
Operating costs and expenses for the year ended December 31, 2017,2023, increased $26.4$158.7 million, or 3%17%, to $856.1$1,091.5 million, compared to $829.7$932.8 million for the year ended December 31, 2016.2022. Excluding itemsexpenses and product costs offset in operating revenues and the $47.1 million loss on the sale of Flag City assets, operating costs and expenses decreased $4.7 million, or less than 1%, when compared to the comparable period in 2016. We had an increase in operations and maintenance expenses primarily due to growth projects recently placed into service and a higher number of maintenance projects. These increases were offset by lower administrative and general expenses due to higher capitalization rates from the increase in capital projects and lower employee incentive costs.
Total other deductions for the year ended December 31, 2017, decreased $6.2 million, or 4%, to $168.5 million compared to $174.7 million for the 2016 period. The decrease in total other deductions was primarily a result of lower interest expense due to higher capitalized interest from growth projects.
2016 Compared with 2015
Our net income for the year ended December 31, 2016, increased $80.2 million, or 36%, to $302.2 million compared to $222.0 million for the year ended December 31, 2015, driven mainly by an increase in net operating revenues discussed below.
Operating revenues for the year ended December 31, 2016, increased $58.0 million, or 5%, to $1,307.2 million, compared to $1,249.2 million for the year ended December 31, 2015. Excluding the net effect of $12.7 million of proceeds received from the settlement of a legal matter in 2016 and $8.8 million of proceeds received from a business interruption claim in 2015, and items offset in fuel and transportation expense, primarily retained fuel, operating revenues increased $82.6 million, or 7%. The increase was driven by an increase in transportation revenues of $70.8 million, which resulted primarily from growth projects which were placed into service, incremental revenues from the Gulf South rate case and a full year of revenues from our Evangeline pipeline. Storage and PAL revenues were higher by $16.9 million primarily from the effects of favorable market conditions on time period price spreads.
Operating costs and expenses for the year ended December 31, 2016, decreased $23.7 million, or 3%, to $829.7 million, compared to $853.4 million for the year ended December 31, 2015. Excluding items offset in operating revenues, operating costs and expenses increased $4.8$68.0 million, or 1%, when compared7%. Our operating expenses were impacted by the following items:
•increased expenses of $5.9 million from the Bayou Ethane acquisition, of which $2.7 million was depreciation and amortization expense;
•increased operating and maintenance expenses of $28.2 million primarily due to higher maintenance projects associated with the comparable period in 2015. The operating expense increase wasrequirements of the Mega Rule and higher materials and supplies and outside services costs; and
•increased administrative and general expenses of $23.2 million primarily due to higher employee-related costs, partially offsetand outside services costs.
Our depreciation and amortization and interest were impacted by decreasesthe following items:
•higher depreciation and amortization expense of $16.4 million from an increased asset base from recently completed growth projects, the Bayou Ethane acquisition and a change in maintenance activitiesthe estimated life of certain of our assets; and depreciation expense.
Total other deductions for the year ended December 31, 2016, increased $1.4•lower interest expense of $10.3 million or 1%, to $174.7 million compared to $173.3 million for the 2015 period. The increase in total other deductions was due to an increaselower average outstanding long-term debt and higher interest income of $8.8 million due to income earned from cash invested in interest expense. The proceeds from the May 2016 issuance of $550.0 million aggregate principal amount of 5.95% Boardwalk Pipelines notes due 2026 (Boardwalk Pipelines 2026 Notes) were initially used to reduce borrowings under our revolving credit facility, which has a lower weighted-average borrowing rate than the Boardwalk Pipelines 2026 Notes.money market funds.
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, sales of limited partner units and our Subordinated Loan.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 to fund our distributions to unitholders. We have no material guarantees of debt or other similar commitments to unaffiliated parties.us.
At December 31, 2017,2023, we had $17.6$20.1 million of cash on hand more than $1.1 billionand $975.0 million of available borrowing capacity under our $1.0 billion revolving credit facility and $300.0 million available under our Subordinated Loan agreement with BPHC.facility. We anticipate that for 2018 our existing capital resources, including our cash on hand, revolving credit facility Subordinated Loan and our cash flows from operating activities, will be adequate to fund our operations.operations and capital expenditures for 2024. We may seek to access the capitaldebt markets to fund some or all capital expenditures for growth projects or acquisitions, to refinance maturing debt or for general partnership purposes. Our abilityWe have an effective shelf registration statement on file with the SEC under which we may publicly issue $1.5 billion of debt securities, warrants or rights from time to accesstime. We have $600.0 million of notes maturing in December 2024, which we expect to retire near or at maturity through available capital resources, including borrowing under our revolving credit facility or publicly issuing debt securities. In June 2023, our revolving credit facility was amended to extend the capital markets for equitymaturity date by one year to May 26, 2028. In December 2023, we paid a $300.0 million distribution to our general partner and BPHC. As of December 31, 2023, we have $4.1 billion of contractual cash payment obligations under firm agreements, of which $3.9 billion represents principal and interest payments related to our long-term debt. Note 12 in Part II, Item 8. of this Annual Report on Form 10-K contains more information regarding our long-term debt and financing under reasonable terms depends onactivities and Notes 5 and 6 contain more information about our financial condition, credit ratings and market conditions.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 13, 2018,2, 2024, our credit ratings for our senior unsecured notes (including those issued by Boardwalk Pipelines) and that of our operating subsidiariessubsidiary having outstanding rated debt were as follows:
| | | | | | | | | | | | | | |
Rating agency | | Rating (Us/Operating Subsidiary) | | Outlook (Us/Operating Subsidiary) |
| | | | |
Rating agency | | Rating
(Us/Operating
Subsidiaries)
| | Outlook
(Us/Operating
Subsidiaries)
|
Standard and Poor's | | BBB-/BBB- | | Stable/Stable |
Moody's Investor Services | | Baa2/Baa1 | | Baa3/Baa2 | Stable/Stable |
Fitch Ratings, Inc. | | BBB/BBB | | BBB-/BBB- | Stable/Stable |
Credit ratings reflect the view of a rating agency and are not a recommendation to buy, sell or hold any security, and may be revised or withdrawn at any time by the rating agency if it determines that the facts and circumstances warrant such a change. Each credit agency’sagency's rating should be evaluated independently of any other credit agency’sagency's rating.
Revolving Credit Facility
Guarantee of Securities of Subsidiaries
Our debt is primarily issued at Boardwalk Pipelines, our wholly owned subsidiary, although we have historically also issued debt at our operating subsidiaries. As of December 31, 2017, we had $385.0 million2023, all of borrowingsthe outstanding under ournotes issued by Boardwalk Pipelines (Subsidiary Issuer) and the full amount of the revolving credit facility, with a weighted-average interest ratewere guaranteed by us (Parent Guarantor). The purpose of 2.72%the guarantees is to help simplify our reporting and no letters of credit issued thereunder. As of capital structure.
February 13, 2018, we had $445.0 million outstanding borrowings under our revolving credit facility, resulting in an available borrowing capacity of approximately $1.1 billion.
In 2017, we extended the maturity date of our revolving credit facility by one additional year to May 26, 2022. The revolving credit facility has a borrowing capacity of $1.5 billion through May 26, 2020, and a borrowing capacity of $1.475 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 the incurrence of additional debt, the sale of assets and sale-leaseback transactions. The financial covenantsWe guarantee amounts borrowed under the revolving credit facility, require us and our subsidiariesbut any amounts borrowed are not subject to maintain, among other things, a ratiothe reporting requirements of total consolidated debt to consolidated EBITDA (as defined in the amended credit agreement) measured for the previous twelve monthsRule 13-01 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 seriesRegulation S-X (Rule 13-01). As of acquisitions, where the purchase price exceeds $100.0December 31, 2023, there was $25.0 million over a rolling 12-month period. We and our subsidiaries were in compliance with all covenant requirementsof
outstanding borrowings under the revolving credit facility asfacility. The following table identifies our principal amounts outstanding for the debt that is subject to the disclosure rules of December 31, 2017. Note 10 in Part II, Item 8Rule 13-01 (in millions):
| | | | | |
| As of December 31, 2023 |
Principal amounts guaranteed by Boardwalk Pipeline Partners and subject to Rule 13-01 (1) | $ | 3,150.0 | |
Principal amounts not guaranteed (2) | 100.0 | |
Other (3) | 11.9 | |
Total debt and finance lease obligation | $ | 3,261.9 | |
| |
(1)This represents principal amounts of this Report contains more information regardingall outstanding debt at Boardwalk Pipelines subject to the disclosure rules of Rule 13-01 (the Guaranteed Notes).
(2)This represents principal amounts of outstanding debt at Texas Gas.
(3)This represents amounts related to a finance lease, unamortized debt discount and issuance costs and outstanding borrowings under the revolving credit facility.
The Guaranteed Notes are fully and unconditionally guaranteed by the Parent Guarantor on a senior unsecured basis. The guarantees of the Guaranteed Notes rank equally with all of our existing and future senior debt, including our guarantee of indebtedness under our revolving credit facility.
Subordinated Loan Agreement with Affiliate
In 2014, we entered into a Subordinated Loan Agreement with BPHC under which we can borrow up to $300.0 million until December 31, 2018. The Subordinated Loan bears interest at increasing rates, ranging from 5.75% to 9.75%, with the first increase occurring on May 1, 2018, to 7.75%, payable semi-annually in June and December, and matures in July 2024. The Subordinated Loan mustguarantees will be prepaid with the net cash proceeds from the issuance of additional equity securities by us or the incurrence of certain indebtedness by us or our subsidiaries, although BPHC may waive such prepayment. BPHC may also demand prepayment at any time, up to the full amount then outstanding, with 15-months' notice. The Subordinated Loan iseffectively subordinated in right of payment to all of our obligations under our revolving credit facility pursuantfuture secured debt to the terms of a Subordination Agreement between BPHC and Wells Fargo, N.A., as representativeextent of the lenders undervalue of the revolving credit facility. Throughassets securing such debt. There are no restrictions on the filing dateSubsidiary Issuer's ability to pay dividends or make loans to the Parent Guarantor. The guaranteed obligations will be terminated with respect to any series of this Report,notes if that series has been discharged or defeased.
Our operating assets, operating liabilities, operating revenues, expenses and other comprehensive income either exist at or are generated by our operating subsidiaries. The Parent Guarantor and the Subsidiary Issuer have no material assets, liabilities or operations independent of their respective financing activities, including the Guaranteed Notes and advances to and from each other, and their investments in the operating subsidiaries. For these reasons, we have not borrowed any amounts undermeet the Subordinated Loan.criteria in Rule 13-01 to omit the summarized financial information from our disclosures.
Capital Expenditures
We capitalize construction costs and expenditures for major renewals and improvements which extend the lives of the respective assets. In accordance with our partnership agreement, we include as growth expenditures those expenditures associated with projects which are expected to increase an asset’s operating capacity or our revenues or cash flows from that which existed immediately prior to the addition or improvement and which are expected to produce a financial return. Capital expenditures associated with projects that do not meet the preceding criteria are considered maintenance capital expenditures.
We are currently engaged in several growth projects, described in Part I, Item 1, Business - Current Growth Projects, of this Report. In 2017, the Northern Supply Access Project and portions of our Coastal Bend Header and Sulphur Storage and Pipeline Expansion projects were placed into service. In 2018, we signed a precedent agreement for a new project on our Gulf South system that will serve a proposed power plant in Texas. The project will provide approximately 0.2 Bcf/d of firm transportation service by adding compression at an existing compressor station and constructing a lateral. The cost of this project is expected to be approximately $100.0 million and has a proposed in-service date of 2020. This project remains subject to customary approvals. In 2018, we expect to incur capital expenditures of approximately $430.0 million related to our growth projects, which primarily consist of the final portions of the Coastal Bend Header project and a gas treating project in Texas and the following projects in Louisiana: three ethylene transportation and storage projects to serve industrial customers, the development of storage wells and associated infrastructure for brine supply services, and two natural gas transportation projects to serve power plants. All of our growth projects are secured by long-term firm contracts.
Our cost and timing estimates for these projects are subject to a variety of risks and uncertainties, including obtaining regulatory approvals, adverse weather conditions, acquiring the right to construct and operate on other owners’ land, delays in obtaining key materials and shortages of qualified labor. Refer to Part I, Item 1A. Risk Factors of this Report for additional risks associated with our growth projects and the related financing.
The nature of our existing growth projects will require us to enhance or modify our existing assets to accommodate increased operating pressures or changing flow patterns. We consider capital expenditures associated with the modification or enhancement of existing assets in the context of a growth project to be growth capital to the extent that the modification would not have been made in the absence of the growth project without regard to the condition of the existing assets.
Growth capital expenditures were $570.5 million, $469.1 million and $232.0 million for the years ended December 31, 2017, 2016 and 2015. Maintenance capital expenditures for the years ended December 31, 2017, 20162023, 2022 and 20152021, were $137.9$164.5 million, $121.3$157.4 million and $142.5$154.3 million.
Growth capital expenditures for the years ended December 31, 2023, 2022 and 2021, were $217.9 million, $180.2 million and $174.9 million. During the year ended December 31, 2023, we acquired Bayou Ethane for $355.0 million. During the year ended December 31, 2022, we spent $6.7 million on natural gas to be used in our integrated natural gas pipeline system. During the year ended December 31, 2021, we acquired certain natural gas pipeline assets in the Lake Charles, Louisiana, area for approximately $20.0 million in cash.
We expect total capital expenditures to be approximately $550.0$420.0 million in 2018,2024, including approximately $120.0$215.0 million for maintenance capital and $430.0$205.0 million related to growth projects. Refer to
Pipeline System Maintenance for further discussion of trends impacting our maintenance capital expenditures.
Contractual Obligations
The following table summarizes significant contractual cash payment obligations under firm commitments as of December 31, 2017, by period (in millions):
|
| | | | | | | | | | | | | | | | | | | |
| Total | | Less than 1 Year | | 1-3 Years | | 3-5 Years | | More than 5 Years |
Principal payments on long-term debt (1) | $ | 3,710.0 |
| | $ | 185.0 |
| | $ | 350.0 |
| | $ | 1,125.0 |
| | $ | 2,050.0 |
|
Interest on long-term debt (2) | 1,005.1 |
| | 158.8 |
| | 287.8 |
| | 232.0 |
| | 326.5 |
|
Capital commitments (3) | 171.2 |
| | 171.2 |
| | — |
| | — |
| | — |
|
Pipeline capacity agreements (4) | 17.7 |
| | 6.3 |
| | 8.4 |
| | 3.0 |
| | — |
|
Operating lease commitments | 26.4 |
| | 4.3 |
| | 8.5 |
| | 8.0 |
| | 5.6 |
|
Capital lease commitments (5) | 11.6 |
| | 1.0 |
| | 2.2 |
| | 2.2 |
| | 6.2 |
|
Total | $ | 4,942.0 |
| | $ | 526.6 |
| | $ | 656.9 |
| | $ | 1,370.2 |
| | $ | 2,388.3 |
|
| |
(1) | Includes our senior unsecured notes, having maturity dates from 2018 to 2027, and $385.0 million of loans outstanding under our revolving credit facility, having a maturity date of May 26, 2022. The amounts included in the Less than 1 Year column are included in long-term debt on our balance sheet because we have sufficient available borrowing capacity under our revolving credit facility to extend the amount that would come due in less than one year.
|
| |
(2) | Interest obligations represent interest due on our senior unsecured notes at fixed rates. Future interest obligations under our revolving credit facility are uncertain, due to the variable interest rate and fluctuating balances, and are not included in the table above. Based on a 2.72% weighted-average interest rate and an unused commitment fee of 0.18% as of December 31, 2017, our future cash obligations under our revolving credit facility would be $12.5 million, $24.9 million and $17.6 million due in less than one year, 1-3 years and 3-5 years. |
| |
(3) | Capital commitments represent binding commitments under purchase orders for materials ordered but not received and firm commitments under binding construction service agreements existing at December 31, 2017. |
| |
(4) | The amounts shown are associated with pipeline capacity agreements on third-party pipelines that allow our operating subsidiaries to transport gas to off-system markets on behalf of our customers. |
| |
(5) | Capital lease commitments represent future non-cancelable minimum lease payments under a capital lease agreement. |
Pursuant to the settlement of the Texas Gas rate case in 2006, we are required to annually fund an amount to the Texas Gas pension plan equal to the amount of actuarially determined net periodic pension cost, including a minimum of $3.0 million. In 2018, we expect to fund approximately $3.0 million to the Texas Gas pension plan.
Distributions
For the years ended December 31, 2017 and 2016, we paid distributions of $102.2 million and for the year ended December 31, 2015, we paid $101.5 million to our partners. Note 12 in Part II, Item 8 of this Report contains further discussion regarding our distributions.
Cash Flows from Operating, Investing and Financing Activities
A significant portion of our revenues are fee-based, being derived from capacity reservation charges under firm transportation agreements with customers, and our operating expenses do not vary significantly from period to period. Significant variability in cash flows from period to period generally results from changes in capital expenditures, pipeline maintenance costs and financing transactions, as well as other longer-term trends in our business which impact earnings, such as lower pricing on contract renewals and other factors, all of which are discussed elsewhere in this MD&A.
Changes in cash flow from operating activities
Net cash provided by operating activities increased $36.2 million to $637.0 million for the year ended December 31, 2017, compared to $600.8 million for the comparable 2016 period primarily due to the change in net income, excluding the effects of non-cash items such as depreciation, amortization and the loss on the sale of operating assets and the 2016 settlement of the Gulf South rate refund.
Changes in cash flow from investing activities
Net cash used in investing activities increased $54.4 million to $644.6 million for the year ended December 31, 2017, compared to $590.2 million for the comparable 2016 period. The increase is a result of an increase in capital expenditures of $118.0 million related to our growth projects discussed in Capital Expenditures, partially offset from proceeds received from the sale of the Flag City processing plant and related assets.
Changes in cash flow from financing activities
Net cash provided by financing activities increased $29.7 million to $20.6 million for the year ended December 31, 2017, compared to $9.1 million cash used for the comparable 2016 period. The increase in cash provided by financing activities resulted primarily from an increase in net borrowings of $29.9 million.
Impact of Inflation
The cumulative impact of inflation over a number of years has resulted in increased costs for current replacement of productive facilities. The majority of our PPE is subject to rate-making treatment, and under current FERC practices, recovery is limited to historical costs. Amounts in excess of historical cost are not recoverable unless a rate case is filed. However, cost-based regulation, along with competition and other market factors, may limit our ability to price jurisdictional services to ensure recovery of inflation’s effect on costs.
Off-Balance Sheet Arrangements
At December 31, 2017, we had no guarantees of off-balance sheet debt 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.
Critical Accounting Estimates and Policies
Our significant accounting policies are described in Note 2 in Part II, Item 88. of this Report.Annual Report on Form 10-K. The preparation of these consolidated financial statements in accordanceconformity with GAAPaccounting principles generally accepted in the U.S. requires us to make estimates and judgmentsassumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities. Estimates are based on historical experience and on various other assumptions that are believed to be reasonable under the circumstances. The result of this process forms the basis for making judgments about the carrying amountamounts of assets and liabilities that are not readily apparent from other sources. We review our estimates and judgmentsassumptions on a regular, ongoing basis. Changes in facts and circumstances may result in revised estimates and actual results may differ materially from those estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the periods in which the facts that give rise to the revisions become known.
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.
RegulationGoodwill
MostGoodwill represents the excess of our natural gas pipeline subsidiaries are regulated by the FERC. Pursuant to FERC regulations, certain revenues that we collect may be subject to possible refunds to our customers. Accordingly, duringcost of an open rate case, estimatesacquisition over the fair value of rate refund reserves are recorded based on regulatory proceedings, advice of counsel and estimated risk-adjusted total exposure, as well as other factors. As of December 31, 2017 and 2016, there were no liabilities for any open rate case recorded on our Consolidated Balance Sheets.
When certain criteria are met, GAAP requires that certain rate-regulated entities account for and reportthe net identifiable assets acquired 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 our 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.
Effective April 1, 2016, Gulf South implemented a fuel tracker as a result of its settled rate case. We apply regulatory accounting for the fuel tracker, under which the value of fuel received from customers paying the full tariff rate and the related
value of fuel used in transportation are recorded to a regulatory asset or liability depending on whether Gulf South uses more fuel than it collects from customers or collects more fuel than it uses. Other than as described for Texas Gas and Gulf South, regulatory accounting is not applicable to our other FERC-regulated operations.
We monitor the regulatory and competitive environment in which we operate to determine whether our regulatory assets continue to be probable of recovery. If we were to determine that all or a portion of our 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 in Part II, Item 8 of this Report contains more information regarding our regulatory assets and liabilities.
Fair Value Measurements
Fair value refers to an exit price that would be received to sell an asset or paid to transfer a liability in an orderly transaction in the principal market in which the reporting entity transacts based on the assumptions market participants would use when pricing the asset or liability assuming its highest and best use. A fair value hierarchy has been established that prioritizes the information used to develop those assumptions giving priority, from highest to lowest, to quoted prices in active markets for identical assets and liabilities (Level 1); observable inputs not included in Level 1, for example, quoted prices for similar assets and liabilities (Level 2); and unobservable data (Level 3), for example, a reporting entity’s own internal data based on the best information available in the circumstances. We use fair value measurements to account for our asset retirement obligations, any impairment charges and the value of our plan assets associated with our pension and postretirement benefit plans. We also use fair value measurements to perform our goodwill impairment testing and report fair values for certain items in the Notes to the Consolidated Financial Statements in Part II, Item 8 of this Report. Notes 5 and 11 in Part II, Item 8 of this Report contain more information regarding our fair value measurements.
Goodwill
assumed. Goodwill is tested for impairment at the reporting unit level at least annually, as of November 30, or more frequently when events occur and circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Accounting requirements provide that a reporting entity may perform an optional qualitative assessment on an annual basis to determine whether events occurred or circumstances changed that would more likely than not reduce the fair value of a reporting unit below its carrying amount. If an initial qualitative assessment identifies that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, or the optional qualitative assessment is not performed, a quantitative analysis underis performed. The quantitative goodwill impairment test is performed by calculating the fair value of the reporting unit and comparing it to the reporting unit's carrying amount. If the fair value of a two-stepreporting unit exceeds its carrying amount, goodwill of the reporting unit is not impaired. However, if the carrying amount of a reporting unit exceeds its fair value, an impairment testloss is recognized in an amount equal to that excess, limited to the total amount of goodwill recorded on the reporting unit.
As of November 30, 2023, our annual goodwill testing date, we performed a quantitative analysis on our two reporting units to measure whether the fair value of the reporting unit is less than its carrying amount. If the fair valueeither 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, 2017, which corresponds with the preparation of our five-year financial plan operating results.was less than their carrying amounts. The fair value measurement of the reporting units was derived based on judgments and assumptions we believe market participants would use in assessing the fair value of the reporting units. These judgments and assumptions included the valuation premise, use of a discounted cash flow model to estimate fair value under an income approach and inputs to the valuation model. The inputs included our five-year financial plan operating results, including operating revenues, the long-term outlook for growth in natural gas and NGLs demand, 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.model and views regarding future market conditions, among others. The reasonableness of fair value estimates under the income approach were supported by a market approach under which we applied EBITDA multiples derived from publicly-available information to each reporting unit's EBITDA. The use of alternate judgments and assumptions, including changes in the risk-free rate, could substantially change the results of our goodwill impairment analysis, including the potential recognition of an impairment charge in our Consolidated Financial Statements.
The results of the quantitative goodwill impairment test for 2017 and 20162023 indicated that the fair value of our two reporting units significantly exceeded their carrying amounts and no goodwill impairment charges were recognized forrecognized. The estimated fair values of our reporting units fluctuate from year to year. In 2023, the estimated fair values of the reporting units.units exceeded their carrying amounts by amounts that were similar to that indicated in 2022, with the excess of both reporting units being in the range of 10% - 20%. Although the prospects for our reporting units remain positive, including their strong base operating cash flows and the markets in which they operate, significant changes in future estimated operating revenues or cash flows, or any other changes to the inputs to the valuation model, such as those previously discussed, could result in the recognition of future impairment charges.
Impairment of Long-Lived Assets (including Tangible and Definite-Lived Intangible Assets)
We evaluate whether the carrying amounts of our long-lived and intangible assets have been impaired when circumstances indicate the carrying amount of those assets may not be recoverable. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the asset. If the carrying amount is not recoverable, an impairment loss is measured as the excess of the asset’sasset's carrying amount over its fair value. We recognized $5.8 million, $3.8asset impairment charges of $0.4 million and $0.4$7.5 million of asset impairment charges for the years ended December 31, 2017, 20162023 and 2015.
Defined Benefit Plans
We are required2022, and immaterial asset impairment charges for the year ended December 31, 2021. The charges recorded in 2022 were primarily due to make a significant numberan increase in the estimate of assumptions in order to estimate the net liabilities and costsexisting asset retirement obligations related to our pension and postretirement benefit obligations to employees under our benefit plans. The assumptions that have the most impact on our pension and postretirement benefit costs are the discount rate, the expected return on plan assets and the rate of compensation increases. These assumptions are evaluated relative to current market factors in the U.S. such as inflation, interest rates and fiscal and monetary policies, as well as our policies regarding management of the plans such as the allocation of plan assets among investment options. Changes in these assumptions can have a material impact on obligations and related expense associated with these plans.retired assets.
In determining the discount rate assumption, we utilize current market information and liability information provided by our plan actuaries, including a discounted cash flow analysis of our pension and postretirement obligations. In particular, the basis for our discount rate selection was the yield on indices of highly rated fixed income debt securities with durations comparable to that of our plan liabilities and with consideration of the change in interest rates, such as the U.S. Treasury yield curve. The Conduent interest rate curve and the Citibank Pension Liability curve were consistently used as the basis for the change in discount rate from the last measurement date with this measure confirmed by the yield on other broad bond indices. Additionally, we supplement our discount rate decision with a yield curve analysis. The yield curve is applied to expected future retirement plan payments to adjust the discount rate to reflect the cash flow characteristics of the plans. The yield curve is a hypothetical AA/Aa yield curve represented by a series of annualized discount rates reflecting bond issues having a rating of Aa or better by Moody's Investors Service, Inc. Note 11 in Part II, Item 8 of this Report contains more information regarding our pension and postretirement benefit obligations.
Forward-Looking Statements
Investors are cautioned that certainCertain statements contained in this Annual Report on Form 10-K, as well as some statements in our other filings with the SEC and periodic press releases and some oral statements made by our officials and our subsidiaries during presentations about us, are “forward-looking.”"forward-looking." Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance, intentions or achievements, and may contain the words “expect,” “intend,” “plan,” “anticipate,” “estimate,” “believe,” “will"expect," "intend," "plan," "anticipate," "estimate," "believe," "will likely result”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 partnershipus or our subsidiaries, are also forward-looking statements.
Forward-looking statements are based on current expectations and projections about future events and their potential impact on us. While management believes that these forward-looking statements are reasonable as and when made, there is no assurance that future events affecting us will be those that we anticipate. All forward-looking statements are inherently subject to a variety of risks and uncertainties, many of which are beyond our control, thatwhich could cause actual results to differ materially from those anticipated or projected. These risks and uncertainties include, among others:
our ability to maintainothers, the impacts of legislative and regulatory initiatives, or replace expiring gas transportationthe implementation thereof, the impacts of climate change, ESG matters and storage contractspipeline safety requirements and to sell short-term capacity on our pipelines;
initiatives, the costs of maintaining and ensuring the integrity and reliability of our pipeline systems, the need to remove pipeline and other assets from service as a result of such activities, and the timing and financial impacts of returning any such assets to service;
the impact of the FERC's rate-making policies and decisions on the services we offer, the rates we are proposing to charge or are charging and our ability to recover the full cost of operating our pipeline, including earning a reasonable return on equity;
the impact of changes to laws and regulations, such as the proposed GHG and methane legislation and other changes in environmental legislations, the pipeline safety bill, and regulatory changes that result from that legislation applicable to interstate pipelines, on our business, including our costs, liabilities and revenues;
we may not complete projects, including growth projects that we have commenced or will commence, the risk of a failure in computer systems or we may complete projects on materially different terms, cost or timing than anticipated and we may not be able to achieve the intended economic or operational benefits of any such projects, if completed;
thecybersecurity attack, successful negotiation, consummation and completion of contemplated transactions, projects and agreements, including obtaining all necessary regulatoryrisks and customer approvalsuncertainties related to the impacts of volatility in energy prices and resolving land owner opposition,our exposure to credit risk relating to default or the
timing, cost, scope, financial performance and execution ofbankruptcy by our recent, current and future acquisitions and growth projects;
the impact to our business of our continuing to make distributions on our common units to our unitholders at our current distribution rate;
the ability of our customers to pay for our services, including the ability of any foundation shippers on our growth projects to provide required credit support or otherwise comply with the terms of precedent agreements;
the impact of new pipelines or new gas supply sources on competition and basis spreads on our pipeline systems;
volatility or disruptions in the capital or financial markets;
the success of our strategy to grow and diversify our business, including expansion into new product lines and geographic areas, especially in light of the unstable price levels of oil and natural gas experienced over the past several years, which can influence the associated production of these commodities;
the impact on our system throughput and revenues from changes in the supply of and demand for natural gas;
our ability to access the bank and capital markets on acceptable terms to refinance our outstanding indebtedness and to fund our capital needs;
operational hazards, litigation and unforeseen interruptions for which we may not have adequate or appropriate insurance coverage;
the future cost of insuring our assets; and
our ability to access new sources of natural gas and the impact on us of any future decreases in supplies of natural gas in our supply areas.
customers. Developments in any of these areas could cause our results to differ materially from results that have been or may be anticipated or projected. Forward-looking statements speak only as of the date they are made and we expressly disclaim any obligation or undertaking to update these statements to reflect any change in our expectations or beliefs or any change in events, conditions or circumstances on which any forward-looking statement is based.
Refer to Part I, Item 1A. of this Annual Report on Form 10-K for additional risks and uncertainties regarding our forward-looking statements.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Interest rate risk: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, 2023 and 2022 (in millions, except interest rates):
| | | 2017 | | 2016 | | 2023 | | 2022 |
Carrying amount of fixed-rate debt | $ | 3,302.5 |
| | $ | 3,378.9 |
|
Fair value of fixed-rate debt | $ | 3,504.4 |
| | $ | 3,529.2 |
|
100 basis point increase in interest rates and resulting debt decrease | $ | 167.5 |
| | $ | 148.3 |
|
100 basis point decrease in interest rates and resulting debt increase | $ | 179.9 |
| | $ | 160.2 |
|
100 basis point increase in interest rates and resulting fair value of debt decrease | |
100 basis point decrease in interest rates and resulting fair value of debt increase | |
Weighted-average interest rate | 5.18 | % | | 5.46 | % | Weighted-average interest rate | 4.84 | % | | 4.84 | % |
At December 31, 2017,2023, we had $385.0$25.0 million ofoutstanding under variable-rate debt outstandingagreements at a weighted-average interest rate of 2.72%6.71%. A 1%100 basis point increase in interest rates would increase our cash payments for interest on our variable-rate debt by $3.9$0.3 million on an annualized basis. At December 31, 2016,2022, we had $180.0 million outstanding underno variable-rate agreements at a weighted-average interest rate of 1.96%.debt outstanding.
Commodity Risk
At December 31, 2017
For the natural gas and 2016, $17.6 millionNGLs (other than ethane supply services) which our pipelines transport and $4.6 million of our undistributed cash, shown on the Consolidated Balance Sheets as Cash and cash equivalents, was primarily invested in Treasury fund accounts. Due to the short-term nature of the Treasury fund accounts, a hypothetical 10% increase or decrease in interest rates would not have a material effect on the fair market value of our Cash and cash equivalents.
Commodity risk:
Our pipelinesstore, we do not take title to the natural gas and NGLs which they transport and store,these products; therefore, theywe do not assume the related commodity price risk associated with these products. For our ethane supply services, which require us to enter into ethane sales and purchase agreements and take title to those products, the products. However, certainpricing contained in those purchase and sales agreements is generally based on the same ethane commodity index, plus a fixed delivery fee. As a result, except for possible timing differences that may occur when volumes ofare purchased in one month and sold in another month, our gas stored underground are available for sale and subjectethane supply services, like our other businesses, result in us having little to no direct commodity price risk. At December 31, 2017 and 2016, approximately $6.4 million and $1.2 million of gas stored underground, which we own and carry as current Gas and liquids stored underground, was available for sale and exposed to commodity price risk. We have historically managed our exposure to commodity price risk through the use of futures, swaps and option contracts; however, at December 31, 2017 and 2016, we had no outstanding derivatives.exposure.
Credit risk: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 NNS.certain firm services. Natural gas price volatility can materially increase credit risk related to gas loaned to customers. We also have credit risk related to customers supporting some of our growth projects. If any significant customer of ours should have credit or financial problems resulting in a delay or failure to pay for services provided by us or repay gas they owe to us, 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, 2017,2023, the amount of gas loaned out by our subsidiaries or owed to our operating subsidiaries due to gas imbalances and gas loaned under PAL and certain firm service agreements was approximately 12.311.2 trillion British thermal units (TBtu). Assuming an average market price during December 20172023 of $2.76$2.33 per million British thermal unitsunit (MMBtu), the market value of that gas was approximately $34.0$26.1 million. As of December 31, 2017,2022, the amount of gas owed to our operating subsidiaries due to gas imbalances and gas loaned under PAL and certain firm service agreements was approximately 13.3 TBtu. Assuming an average market price during December 2022 of $5.33 per MMBtu, the market value of that gas was approximately $70.9 million. As of December 31, 2023 and 2022, there were no outstanding NGL imbalances owed to our operating subsidiaries. As of December 31, 2016, the amount of gas loaned out by our subsidiaries or owed to our subsidiaries due to gas imbalances was approximately 13.6 TBtu. Assuming an average market price during December 2016 of $3.47 per MMBtu, the market value of this gas at December 31, 2016, would have been approximately $47.2 million. As of December 31, 2016, the amount of NGLs owed to our operating subsidiaries due to imbalances was less than 0.1 MMBbls, which had a market value of approximately $0.4 million.
Although nearly all of our customers pay for our services on a timely basis, we actively monitor the credit exposure to our customers. We include in our ongoing assessments, amounts due pursuant to services we render plus the value of any gas we have lent to a customer through NNS or PAL services and the value of gas due to us under a transportation imbalance. Our natural gas pipeline tariffs contain language that allow us to require a customer that does not meet certain credit criteria to provide cash
collateral, post a letter of credit or provide a guarantee from a credit-worthy entity in an amount equaling up to three months of capacity reservation charges. For certain agreements with customers, for example, those related to our growth projects, we have included contractual provisions that require additional credit support should the credit ratings of those customers fall below investment grade.
Natural gas producers comprise a significant portion of our revenues and support several of our growth projects. For example, in 2017, approximately 46% of our revenues were generated from contracts with natural gas producers. The prices of oil and natural gas have been unstable over the past several years as a result of increasing gas supplies, mainly from shale production areas in the U.S. Should the prices of oil and natural gas continue to remain unstable, we could be exposed to increased credit risk associated with our producer customer group. We continue to monitor our credit risk carefully, especially as it relates to customers that may be affected by the current oil and natural gas markets. Refer to Part I, Item 1A. Risk Factors - We are exposed to credit risk relating to default or bankruptcy by our customers for further discussion regarding credit risk.
Item 8. Financial Statements and Supplementary Data
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Boardwalk GP, LLC
and the Partners of Boardwalk Pipeline Partners, LP
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Boardwalk Pipeline Partners, LP and subsidiaries (the “Partnership”"Company") as of December 31, 20172023 and 2016, and2022, the related consolidated statements of income, comprehensive income, cash flows and changes in equitypartners' capital, for each of the three years in the period ended December 31, 20172023, 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 PartnershipCompany as of December 31, 20172023 and 2016,2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017,2023, 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, 2017, 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 15, 2018, 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'sCompany's management. Our responsibility is to express an opinion on the Partnership'sCompany's financial statements based on our audits. We are a public accounting firm registered with the PCAOBPublic Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the PartnershipCompany in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit council and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Goodwill — Refer to Notes 2 and 9 to the financial statements
Critical Audit Matter Description
Goodwill is tested for impairment at the reporting unit level at least annually as of November 30, or more frequently when events occur and circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. As of November 30, 2023, the Company performed a quantitative analysis for its annual goodwill impairment test of its two reporting units to measure whether the fair value of either of the reporting units is less than their carrying amounts. If the carrying amount of a reporting unit exceeds its fair value, an impairment loss is recognized in an amount equal to that excess, limited to the total amount of goodwill recorded on the reporting unit.
The fair value measurement of the reporting units is derived based on judgments and assumptions, including the use of a discounted cash flow model to estimate fair value and inputs to the valuation model. The inputs included the five-year financial plan operating results, including operating revenues, the long-term outlook for growth in natural gas and NGLs
demand, and the applied discount rate. The use of alternate judgments and assumptions could substantially change the results of the goodwill impairment analysis, including the recognition of an impairment charge in the Consolidated Statement of Income. The results of the quantitative goodwill impairment test indicated that the fair value of the Company's reporting units exceeded their carrying amounts and no goodwill impairment charges were recognized.
We identified goodwill for Boardwalk Pipeline Partners, LP as a critical audit matter because of the significant judgments made by management to estimate the fair value of each reporting unit. This required a high degree of auditor judgment and an increased extent of effort, including the need to involve fair value specialists, when performing audit procedures to evaluate the reasonableness of management's judgments and assumptions related to the applied discount rate, the long-term outlook for growth in natural gas and NGLs demand, and the Company's future estimated operating revenues within the five-year financial plan operating results.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to management's assumptions underlying the applied discount rates, the long-term outlook for growth in natural gas and NGLs demand, and the Company's future estimated operating revenues within the five-year financial plan operating results included the following, among others:
•We tested the effectiveness of controls over management's goodwill impairment test, including controls over management's estimate of the applied discount rate, the long-term outlook for growth in natural gas and NGLs demand, and the future estimated operating revenues for each reporting unit.
•We evaluated management's ability to accurately forecast future operating revenues by comparing actual results to management's historical forecasts for each reporting unit.
•We evaluated the reasonableness of the future estimated operating revenues within the five-year financial plan operating results by comparing the forecasts to:
•Historical operating revenues of the Company’s similar or existing contracts with customers and average annual growth rates.
•Forecasted information in analyst and industry reports for the Company and certain of its peer companies.
•We evaluated contracts subject to renewal within the five-year financial plan by making a selection of contracts and assessing the reasonableness of renewal assumptions, including rates and volumes.
•With the assistance of our fair value specialists, we evaluated the reasonableness of the applied discount rate, and the long-term outlook for growth in natural gas and NGLs demand used as inputs to management's goodwill impairment test for each reporting unit by:
•Comparing the Company's estimate of the long-term outlook for growth in natural gas and NGLs demand for each reporting unit to industry reports and other market data.
•Developing a range of independent estimates of the applied discount rate for each reporting unit and comparing those to the applied discount rates selected by management for each reporting unit.
Acquisition — Purchase Price Allocation — Refer to Note 3 to the financial statements
Critical Audit Matter Description
The Company completed the acquisition of Williams Olefins Pipeline Holdco LLC ("Bayou Ethane") for cash consideration of $355.0 million on September 29, 2023. The Company accounted for the acquisition of Bayou Ethane as a business combination. Accordingly, the purchase price was allocated to the assets acquired and liabilities assumed based on their estimated fair values on the date of acquisition. The fair values for property, plant and equipment (PPE), including rights-of-way, were determined primarily using a combination of the market and cost approaches. The fair values for the customer-based intangibles were determined using a discounted cash flow analysis with inputs not observable in the market, such as estimated future cash flows and weighted average cost of capital rates, which were considered Level 3 fair value estimates.
We identified the acquisition of Bayou Ethane as a critical audit matter because of the estimates management made to determine the fair value of assets acquired and liabilities assumed. This required a high degree of auditor judgment and an increased extent of effort, including the need to involve fair value specialists, when performing audit procedures to evaluate the weighted average cost of capital and the fair value of acquired property, plant and equipment, including rights-of-way, and intangible assets.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the fair value of assets acquired and liabilities assumed for Bayou Ethane included the following, among others:
•We tested the effectiveness of controls over the purchase price allocation, including management's controls over the assumptions used in the valuation of the property, plant, and equipment, including rights-of-way, and intangible assets, including estimating the appraisal and fair value of the acquired property, plant and equipment and intangible assets, determination of the weighted average cost of capital, and reviewing the work of third-party specialists.
•With the assistance of our fair value specialists:
•We evaluated the reasonableness of selected valuation methodologies, and use of management's experts.
•We tested cost to acquire or construct comparable assets and the remaining useful lives used for the cost approach for property, plant and equipment, including rights-of-way, and compared such estimates to independent market information to determine reasonableness.
•We tested the methodology used for the valuation of intangible assets.
•We developed a range of independent estimates of the weighted average cost of capital and compared that to the weighted average cost of capital utilized by management.
/s/ Deloitte & Touche LLP
Houston, Texas
February 15, 20186, 2024
We have served as the Partnership'sCompany's auditor since 2003.
BOARDWALK PIPELINE PARTNERS, LP
CONSOLIDATED BALANCE SHEETS
(Millions)
| | | | | | | | | | | |
| December 31, |
ASSETS | 2023 | | 2022 |
Current Assets: | | | |
Cash and cash equivalents | $ | 20.1 | | | $ | 215.6 | |
Receivables: | | | |
Trade, net | 204.6 | | | 148.4 | |
Other | 24.9 | | | 25.4 | |
Gas transportation receivables | 7.0 | | | 22.0 | |
Gas stored underground and other product inventory | 3.3 | | | 41.6 | |
| | | |
Prepayments | 24.3 | | | 23.7 | |
Other current assets | 4.5 | | | 8.7 | |
Total current assets | 288.7 | | | 485.4 | |
| | | |
Property, Plant and Equipment: | | | |
Natural gas transmission and other plant | 13,242.3 | | | 12,616.7 | |
Construction work in progress | 287.2 | | | 187.6 | |
Property, plant and equipment, gross | 13,529.5 | | | 12,804.3 | |
Less—accumulated depreciation and amortization | 4,672.9 | | | 4,288.3 | |
Property, plant and equipment, net | 8,856.6 | | | 8,516.0 | |
| | | |
Other Assets: | | | |
Goodwill | 237.4 | | | 237.4 | |
Gas stored underground | 99.3 | | | 153.5 | |
Other | 214.4 | | | 177.6 | |
Total other assets | 551.1 | | | 568.5 | |
| | | |
Total Assets | $ | 9,696.4 | | | $ | 9,569.9 | |
|
| | | | | | | |
| December 31, |
ASSETS | 2017 | | 2016 |
Current Assets: | | | |
Cash and cash equivalents | $ | 17.6 |
| | $ | 4.6 |
|
Receivables: | |
| | |
|
Trade, net | 116.8 |
| | 127.1 |
|
Other | 16.6 |
| | 12.7 |
|
Gas transportation receivables | 4.6 |
| | 8.2 |
|
Gas and liquids stored underground | 6.5 |
| | 1.3 |
|
Prepayments | 17.9 |
| | 17.7 |
|
Other current assets | 0.6 |
| | 2.6 |
|
Total current assets | 180.6 |
| | 174.2 |
|
| | | |
Property, Plant and Equipment: | |
| | |
|
Natural gas transmission and other plant | 10,467.1 |
| | 9,958.8 |
|
Construction work in progress | 416.5 |
| | 368.5 |
|
Property, plant and equipment, gross | 10,883.6 |
| | 10,327.3 |
|
Less—accumulated depreciation and amortization | 2,621.1 |
| | 2,333.8 |
|
Property, plant and equipment, net | 8,262.5 |
| | 7,993.5 |
|
| | | |
Other Assets: | |
| | |
|
Goodwill | 237.4 |
| | 237.4 |
|
Gas stored underground | 86.3 |
| | 93.5 |
|
Other | 139.8 |
| | 139.2 |
|
Total other assets | 463.5 |
| | 470.1 |
|
| | | |
Total Assets | $ | 8,906.6 |
| | $ | 8,637.8 |
|
The accompanying notes are an integral part of these consolidated financial statements.
BOARDWALK PIPELINE PARTNERS, LP
CONSOLIDATED BALANCE SHEETS
(Millions)
| | | | | | | | | | | |
| December 31, |
LIABILITIES AND PARTNERS' CAPITAL | 2023 | | 2022 |
Current Liabilities: | | | |
Payables: | | | |
Trade | $ | 113.2 | | | $ | 70.7 | |
Affiliates | 3.4 | | | 2.6 | |
Other | 16.4 | | | 17.4 | |
Gas transportation payables | 7.8 | | | 41.2 | |
Accrued taxes, other | 67.9 | | | 62.8 | |
Accrued interest | 34.2 | | | 33.9 | |
Accrued payroll and employee benefits | 44.0 | | | 38.3 | |
| | | |
Regulatory liabilities | 15.1 | | | 55.1 | |
| | | |
Other current liabilities | 60.3 | | | 50.7 | |
Total current liabilities | 362.3 | | | 372.7 | |
| | | |
Long-term debt and finance lease obligation | 3,261.9 | | | 3,233.4 | |
| | | |
Other Liabilities and Deferred Credits: | | | |
Pension liability | 4.7 | | | 8.8 | |
Asset retirement obligations | 59.2 | | | 53.9 | |
Provision for other asset retirement | 98.1 | | | 93.2 | |
| | | |
Other | 119.1 | | | 105.7 | |
Total other liabilities and deferred credits | 281.1 | | | 261.6 | |
| | | |
Commitments and Contingencies | | | |
| | | |
Partners' Capital: | | | |
Partners' capital | 5,867.7 | | | 5,781.7 | |
Accumulated other comprehensive loss | (76.6) | | | (79.5) | |
Total partners' capital | 5,791.1 | | | 5,702.2 | |
| | | |
Total Liabilities and Partners' Capital | $ | 9,696.4 | | | $ | 9,569.9 | |
|
| | | | | | | |
| December 31, |
LIABILITIES AND PARTNERS' CAPITAL | 2017 | | 2016 |
Current Liabilities: | | | |
Payables: | | | |
Trade | $ | 76.0 |
| | $ | 113.8 |
|
Affiliates | 1.5 |
| | 1.4 |
|
Other | 11.9 |
| | 23.7 |
|
Gas payables | 5.7 |
| | 6.7 |
|
Accrued taxes, other | 57.1 |
| | 52.7 |
|
Accrued interest | 37.9 |
| | 40.6 |
|
Accrued payroll and employee benefits | 33.7 |
| | 38.5 |
|
Construction retainage | 32.4 |
| | 19.6 |
|
Deferred income | 1.9 |
| | 7.5 |
|
Other current liabilities | 22.3 |
| | 28.4 |
|
Total current liabilities | 280.4 |
| | 332.9 |
|
| | | |
Long–term debt and capital lease obligation | 3,686.8 |
| | 3,558.0 |
|
| | | |
Other Liabilities and Deferred Credits: | |
| | |
|
Pension liability | 21.8 |
| | 22.0 |
|
Asset retirement obligation | 46.0 |
| | 44.7 |
|
Provision for other asset retirement | 65.8 |
| | 63.7 |
|
Payable to affiliate | 16.0 |
| | 16.0 |
|
Other | 65.0 |
| | 69.6 |
|
Total other liabilities and deferred credits | 214.6 |
| | 216.0 |
|
| | | |
Commitments and Contingencies |
|
| |
|
|
| | | |
Partners’ Capital: | |
| | |
|
Common units – 250.3 million units issued and outstanding as of December 31, 2017 and 2016 | 4,713.1 |
| | 4,522.2 |
|
General partner | 92.7 |
| | 88.8 |
|
Accumulated other comprehensive loss | (81.0 | ) | | (80.1 | ) |
Total partners’ capital | 4,724.8 |
| | 4,530.9 |
|
Total Liabilities and Partners' Capital | $ | 8,906.6 |
| | $ | 8,637.8 |
|
The accompanying notes are an integral part of these consolidated financial statements.
BOARDWALK PIPELINE PARTNERS, LP
CONSOLIDATED STATEMENTS OF INCOME
(Millions, except per unit amounts)(Millions)
| | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, |
| 2023 | | 2022 | | 2021 |
Operating Revenues: | | | | | |
Transportation | $ | 1,287.0 | | | $ | 1,228.8 | | | $ | 1,152.6 | |
Storage, parking and lending | 160.9 | | | 129.2 | | | 110.4 | |
Product sales | 100.3 | | | 11.1 | | | 11.7 | |
Other | 69.5 | | | 62.9 | | | 65.4 | |
Total operating revenues | 1,617.7 | | | 1,432.0 | | | 1,340.1 | |
Operating Costs and Expenses: | | | | | |
Fuel and transportation | 26.3 | | | 22.4 | | | 22.1 | |
Product costs | 87.8 | | | 1.0 | | | — | |
Operation and maintenance | 281.0 | | | 250.9 | | | 226.9 | |
Administrative and general | 171.9 | | | 147.7 | | | 144.6 | |
Depreciation and amortization | 408.7 | | | 392.3 | | | 366.3 | |
Loss (gain) on sale of assets, impairments and other | 0.3 | | | 4.0 | | | (0.1) | |
Taxes other than income taxes | 115.5 | | | 114.5 | | | 113.2 | |
Total operating costs and expenses | 1,091.5 | | | 932.8 | | | 873.0 | |
| | | | | |
Operating income | 526.2 | | | 499.2 | | | 467.1 | |
Other Deductions (Income): | | | | | |
Interest expense | 155.6 | | | 165.9 | | | 160.8 | |
Interest income | (12.1) | | | (3.3) | | | — | |
Miscellaneous other income, net | (4.1) | | | (6.4) | | | (9.4) | |
Total other deductions | 139.4 | | | 156.2 | | | 151.4 | |
Income before income taxes | 386.8 | | | 343.0 | | | 315.7 | |
Income taxes | 0.8 | | | 0.8 | | | 0.7 | |
Net income | $ | 386.0 | | | $ | 342.2 | | | $ | 315.0 | |
|
| | | | | | | | | | | |
| For the Year Ended December 31, |
| 2017 | | 2016 | | 2015 |
Operating Revenues: | | | | | |
Transportation | $ | 1,180.7 |
| | $ | 1,142.4 |
| | $ | 1,091.1 |
|
Parking and lending | 20.2 |
| | 18.2 |
| | 11.4 |
|
Storage | 81.5 |
| | 91.4 |
| | 81.3 |
|
Other | 40.2 |
| | 55.2 |
| | 65.4 |
|
Total operating revenues | 1,322.6 |
| | 1,307.2 |
| | 1,249.2 |
|
| | | | | |
Operating Costs and Expenses: | |
| | |
| | |
|
Fuel and transportation | 54.8 |
| | 70.8 |
| | 99.3 |
|
Operation and maintenance | 204.2 |
| | 199.9 |
| | 209.5 |
|
Administrative and general | 126.5 |
| | 142.2 |
| | 130.4 |
|
Depreciation and amortization | 322.8 |
| | 317.8 |
| | 323.7 |
|
Loss (gain) on sale of assets and impairments | 49.0 |
| | 3.7 |
| | (0.1 | ) |
Taxes other than income taxes | 98.8 |
| | 95.3 |
| | 90.6 |
|
Total operating costs and expenses | 856.1 |
| | 829.7 |
| | 853.4 |
|
| | | | | |
Operating income | 466.5 |
| | 477.5 |
| | 395.8 |
|
| | | | | |
Other Deductions (Income): | |
| | |
| | |
|
Interest expense | 171.0 |
| | 182.8 |
| | 176.4 |
|
Interest income | (0.4 | ) | | (0.4 | ) | | (0.4 | ) |
Miscellaneous other income, net | (2.1 | ) | | (7.7 | ) | | (2.7 | ) |
Total other deductions | 168.5 |
| | 174.7 |
| | 173.3 |
|
| | | | | |
Income before income taxes | 298.0 |
| | 302.8 |
| | 222.5 |
|
| | | | | |
Income taxes | 1.0 |
| | 0.6 |
| | 0.5 |
|
| | | | | |
Net income | 297.0 |
| | 302.2 |
| | 222.0 |
|
Net Income per Unit: | | | |
| | |
|
| | | | | |
Net income per common unit | $ | 1.16 |
| | $ | 1.18 |
| | $ | 0.87 |
|
Weighted-average number of common units outstanding | 250.3 |
| | 250.3 |
| | 248.8 |
|
Cash distribution declared and paid to common units per common unit | $ | 0.40 |
| | $ | 0.40 |
| | $ | 0.40 |
|
The accompanying notes are an integral part of these consolidated financial statements.
BOARDWALK PIPELINE PARTNERS, LP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Millions)
| | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, |
| 2023 | | 2022 | | 2021 |
Net income | $ | 386.0 | | | $ | 342.2 | | | $ | 315.0 | |
Other comprehensive income (loss): | | | | | |
Reclassification adjustment transferred to Net income from cash flow hedges | 0.1 | | | 0.5 | | | 0.9 | |
Pension and other postretirement benefit costs, net of tax | 2.8 | | | (7.4) | | | 6.3 | |
Total Comprehensive Income | $ | 388.9 | | | $ | 335.3 | | | $ | 322.2 | |
|
| | | | | | | | | | | |
| For the Year Ended December 31, |
| 2017 | | 2016 | | 2015 |
Net income | $ | 297.0 |
| | $ | 302.2 |
| | $ | 222.0 |
|
Other comprehensive income (loss): | |
| | |
| | |
|
Loss on cash flow hedge | (1.5 | ) | | — |
| | — |
|
Reclassification adjustment transferred to Net income from cash flow hedges | 2.5 |
| | 2.4 |
| | 2.4 |
|
Pension and other postretirement benefit costs | (1.9 | ) | | 1.8 |
| | (13.9 | ) |
Total Comprehensive Income | $ | 296.1 |
| | $ | 306.4 |
| | $ | 210.5 |
|
The accompanying notes are an integral part of these consolidated financial statements.
BOARDWALK PIPELINE PARTNERS, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
| | | | | | | | | | For the Year Ended December 31, |
| For the Year Ended December 31, |
| 2023 | | | 2023 | | 2022 | | 2021 |
OPERATING ACTIVITIES: | 2017 | | 2016 | | 2015 |
Net income | |
Net income | |
Net income | $ | 297.0 |
| | $ | 302.2 |
| | $ | 222.0 |
|
Adjustments to reconcile net income to cash provided by operations: | |
| | | | |
Depreciation and amortization | 322.8 |
| | 317.8 |
| | 323.7 |
|
Depreciation and amortization | |
Depreciation and amortization | |
Amortization of deferred costs and other | 8.1 |
| | 2.1 |
| | 7.7 |
|
Loss (gain) on sale of assets and impairments | 49.0 |
| | 3.7 |
| | (0.1 | ) |
Loss (gain) on sale of assets, impairments and other | |
Changes in operating assets and liabilities: | |
| | | | |
Trade and other receivables | 6.1 |
| | (10.4 | ) | | (18.6 | ) |
Gas receivables and storage assets | 5.6 |
| | 10.9 |
| | (14.3 | ) |
Costs recoverable from customers | 3.8 |
| | — |
| | (0.3 | ) |
Other assets | (3.8 | ) | | 0.8 |
| | (3.2 | ) |
Trade and other receivables | |
Trade and other receivables | |
| Gas transportation receivables, storage assets and other product inventory | |
Gas transportation receivables, storage assets and other product inventory | |
Gas transportation receivables, storage assets and other product inventory | |
| Prepayments and other assets | |
Prepayments and other assets | |
Prepayments and other assets | |
Trade and other payables | (14.0 | ) | | (20.0 | ) | | 39.4 |
|
Other payables, affiliates | — |
| | (0.1 | ) | | (0.7 | ) |
Gas payables | (5.8 | ) | | 5.3 |
| | (3.7 | ) |
Gas transportation payables | |
Accrued liabilities | (4.1 | ) | | 9.9 |
| | 0.3 |
|
Regulatory assets and liabilities | |
Other liabilities | (27.7 | ) | | (21.4 | ) | | 24.2 |
|
Net cash provided by operating activities | 637.0 |
| | 600.8 |
| | 576.4 |
|
INVESTING ACTIVITIES: | |
| | |
| | |
| INVESTING ACTIVITIES: | | | |
Capital expenditures | (708.4 | ) | | (590.4 | ) | | (374.5 | ) |
Proceeds from sale of operating assets | 63.8 |
| | 0.2 |
| | 0.8 |
|
Proceeds from other recoveries | — |
| | — |
| | 6.2 |
|
| Acquisition of business | |
| Acquisition of business | |
| Acquisition of business | |
Net cash used in investing activities | (644.6 | ) | | (590.2 | ) | | (367.5 | ) |
FINANCING ACTIVITIES: | |
| | |
| | |
| FINANCING ACTIVITIES: | | | |
Proceeds from long-term debt, net of issuance cost | 494.0 |
| | 539.1 |
| | 247.1 |
|
Repayment of borrowings from long-term debt and term loan | (575.0 | ) | | (250.0 | ) | | (725.0 | ) |
Proceeds from borrowings on revolving credit agreement | 765.0 |
| | 490.0 |
| | 1,125.0 |
|
Repayment of borrowings on revolving credit agreement, including financing fees | (560.8 | ) | | (685.8 | ) | | (873.6 | ) |
Principal payment of capital lease obligation | (0.5 | ) | | (0.5 | ) | | (0.4 | ) |
Repayment of borrowings from long-term debt | |
Proceeds from borrowings on revolving credit facility | |
Repayments of borrowings on revolving credit facility, including financing fees | |
Principal payment of finance lease obligation | |
Advances from affiliates | 0.1 |
| | 0.3 |
| | 0.6 |
|
Distributions paid | (102.2 | ) | | (102.2 | ) | | (101.5 | ) |
Proceeds from sale of common units | — |
| | — |
| | 113.1 |
|
Capital contributions from general partner | — |
| | — |
| | 2.3 |
|
Net cash provided by (used in) financing activities | 20.6 |
| | (9.1 | ) | | (212.4 | ) |
Increase (decrease) in cash and cash equivalents | 13.0 |
| | 1.5 |
| | (3.5 | ) |
Net cash used in financing activities | |
(Decrease) increase in cash and cash equivalents | |
Cash and cash equivalents at beginning of period | 4.6 |
| | 3.1 |
| | 6.6 |
|
Cash and cash equivalents at end of period | $ | 17.6 |
| | $ | 4.6 |
| | $ | 3.1 |
|
The accompanying notes are an integral part of these consolidated financial statements.
BOARDWALK PIPELINE PARTNERS, LP
CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS'PARTNERS' CAPITAL
(Millions)
| | | | | | | | | | | | | | | | | | | | |
| | Partners' Capital | | Accumulated Other Comprehensive Income (Loss) | | Total Partners' Capital |
Balance December 31, 2020 | | $ | 5,328.9 | | | $ | (79.8) | | | $ | 5,249.1 | |
Add (deduct): | | | | | | |
Net income | | 315.0 | | | — | | | 315.0 | |
Distributions paid | | (102.2) | | | — | | | (102.2) | |
Other comprehensive income, net of tax | | — | | | 7.2 | | | 7.2 | |
Balance December 31, 2021 | | $ | 5,541.7 | | | $ | (72.6) | | | $ | 5,469.1 | |
Add (deduct): | | | | | | |
Net income | | 342.2 | | | — | | | 342.2 | |
Distributions paid | | (102.2) | | | — | | | (102.2) | |
Other comprehensive loss, net of tax | | — | | | (6.9) | | | (6.9) | |
Balance December 31, 2022 | | $ | 5,781.7 | | | $ | (79.5) | | | $ | 5,702.2 | |
Add (deduct): | | | | | | |
Net income | | 386.0 | | | — | | | 386.0 | |
Distributions paid | | (300.0) | | | — | | | (300.0) | |
Other comprehensive income, net of tax | | — | | | 2.9 | | | 2.9 | |
Balance December 31, 2023 | | $ | 5,867.7 | | | $ | (76.6) | | | $ | 5,791.1 | |
|
| | | | | | | | | | | | | | | |
| Common Units | | General Partner | | Accumulated Other Comp (Loss) Income | | Total Partners' Capital |
Balance January 1, 2015 | $ | 4,095.1 |
| | $ | 80.0 |
| | $ | (72.8 | ) | | $ | 4,102.3 |
|
Add (deduct): | | | | | | | |
|
Net income | 217.5 |
| | 4.5 |
| | — |
| | 222.0 |
|
Distributions paid | (99.5 | ) | | (2.0 | ) | | — |
| | (101.5 | ) |
Sale of common units, net of related transaction costs | 113.1 |
| | — |
| | — |
| | 113.1 |
|
Capital contribution from general partner | — |
| | 2.3 |
| | — |
| | 2.3 |
|
Other comprehensive loss, net of tax | — |
| | — |
| | (11.5 | ) | | (11.5 | ) |
Balance December 31, 2015 | $ | 4,326.2 |
| | $ | 84.8 |
| | $ | (84.3 | ) | | $ | 4,326.7 |
|
Add (deduct): | | | | | | | |
|
Net income | 296.2 |
| | 6.0 |
| | — |
| | 302.2 |
|
Distributions paid | (100.2 | ) | | (2.0 | ) | | — |
| | (102.2 | ) |
Other comprehensive income, net of tax | — |
| | — |
| | 4.2 |
| | 4.2 |
|
Balance December 31, 2016 | $ | 4,522.2 |
| | $ | 88.8 |
| | $ | (80.1 | ) | | $ | 4,530.9 |
|
Add (deduct): | |
| | |
| | |
| | |
|
Net income | 291.1 |
| | 5.9 |
| | — |
| | 297.0 |
|
Distributions paid | (100.2 | ) | | (2.0 | ) | | — |
| | (102.2 | ) |
Other comprehensive loss, net of tax | — |
| | — |
| | (0.9 | ) | | (0.9 | ) |
Balance December 31, 2017 | $ | 4,713.1 |
| | $ | 92.7 |
| | $ | (81.0 | ) | | $ | 4,724.8 |
|
The accompanying notes are an integral part of these consolidated financial statements.
BOARDWALK PIPELINE PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1: Corporate Structure
Boardwalk Pipeline Partners, LP (the Partnership)Company) is a Delaware limited partnership formed in 2005 to own and operate the business conducted by its primary subsidiary Boardwalk Pipelines, LP (Boardwalk Pipelines) and its operating subsidiaries, Gulf South Pipeline Company, LPLLC (Gulf South), Texas Gas Transmission, LLC (Texas Gas), Gulf Crossing Pipeline Company LLC (Gulf Crossing), Boardwalk Louisiana Midstream, LLC (Louisiana Midstream), Boardwalk Louisiana Gas Transmission, LLC, Boardwalk Texas Intrastate, LLC, Boardwalk Petrochemical Pipeline, LLC, and Boardwalk Texas Intrastate,Ethane Pipeline Company, LLC (together, the operating subsidiaries), which consists of integrated pipeline and storage systems for natural gas and natural gas liquids and other hydrocarbons (herein referred to together as NGLs) pipeline and storage systems.. All of the Partnership’sCompany's operations are conducted by the operating subsidiaries.
As of February 13, 2018,December 31, 2023, Boardwalk Pipelines Holding Corp. (BPHC), a wholly-ownedwholly owned subsidiary of Loews Corporation (Loews), owned 125.6 milliondirectly or indirectly, 100% of the Partnership’s common units, and, through Boardwalk GP, LP (Boardwalk GP), an indirect wholly-owned subsidiary of BPHC, holds the Company's capital.
2% general partner interest and all of the incentive distribution rights (IDRs) of the Partnership. As of February 13, 2018, the common units and general partner interest owned by BPHC represent approximately 51% of the Partnership’s equity interests, excluding the IDRs. The Partnership’s common units are traded under the symbol “BWP” on the New York Stock Exchange.
Note 2: Basis of Presentation and Significant Accounting Policies
Basis of Presentation
The accompanying consolidated financial statements of the Partnership wereCompany have been prepared in accordance with accounting principles generally accepted in the United States of America (U.S.) (GAAP). Certain amounts reported in Other revenues and Fuel and transportation expense were reclassified to Product sales and Product costs to conform to the current presentation in connection with the acquisition discussed in Note 3. The amounts reclassified represent NGL product sales that occurred during 2022 and 2021. The effect of the reclassification was a decrease in Other revenues and an increase in Product sales of $11.1 million and $11.7 million for the years ended December 31, 2022 and 2021, and a decrease in Fuel and transportation expense and an increase in Product costs of $1.0 million and an immaterial amount for the years ended December 31, 2022 and 2021. These reclassifications had no impact on Total operating revenues, Operating income or Net income.
Principles of Consolidation
The consolidated financial statements include the Partnership’sCompany's accounts and those of its wholly-ownedwholly owned subsidiaries after elimination of intercompany transactions.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and disclosure of contingent assets and liabilities and the fair values of certain items. The PartnershipCompany bases its estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, which form the basis for making judgments about the carrying amounts of assets and liabilities that are not readily apparent from other sources. Actual results could differ from such estimates.
Segment Information
The PartnershipCompany operates in one reportable segment - the operation of interstate natural gas and NGLs pipeline systems and integrated storage facilities. This segment consists of interstate natural gas pipeline systems which are located in the Gulf Coast region, Oklahoma, Arkansas, and the Midwestern states of Tennessee, Kentucky, Illinois, Indiana and Ohio and the Partnership'sintegrated natural gas storage facilities located in Indiana, Kentucky, Louisiana and Mississippi, and NGLs pipelines and storage facilities located in Louisiana and Texas.
Regulatory Accounting
Most of the Partnership'sCompany's natural gas pipeline subsidiaries and its interstate ethane transportation pipeline are regulated by the Federal Energy Regulatory Commission (FERC). When certain criteria are met, GAAP requires that certain rate-regulated entities account for and report assets and liabilities consistent with the economic effect of the manner in which
independent third-party regulators establish rates (regulatory accounting). This basis of accounting is applicable to operations of the Partnership’sCompany's Texas Gas subsidiary, which records certain costs and benefits as regulatory assets and liabilities in order to provide for recovery from or refundrefunds to customers in future periods, but is not applicable to the operations associated with the Fayetteville and Greenville Laterals due to rates charged under negotiated rate agreements and a portion of theTexas Gas' storage capacity due to the regulatory treatment associated with the rates charged for that capacity.
Effective April 1, 2016, the Partnership's Gulf South subsidiary implemented a fuel tracker as a result of a rate case settlement. The PartnershipCompany also applies regulatory accounting for theits fuel tracker,trackers on Gulf South, under which the value of fuel received from customers paying the maximum tariff rate and the related value of fuel used in transportation are recorded to a regulatory asset or liability depending on whether Gulf South uses more fuel than it collects from customers or collects more fuel than it uses. Prior to the implementation of the fuel tracker 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, regulatory accounting is not applicable to the Partnership’sCompany's other FERC-regulated operations.
The PartnershipCompany 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 determineCompany determines that all or a portion of its regulatory assets no longer metmeets the criteria for recognition as regulatory assets, that portion which wasis not recoverable wouldwill be written off, net of any regulatory liabilities.
Note 911 contains more information regarding the Partnership’sCompany's regulatory assets and liabilities.
Fair Value Measurements
Fair value refers to an exit price that would be received to sell an asset or paid to transfer a liability in an orderly transaction in the principal market in which the reporting entity transacts based on the assumptions market participants would use when pricing the asset or liability assuming its highest and best use. A fair value hierarchy has been established that prioritizes the information used to develop those assumptions giving priority, from highest to lowest, to quoted prices in active markets for identical assets and liabilities (Level 1); observable inputs not included in Level 1, for example, quoted prices for similar assets and liabilities (Level 2); and unobservable data (Level 3), for example, a reporting entity’sentity's own internal data based on the best information available in the circumstances. The PartnershipCompany uses fair value measurements to account for business combinations, equity securities, asset retirement obligations (ARO), pension and postretirement benefits other than pension (PBOP) assets and any impairment charges. Fair value measurements are also used to perform goodwill impairment testing and report fair values for certain items contained in this Report. The Partnership considers any transfers between levels within the fair value hierarchy to have occurred at the beginning of a quarterly reporting period. The Partnership did not recognize any transfers between Level 1 and Level 2 of the fair value hierarchy and did not change its valuation techniques or inputs during the year ended December 31, 2017.
Notes 53, 7 and 1113 contain more information regarding fair value measurements.
Cash and Cash Equivalents
Cash equivalents are highly liquid investments with an original maturity of three months or less and are stated at cost plus accrued interest, which approximates fair value. The PartnershipCompany had no restricted cash at December 31, 20172023 and 2016.2022.
Cash Management
The operating subsidiaries participate in an intercompany cash management program with those that are FERC-regulated participating to the extent they are permitted under FERC regulations. Under the cash management program, depending on whether a participating subsidiary has short-term cash surpluses or cash requirements, Boardwalk Pipelines either provides cash to them or they provide cash to Boardwalk Pipelines. The transactions are represented by demand notes and are stated at historical carrying amounts. Interest income and expense are recognized on an accrual basis when collection is reasonably assured. The interest rate on intercompany demand notes is London Interbank Offered Rate (LIBOR) plus 1% and is adjusted every three months.
Trade and Other Receivables
Trade and other receivables are stated at their historical carrying amount, net of allowances for doubtful accounts. The PartnershipCompany establishes an allowance for doubtful accounts under an expected credit loss model based on a case-by-case basis when it believes the required payment ofhistorical credit loss experience and specific amounts owed is unlikely to occur.facts and circumstances. Uncollectible receivables are written off when a settlement is reached for an amount that is less than the outstanding historical balance or a receivable amount is deemed otherwise unrealizable.
Gas Stored Underground and Gas Receivables and Payables
Certain of the Partnership'sCompany'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 (NNS) and parking and lending (PAL) services. Gas stored underground includes the historical cost of natural gas volumes owned by the operating subsidiaries, at times reduced by certain operational encroachments upon that gas. Current gas stored underground represents net retained fuel remaining after providing transportation and storage services which is available for resale and is valued at the lower of weighted-average cost or market.
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 PartnershipCompany in providing these services, the PartnershipCompany does not record the related gas on its balance sheet.the Consolidated Balance Sheets. Certain of the Partnership'sCompany's operating subsidiaries also periodically lend gas and NGLs to customers.
In the course of providing transportation and storage services to customers, the operating subsidiaries may receive different quantities of gas from shippers and operators than the quantities delivered on behalf of those shippers and operators.
This results in transportation and exchange gas receivables and payables, commonly known as imbalances, which are primarily settled in cash or the receipt or delivery of gas in the future. Settlement of imbalances requires agreement between the pipelines and shippers or operators as to allocations of volumes to specific transportation contracts and timing of delivery of gas based on operational conditions. The receivables and payables are valued at market price for operations where regulatory accounting is not applicable and are valued at the historical value of gas in storage for operations where regulatory accounting is applicable.
Materials and Supplies
Materials and supplies are carried at average cost and are included in Other Assets on the Consolidated Balance Sheets. The PartnershipCompany 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, 20172023 and 2016,2022, the PartnershipCompany held approximately $20.1$38.1 million and $19.2$34.3 million of materials and supplies.
Property, Plant and Equipment and Repair and Maintenance Costs
PPE is recorded at its original cost of construction or fair value of assets purchased. Construction costs and expenditures for major renewals and improvements which extend the lives of the respective assets are capitalized. Construction work in progress is included in the financial statements as a component of PPE. Repair and maintenance costs are expensed as incurred.
Depreciation of PPE related to operations for which regulatory accounting does not apply is provided for using the straight-line method of depreciation over the estimated useful lives of the assets, which range from 3 to 35 years. The ordinary sale or retirement of PPE for these assets could result in a gain or loss.loss being recorded in the income statement. Depreciation of PPE related to operations for which regulatory accounting is applicable is provided for primarily on the straight-line method at FERC-prescribed rates over estimated useful lives of 5 to 62 years. Reflecting the application of composite depreciation, gains and losses from the ordinary sale or retirement of PPE for these assets are not recognized in earnings and generally do not impact PPE, net.
Note 68 contains more information regarding the Partnership’sCompany's PPE.
Goodwill and Intangible Assets
Goodwill represents the excess of the cost of an acquisition over the fair value of the net identifiable assets acquired and liabilities assumed. Goodwill is tested for impairment at the reporting unit level at least annually, as of November 30, or more frequently when events occur and circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. To test goodwill, a quantitative analysis is performed under a two-step impairment testA reporting entity may perform an optional qualitative assessment on an annual basis to measuredetermine whether events occurred or circumstances changed that would more likely than not reduce the fair value of thea reporting unit is less thanbelow its carrying amount. If based upon a quantitative analysisan initial qualitative assessment identifies that it is more likely than not that the fair value of thea reporting unit is less than its carrying amount, includingor the optional qualitative assessment is not performed, a quantitative analysis is performed. The quantitative goodwill impairment test is performed by calculating 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 and comparing it to the reporting unit's goodwill is determined to be less thancarrying amount. If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is not impaired. However, if the carrying amount of a reporting unit exceeds its fair value, an impairment loss is recognized forin an amount equal to that excess, limited to the difference.total amount of goodwill recorded on the reporting unit.
Intangible assets are those assets which provide future economic benefit but have no physical substance. The PartnershipCompany 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 7Notes 3 and 9 contains more information regarding the Partnership'sCompany's goodwill and intangible assets.
Impairment of Long-lived Assets (including Tangible and Definite-lived Intangible Assets)
The PartnershipCompany evaluates its long-lived and intangible assets for impairment when, in management’smanagement'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’smanagement's estimate of undiscounted future cash flows attributable to the remaining economic useful life of the asset (or asset group) is compared to the carrying amount of the asset (or asset group) to determine whether an impairment has occurred. If an impairment of the carrying amount has occurred, the amount of impairment recognized in the
financial statements is determined by estimating the fair value of the assets (or asset group) and recording a loss to the extent that the carrying amount exceeds the estimated fair value.
Capitalized Interest and Allowance for Funds Used During Construction (AFUDC)
The PartnershipCompany records capitalized interest, which represents the cost of borrowed funds used to finance construction activities for operations where regulatory accounting is not applicable. The PartnershipCompany 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’sCompany'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 withinon the Consolidated Statements of Income. The following table summarizes capitalized interest and the allowance for borrowed funds and allowance for equity funds used during construction (in millions):
| | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, |
| 2023 | | 2022 | | 2021 |
Capitalized interest and allowance for borrowed funds used during construction | $ | 3.6 | | | $ | 2.2 | | | $ | 3.8 | |
Allowance for equity funds used during construction | 5.7 | | | 6.2 | | | 7.9 | |
|
| | | | | | | | | | | |
| For the Year Ended December 31, |
| 2017 | | 2016 | | 2015 |
Capitalized interest and allowance for borrowed funds used during construction | $ | 19.2 |
| | $ | 7.4 |
| | $ | 3.4 |
|
Allowance for equity funds used during construction | 1.9 |
| | 7.9 |
| | 2.7 |
|
Income Taxes
The PartnershipCompany is not a taxable entity for federal income tax purposes. As such, it does not directly pay federal income tax. The Partnership’sCompany's taxable income or loss, which may vary substantially from the net income or loss reported inon the Consolidated Statements of Income, is includable in the federal income tax returns of each partner.of its partners. The aggregate difference in the basis of the Partnership’sCompany's net assets for financial and income tax purposes cannot be readily determined as the Partnership does not have access to the information about each partner’s tax attributes related to the Partnership.is $5.6 billion. The subsidiaries of the PartnershipCompany directly incur some income-based state taxes which are presented in Income taxes on the Consolidated Statements of Income.
Note 1314 contains more information regarding the Partnership’sCompany's income taxes.
Revenue Recognition
The maximum rates that may be charged by the majority of the Partnership's operating subsidiaries for their services 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. Revenues from transportation and storage services are recognized in the period the service is provided based on contractual terms and the related volumes transported or stored. In connection with some PAL and interruptible storage service agreements, cash is received at the inception of the service period resulting in the recording of deferred revenues which are recognized in revenues over the period the services are provided. At December 31, 2017 and 2016, the Partnership had deferred revenues of $1.8 million and $8.4 million, which are expected to be recognized through 2018.
Retained fuel is recognized in revenues at market prices in the month of retention for operations where regulatory accounting is not applicable. The related fuel consumed in providing transportation services is recorded in Fuel and transportation expenses at market prices in the month consumed. In some cases, customers may elect to pay cash for the cost of fuel used in providing transportation services instead of having fuel retained in-kind. Retained fuel included in Transportation on the Consolidated Statements of Income for the years ended December 31, 2017, 2016 and 2015, was $28.0 million, $29.1 million and $53.2 million. As discussed under the Regulatory Accounting policy, Gulf South implemented a fuel tracker effective April 1, 2016, for customers paying the maximum tariff rate. Prior to the implementation of the fuel tracker and the application of regulatory accounting, the value of fuel received from customers was reflected in operating revenues and the value of fuel consumed was reflected in operating expenses.
The Partnership has contractual retainage provisions in some of its ethylene storage contracts that provide for the Partnership to retain ownership of 0.5% of customer inventory volumes injected into storage wells. The Partnership may sell the retainage volumes if commercially marketable volumes are on hand. The Partnership recognizes revenue for ethylene retainage volumes upon the physical sale of such volumes.
Under FERC regulations, certain revenues that the operating 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. At December 31, 2017 and 2016, the Partnership did not have a refund liability for any open rate case recorded on the Consolidated Balance Sheets.
Asset Retirement Obligations
The accounting requirements for existing legal obligations associated with the future retirement of long-lived assets require entities to record the fair value of a liability for an ARO in the period during which the liability is incurred. The liability is initially recognized at fair value and is increased with the passage of time as accretion expense is recorded, until the liability is ultimately settled. The accretion expense is included within Operation and maintenance costs withinon 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 810 contains more information regarding the Partnership’sCompany's ARO.
Environmental Liabilities
The PartnershipCompany records environmental liabilities based on management’smanagement'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 46 contains more information regarding the Partnership’sCompany's environmental liabilities.
Defined Benefit Plans
The PartnershipCompany maintains postretirement benefit plans for certain employees. The PartnershipCompany 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 inon 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 inon the Consolidated Statements of Income.
Note 1113 contains more information regarding the Partnership’sCompany's pension and other postretirement benefit obligations.
Long-Term Compensation
Unit-Based
and Other Long-Term Compensation
The PartnershipCompany provides performance awards of phantom common units (Phantom Common Units)(Performance Awards) to certain of its employees under its 2018 Long-Term Incentive Plan (LTIP)(2018 LTIP). The Partnership also provides toA Performance Award is a long-term incentive award with a stated target amount which is payable in cash, after 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.adjustments, upon vesting based on certain specified performance criteria being met.
The PartnershipCompany 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 target amount in the case of the Long-Term Cash Bonuses and amounts under retention payment agreements.for Performance Awards. All outstanding awards are required to be settled in cash and are classified as a liability until settlement. Unit-based compensation awards are remeasured each reporting period until the final amount of awards is determined. 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 1113 contains more information regarding the Partnership’s unit-based and otherCompany's long-term compensation.
Partner Capital Accounts
For purposes of maintaining capital accounts, items of income and loss of the PartnershipCompany are allocated among the partners each period, or portion thereof, in accordance with the partnership agreement, based on their respective ownership interests, after deductinginterests.
Leases
Operating lease right-of-use assets and lease liabilities are recognized at the lease commencement date based on the present value of lease payments over the lease term. The discount rate used to determine the commencement date present value of lease payments is typically the Company's secured borrowing rate, as the implicit rate of most of the Company's leases is not readily determinable. The Company has elected not to record any priority allocationsleases with terms of twelve months or less on the Consolidated Balance Sheets.
Revenue Recognition
Nature of Contracts
The Company primarily earns revenues from contracts with customers by providing transportation and storage services for natural gas and NGLs on a firm and interruptible basis and providing ethane supply and transportation services for industrial customers in Louisiana and Texas. The Company also provides interruptible natural gas PAL services. The Company's customers choose, based upon their particular needs, the applicable mix of services depending upon availability of pipeline and storage capacity, the price of services and the volume and timing of customer requirements. The maximum applicable rates that may be charged by the majority of the Company's operating subsidiaries are established through the FERC's cost-based rate-making process; however, the FERC also allows for discounted or negotiated rates as an alternative to cost-based rates. Under the FERC regulations, certain revenues that the Company's subsidiaries collect may be subject to possible refunds to customers. Accordingly, during a rate case, estimated refund liabilities are recorded considering regulatory proceedings, advice of counsel and estimated risk-adjusted total exposure, as well as other factors. The Company's service contracts can range from one to twenty years although the Company may enter into shorter- or longer-term contracts, and services are invoiced monthly with payment from the customer generally expected within ten to thirty days, depending on the terms of the contract. For the ethane supply contracts, the purchases and sales are with different counterparties and control transfers at different receipt and delivery points, resulting in the purchases and sales being presented on a gross basis in the Consolidated Statements of Income.
Firm Service Contracts: The Company offers firm services to its customers. The Company's customers can reserve a specific amount of pipeline capacity at specified receipt and delivery points on the Company's pipeline system (transportation service) or can reserve a specific amount of storage capacity at specified injection and withdrawal points at the Company's storage facilities (storage service). The Company accounts for firm services as a single promise to stand ready each month of the contract term to provide the committed capacity for either transportation or storage services when needed by the customer, which represents a series of distinct monthly services that are substantially the same with the same pattern of transfer to the customer. Although several activities may be required to provide the firm service, the individual activities do not represent
distinct performance obligations because all of the activities must be performed in combination in order for the Company to provide the firm service.
The transaction price for firm service contracts is comprised of a fixed fee based on the quantity of capacity reserved, regardless of use (capacity reservation fee), plus variable fees in the form of cash distributionsa 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 general partnersingle performance obligation of providing transportation or storage service and recognized over time based upon the output measure of time as the holderCompany completes its stand-ready obligation to provide contracted capacity and the customer receives and consumes the benefit of IDRs.
Recently Issued Accounting Pronouncements
In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update 2014-09, Revenue from Contractsreserved capacity, which corresponds with Customers (Topic 606), (ASC 606) which will require entities to recognize revenue in an amount that reflects the transfer of promised goods orcontrol to the customer. The fixed fee is recognized ratably over the contract term, representative of the proportion of the committed stand-ready capacity obligation that has been fulfilled to date, and the usage fee is recognized upon satisfaction of each distinct monthly performance obligation, consistent with the allocation objective and based upon the level of effort required to satisfy the stand-ready obligation in a given month. Capacity reservation revenues derived from a firm service contract are generally consistent during the contract term, but can be higher in winter periods than the rest of the year based upon seasonal rates.
Interruptible Service Contracts: In providing interruptible services to customers, the Company agrees to transport or store natural gas or NGLs for a customer when capacity is available. The Company does not account for interruptible services with a customer as a contract until the customer nominates for service and the Company accepts the nomination based upon available pipeline or storage capacity or product availability because there are no enforceable rights and obligations until that time. The nomination and acceptance process is a daily activity and acceptance is granted based upon priority of service and availability of capacity and products. Upon acceptance, the Company accounts for interruptible services similarly to its firm services.
The transaction price for interruptible service contracts is comprised of a variable fee in an amountthe form of a usage fee paid on the volume of commodity actually transported or injected and withdrawn from storage. The transaction price is allocated to the single performance obligation of providing interruptible service. Interruptible service revenues for natural gas transportation and storage are generally recognized over time based on the output measure of volume transported or stored when services are rendered upon the successful allocation of the services provided to the customer's account, which best depicts the transfer of control to the customer and satisfaction of the promised service. Interruptible services are recognized in the month services are provided because the Company has a right to consideration from customers in amounts that correspond directly to the entity expectsvalue that the customer receives from the Company's performance. The rates charged may vary on a daily, monthly or seasonal basis.
Minimum Volume Commitment (MVC) Contracts: Certain of the Company's transportation, storage or ethane supply contracts require customers to be entitledtransport, store or purchase a minimum volume of commodity over a specified time period. If a customer fails to meet its MVC for the specified time period, the customer is obligated to pay a contractually-determined deficiency fee based upon the shortfall between the actual volumes transported, stored or purchased and the MVC for that period. MVC contracts are generally similar in exchangenature to a firm service contract where the performance obligation is a stand-ready obligation that is a series of distinct services that are substantially the same with the same pattern of transfer to the customer. The transaction price for those goodsa MVC is a fee for the volume of commodity actually transported, stored or services.delivered, which is allocated to each distinct monthly performance obligation, consistent with the allocation objective and based upon the level of effort required to satisfy the obligation of the transacted activities in a given month. Revenues associated with transportation and storage services are generally recognized over time based on the output measure of volume transported or stored and revenues associated with ethane supply are generally recognized at a point in time based on barrels delivered, with the recognition of the deficiency fee in the period when it is known the customer cannot make up the deficient volume in the specified period.
Other: ASC 606Certain ethane supply contracts include a stated volume that the Company supplies to customers, and any volume requested above the stated volume is based on product availability. Revenues for these ethane supply contracts are generally recognized at a point in time when each barrel is transferred to the customer because the customer is able to direct the use of, and obtain substantially all of the remaining benefits from, the product at that time. Periodically, the Company may also enter into contracts with customers for the sale of natural gas or NGLs. The Company recognizes revenues for these transactions at the point in time of the physical sale of the commodity, which corresponds with the transfer of control of the commodity to the customer and the consideration is measured as the stated sales price in the contract.
Contract Balances
The Company records contract assets primarily related to performance obligations completed but not billed, or partially billed, as of the reporting date. The Company records contract liabilities, or deferred revenue, when payment is received in advance of satisfying its performance obligations.
Note 3: Acquisition
On September 29, 2023, Boardwalk Resources Company, LLC, a wholly owned subsidiary of the Company, acquired 100% of the equity interests of Williams Olefins Pipeline Holdco LLC (Bayou Ethane) from Williams Field Services Group, LLC for $355.0 million in cash, including working capital. Bayou Ethane owns an approximately 380-mile pipeline system that transports ethane from Mont Belvieu, Texas, to the Mississippi River corridor in Louisiana and two 15-mile pipelines in the Houston Ship Channel area that carry ammonia and hydrogen chloride. Bayou Ethane provides ethane supply and transportation services for industrial customers in Louisiana and Texas. In providing ethane supply services, Bayou Ethane purchases ethane at Mont Belvieu and various locations in Louisiana and utilizes its pipeline to deliver supply to its customers. The acquisition allows the Company to extend its assets, diversify its customer base and service offerings and to complement its existing NGLs operations. The purchase price was funded with available cash on hand.
The acquisition was accounted for as a business combination. The purchase price was allocated to the assets acquired and liabilities assumed based on their estimated fair values on the date of acquisition. The fair values for PPE, including rights-of-way, were determined primarily using a combination of the market and cost approaches. The fair values for the customer-based intangibles were determined using a discounted cash flow analysis with inputs not observable in the market, such as estimated future cash flows and weighted-average cost of capital rates, which were considered Level 3 fair value estimates. During the fourth quarter 2023, the purchase price allocation was finalized. The final fair values of the assets acquired and liabilities assumed as of September 29, 2023, the acquisition date, were as follows (in millions):
| | | | | | | | |
Current assets | | $ | 51.8 | |
Property, plant and equipment | | 296.2 | |
Customer-based intangibles (1) | | 33.9 | |
Noncurrent assets | | 0.5 | |
Total assets acquired | | 382.4 | |
Current liabilities | | 26.7 | |
Noncurrent liabilities | | 0.7 | |
Total liabilities assumed | | 27.4 | |
Net assets acquired | | $ | 355.0 | |
(1) also requires disclosures regardingCustomer-based intangibles have a weighted-average useful life of 35 years and are recorded in Other Assets.
For the nature, amount, timingyear ended December 31, 2023, the acquisition contributed $101.5 million and uncertainty of$5.5 million to the Company's operating revenues and cash flowsnet income. The Company incurred an immaterial amount of acquisition costs related to the acquisition for the year ended December 31, 2023. Acquisition costs were expensed as incurred and are recorded in Administrative and general on the Consolidated Statements of Income.
Pro Forma Financial Information(unaudited)
The following unaudited pro forma results of operations are presented as if the acquisition occurred on January 1, 2022. Such results are not necessarily indicative of future results. These pro forma results also do not reflect any cost savings, operating synergies or revenue enhancements that the Company may achieve or the costs necessary to achieve those objectives (in millions):
| | | | | | | | | | | |
| Pro Forma |
| For the Year Ended December 31, |
| 2023 | | 2022 |
Operating revenue (1)(2) | $ | 1,962.8 | | | $ | 2,253.4 | |
Net income (2) | 393.8 | | | 357.4 | |
(1)Bayou Ethane provides ethane supply services, which result in ethane sales and purchases being presented on a gross basis in the Consolidated Statements of Income.
(2)The average ethane price of $0.25 per gallon for the year ended December 31, 2023, was lower as compared to $0.48 per gallon for the comparable period for 2022, which resulted in higher revenues in the 2022 period.
The pro forma information was adjusted for the following items:
•Revenues and operating costs were based on actual results for the periods indicated. Acquisition costs were not material and were excluded; and
•Depreciation and amortization expense was calculated using PPE and intangible asset amounts as determined by the purchase price allocation and estimated useful lives.
Note 4: Revenues
The Company operates in one reportable segment. It contracts directly with end-use customers, including electric power generators, local distribution companies, industrial users and exporters of liquefied natural gas. The Company also contracts with other customers, including producers and marketers of natural gas and interstate and intrastate pipelines, who, in turn, provide transportation and storage services for end-users. The following table presents the Company's revenues disaggregated by type of service (in millions):
| | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, |
| 2023 | | 2022 | | 2021 |
Revenues from Contracts with Customers | | | | | |
Firm Service (1)(3) | $ | 1,489.7 | | | $ | 1,311.9 | | | $ | 1,247.5 | |
Interruptible Service | 51.6 | | | 56.2 | | | 32.0 | |
Other revenues (3) | 40.2 | | | 29.9 | | | 26.1 | |
Total Revenues from Contracts with Customers | 1,581.5 | | | 1,398.0 | | | 1,305.6 | |
Other operating revenues (2)(3) | 36.2 | | | 34.0 | | | 34.5 | |
Total Operating Revenues | $ | 1,617.7 | | | $ | 1,432.0 | | | $ | 1,340.1 | |
(1)Revenues earned from contracts with MVCs are included in firm service given the stand-ready nature of the performance obligation and the guaranteed nature of the fees over the contract term.
(2)Other operating revenues include certain revenues earned from operating leases, pipeline management fees and other activities that are not considered central and ongoing major business operations of the Company and do not represent revenues earned from contracts with customers.
(3)Revenues attributable to Bayou Ethane were $74.9 million in firm service, $25.4 million in other revenues and $1.2 million in other operating revenues for the year ended December 31, 2023.
Contract Balances
As of December 31, 2023 and 2022, the Company had receivables recorded in Trade Receivables, net from contracts with customers of $204.6 million and $148.4 million, contract assets recorded in Other Assets from contracts with a customer of
$6.2 million and $3.3 million, and contract liabilities recorded in Other Current Liabilities (current portion) and Other Liabilities (noncurrent portion) from contracts with customers of $21.4 million and $23.0 million.
As of December 31, 2023, contract liabilities are expected to be recognized through 2040. Significant changes in the contract liability balances during the year ended December 31, 2023, were as follows (in millions):
| | | | | | | | |
| | Contract Liabilities |
Balance as of December 31, 2022(1) | | $ | 23.0 | |
Revenues recognized that were included in the contract liability balances at the beginning of the period | | (3.9) | |
Increases due to cash received, excluding amounts recognized as revenues during the period | | 1.8 | |
Other | | 0.5 | |
Balance as of December 31, 2023(1) | | $ | 21.4 | |
(1)As of December 31, 2023 and 2022, $3.5 million and $3.6 million were recorded in Other Current Liabilities (current portion), and $17.9 million and $19.4 million were recorded in Other Liabilities (noncurrent portion).
Significant changes in the contract liability balances during the year ended December 31, 2022, were as follows (in millions):
| | | | | | | | |
| | Contract Liabilities |
Balance as of December 31, 2021(1) | | $ | 19.2 | |
Revenues recognized that were included in the contract liability balances at the beginning of the period | | (5.1) | |
Increases due to cash received, excluding amounts recognized as revenues during the period | | 8.9 | |
Balance as of December 31, 2022(1) | | $ | 23.0 | |
(1)As of December 31, 2022 and 2021, $3.6 million was recorded in Other Current Liabilities (current portion) and $19.4 million and $15.6 million were recorded in Other Liabilities (noncurrent portion).
Performance Obligations
The Partnership implemented ASC 606 effective January 1, 2018, applying ASC 606following table includes estimated operating revenues expected to customer contracts whichbe recognized in the future related to agreements that contain performance obligations that were not completedunsatisfied as of December 31, 2023. The amounts presented primarily consist of fixed fees or MVCs which are typically recognized over time as the effective date, onperformance obligation is satisfied, in accordance with firm service contracts or guaranteed minimum fees associated with the performance obligation that are satisfied at a modified retrospective basis,point in time under certain ethane supply contracts. For the Company's customers that are charged maximum tariff rates related to its FERC-regulated operating subsidiaries, the amounts below reflect the current tariff rate for such services for the term of the agreements; however, the tariff rates may be subject to future adjustment. The Company has elected to exclude the following from the table: (a) unsatisfied performance obligations from usage fees associated with its firm services because of the variable nature of such services; (b) unsatisfied performance obligations from the ethane commodity indexed portion of the ethane supply contracts because of the variable nature of ethane prices, and (c) consideration in contracts that is recognized in revenue as invoiced, such as for interruptible services. The estimated revenues reflected in the table may include estimated revenues that are anticipated under executed precedent transportation agreements for projects that are subject to regulatory approvals.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | In millions |
| | 2024 | | 2025 | | Thereafter | | Total |
Estimated revenues from contracts with customers from unsatisfied performance obligations as of December 31, 2023 | | $ | 1,362.0 | | | $ | 1,250.0 | | | $ | 6,840.5 | | | $ | 9,452.5 | |
Operating revenues which are fixed and determinable (operating leases) | | 28.0 | | | 27.5 | | | 163.5 | | | 219.0 | |
Total projected operating revenues under committed firm agreements as of December 31, 2023 | | $ | 1,390.0 | | | $ | 1,277.5 | | | $ | 7,004.0 | | | $ | 9,671.5 | |
Note 5:Leases
The Company has various operating lease commitments extending through 2058, generally covering office space and equipment rentals, some of which contain options to renew or extend the lease term. The Company also has a cumulative reduction to partners' capital of $12.8 million. The adjustment to partners' capital as of January 1, 2018, resulted from two items: (i) contracts which had changesfinance lease related to the rates during the service periodlease of an office building in Owensboro, Kentucky, entered into in 2013, that has a fifteen-year term with two twenty-year renewal options.
The components of lease cost were chargedas follows (in millions):
| | | | | | | | | | | | | | | | | | | | |
| | For the Year Ended December 31, |
| | 2023 | | 2022 | | 2021 |
Operating lease cost | | $ | 3.8 | | | $ | 3.8 | | | $ | 4.0 | |
Short-term lease cost | | 4.7 | | | 3.1 | | | 2.9 | |
Finance lease cost: | | | | | | |
Amortization of right-of-use asset | | 0.7 | | | 0.7 | | | 0.7 | |
Interest on lease liability | | 0.3 | | | 0.3 | | | 0.4 | |
Total lease cost | | $ | 9.5 | | | $ | 7.9 | | | $ | 8.0 | |
The following provides supplemental balance sheet information related to the customer without corresponding changes in service levels that were being provided byCompany's leases:
| | | | | | | | | | | | | | | | | |
| As of December 31, |
| 2023 | | 2022 |
Right-of-use assets (in millions) | | | | | |
Operating leases (recorded in Other Assets) | $ | 18.9 | | $ | 18.7 |
Finance lease (recorded in Property, Plant and Equipment) | | 3.2 | | | 4.0 |
Lease liabilities (in millions) | | | | | |
Operating leases (recorded in Other Liabilities, current and non-current) | | 19.6 | | | 20.6 |
Finance lease (recorded in Other Current Liabilities and Long-term debt and finance lease obligation) | | 4.5 | | | 5.4 |
Weighted-average remaining lease term (years) | | | | | |
Operating leases | | 9.9 | | | 10.4 |
Finance lease | | 4.6 | | | 5.6 |
Weighted-average discount rate | | | | | |
Operating leases | | 3.20 | % | | | 2.86 | % |
Finance lease | | 5.89 | % | | | 5.89 | % |
The table below presents the Partnership, and (ii) the de-recognition of gas stored underground available for sale from customers who elected to have fuel retained in-kind because under ASC 606, retained fuel is not considered additional consideration included in the transaction price.
In February 2016, the FASB issued Accounting Standards Update 2016-02, Leases (Topic 842) (ASU 2016-02), which will require, among other things, the recognitionmaturities of lease assets and lease liabilities by lessees for those leases classified as operating leases under current GAAP. The amendments are to be applied at the beginning of the earliest period presented using a modified retrospective approach. ASU 2016-02 is effective for interim and annual reporting periods beginning after December 15, 2018, however, early adoption is permitted. The Partnership has initiated a project to evaluate the impact that ASU 2016-02 will have on its financial statements when implemented, however, no conclusions have been reached.(in millions):
| | | | | | | | | | | |
| As of December 31, 2023 |
| Operating Leases | | Finance Lease |
2024 | $ | 3.7 | | | $ | 1.1 | |
2025 | 2.6 | | | 1.1 | |
2026 | 1.9 | | | 1.1 | |
2027 | 1.3 | | | 1.1 | |
2028 | 0.3 | | | 0.7 | |
Thereafter | 13.3 | | | — | |
Total | 23.1 | | | 5.1 | |
Less: discount | (3.5) | | | (0.6) | |
Total lease liabilities | $ | 19.6 | | | $ | 4.5 | |
Note 3: Asset Disposition and Impairments
On May 9, 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 $63.6 million, including customary adjustments. The Partnership recognized losses and impairment charges, reported within Total operating costs and expenses, of $47.1 million on the sale.
Note 4:6: Commitments and Contingencies
Legal Proceedings and Settlements
The Partnership'sCompany and its subsidiaries are parties to various legal actions arising in the normal course of business. Management believes the disposition of these outstanding legal actions, including the legal actions identified below, will not have a material impact on the Partnership'sCompany's financial condition, results of operations or cash flows.
Southeast Louisiana Flood ProtectionMishal and Berger Litigation
On May 25, 2018, plaintiffs Tsemach Mishal and Paul Berger (on behalf of themselves and the purported class, Plaintiffs) initiated a purported class action in the Court of Chancery of the State of Delaware (the Trial Court) against the following defendants: the Company, Boardwalk GP, LP (Boardwalk GP), Boardwalk GP, LLC and BPHC (together, Defendants), regarding the potential exercise by Boardwalk GP of its right to purchase the issued and outstanding common units of the Company not already owned by Boardwalk GP or its affiliates (Purchase Right).
On June 25, 2018, Plaintiffs and Defendants entered into a Stipulation and Agreement of Compromise and Settlement, subject to the approval of the Trial Court (the Proposed Settlement). Under the terms of the Proposed Settlement, the lawsuit would be dismissed, and related claims against the Defendants would be released by the Plaintiffs, if BPHC, the sole member of the general partner of Boardwalk GP, elected to cause Boardwalk GP to exercise its Purchase Right for a cash purchase price, as determined by the Company's Third Amended and Restated Agreement of Limited Partnership, as amended (the Limited Partnership Agreement), and gave notice of such election as provided in the Limited Partnership Agreement within a period specified by the Proposed Settlement. On June 29, 2018, Boardwalk GP elected to exercise the Purchase Right and gave notice within the period specified by the Proposed Settlement. On July 18, 2018, Boardwalk GP completed the purchase of the Company's common units pursuant to the Purchase Right.
On September 28, 2018, the Trial Court denied approval of the Proposed Settlement. On February 11, 2019, a substitute verified class action complaint was filed in this proceeding, which, among other things, added Loews as a Defendant. The Defendants filed a motion to dismiss, which was heard by the Trial Court in July 2019. In October 2019, the Trial Court ruled on the motion and granted a partial dismissal, with certain aspects of the case proceeding to trial. A trial was held the week of February 22, 2021, and post-trial oral arguments were held on July 14, 2021.
On November 12, 2021, the Trial Court issued a ruling in the case. The Trial Court held that Boardwalk GP breached the Limited Partnership Agreement and found that Boardwalk GP is liable to the Plaintiffs for approximately $690.0 million in damages, plus pre-judgment interest (approximately $166.0 million), post-judgment interest and attorneys' fees. The Trial Court's ruling and damages award was against Boardwalk GP, and not the Company or its subsidiaries.
The PartnershipDefendants believed that the Trial Court ruling included factual and its subsidiary, legal errors. Therefore, on January 3, 2022, the Defendants appealed the Trial Court's ruling to the Supreme Court of the State of Delaware (the Supreme Court). On January 17, 2022, the Plaintiffs filed a cross-appeal to the Supreme Court contesting the calculation of damages by the Trial Court. Oral arguments were held on September 14, 2022, and on December 19, 2022, the Supreme Court reversed the Trial
Court's ruling and remanded the case to the Trial Court for further proceedings related to claims not decided by the Trial Court's ruling. Briefing by the parties at the Trial Court on the remanded issues was completed in September 2023. A hearing on the remanded issues is scheduled at the Trial Court in April 2024.
City of New Orleans Litigation
Gulf South, along with approximately 100several other energy companies operating in Southern Louisiana, havehas been named as defendantsa defendant in a petition for damages and injunctive relief in state district court for Orleans Parish, Louisiana, (Case No. 13-6911)19-3466) by the BoardCity of Commissioners of the Southeast Louisiana Flood Protection Authority - East (Flood Protection Authority).New Orleans. The case was filed in state court, but was removed to the U.S. District Court for the Eastern District of New Orleans (Court) in August 2013.on March 29, 2019. The lawsuit claims includedinclude, among other things, negligence, strict liability, public nuisance private nuisance,and breach of contract, and breach of the natural servitude of drain against the defendants, alleging that the defendants’defendants' drilling, dredging, pipeline and industrial operations since the 1930s have caused increased storm surge risk, increased flood protection costs and unspecified damages to the Flood Protection Authority.City of New Orleans. In addition to attorney fees and unspecified monetary damages,October 2020, this case was stayed pending the lawsuit sought abatement and restorationoutcome of the coastal lands, including backfilling and revegetating of canals dredged and used by the defendants, and abatement and restoration activities such as wetlands creation, reef creation, land bridge construction, hydrologic restoration, shoreline protection, structural protection, bank stabilization and ridge restoration. On February 13, 2015, the Court dismissed the case with prejudice. The Flood Protection Authority appealed the dismissal of the casea consolidated appeal to the U.S.Fifth Circuit Court of Appeals forin a similar case. On August 5, 2021, the Fifth Circuit in May 2015 (Case No. 15-CV-30162). On March 3, 2017, the U.S. Court of Appeals forruled in favor of the oil-and-gas defendants in that consolidated appeal, finding that the two cases being appealed should be re-examined in federal district court since they involve operations that were federally overseen at the time. The ruling reverses a previous decision that allowed the cases to be heard in state court, which the plaintiffs had sought. As a result of the Fifth Circuit upheldCourt of Appeals' decision, it is anticipated that this case will be reviewed in federal district court to determine whether the Court’s dismissal. On April 12, 2017,case should be heard in that court.
Gulf South and Texas Gas have been named as defendants in several suits in the Fifth Circuit deniedState of Louisiana that are similar in nature to the Flood Protection Authorities' Petition for Rehearing En Banc. On July 11, 2017, the plaintiffsCity of New Orleans Litigation discussed above. These cases were filed a writ of certiorari with the United States Supreme Courtin Louisiana state courts and are advancing to review the case. On October 30, 2017, the United States Supreme Court denied a rehearing of the case.
Settlements and Insurance Proceeds
discovery.
For the year ended December 31, 2016, the Partnership received $12.7 million in cash from the settlement of a legal claim which was recorded in
Transportation revenues.
For the year ended December 31, 2015, the Partnership received $8.8 million in insurance proceeds from a business interruption claim related to Louisiana Midstream, which was recorded in Transportation revenues.
Environmental and Safety Matters
The Company's operating subsidiaries are subject to federal, state, and local environmental laws and regulations in connection with the operation and remediation of various operating sites. As of December 31, 20172023 and 2016,2022, the PartnershipCompany had an accrued liability of approximately $5.0$10.1 million and $3.0 million related to assessment and/or remediation costs associated with the historical use of polychlorinated biphenyls, petroleum hydrocarbons and mercury. The liability represents management’smanagement'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 fourthirty years. As of December 31, 20172023 and 2022, approximately $6.7 million and $1.3 million were recorded in Other Current Liabilities and 2016, approximately $1.2$3.4 million and $1.7 million were recorded in Other current liabilities and approximately $3.8 million and $3.3 million were recorded in Other Liabilities and Deferred Credits.
Clean Air Act and Climate Change
The Partnership’sCompany's pipelines and associated facilities are subject to the federal Clean Air Act as amended, (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 PartnershipCompany 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’sCompany's projects. Over the next several years, the PartnershipCompany 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. TheSince that time, the EPA published a final rule in November 2017 that issued area designations of either “attainment/unclassifiable” or “unclassifiable” with respect to ground-level
ozone, issued final requirements that apply to state, local and tribal air agencies for approximately 85%implementing the 2015 NAAQS for ground-level ozone and, on December 31, 2020, published notice of a final action to retain the 2015 ozone NAAQS without revision on a going-forward basis. However, several groups filed litigation over the December 2020 final action and in October 2021, the EPA announced that it would reconsider the December 2020 determination to maintain the November 2015 NAAQS. In August 2023, the EPA announced a new review of the U.S. countiesozone NAAQS to ensure the standards protect people’s health and reflect the most current, relevant science. The new review will incorporate the reconsideration of the December 2020 final action. Until a final decision following the review is expected to issue final non-attainment area requirements pursuant to this NAAQS rule byreleased, the second quarter 2018.full extent of the impacts of any new standards are not clear. States are also expected to implement more stringent regulations that could apply to the Partnership'sCompany's operations. Compliance with thisany final ruledecision could, among other things, require installation orof new emission controls on some of the Partnership'sCompany's equipment, result in longer permitting timelines and significantly increase its capital expenditures and operating costs. Additionally, the threat of climate change continues to attract considerable public, governmental and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at
the international, national, regional, state and local levels of government to monitor and limit emissions of greenhouse gases (GHGs). These efforts have included consideration of cap-and-trade programs, carbon taxes, and GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. The EPA has determined that greenhouse gas (GHG)GHG emissions endanger public health and the environment because emissions of such gases are potentially contributing to warming of the earth’s atmosphere and, other climatic changes. Based on these findings, the EPAas 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, 2017, 2016 and 2015, was approximately $13.8 million, $13.2 million and $12.2 million. The following table summarizes minimum future commitments related to these items at December 31, 2017 (in millions):
|
| | | |
2018 | $ | 4.3 |
|
2019 | 4.3 |
|
2020 | 4.2 |
|
2021 | 4.0 |
|
2022 | 4.0 |
|
Thereafter | 5.6 |
|
Total | $ | 26.4 |
|
Commitments for Construction
The Partnership’sCompany'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 asAs of December 31, 2017,2023, the commitments were approximately $171.2$134.2 million, all of which are expected to be settled within the next twelve months.
Pipeline Capacity and Storage Agreements
The Partnership’sCompany's operating subsidiaries have entered into pipeline capacity and storage agreements with third-party pipelines that allow the operating subsidiaries to transport gas to off-system markets on behalf of customers.customers or store natural gas. Additionally, in connection with the Bayou Ethane acquisition, the Company has assumed a pipeline capacity agreement with a third party to facilitate the transportation of ethane and an ethane storage agreement. The PartnershipCompany incurred expenses of $6.2$5.8 million, $6.5$3.2 million and $6.9$7.7 million related to pipeline capacity and storage agreements for the years ended December 31, 2017, 20162023, 2022 and 2015.2021. The table below presents the future commitments related to pipeline capacitythese agreements as of December 31, 2017, were2023 (in millions):
|
| | | |
2018 | $ | 6.3 |
|
2019 | 5.5 |
|
2020 | 2.9 |
|
2021 | 1.7 |
|
2022 | 1.3 |
|
Thereafter | — |
|
Total | $ | 17.7 |
|
| | | | | |
2024 | $ | 7.9 | |
2025 | 8.0 | |
2026 | 8.0 | |
2027 | 3.2 | |
2028 | 0.1 | |
Thereafter | — | |
Total | $ | 27.2 | |
Note 5: Other Comprehensive Income and7: Fair Value Measurements
Other Comprehensive Income
The Partnership estimates that approximately $2.8 million of net losses reported in AOCI as of
December 31, 2017, are expected to be reclassified into earnings within the next twelve months. This amount is comprised of a $1.6 million decrease to earnings related to net periodic benefit cost and a $1.2 million decrease to earnings 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. The following table shows the components and reclassifications to net income of Accumulated other comprehensive loss which is included in Partners' Capital for the years ended December 31, 2015 through 2017 (in millions):
|
| | | | | | | | | | | |
| Cash Flow Hedges | | Pension and Other Postretirement Costs | | Total |
Beginning balance, January 1, 2015 | $ | (10.8 | ) | | $ | (62.0 | ) | | $ | (72.8 | ) |
Reclassifications: Interest expense (1) | 2.4 |
| | — |
| | 2.4 |
|
Pension and other postretirement benefit costs | — |
| | (13.9 | ) | | (13.9 | ) |
Ending balance, December 31, 2015 | $ | (8.4 | ) | | $ | (75.9 | ) | | $ | (84.3 | ) |
Reclassifications: Interest expense (1) | 2.4 |
| | — |
| | 2.4 |
|
Pension and other postretirement benefit costs | — |
| | 1.8 |
| | 1.8 |
|
Ending balance, December 31, 2016 | $ | (6.0 | ) | | $ | (74.1 | ) | | $ | (80.1 | ) |
Loss recorded in AOCI | (1.5 | ) | | — |
| | (1.5 | ) |
Reclassifications: Interest expense (1) | 2.5 |
| | — |
| | 2.5 |
|
Pension and other postretirement benefit costs | — |
| | (1.9 | ) | | (1.9 | ) |
Ending balance, December 31, 2017 | $ | (5.0 | ) | | $ | (76.0 | ) | | $ | (81.0 | ) |
| |
(1) | Related to amounts deferred in AOCI from the treasury rate locks described above. |
Financial Assets and Liabilities
As of December 31, 2017 and 2016, the PartnershipThe Company had no assets and liabilities which wereequity securities recorded at fair value on a recurring basis. basis in Other Current Assets of $2.3 million and $3.0 million as of December 31, 2023 and 2022. The equity securities were received as part of a settlement of a bankruptcy claim. The equity securities were valued based on quoted market prices at December 31, 2023 and 2022, and were considered Level 1 investments. The Company had no liabilities recorded at fair value on a recurring basis as of December 31, 2023 and 2022.
Financial Assets and Liabilities Not Measured at Fair Value
The following methods and assumptions were used in estimating the fair value amounts included in the disclosures for financial assets and liabilities:
Cash and Cash Equivalents: For cash and short-term financial assets, the carrying amount is a reasonable estimate of fair value due to the short maturity of those instruments.
Long-Term Debt: The estimated fair value of the Partnership'sCompany's publicly traded debt is based on quoted market prices at December 31, 20172023 and 2016.2022. The fair market value of the debt that is not publicly traded is based on market prices of similar debt at December 31, 20172023 and 2016.2022. The carrying amount of the Partnership'sCompany's variable-rate debt approximatesat December 31, 2023, approximated fair value because the instruments bear a floating market-based interest rate.
The carrying amounts and estimated fair values of the Partnership'sCompany's financial assets and liabilities which were not recorded at fair value on the Consolidated Balance Sheets as of December 31, 20172023 and 2016,2022, were as follows (in millions):
|
| | | | | | | | | | | | | | | | | | | | |
As of December 31, 2017 | | | | Estimated Fair Value |
Financial Assets | | Carrying Amount | | Level 1 | | Level 2 | | Level 3 | | Total |
Cash and cash equivalents | | $ | 17.6 |
| | $ | 17.6 |
| | $ | — |
| | $ | — |
| | $ | 17.6 |
|
| | | | | | | | | | |
Financial Liabilities | | | | | | | | | | | | | | | |
Long-term debt | | $ | 3,687.5 |
| (1) | $ | — |
| | $ | 3,889.4 |
| | $ | — |
| | $ | 3,889.4 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
As of December 31, 2023 | | | | Estimated Fair Value |
Financial Assets | | Carrying Amount | | Level 1 | | Level 2 | | Level 3 | | Total |
Cash and cash equivalents | | $ | 20.1 | | | $ | 20.1 | | | $ | — | | | $ | — | | | $ | 20.1 | |
| | | | | | | | | | |
Financial Liabilities | | | | | | | | | | |
Long-term debt | | $ | 3,262.4 | | (1) | $ | — | | | $ | 3,155.3 | | | $ | — | | | $ | 3,155.3 | |
(1) The carrying amount of long-term debt excludes an $8.1excluded a $3.6 million long-term capitalfinance lease obligation and
$8.84.1 million of unamortized debt issuance costs.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
As of December 31, 2022 | | | | Estimated Fair Value |
Financial Assets | | Carrying Amount | | Level 1 | | Level 2 | | Level 3 | | Total |
Cash and cash equivalents | | $ | 215.6 | | | $ | 215.6 | | | $ | — | | | $ | — | | | $ | 215.6 | |
| | | | | | | | | | |
Financial Liabilities | | | | | | | | | | |
Long-term debt | | $ | 3,234.0 | | (1) | $ | — | | | $ | 3,041.4 | | | $ | — | | | $ | 3,041.4 | |
|
| | | | | | | | | | | | | | | | | | | | |
As of December 31, 2016 | | | | Estimated Fair Value |
Financial Assets | | Carrying Amount | | Level 1 | | Level 2 | | Level 3 | | Total |
Cash and cash equivalents | | $ | 4.6 |
| | $ | 4.6 |
| | $ | — |
| | $ | — |
| | $ | 4.6 |
|
| | | | | | | | | | |
Financial Liabilities | | | | | | | | | | | |
Long-term debt | | $ | 3,558.9 |
| (1) | $ | — |
| | $ | 3,709.2 |
| | $ | — |
| | $ | 3,709.2 |
|
(1) The carrying amount of long-term debt excludes an $8.6excluded a $4.5 million long-term capitalfinance lease obligation and
$9.55.1 million of unamortized debt issuance costs.
Note 6: 8: Property, Plant and Equipment
The following table presents the Partnership’sCompany's PPE as of December 31, 20172023 and 20162022 (in millions):
|
| | | | | | | | | | | | |
Category | | 2017 Amount | | Weighted-Average Useful Lives (Years) | | 2016 Amount | | Weighted-Average Useful Lives (Years) |
Depreciable plant: | | | | | | | | |
Transmission | | $ | 9,115.4 |
| | 38 | | $ | 8,337.1 |
| | 38 |
Storage | | 776.7 |
| | 38 | | 779.2 |
| | 38 |
Gathering | | 109.2 |
| | 23 | | 385.2 |
| | 28 |
General | | 196.7 |
| | 13 | | 194.2 |
| | 13 |
Rights of way and other | | 127.6 |
| | 36 | | 125.7 |
| | 36 |
Total utility depreciable plant | | 10,325.6 |
| | 37 | | 9,821.4 |
| | 37 |
| | | | | | | | |
Non-depreciable: | | |
| |
| | |
| | |
Construction work in progress | | 416.5 |
| | | | 368.5 |
| | |
Storage | | 105.5 |
| | | | 105.5 |
| | |
Land | | 36.0 |
| | | | 31.9 |
| | |
Total non-depreciable assets | | 558.0 |
| | | | 505.9 |
| | |
| | | | | | | | |
Total PPE | | 10,883.6 |
| | | | 10,327.3 |
| | |
Less: accumulated depreciation | | 2,621.1 |
| | | | 2,333.8 |
| | |
| | | | | | | | |
Total PPE, net | | $ | 8,262.5 |
| | | | $ | 7,993.5 |
| | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Category | | 2023 Amount | | 2023 Weighted-Average Useful Lives (Years) | | 2022 Amount | | 2022 Weighted-Average Useful Lives (Years) |
Depreciable plant: | | | | | | | | |
Transmission | | $ | 11,405.4 | | | 38 | | $ | 10,913.0 | | | 38 |
Storage | | 951.3 | | | 39 | | 921.9 | | | 38 |
Gathering | | 106.1 | | | 24 | | 111.1 | | | 24 |
General, intangibles and other | | 535.4 | | | 20 | | 473.0 | | | 21 |
Total utility depreciable plant | | 12,998.2 | | | 37 | | 12,419.0 | | | 37 |
| | | | | | | | |
Non-depreciable: | | | | | | | | |
Construction work in progress | | 287.2 | | | | | 187.6 | | | |
Storage | | 197.5 | | | | | 151.6 | | | |
Land | | 46.6 | | | | | 46.1 | | | |
Total non-depreciable assets | | 531.3 | | | | | 385.3 | | | |
| | | | | | | | |
Total PPE, gross | | 13,529.5 | | | | | 12,804.3 | | | |
Less: accumulated depreciation and amortization | | 4,672.9 | | | | | 4,288.3 | | | |
| | | | | | | | |
Total PPE, net | | $ | 8,856.6 | | | | | $ | 8,516.0 | | | |
The non-depreciable assets were not included in the calculation of the weighted-average useful lives.
For the years ended December 31, 2023, 2022 and 2021, depreciation expense for PPE was $406.5 million, $390.4 million and $364.4 million and was recorded in Depreciation and amortization on the Consolidated Statements of Income.
The PartnershipCompany holds undivided interests in certain assets, including the Bistineau storage facility of which the Partnership owns 92%, the Mobile Bay Pipeline, of which the PartnershipCompany owns 64%, and offshore and other assets, comprised of pipeline and gathering assets in which the PartnershipCompany holds various ownership interests. In addition, the PartnershipCompany owns 83% of two ethylene wells and supporting surface facilities in Choctaw, Louisiana, and certain ethylene and propylene pipelines connecting Louisiana Midstream’sMidstream's storage facilities in Choctaw to chemical manufacturing plants in Geismar, Louisiana.
The proportionate share of investment associated with these interests has been recorded as PPE on the balance sheets.Consolidated Balance Sheets. The PartnershipCompany records its portion of direct operating expenses associated with the assets in Operation and maintenance expense. expense. The following table presents the gross PPE investment and related accumulated depreciation for the Partnership’sCompany's undivided interests as of December 31, 20172023 and 20162022 (in millions):
|
| | | | | | | | | | | | | | | |
| 2017 | | 2016 |
| Gross PPE Investment | | Accumulated Depreciation | | Gross PPE Investment | | Accumulated Depreciation |
Bistineau storage | $ | 75.5 |
| | $ | 24.0 |
| | $ | 73.6 |
| | $ | 21.8 |
|
Mobile Bay Pipeline | 13.2 |
| | 5.8 |
| | 13.3 |
| | 5.4 |
|
NGL pipelines and facilities | 34.8 |
| | 5.2 |
| | 34.8 |
| | 4.2 |
|
Offshore and other assets | 16.2 |
| | 12.7 |
| | 15.1 |
| | 11.8 |
|
Total | $ | 139.7 |
| | $ | 47.7 |
| | $ | 136.8 |
| | $ | 43.2 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| 2023 | | 2022 |
| Gross PPE Investment | | Accumulated Depreciation | | Gross PPE Investment | | Accumulated Depreciation |
Mobile Bay Pipeline | $ | 15.4 | | | $ | 8.3 | | | $ | 15.4 | | | $ | 7.9 | |
NGLs pipelines and facilities | 54.6 | | | 13.5 | | | 54.4 | | | 12.0 | |
Offshore and other assets | 13.0 | | | 10.9 | | | 13.0 | | | 10.6 | |
Total | $ | 83.0 | | | $ | 32.7 | | | $ | 82.8 | | | $ | 30.5 | |
Asset Impairment ChargesImpairments
The PartnershipCompany recognized $5.8 million, $3.8 million and $0.4 million of asset impairment charges of $0.4 million and $7.5 million for the years ended December 31, 2017, 20162023 and 2015. A portion of the2022, and immaterial asset impairment charges for the year ended December 31, 2021. The 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 2016 were primarily due to materials and supplies inventory that were determined to be obsolete and the remainder of the charges in 2017 and the charges in 20152022 were primarily due to an increase in the estimate of AROexisting AROs related to assets havingretired assets.
Base Gas Reclassification
In September 2022, Gulf South, a wholly owned subsidiary of the Company, submitted an application with the FERC seeking authorization to reclassify 13.5 billion cubic feet of working gas as additional base gas. The reclassification was necessary to reflect changing operational needs and was supported, among other things, by an operational study of certain storage assets. In the first quarter 2023, the FERC comment period closed with no protests. As of March 31, 2023, as a result of the operational need for the base gas, Gulf South reclassified the carrying amount.
amount of approximately $47.8 million of natural gas to Property, Plant and Equipment, of which $40.9 million had been recorded in Gas Stored Underground within Current Assets, and $6.9 million had been recorded in Gas Stored Underground within Other Assets. The application was approved by the FERC in April 2023.
Note 7: 9: Goodwill and Intangible Assets
Goodwill
As of December 31, 20172023 and 2016,2022, the PartnershipCompany had recorded in itson the Consolidated Balance Sheets $237.4 million of goodwill.
The PartnershipCompany performed its annual goodwill impairment test for its tworeporting units asas of November 30, 2017.2023 and 2022. The results of the quantitative goodwill impairment test indicated that the fair value of the Partnership’sCompany's reporting units significantly exceeded their carrying amounts. The fair value measurement of the reporting units was derived based on judgments and assumptions the Company believes market participants would use in assessing the fair value of the reporting units. These judgments and assumptions included the valuation premise, use of a discounted cash flow model to estimate fair value under an income approach and inputs to the valuation model. The inputs included the Company's five-year financial plan operating results, including operating revenues, the long-term outlook for growth in natural gas and NGLs demand, measures of the risk-free rate, equity premium and systematic risk used in the calculation of the applied discount rate under the capital asset pricing model and views regarding future market conditions, among others. The reasonableness of fair value estimates under the income approach were supported by a market approach under which the Company applied earnings before interest, income taxes, depreciation and amortization (EBITDA) multiples derived from publicly-available information to each reporting unit's EBITDA.
No impairment chargecharges related to goodwill waswere recorded for any of the Partnership’sCompany's reporting units during 2017, 20162023, 2022 or 2015.2021.
Intangible Assets
The following table contains information regarding the Partnership'sCompany's intangible assets, which includes customer relationships acquired as part of its acquisitions (in millions):
| | | | | | | | | | | |
| As of December 31, |
| 2023 | | 2022 |
Gross carrying amount (1) | $ | 93.3 | | | $ | 59.4 | |
Accumulated amortization | (21.3) | | | (19.1) | |
Net carrying amount | $ | 72.0 | | | $ | 40.3 | |
|
| | | | | | | |
| December 31, |
| 2017 | | 2016 |
Gross carrying amount | $ | 59.4 |
| | $ | 59.4 |
|
Accumulated amortization | (9.5 | ) | | (7.5 | ) |
Net carrying amount | $ | 49.9 |
| | $ | 51.9 |
|
| | | |