Document and Entity Information
Document and Entity Information Document - USD ($) | 12 Months Ended | |
Dec. 31, 2018 | Feb. 21, 2019 | |
Entity Information [Line Items] | ||
Entity Registrant Name | Transcontinental Gas Pipe Line Company, LLC | |
Entity Central Index Key | 99,250 | |
Document Type | 10-K | |
Document Period End Date | Dec. 31, 2018 | |
Amendment Flag | false | |
Document Fiscal Year Focus | 2,018 | |
Document Fiscal Period Focus | FY | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Non-accelerated Filer | |
Entity Shell Company | false | |
Entity Small Business | false | |
Entity Emerging Growth Company | false | |
Entity Common Stock, Shares Outstanding | 0 | |
Entity Well-known Seasoned Issuer | No | |
Entity Voluntary Filers | No | |
Entity Current Reporting Status | Yes | |
Entity Public Float | $ 0 |
Consolidated Statement of Compr
Consolidated Statement of Comprehensive Income - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Revenues [Abstract] | |||
Natural gas sales | $ 127,821 | $ 99,100 | $ 86,720 |
Natural gas transportation | 1,784,794 | 1,531,778 | 1,397,341 |
Natural gas storage | 136,666 | 137,348 | 122,555 |
Other | 10,600 | 6,779 | 9,519 |
Total operating revenues | 2,059,881 | 1,775,005 | 1,616,135 |
Operating Costs and Expenses: | |||
Cost of natural gas sales | 127,821 | 99,100 | 86,720 |
Cost of natural gas transportation | 38,749 | 19,589 | 19,689 |
Operation and maintenance | 399,293 | 401,871 | 316,989 |
Administrative and general | 189,588 | 182,121 | 168,759 |
Depreciation and amortization | 366,566 | 318,058 | 307,707 |
Taxes - other than income taxes | 67,537 | 65,612 | 60,119 |
Regulatory charge (credit) resulting from Tax Reform (Note 1) | (20,867) | 471,096 | 0 |
Other expense, net | 64,918 | 63,644 | 57,064 |
Total operating costs and expenses | 1,233,605 | 1,621,091 | 1,017,047 |
Operating Income | 826,276 | 153,914 | 599,088 |
Other (Income) and Other Expenses: | |||
Interest expense - affiliate | 60 | 60 | 60 |
Interest expense - other | 218,126 | 158,814 | 151,234 |
Interest income - affiliate | (7,606) | (3,507) | (2,201) |
Interest income - other | (3,448) | (2,782) | (2,185) |
Allowance for equity and borrowed funds used during construction (AFUDC) | (116,347) | (92,013) | (68,964) |
Equity in (earnings) loss of unconsolidated affiliates | (1,068) | 6,188 | (5,914) |
Miscellaneous other (income) expenses, net | (4,520) | 31,426 | 3,683 |
Total other (income) and other expenses | 85,197 | 98,186 | 75,713 |
Net Income | 741,079 | 55,728 | 523,375 |
Other comprehensive income: | |||
Equity interest in unrealized gain on interest rate hedges (includes $(143), $103, and $167 for the years ended December 31, 2018, 2017, and 2016, respectively, of accumulated other comprehensive income reclassification for equity interest in realized losses (gains) on interest rate hedges) | 197 | 327 | 41 |
Comprehensive Income | $ 741,276 | $ 56,055 | $ 523,416 |
Consolidated Statement of Com_2
Consolidated Statement of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Income Statement [Abstract] | |||
Accumulated other comprehensive income reclassification for realized losses (gains) on interest rate hedges | $ (143) | $ 103 | $ 167 |
Consolidated Balance Sheet
Consolidated Balance Sheet - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Current Assets: | ||
Cash | $ 0 | $ 0 |
Receivables: | ||
Trade | 190,833 | 167,928 |
Affiliates | 1,018 | 1,109 |
Advances to affiliate | 33,034 | 395,247 |
Other | 10,365 | 2,494 |
Transportation and exchange gas receivables | 4,515 | 3,205 |
Inventories: | ||
Gas in storage, at original cost | 875 | 790 |
Gas available for customer nomination, at average cost | 25,767 | 1,850 |
Materials and supplies, at average cost | 36,563 | 37,387 |
Regulatory assets | 95,770 | 97,149 |
Other | 12,574 | 12,508 |
Total current assets | 411,314 | 719,667 |
Investments, at cost plus equity in undistributed earnings | 26,520 | 28,505 |
Property, Plant and Equipment: | ||
Natural gas transmission plant | 15,908,878 | 13,771,183 |
Less-Accumulated depreciation and amortization | 4,147,729 | 3,859,520 |
Total property, plant and equipment, net | 11,761,149 | 9,911,663 |
Other Assets: | ||
Regulatory assets | 289,479 | 276,315 |
Other | 167,490 | 141,786 |
Total other assets | 456,969 | 418,101 |
Total assets | 12,655,952 | 11,077,936 |
Payables: | ||
Trade | 201,350 | 444,021 |
Affiliates | 50,727 | 43,420 |
Cash overdrafts | 25,561 | 25,132 |
Transportation and exchange gas payables | 5,973 | 2,121 |
Accrued liabilities: | ||
Property and other taxes | 15,428 | 12,843 |
Interest | 62,066 | 49,900 |
Regulatory liabilities | 5,097 | 16,350 |
Customer deposits | 36,400 | 15,754 |
Customer advances | 36,642 | 44,689 |
Asset retirement obligations | 45,714 | 13,676 |
Other | 22,134 | 20,390 |
Long-term debt due within one year | 15,419 | 251,430 |
Total current liabilities | 522,511 | 939,726 |
Long-Term Debt | 3,998,988 | 2,191,576 |
Other Long-Term Liabilities: | ||
Asset retirement obligations | 348,609 | 350,280 |
Regulatory liabilities | 1,026,892 | 990,702 |
Advances for construction costs | 211 | 426,771 |
Deferred revenue | 226,164 | 236,729 |
Other | 3,977 | 4,828 |
Total other long-term liabilities | 1,605,853 | 2,009,310 |
Contingent Liabilities and Commitments (Note 3) | ||
Member's Equity: | ||
Member's capital | 4,428,499 | 4,088,499 |
Retained earnings | 2,099,567 | 1,848,488 |
Accumulated other comprehensive income | 534 | 337 |
Total member's equity | 6,528,600 | 5,937,324 |
Total liabilities and member's equity | $ 12,655,952 | $ 11,077,936 |
Consolidated Statement of Membe
Consolidated Statement of Member's Equity Consolidated Statement of Member's Equity - USD ($) $ in Thousands | Total | Member's Capital | Retained Earnings | Accumulated Other Comprehensive Income (Loss) |
Balance at beginning of period at Dec. 31, 2015 | $ 3,176,499 | $ 2,379,385 | $ (31) | |
Cash contributions from parent | $ 502,000 | 502,000 | ||
Net income | 523,375 | 523,375 | ||
Cash distributions to parent | (440,000) | (440,000) | ||
Equity interest in unrealized gain on interest rate hedge | 41 | 41 | ||
Noncash distribution to Parent | 0 | |||
Balance at end of period at Dec. 31, 2016 | 6,141,269 | 3,678,499 | 2,462,760 | 10 |
Cash contributions from parent | 410,000 | 410,000 | ||
Net income | 55,728 | 55,728 | ||
Cash distributions to parent | (430,000) | (430,000) | ||
Equity interest in unrealized gain on interest rate hedge | 327 | 327 | ||
Noncash distribution to Parent | 240,000 | |||
Balance at end of period at Dec. 31, 2017 | 5,937,324 | 4,088,499 | 1,848,488 | 337 |
Cash contributions from parent | 340,000 | 340,000 | ||
Net income | 741,079 | 741,079 | ||
Cash distributions to parent | (490,000) | (490,000) | ||
Equity interest in unrealized gain on interest rate hedge | 197 | 197 | ||
Noncash distribution to Parent | 0 | |||
Balance at end of period at Dec. 31, 2018 | $ 6,528,600 | $ 4,428,499 | $ 2,099,567 | $ 534 |
Consolidated Statement of Cash
Consolidated Statement of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Cash flows from operating activities: | |||
Net income | $ 741,079 | $ 55,728 | $ 523,375 |
Adjustments to reconcile net income to net cash provided by operating activities: | |||
Depreciation and amortization | 366,566 | 318,058 | 307,707 |
Allowance for equity funds used during construction (equity AFUDC) | (87,111) | (69,653) | (56,468) |
Regulatory charge (credit) resulting from Tax Reform (Note 1) | (20,867) | 471,096 | 0 |
Equity in (earnings) loss of unconsolidated affiliates | (1,068) | 6,188 | (5,914) |
Distributions from unconsolidated affiliates | 3,250 | 8,036 | 8,631 |
Changes in operating assets and liabilities: | |||
Receivables - affiliates | 91 | (620) | 595 |
Receivables - trade and other | (30,776) | (26,107) | 5,941 |
Transportation and exchange gas receivable | (1,310) | (1,378) | 600 |
Regulatory assets - current | 1,379 | (10,090) | (7,484) |
Regulatory assets - non-current | (8,605) | (10,761) | (271) |
Inventories | (23,178) | 15,182 | 1,632 |
Payables - affiliates | 7,307 | 12,514 | (10,909) |
Payables - trade | (35,869) | (9,823) | 29,375 |
Accrued liabilities | 29,740 | (29,651) | 74,759 |
Asset retirement obligations - non-current | 34,075 | 103,105 | 31,114 |
Asset retirement obligation - removal costs | (9,416) | (4,578) | (4,911) |
Deferred Revenue | (10,565) | (4,542) | 0 |
Other, net | 21,570 | 4,117 | 32,080 |
Net cash provided by operating activities | 976,292 | 826,821 | 929,852 |
Cash flows from financing activities: | |||
Proceeds from long-term debt | 993,440 | 0 | 998,250 |
Proceeds from other financing obligations | 50,269 | 0 | 0 |
Retirement of long-term debt | (250,000) | 0 | (200,000) |
Payments on other financing obligations | (3,705) | (486) | 0 |
Payments of debt issuance costs | (10,148) | (13) | (8,381) |
Cash distributions to parent | (490,000) | (430,000) | (440,000) |
Cash contributions from parent | 340,000 | 410,000 | 502,000 |
Net cash provided by (used in) financing activities | 629,856 | (20,499) | 851,869 |
Cash flows from investing activities: | |||
Property, plant and equipment additions, net of equity AFUDC | (2,326,672) | (1,576,611) | (1,213,969) |
Contributions and advances for construction costs | 408,912 | 425,397 | 216,447 |
Disposal of property, plant and equipment, net | (26,469) | (49,090) | (12,529) |
Advances to affiliate, net | 362,213 | 416,446 | (747,085) |
Purchase of ARO Trust investments | (51,793) | (57,099) | (70,901) |
Proceeds from sale of ARO Trust investments | 27,661 | 31,435 | 44,195 |
Proceeds from insurance | 0 | 3,200 | 2,121 |
Net cash used in investing activities | (1,606,148) | (806,322) | (1,781,721) |
Increase (decrease) in cash | 0 | 0 | 0 |
Cash at beginning of period | 0 | 0 | 0 |
Cash at end of period | 0 | 0 | 0 |
Increase to property, plant and equipment, net of equity AFUDC | (2,085,888) | (1,784,254) | (1,200,696) |
Changes in related accounts payable and accrued liabilities | (240,784) | 207,643 | (13,273) |
Property, plant and equipment additions, net of equity AFUDC | (2,326,672) | (1,576,611) | (1,213,969) |
Supplemental Cash Flow Elements [Abstract] | |||
Interest (exclusive of amount capitalized) | 168,418 | 136,439 | 103,391 |
Income taxes | $ 632 | $ 2,089 | $ 828 |
Revenue Recognition (Notes)
Revenue Recognition (Notes) | 12 Months Ended |
Dec. 31, 2018 | |
Revenue Recognition [Abstract] | |
Revenue from Contract with Customer [Text Block] | 2. REVENUE RECOGNITION Revenue by Category Our revenue disaggregation by major service line includes Natural gas sales , Natural gas transportation , Natural gas storage , and Other , which are separately presented on the Consolidated Statement of Comprehensive Income. Contract Liabilities The following table presents a reconciliation of our contract liabilities: December 31, 2018 (Thousands) Balance at beginning of period $ 247,296 Payments received and deferred — Recognized in revenue (10,566 ) Balance at end of period $ 236,730 The following table presents the amount of the contract liabilities balance as of December 31, 2018 , expected to be recognized as revenue in each of the next five years as performance obligations are expected to be satisfied: (Thousands) 2019 $ 10,566 2020 10,568 2021 10,566 2022 10,566 2023 10,566 Thereafter 183,898 Remaining Performance Obligations The following table presents the transaction price allocated to the remaining performance obligations under certain contracts as of December 31, 2018 . These primarily include reservation charges on contracted capacity on our firm transportation and storage contracts with customers. Amounts from certain contracts included in the table below, which are subject to the periodic review and approval by the FERC, reflect the rates for such services in our current FERC tariffs for the life of the related contracts; however, these rates may change based on future tariffs approved by the FERC and the amount and timing of these changes is not currently known. As a practical expedient permitted by ASC 606, this table excludes the variable consideration component for commodity charges. It also excludes consideration that will be recognized in future periods (see above for Contract Liabilities and the expected recognition of those amounts within revenue). As noted above, certain of our contracts contain evergreen provisions for periods beyond the initial term of the contract. The remaining performance obligation as of December 31, 2018 , does not consider potential future performance obligations for which the renewal has not been exercised. The table below also does not include contracts with customers for which the underlying facilities have not received FERC authorization to be placed into service. (Thousands) 2019 $ 2,085,113 2020 1,956,772 2021 1,881,776 2022 1,520,358 2023 1,386,290 Thereafter 12,501,777 Total $ 21,332,086 Accounts Receivable Receivables from contracts with customers are included within Receivables - Trade and Receivables - Affiliates and receivables that are not related to contracts with customers are included with Receivables - Advances to affiliate and Receivables - Other in our Consolidated Balance Sheet. |
Summary of Significant Accounti
Summary of Significant Accounting Policies (Notes) | 12 Months Ended |
Dec. 31, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Summary of Significant Accounting Policies | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Corporate Structure and Control In this report, Transco (which includes Transcontinental Gas Pipe Line Company, LLC and, unless the context otherwise requires, all of our majority-owned subsidiaries) is at times referred to in the first person as “we,” “us” or “our.” Transco was indirectly owned by Williams Partners L.P. (WPZ), a publicly traded Delaware limited partnership, which was consolidated by The Williams Companies, Inc. (Williams). On August 10, 2018, Williams completed a merger with WPZ, pursuant to which Williams acquired all of the publicly held outstanding common units of WPZ in exchange for shares of Williams' common stock (WPZ Merger). Williams continued as the surviving entity. Transco is now indirectly owned by Williams. Transco is a single member limited liability company, and as such, single member losses are limited to the amount of its investment. Related Party Transaction A former member of Williams' Board of Directors, who was elected in 2013 and resigned during 2016, is also the current chairman, president, and chief executive officer of Public Service Enterprise Group, an energy services company that is a customers of ours. This board member does not have any material interest in any transactions between the energy services company and us and he had no role in any such transactions. Nature of Operations We are an interstate natural gas transmission company that owns a natural gas pipeline system extending from Texas, Louisiana, Mississippi and the Gulf of Mexico through Alabama, Georgia, South Carolina, North Carolina, Virginia, Maryland, Delaware, Pennsylvania and New Jersey to the New York City metropolitan area. The system serves customers in Texas and the 12 southeast and Atlantic seaboard states mentioned above, including major metropolitan areas in Georgia, Washington D.C., Maryland, North Carolina, New York, New Jersey and Pennsylvania. Regulatory Accounting We are regulated by the Federal Energy Regulatory Commission (FERC). The Accounting Standards Codification (ASC) Regulated Operations (Topic 980), provides that rate-regulated public utilities account for and report regulatory assets and liabilities consistent with the economic effect of the way in which regulators establish rates if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. Accounting for businesses that are regulated and apply the provisions of Topic 980 can differ from the accounting requirements for non-regulated businesses. Transactions that are recorded differently as a result of regulatory accounting requirements include the capitalization of an equity return component on regulated capital projects, capitalization of other project costs, retirements of general plant assets, employee related benefits, environmental costs, negative salvage, asset retirement obligations (ARO), and other costs and taxes included in, or expected to be included in, future rates. As a rate-regulated entity, our management has determined that it is appropriate to apply the accounting prescribed by Topic 980 and, accordingly, the accompanying consolidated financial statements include the effects of the types of transactions described above that result from regulatory accounting requirements. In December 2017, the Tax Cuts and Jobs Act (Tax Reform) was enacted, which, among other things, reduced the federal corporate income tax rate from 35 percent to 21 percent. We have recognized a regulatory liability to reflect the probable return to certain customers through future rates of the future decrease in income taxes payable associated with Tax Reform. In determining the estimated liability that we currently believe is probable of return to certain customers through future rates, we considered the mix of services provided by us, taking into consideration that certain of these services are provided under contractually based rates, in lieu of recourse-based rates, that are designed to recover the cost of providing those services, with no expected future rate adjustment for the term of those contracts. The liability was recorded in December 2017 through a regulatory charge to operating income of $471.1 million, this regulatory charge was reduced by $20.9 million in 2018 mostly due to an updated weighted average state income tax rate. The timing and actual amount of such return will be subject to future negotiations regarding this matter and many other elements of cost-of-service rate proceedings, including other costs of providing service. Certain of our equity-method investees recorded similar regulatory liabilities, for which our Equity in (earnings) loss of unconsolidated affiliates on our Consolidated Statement of Comprehensive Income has been reduced by $2.0 and $10.3 million in 2018 and 2017, respectively, related to our proportionate share of the associated regulatory charges. Our regulatory asset associated with the effects of deferred taxes on equity funds used during construction was also impacted by Tax Reform and was reduced by $0.9 million and $32.7 million in 2018 and 2017, respectively, through a charge to Miscellaneous other (income) expenses, net on our Consolidated Statement of Comprehensive Income. Basis of Presentation Williams’ acquisition of Transco Energy Company and its subsidiaries, including us, in 1995 was accounted for using the purchase method of accounting. Accordingly, an allocation of the purchase price was assigned to our assets and liabilities based on their estimated fair values. The purchase price allocation to us primarily consisted of a $1.5 billion allocation to property, plant and equipment and adjustments to deferred taxes based upon the book basis of the net assets recorded as a result of the acquisition. The amount allocated to property, plant and equipment is being depreciated on a straight-line basis over 40 years, the estimated useful lives of these assets at the date of acquisition, at approximately $35 million per year. At December 31, 2018 , the remaining property, plant and equipment allocation was approximately $0.6 billion. Current FERC policy does not permit us to recover through rates amounts in excess of original cost. Principles of Consolidation The consolidated financial statements include our accounts and the accounts of the subsidiaries we control. Companies in which we and our subsidiaries own 20 percent to 50 percent of the voting common stock or otherwise exercise significant influence over operating and financial policies of the company are accounted for under the equity method. The equity method investments as of December 31, 2018 and December 31, 2017 consist of Cardinal Pipeline Company, LLC (Cardinal) with ownership interest of approximately 45 percent and Pine Needle LNG Company, LLC (Pine Needle) with ownership interest of 35 percent. We received distributions associated with our equity method investments totaling $3.2 million, $8.0 million, and $8.6 million in 2018 , 2017 and 2016 , respectively. Use of Estimates The preparation of financial statements in conformity with U.S. generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates and assumptions which, in the opinion of management, are significant to the underlying amounts included in the financial statements and for which it would be reasonably possible that future events or information could change those estimates include: 1) revenues subject to refund; 2) litigation-related contingencies; 3) environmental remediation obligations; 4) impairment assessments of long-lived assets; 5) depreciation; 6) asset retirement obligations; and 7) regulatory deferred taxes. Revenue Recognition (subsequent to the adoption of ASC 606) Our customers are comprised of public utilities, municipalities, gas marketers and producers, intrastate pipelines, direct industrial users, and electrical power generators. A performance obligation is a promise in a contract to transfer a distinct good or service (or integrated package of goods or services) to the customer. A contract’s transaction price is allocated to each distinct performance obligation and recognized as revenue, when, or as, the performance obligation is satisfied. A performance obligation is distinct if the product or service is separately identifiable from other items in the integrated package of services and if a customer can benefit from it on its own or with other resources that are readily available to the customer. Service revenue contracts contain a series of distinct services, with the majority of our contracts having a single performance obligation that is satisfied over time as the customer simultaneously receives and consumes the benefits provided by our performance. Most of our product sales contracts have a single performance obligation with revenue recognized at a point in time when the products have been sold and delivered to the customer. Certain customers reimburse us for costs we incur associated with construction of property, plant, and equipment utilized in our operations. As a rate-regulated entity applying Topic 980, we follow FERC guidelines with respect to reimbursement of construction costs. FERC tariffs only allow for cost reimbursement and are non-negotiable in nature; thus, in our judgment, the construction activities do not represent an ongoing major and central operation of our gas pipelines business and are not within the scope of Accounting Standards Update (ASU) 2014-09, Revenues from Contracts with Customers (ASC 606). Accordingly, cost reimbursements are treated as a reduction to the cost of the constructed asset. Service Revenues We are subject to regulation by certain state and federal authorities, including the FERC, with revenue derived from both firm and interruptible transportation and storage contracts. Firm transportation and storage agreements provide for a fixed reservation charge based on the pipeline or storage capacity reserved, and a commodity charge based on the volume of natural gas delivered/stored, each at rates specified in our FERC tariffs or as negotiated with our customers, with contract terms that are generally long-term in nature. Most of our long-term contracts contain an evergreen provision, which allows the contracts to be extended for periods primarily up to one year in length an indefinite number of times following the specified contract term and until terminated generally by either us or the customer. Interruptible transportation and storage agreements provide for a volumetric charge based on actual commodity transportation or storage utilized in the period in which those services are provided, and the contracts are generally limited to one month periods or less. Our performance obligations include the following: • Firm transportation or storage under firm transportation and storage contracts - an integrated package of services typically constituting a single performance obligation, which includes standing ready to provide such services and receiving, transporting or storing (as applicable), and redelivering commodities; • Interruptible transportation and storage under interruptible transportation and storage contracts - an integrated package of services typically constituting a single performance obligation once scheduled, which includes receiving, transporting or storing (as applicable), and redelivering commodities. In situations where, in our judgment, we consider the integrated package of services as a single performance obligation, which represents a majority of our contracts with customers, we do not consider there to be multiple performance obligations because the nature of the overall promise in the contract is to stand ready (with regard to firm transportation and storage contracts), receive, transport or store, and redeliver natural gas to the customer; therefore, revenue is recognized over time upon satisfaction of our daily stand ready performance obligation. We recognize revenues for reservation charges over the performance obligation period, which is the contract term, regardless of the volume of natural gas that is transported or stored. Revenues for commodity charges from both firm and interruptible transportation services and storage services are recognized when natural gas is delivered at the agreed upon delivery point or when natural gas is injected or withdrawn from the storage facility because they specifically relate to our efforts to provide these distinct services. Generally, reservation charges and commodity charges are recognized as revenue in the same period they are invoiced to our customers. As a result of the ratemaking process, certain amounts collected by us may be subject to refunds upon the issuance of final orders by the FERC in pending rate proceedings. We use judgment to record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel, and other risks. Product Sales In the course of providing transportation services to customers, we may receive different quantities of natural gas from customers than the quantities delivered on behalf of those customers. The resulting imbalances are primarily settled through the purchase or sale of natural gas with each customer under terms provided for in our FERC tariffs. Revenue is recognized from the sale of natural gas upon settlement of the transportation and exchange imbalances (See Gas Imbalances in this Note). Contract Liabilities Our contract liabilities consist of advance payments from customers, which include prepayments, and other billings for which future services are to be provided under the contract. These amounts are deferred until recognized in revenue when the associated performance obligation has been satisfied, which is primarily straight-line over the remaining contractual service periods, and are classified as current or non-current according to when such amounts are expected to be recognized. Current and non-current contract liabilities are included within Accrued Liabilities and Other Long-Term Liabilities - Deferred revenue , respectively, in our Consolidated Balance Sheet. Contracts requiring advance payments and the recognition of contract liabilities are evaluated to determine whether the advance payments provide us with a significant financing benefit. This determination is based on the combined effect of the expected length of time between when we transfer the promised good or service to the customer and when the customer pays for those goods or services and the prevailing interest rates. We have assessed our contracts and determined none of our contracts contain a significant financing component. Revenue Recognition (prior to the adoption of ASC 606) Revenues for transportation of gas under long-term firm agreements are recognized considering separately the reservation and commodity charges. Reservation revenues are recognized monthly over the term of the agreement regardless of the volume of natural gas transported. Commodity revenues from both firm and interruptible transportation are recognized in the period transportation services are provided based on volumes of natural gas physically delivered at the agreed upon delivery point. Revenues for the storage of gas under firm agreements are recognized considering separately the reservation, capacity, and injection and withdrawal charges. Reservation and capacity revenues are recognized monthly over the term of the agreement regardless of the volume of storage service actually utilized. Injection and withdrawal revenues are recognized in the period when volumes of natural gas are physically injected into or withdrawn from storage. In the course of providing transportation services to customers, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. The resulting imbalances are primarily settled through the purchase and sale of gas with our customers under terms provided in our FERC tariff. Revenue is recognized from the sale of gas upon settlement of the transportation and exchange imbalances (See Gas Imbalances in this Note). As a result of the ratemaking process, certain revenues collected by us may be subject to refunds upon the issuance of final orders by the FERC in pending rate proceedings. We record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel and other risks. Environmental Matters We are subject to federal, state, and local environmental laws and regulations. Environmental expenditures are expensed or capitalized depending on their economic benefit and potential for rate recovery. We believe that any expenditures required to meet applicable environmental laws and regulations are prudently incurred in the ordinary course of business and such expenditures would be permitted to be recovered through rates. Property, Plant and Equipment Property, plant and equipment is recorded at cost. The carrying values of these assets are also based on estimates, assumptions and judgments relative to capitalized costs, useful lives and salvage values. These estimates, assumptions and judgments reflect FERC regulations, as well as historical experience and expectations regarding future industry conditions and operations. The FERC identifies installation, construction and replacement costs that are to be capitalized. All other costs are expensed as incurred. Gains or losses from the ordinary sale or retirement of property, plant and equipment are credited or charged to accumulated depreciation; certain other gains or losses are recorded in operating income. We provide for depreciation under the composite (group) method at straight-line FERC prescribed rates that are applied to the cost of the group for transmission facilities, production and gathering facilities and storage facilities. Under this method, assets with similar lives and characteristics are grouped and depreciated as one asset. Included in our depreciation rates is a negative salvage component (net cost of removal) that we currently collect in rates. Our depreciation rates are subject to change each time we file a general rate case with the FERC. Depreciation rates used for major regulated gas plant facilities at December 31, 2018 , 2017 and 2016 are as follows: Category of Property 2018-2016 Gathering facilities 1.35% - 2.50% Storage facilities 2.10% - 2.25% Onshore transmission facilities 2.61% - 5.00% Offshore transmission facilities 1.20% - 1.20% We record a liability and increase the basis in the underlying asset for the present value of each expected future ARO at the time the liability is initially incurred, typically when the asset is acquired or constructed. Measurements of AROs include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market-risk premium. The ARO asset is depreciated in a manner consistent with the expected timing of the future abandonment of the underlying physical assets. We measure changes in the liability due to passage of time by applying an interest method of allocation. The depreciation of the ARO asset and accretion of the ARO liability are recognized as an increase to a regulatory asset, as management expects to recover such amounts in future rates. The regulatory asset is amortized commensurate with our collection of these costs in rates. Impairment of Long-lived Assets We evaluate the long lived assets of identifiable business activities for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. When an indicator of a potential impairment has occurred we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred. We apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes including selling in the near term or holding for the remaining estimated useful life. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value. For assets identified to be disposed of in the future and considered held for sale in accordance with the ASC Property, Plant, and Equipment (Topic 360), we compare the carrying value to the estimated fair value less the cost to sell to determine if recognition of an impairment is required. Until the assets are disposed of, the estimated fair value, which includes estimated cash flows from operations until the assumed date of sale, is recalculated when related events or circumstances change. Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows used to determine recoverability of an asset and the estimate of an asset’s fair value used to calculate the amount of impairment to recognize. Allowance for Funds Used During Construction Allowance for funds used during construction (AFUDC) represents the estimated cost of borrowed and equity funds applicable to utility plant in process of construction and are included as a cost of property, plant and equipment because it constitutes an actual cost of construction under established regulatory practices. The FERC has prescribed a formula to be used in computing separate allowances for borrowed and equity AFUDC. The allowance for borrowed funds used during construction was $29.2 million, $22.3 million and $12.5 million, for 2018 , 2017 and 2016 , respectively. The allowance for equity funds was $87.1 million, $69.7 million, and $56.5 million, for 2018 , 2017 and 2016 , respectively. Income Taxes We are a natural gas company organized as a pass-through entity and our taxable income or loss is consolidated on the federal income tax return of our parent, Williams. We generally are treated as a pass-through entity for state and local income tax purposes, and those taxes are generally borne on a consolidated basis by Williams. Net income for financial statement purposes may differ significantly from taxable income of Williams as a result of differences between the tax basis and financial reporting basis of assets and liabilities. Accounts Receivable and Allowance for Doubtful Receivables Accounts receivable are stated at the historical carrying amount net of reserves or write-offs. We do not offer extended payment terms and typically receive payment within one month. We consider receivables past due if full payment is not received by the contractual due date. Our credit risk exposure in the event of nonperformance by the other parties is limited to the face value of the receivables. We perform ongoing credit evaluations of our customers’ financial condition and require collateral from our customers, if necessary. Due to our customer base, we have not historically experienced recurring credit losses in connection with our receivables. Receivables determined to be uncollectible are reserved or written off in the period of determination. Gas Imbalances In the course of providing transportation services to customers, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. Additionally, we transport gas on various pipeline systems which may deliver different quantities of gas on behalf of us than the quantities of gas received from us. These transactions result in gas transportation and exchange imbalance receivables and payables which are recovered or repaid in cash or through the receipt or delivery of gas in the future and are recorded in the accompanying Consolidated Balance Sheet. Settlement of imbalances requires agreement between the pipelines and shippers as to allocations of volumes to specific transportation contracts and timing of delivery of gas based on operational conditions. Our tariff includes a method whereby most transportation imbalances are settled on a monthly basis. Each month a portion of the imbalances are not identified to specific parties and remain unsettled. These are generally identified to specific parties and settled in subsequent periods. We believe that amounts that remain unidentified to specific parties and unsettled at year end are valid balances that will be settled with no material adverse effect upon our financial position, results of operations or cash flows. Management has implemented a policy of continuing to carry any unidentified transportation and exchange imbalances on the books for a three-year period. At the end of the three year period a final assessment will be made of their continued validity. Absent a valid reason for maintaining the imbalance, any remaining balance will be recognized in income. Certain imbalances are being recovered or repaid in cash or through the receipt or delivery of gas upon agreement of the parties as to the allocation of the gas volumes, and as permitted by pipeline operating conditions. These imbalances have been classified as current assets and current liabilities at December 31, 2018 and 2017. We utilize the average cost method of accounting for gas imbalances. Deferred Cash Out Most transportation imbalances are settled in cash on a monthly basis (cash-out). In accordance with our tariff, revenues received from the cash-out of transportation imbalances in excess of costs incurred are deferred and offset by the deferral of costs incurred in excess of revenues received. At the end of each annual August through July reporting period, if the cumulative revenues received exceed the costs incurred, the over recovered amounts are refunded. If the cumulative revenues received are less than the costs incurred, the net under recovered amounts are carried forward and offset against any future net over recoveries that may occur in a subsequent annual reporting period. Gas Inventory We utilize the last-in, first-out (LIFO) method of accounting for inventory gas in storage. At December 31, 2018 and 2017, Gas in Storage, at LIFO, was zero. The basis for determining current cost at the end of each year is the December monthly average gas price delivered to pipelines in Texas and Louisiana. We utilize the average cost method of accounting for gas available for customer nomination. Liquefied natural gas in storage is valued at original cost. Materials and Supplies Inventory All inventories are stated at average cost. We perform an annual review of Materials and Supplies inventories, including a quarterly analysis of parts that may no longer be useful due to planned replacements of compressor engines and other components on our system. Based on this assessment, we record a reserve for the value of the inventory which can no longer be used for maintenance and repairs on our pipeline. There was a minimal reserve at December 31, 2018 and 2017. Contingent Liabilities We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss is probable and the amount of the loss can be reasonably estimated. These liabilities are calculated based upon our assumptions and estimates with respect to the likelihood or amount of loss and upon advice of legal counsel, engineers, or other third parties regarding the probable outcomes of the matters. These calculations are made without consideration of any potential recovery from third-parties. We recognize insurance recoveries or reimbursements from others when realizable. Revisions to these liabilities are generally reflected in income when new or different facts or information become known or circumstances change that affect the previous assumptions or estimates. Pension and Other Postretirement Benefits We do not have employees. Certain of the costs charged to us by Williams associated with employees who directly support us include costs related to Williams’ pension and other postretirement benefit plans. (See Note 7.) Although the underlying benefit plans of Williams are single-employer plans, we follow multiemployer plan accounting whereby the amount charged to us and thus paid by us, is based on our share of net periodic benefit cost. Cash Flows from Operating Activities and Cash Equivalents We use the indirect method to report cash flows from operating activities, which requires adjustments to net income to reconcile to net cash flows provided by operating activities. We include short-term, highly-liquid investments that have an original maturity of three months or less as cash equivalents. Accounting Standards Issued and Adopted Effective January 1, 2018, we adopted Accounting Standards Update (ASU) 2016-15 “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments” (ASU 2016-15). Among other things, ASU 2016-15 permits an accounting policy election to classify distributions received from equity-method investees using either the cumulative earnings approach or the nature of distribution approach. We have elected to apply the nature of distribution approach and have retrospectively conformed the prior year presentation within the Consolidated Statement of Cash Flows in accordance with ASU 2016-15. For the periods ended December 31, 2017 and December 31, 2016, amounts previously presented as Return of capital from unconsolidated affiliates within Investing Activities are now presented as part of Distributions from unconsolidated affiliates within Operating Activities , resulting in an increase to Net cash provided by operating activities of $3.9 million and $2.8 million, respectively, with a corresponding reduction in Net cash used in investing activities . In May 2014, the Financial Accounting Standards Board (FASB) issued ASU 2014-09 establishing Accounting Standards Codification (ASC) Topic 606, “Revenue from Contracts with Customers” (ASC 606). ASC 606 establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to be entitled to receive in exchange for those goods or services and requires significantly enhanced revenue disclosures. In August 2015, the FASB issued ASU 2015-14 “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date” (ASU 2015-14). Per ASU 2015-14, the standard became effective for interim and annual reporting periods beginning after December 15, 2017. We adopted the provisions of ASC 606 effective January 1, 2018, utilizing the modified retrospective transition method for all contracts with customers, which included applying the provisions of ASC 606 beginning January 1, 2018, to all contracts not completed as of that date. There was no cumulative effect adjustment to retained earnings upon initially applying ASC 606 for periods prior to January 1, 2018. For each revenue contract type, we conducted a formal contract review process to evaluate the impact of ASC 606. As a result of the adoption of ASC 606, there are no changes to the timing of our revenue recognition or differences in the presentation in our consolidated financial statements from those under the previous revenue standard. (See Note 2.) Accounting Standards Issued But Not Yet Adopted In June 2016, the FASB issued ASU 2016-13 "Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments" (ASU 2016-13). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments. For trade and other receivables, held-to-maturity debt securities, loans, and other instruments, entities will be required to use a new forward-looking "expected loss" model that generally will result in the earlier recognition of allowances for losses. The guidance also requires increased disclosures. ASU 2016-13 is effective for interim and annual periods beginning after December 15, 2019. Early adoption is permitted. The standard requires varying transition methods for the different categories of amendments. We do not expect ASU 2016-13 to have a significant impact on our financial s |
Contingent Liabilities and Comm
Contingent Liabilities and Commitments (Notes) | 12 Months Ended |
Dec. 31, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
Contingent Liabilities and Commitments | CONTINGENT LIABILITIES AND COMMITMENTS Rate Matters General rate case (Docket No. RP18-1126) On August 31, 2018, we filed a general rate case with the FERC for an overall increase in rates and to comply with the terms of the settlement in our prior rate case to file a rate case no later than August 31, 2018. On September 28, 2018, the FERC issued an order accepting and suspending our general rate filing to be effective March 1, 2019, subject to refund and the outcome of a hearing, except that rates for certain services that were proposed as overall rate decreases were accepted, without suspension, to be effective October 1, 2018. The decreased rates will not be subject to refund but may be subject to decrease prospectively under Section 5 of the Natural Gas Act of 1938, as amended. Income tax matters On March 15, 2018, the FERC issued a revised policy statement (the March 15 Statement) in Docket No. PL17-1 regarding the recovery of income tax costs in rates of natural gas pipelines. The FERC found that an impermissible double recovery results from granting a Master Limited Partnership (MLP) pipeline both an income tax allowance and a return on equity pursuant to the discounted cash flow methodology. As a result, the FERC will no longer permit a MLP pipeline to recover an income tax allowance in its cost of service. The FERC further stated it will address the application of this policy to non-MLP partnership forms as those issues arise in subsequent proceedings. One of the benefits of the WPZ Merger is to allow us to continue to recover an income tax allowance in our cost of service rates. On July 18, 2018, the FERC issued an order dismissing the requests for rehearing and clarification of the revised policy statement. In addition, the FERC provided guidance that an MLP pipeline (or other pass-through entity) no longer recovering an income tax allowance pursuant to the revised policy may eliminate previously accumulated deferred income taxes (ADIT) from its cost of service instead of flowing these previously accumulated ADIT balances to ratepayers. This guidance, if implemented, would significantly mitigate the impact of the March 15 Statement. However, the FERC stated that the revised policy statement and such guidance do not establish a binding rule, but are instead expressions of general policy intent designed to provide guidance by notifying entities of the course of action the FERC intends to follow in future adjudications. To the extent the FERC addresses these issues in future proceedings, it will consider any arguments regarding not only the application of the revised policy to the fact of the case, but also any arguments regarding the underlying validity of the policy itself. The FERC's guidance on ADIT likely will be challenged by customers and state commission, which would result in a long period of revenue uncertainty for pipelines eliminating ADIT from their cost of service. The WPZ Merger has the additional benefit of eliminating this uncertainty. On March 15, 2018, the FERC also issued a Notice of Proposed Rulemaking in Docket No. RM18-11 proposing a filing process that will allow it to determine which natural gas pipelines may be collecting unjust and unreasonable rates in light of the reduction in the corporate income tax rate in Tax Reform and the revised policy statement. On July 18, 2018, the FERC issued a Final Rule in the docket, retaining the filing requirement and reaffirming the options that pipelines have to either reflect the reduced tax rate or explain why no rate change is necessary. FERC also clarified that a natural gas company organized as a pass-through entity all of whose income or losses are consolidated on the federal income tax return of its corporate parent is considered to be subject to the federal corporate income tax, and is thus eligible for a tax allowance. We believe this Final Rule and the previously discussed WPZ Merger allow for the continued recovery of income tax allowances in our rates. Our Docket No. RP18-1126 rate case filing (discussed above) reflects a tax allowance based on this clarification, and the FERC's September 28, 2018 order in that rate case proceeding finds that we are exempt from the FERC Form No. 501-G filing requirement established in Docket No. RM18-11. On March 15, 2018, the FERC also issued a Notice of Inquiry in Docket No. RM18-12 seeking comments on the additional impacts of Tax Reform on jurisdictional rates, particularly whether, and if so how, the FERC should address changes relating to ADIT amounts after the corporate income tax rate reduction and bonus depreciation rules, as well as whether other features of Tax Reform require FERC action. We are evaluating the impact of these developments and currently expect any associated impacts would be prospective and determined through subsequent rate proceedings. We also continue to monitor developments that may impact our regulatory liabilities resulting from Tax Reform. It is reasonably possible that our future tariff-based rates collected may be adversely impacted. Station 62 Incident On October 8, 2015, an explosion and fire occurred at our Compressor Station No. 62 in Gibson, Louisiana. At the time of the incident, planned facility maintenance was being performed at the station and the facility was not operational. The incident was related to maintenance work being performed on the slug catcher at the station. Four contractor employees were killed in the incident and others were injured. In responding to the incident, we cooperated with local, state and federal authorities, including the Louisiana State Police, Terrebonne Parish, the Louisiana Department of Environmental Quality, the U.S. Environmental Protection Agency (Region 6), the Occupational Safety and Health Administration, and the U.S. Department of Transportation's Pipeline and Hazardous Materials Safety Administration (PHMSA). On July 29, 2016, PHMSA issued a Notice of Probable Violation (NOPV), which includes a $1.6 million proposed civil penalty to us in connection with the incident. This penalty was accrued in the second quarter of 2016 and would not be covered by our insurance policies. We filed a response to the NOPV on August 25, 2016, and on July 14, 2017, PHMSA held a hearing on the NOPV. On December 20, 2018, the PHMSA issued a Final Order, which made findings of violation, reduced the civil penalty to $1.4 million, and specified actions that need to be taken by us to comply with pipeline safety regulations. The incident did not cause any rupture of the gas pipeline or any damage to the building containing the compressor engines. In anticipation of the planned maintenance, our Southeast Louisiana Lateral was taken out of service on October 4, 2015, which affected approximately 200 MMcf/d of natural gas production. The lateral was restored to service in early 2016 after repairs were made to the facilities damaged in the incident. We, with the insurer of one of our contractors, have settled several claims against us for wrongful death and personal injury. In addition, we are a defendant in other lawsuits seeking damages for wrongful death, personal injury and property damages. We believe it is reasonably possible that losses will be incurred on some lawsuits. However, in management's judgment, the ultimate resolution of these matters will not have a material effect on our financial condition, results of operations or cash flows. While we also have claims for indemnification, we continue to believe that it is probable that any ultimate losses incurred will be covered by our contractors' insurance and our insurance. Environmental Matters We have had studies underway for many years to test some of our facilities for the presence of toxic and hazardous substances such as polychlorinated biphenyls (PCBs) and mercury to determine to what extent, if any, remediation may be necessary. We have also similarly evaluated past on-site disposal of hydrocarbons at a number of our facilities. We have worked closely with and responded to data requests from the U.S. Environmental Protection Agency (EPA) and state agencies regarding such potential contamination of certain of our sites. On the basis of the findings to date, we estimate that environmental assessment and remediation costs under various federal and state statutes will total approximately $5 million to $7 million (including both expense and capital expenditures), measured on an undiscounted basis, and will substantially be spent over the next four to six years. This estimate depends on a number of assumptions concerning the scope of remediation that will be required at certain locations and the cost of the remedial measures. We are conducting environmental assessments and implementing a variety of remedial measures that may result in increases or decreases in the total estimated costs. At December 31, 2018, we had a balance of approximately $3.5 million for the expense portion of these estimated costs, $1.5 million recorded in Accrued liabilities and $2.0 million recorded in Other Long-Term Liabilities - Other in the Consolidated Balance Sheet. At December 31, 2017 , we had a balance of approximately $4.0 million for the expense portion of these estimated costs, $1.8 million recorded in Accrued liabilities and $2.2 million recorded in Other Long-Term Liabilities - Other in the Consolidated Balance Sheet. We have been identified as a potentially responsible party (PRP) at various Superfund and state waste disposal sites. Based on present volumetric estimates and other factors, our estimated aggregate exposure for remediation of these sites is less than $0.5 million. The estimated remediation costs for all of these sites are included in the $5 million to $7 million range discussed above. Liability under the Comprehensive Environmental Response, Compensation and Liability Act and applicable state law can be joint and several with other PRPs. Although volumetric allocation is a factor in assessing liability, it is not necessarily determinative; thus, the ultimate liability could be substantially greater than the amounts described above. The EPA and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules. These rulemakings include, but are not limited to, rules for reciprocating internal combustion engine maximum achievable control technology, air quality standards for one-hour nitrogen dioxide emissions, and volatile organic compound and methane new source performance standards impacting design and operation of storage vessels, pressure valves, and compressors. The EPA previously issued its rule regarding National Ambient Air Quality Standards for ground-level ozone. We are monitoring the rule’s implementation as it will trigger additional federal and state regulatory actions that may impact our operations. Implementation of the regulations is expected to result in impacts to our operations and increase the cost of additions to Total property, plant and equipment, net in the Consolidated Balance Sheet for both new and existing facilities in affected areas. We are unable to reasonably estimate the cost of additions that may be required to meet the regulations at this time due to uncertainty created by various legal challenges to these regulations and the need for further specific regulatory guidance. We consider prudently incurred environmental assessment and remediation costs and the costs associated with compliance with environmental standards to be recoverable through rates. To date, we have been permitted recovery of environmental costs, and it is our intent to continue seeking recovery of such costs through future rate filings. Other Matters Various other proceedings are pending against us and are considered incidental to our operations. Summary We estimate that for all matters for which we are able to reasonably estimate a range of loss, including those noted above and others that are not individually significant, our aggregate reasonably possible losses beyond amounts accrued for all of our contingent liabilities are immaterial to our expected future annual results of operations, liquidity and financial position. These calculations have been made without consideration of any potential recovery from third parties. We have disclosed all significant matters for which we are unable to reasonably estimate a range of possible loss. Other Commitments Commitments for construction We have commitments for construction and acquisition of property, plant and equipment of approximately $137 million at December 31, 2018 . |
Debt, Financing Arrangements an
Debt, Financing Arrangements and Leases (Notes) | 12 Months Ended |
Dec. 31, 2018 | |
Debt Disclosure [Abstract] | |
Debt, Financing Arrangements and Leases | DEBT, FINANCING ARRANGEMENTS AND LEASES Long-Term Debt At December 31, 2018 and 2017 , long-term debt outstanding was as follows (in thousands): 2018 2017 Debentures: 7.08% due 2026 $ 7,500 $ 7,500 7.25% due 2026 200,000 200,000 Total debentures 207,500 207,500 Notes: 6.05% due 2018 — 250,000 7.85% due 2026 1,000,000 1,000,000 4.0% due 2028 400,000 — 5.4% due 2041 375,000 375,000 4.45% due 2042 400,000 400,000 4.6% due 2048 600,000 — Total notes 2,775,000 2,025,000 Other financing obligation 1,067,286 230,926 Total long-term debt, including current portion 4,049,786 2,463,426 Unamortized debt issuance costs (24,242 ) (15,377 ) Unamortized debt premium and discount, net (11,137 ) (5,043 ) Long-term debt due within one year (15,419 ) (251,430 ) Total long-term debt $ 3,998,988 $ 2,191,576 Aggregate minimum maturities (face value) applicable to long-term debt outstanding at December 31, 2018 , for the next five years, are as follows (in thousands): 2019: Other financing obligation $ 15,419 2020: Other financing obligation $ 17,042 2021: Other financing obligation $ 18,837 2022: Other financing obligation $ 20,821 2023: Other financing obligation $ 23,014 No property is pledged as collateral under any of our long-term debt issues. Restrictive Debt Covenants At December 31, 2018 , none of our debt instruments restrict the amount of distributions to our parent, provided, however, that under the credit facility described below, we are restricted from making distributions to our parent during an event of default if we have directly incurred indebtedness under the credit facility. Our debt agreements contain restrictions on our ability to incur secured debt beyond certain levels and to guarantee certain indebtedness. The indenture governing our $1 billion of 7.85 percent Senior Notes due 2026 further restricts our ability to guarantee certain indebtedness. Issuance and Retirement of Long-Term Debt On March 15, 2018, we issued $400 million of 4.0 percent senior unsecured notes due 2028 and $600 million of 4.6 percent senior unsecured notes due 2048 to investors in a private debt placement. We used the net proceeds to repay indebtedness, including our $250 million of 6.05 percent senior unsecured notes due 2018 upon their maturity on June 15, 2018, and for general corporate purposes, including the funding of capital expenditures. The notes were issued under an Indenture, dated as of March 15, 2018 between us and The Bank of New York Mellon Trust Company, N.A., as trustee. As part of the issuance, we entered into a registration rights agreement with the initial purchasers of the notes. Under the terms of the agreement, we were obligated to file and consummate a registration statement for an offer to exchange the notes for a new issue of substantially identical notes registered under the Securities Act within 365 days after closing and to use commercially reasonable efforts to complete the exchange offer. We filed a registration statement, which was subsequently declared effective by the SEC, and consummated the exchange offer in the third quarter of 2018. Other Financing Obligations Dalton Expansion Project During the construction of our Dalton Expansion Project, we received funding from a co-owner for its proportionate share of construction costs related to its undivided ownership interest in the Dalton lateral. Amounts received were recorded in Advances for construction costs and 100 percent of the costs associated with construction were capitalized on our Consolidated Balance Sheet. Upon placing the project in service during the third quarter of 2017, we began leasing this co-owner's undivided interest in the lateral, including the associated pipeline capacity, and reclassified approximately $235.8 million of funding previously received from our co-owner from Advances for construction costs to Long-Term Debt on our Consolidated Balance Sheet to reflect the financing obligation payable to our co-owner over an expected term of 35 years. At December 31, 2017, the amount included in Long-Term Debt on our Consolidated Balance Sheet for financing obligation is $229.4 million, and the amount included in Long-term debt due within one year on our Consolidated Balance Sheet is $1.6 million. As this transaction did not meet the criteria for sale leaseback accounting due to our continued involvement, it was accounted for as a financing arrangement over the course of the capacity agreement. The obligation matures in July 2052, requires monthly interest and principal payments, and bears an interest rate of approximately 9 percent. During 2018, we received an additional $29.8 million of funding from a co-owner for its proportionate share of construction costs related to its undivided ownership interest in the Dalton lateral. At December 31, 2018, the amount included in Long-Term Debt on our Consolidated Balance Sheet for this financing obligation is $258.1 million, and the amount included in Long-term debt due within one year on our Consolidated Balance Sheet for this financing obligation is $1.9 million. Atlantic Sunrise Project During the construction of our Atlantic Sunrise Project, we received funding from a co-owner for its proportionate share of construction costs related to an undivided ownership interest in certain parts of the project. Amounts received were recorded in Advances for construction costs and 100 percent of the costs associated with construction were capitalized on our Consolidated Balance Sheet. Upon placing the project into service during October 2018, we began utilizing this co-owner's undivided interest in the lateral, including the associated pipeline capacity, and reclassified $810.3 million of funding previously received from our partner from Advances for construction costs to debt to reflect the financing obligation payable to our co-owner over an expected term of 20 years. During 2018, after the project was placed into service, we received an additional $20.5 million of funding from a co-owner for its proportionate share of construction costs related to its undivided ownership interest in Atlantic Sunrise. At December 31, 2018, the amount included in Long-Term Debt on our Consolidated Balance Sheet for this financing obligation is $793.8 million, and the amount included in Long-term debt due within one year on our Consolidated Balance Sheet for this financing obligation is $13.5 million. As this transaction did not meet the criteria for sale leaseback accounting due to our continued involvement, it was accounted for as a financing arrangement over the course of the capacity agreement. The obligation matures in 2038 requires monthly interest and principal payments, and bears an interest rate of approximately 10 percent. Long-Term Debt Due Within One Year The long-term debt due within one year at December 31, 2018 is associated with the previously described other financing obligations. The long-term debt due within one year at December 31, 2017 is associated with the $250 million of 6.05 percent notes that matured on June 15, 2018 and with the previously described other financing obligation for the Dalton Expansion Project. Credit Facility On July 13, 2018, we, along with Williams and Northwest (the “borrowers”), the lenders named therein, and an administrative agent entered into a Credit Agreement with aggregate commitments available of $4.5 billion, with up to an additional $500 million increase in aggregate commitments available under certain circumstances. We and Northwest are each subject to a $500 million borrowing sublimit. The facility made available under the Credit Agreement is initially available for five years from the Credit Agreement Effective Date (the “Maturity Date”). The borrowers may request an extension of the Maturity Date for an additional one-year period up to two times, to allow a Maturity Date as late as the seventh anniversary of the Credit Agreement Effective Date, subject to certain conditions. The Credit Agreement allows for same day swingline borrowings up to an aggregate amount of $200 million, subject to other utilization of the aggregate commitments under the Credit Agreement. Letter of credit commitments of $1.0 billion are, subject to the $500 million borrowing sublimit applicable to us and Northwest, available to the borrowers. At December 31, 2018 no letters of credit have been issued and loans to Williams of $160 million were outstanding under the credit facility. Measured as of December 31, 2018 , we are in compliance with our financial covenant under the credit facility. Various covenants may limit, among other things, a borrower's and its material subsidiaries' ability to grant certain liens supporting indebtedness, merge or consolidate, sell all or substantially all of its assets, enter into certain affiliate transactions, make certain distributions during an event of default, enter into certain restrictive agreements, and allow any material change in the nature of its business. If an event of default with respect to a borrower occurs under the credit facility, the lenders will be able to terminate the commitments for the respective borrowers and accelerate the maturity of any loans of the defaulting borrower under the credit facility agreement and exercise other rights and remedies. Other than swing line loans, each time funds are borrowed, the applicable borrower may choose from two methods of calculating interest: a fluctuating base rate equal to Citibank N.A.'s alternate base rate plus an applicable margin or a periodic fixed rate equal to the London Interbank Offered Rate plus an applicable margin. We are required to pay a commitment fee based on the unused portion of the credit facility. The applicable margin and the commitment fee are determined by reference to a pricing schedule based on the applicable borrower's senior unsecured long-term debt ratings. Williams participates in a commercial paper program and Williams management considers amounts outstanding under this program to be a reduction of available capacity under the credit facility. The program allows a maximum outstanding amount at any time of $4.0 billion of unsecured commercial paper notes. At December 31, 2018, Williams had no outstanding commercial paper. Lease Obligations The future minimum lease payments under our various operating leases are as follows (in thousands): 2019 $ 9,044 2020 9,014 2021 8,865 2022 8,808 2023 8,829 Thereafter 65,107 Total net minimum obligations $ 109,667 Our lease expense was $10.8 million in 2018 , $11.0 million in 2017 , and $10.6 million in 2016 . |
ARO Trust (Notes)
ARO Trust (Notes) | 12 Months Ended |
Dec. 31, 2018 | |
Investments, Debt and Equity Securities [Abstract] | |
ARO Trust | ARO TRUST We are entitled to collect in rates the amounts necessary to fund our ARO. We deposit monthly, into an external trust account (ARO Trust), the revenues specifically designated for ARO. The ARO Trust carries a moderate risk portfolio. The Money Market Funds held in our ARO Trust are considered investments. We measure the financial instruments held in our ARO Trust at fair value. However, in accordance with ASC Topic 980, Regulated Operations, both realized and unrealized gains and losses of the ARO Trust are recorded as regulatory assets or liabilities. Effective March 1, 2013, the annual funding obligation is approximately $36.4 million, with deposits made monthly. Investments within the ARO Trust at fair value were as follows (in millions): December 31, 2018 December 31, 2017 Amortized Cost Basis Fair Value Amortized Cost Basis Fair Value Money Market Funds $ 21.7 $ 21.7 $ 12.6 $ 12.6 U.S. Equity Funds 46.4 56.8 35.9 50.5 International Equity Funds 21.9 21.4 20.7 24.6 Municipal Bond Funds 50.1 49.6 46.8 46.9 Total $ 140.1 $ 149.5 $ 116.0 $ 134.6 |
Fair Value Measurements (Notes)
Fair Value Measurements (Notes) | 12 Months Ended |
Dec. 31, 2018 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | FAIR VALUE MEASUREMENTS The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities. The carrying values of short-term financial assets (advances to affiliate) that have variable interest rates, accounts receivable and accounts payable approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table. Fair Value Measurements Using Carrying Amount Fair Value Quoted Prices In Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) (Millions) Assets (liabilities) at December 31, 2018: Measured on a recurring basis: ARO Trust investments $ 149.5 $ 149.5 $ 149.5 $ — $ — Additional disclosures: Long-term debt, including current portion (4,014.4 ) (4,785.5 ) — (4,785.5 ) — Assets (liabilities) at December 31, 2017: Measured on a recurring basis: ARO Trust investments $ 134.6 $ 134.6 $ 134.6 $ — $ — Additional disclosures: Long-term debt (2,443.0 ) (3,103.3 ) — (3,103.3 ) — Fair Value Methods The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value: ARO Trust investments - We deposit a portion of our collected rates, pursuant to the terms of the Docket No. RP12-993 rate case settlement, into the ARO Trust which is specifically designated to fund future asset retirement obligations. The ARO Trust invests in a portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted prices in an active market and are reported in Other Assets-Other on the accompanying Consolidated Balance Sheet. However, both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities. See Note 5 for more information regarding the ARO Trust. Long-term debt - The disclosed fair value of our long-term debt is determined primarily by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments. The fair values of the financing obligations associated with our Dalton and Atlantic Sunrise expansions, which are included within long-term debt, were determined using an income approach (See Note 4 - Debt and Financing Agreements). Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No transfers between Level 1 and Level 2 occurred during the years ended December 31, 2018 or 2017 . |
Employee Benefit Plans (Notes)
Employee Benefit Plans (Notes) | 12 Months Ended |
Dec. 31, 2018 | |
Retirement Benefits [Abstract] | |
Employee Benefit Plans [Text Block] | BENEFIT PLANS Certain of the benefit costs charged to us by Williams associated with employees who directly support us are described below. Additionally, allocated corporate expenses from Williams to us also include amounts related to these same employee benefits, which are not included in the amounts presented below. Pension and Other Postretirement Benefit Plans Williams has noncontributory defined benefit pension plans (Williams Pension Plan, Williams Inactive Employees Pension Plan and The Williams Companies Retirement Restoration Plan) that provide pension benefits for its eligible employees. Pension costs charged to us by Williams was $12.8 million, $15.6 million and $8.7 million for 2018 , 2017 , and 2016 , respectively. Included in our pension costs are settlement charges of $2.7 million and $7.6 million for 2018 and 2017, respectively. These amounts reflect the portion of Williams’ settlement charge directly charged to us which was required as a result of lump-sum benefit payments made under Williams’ program to pay out certain deferred vested pension benefits, as well as lump-sum benefit payments made throughout 2018 and 2017. In addition, we were charged $2.7 million and $4.6 million for 2018 and 2017, respectively, of allocated corporate expenses also associated with the settlement charge. Williams makes annual cash contributions to the pension plans, based on annual actuarial estimates, which Transco recovers through rates that are set through periodic general rate filings. Effective with the RP12-993 Settlement, any amounts of annual contributions that exceed an upper threshold or fall below a lower threshold are recorded as adjustments to income and collected or refunded through future rate adjustments. The amount of deferred pension collections recorded as a regulatory liability at December 31, 2018 and 2017 were $48.5 million and $32.5 million, respectively. Williams provides subsidized retiree health care and life insurance benefits to certain eligible participants. Generally, participants that were employed by Williams on or before December 31, 1991 or December 31, 1995, if they were employees or retirees of Transco Energy Company and its subsidiaries, are eligible for subsidized retiree health care benefits. We recognized other postretirement benefit income of $5.9 million, $10.9 million and $12.0 million for 2018, 2017, and 2016, respectively. We have been allowed by rate case settlements to collect or refund in future rates any differences between the actuarially determined costs and amounts currently being recovered in rates related to other postretirement benefits. Any differences between the annual actuarially determined cost and amounts currently being recovered in rates are recorded as an adjustment to expense and collected or refunded through future rate adjustments. The amount of other postretirement benefits costs deferred as a regulatory liability at December 31, 2018 and 2017 are $79.8 million and $73.9 million, respectively. These amounts are comprised of amounts being deferred for future rate treatment of $73.9 million and $65.4 million at December 31, 2018 and 2017, respectively, and amounts of $5.9 million and $8.5 million being amortized over a period of approximately 8 years per Docket No. RP12-993 at December 31, 2018 and 2017, respectively. Defined Contribution Plan Williams maintains a defined contribution plan for substantially all of its employees. Williams charged us compensation expense of $7.9 million, $7.7 million and $6.5 million in 2018, 2017 and 2016, respectively, for Williams’ company matching contributions to this plan. Employee Stock-Based Compensation Plan Information The Williams Companies, Inc. 2007 Incentive Plan, as subsequently amended and restated, (Plan) provides for Williams’ common stock based awards to both employees and non-management directors. The Plan permits the granting of various types of awards including, but not limited to, restricted stock units and stock options. Awards may be granted for no consideration other than prior and future services or based on certain financial performance targets achieved. Williams currently bills us directly for compensation expense related to stock-based compensation awards based on the fair value of the awards. We are also billed for our proportionate share of Williams’ and other affiliates’ stock-based compensation expense through various allocation processes. Total stock-based compensation expense for the years ended December 31, 2018 , 2017 , and 2016 was $6.3 million, $5.7 million and $4.0 million, respectively, excluding amounts allocated from WPZ and Williams. |
Transactions with Major Custome
Transactions with Major Customers and Affiliates (Notes) | 12 Months Ended |
Dec. 31, 2018 | |
Transactions with Major Customers and Affiliates [Abstract] | |
Transactions with Major Customers and Affiliates | TRANSACTIONS WITH MAJOR CUSTOMERS AND AFFILIATES Major Customers Operating revenues received from three of our major customers in 2018 , 2017 and 2016 are as follows (in millions): 2018 2017 2016 Duke Energy Corporation $ 194.5 $ 198.4 $ 178.9 National Grid 186.1 177.4 166.3 The Southern Company, Inc. 166.2 160.0 69.6 Affiliates We are a participant in Williams' cash management program, and we make advances to and receive advances from Williams. At December 31, 2018 and 2017 , our advances to Williams totaled approximately $33.0 million and $395.2 million , respectively. These advances are represented by demand notes and are classified as Receivables - Advances to affiliate in the accompanying Consolidated Balance Sheet. Advances are stated at the historical carrying amounts. Interest income is recognized when chargeable and collectability is reasonably assured. The interest rate on these intercompany demand notes is based upon the daily overnight investment rate paid on Williams' excess cash at the end of each month. At December 31, 2018 , the interest rate was 2.24 percent. Included in Operating Revenues in the accompanying Consolidated Statement of Comprehensive Income for 2018 , 2017 and 2016 are revenues received from affiliates of $10.1 million, $10.3 million, and $11.2 million, respectively. The rates charged to provide sales and services to affiliates are the same as those that are charged to similarly-situated nonaffiliated customers. Included in Cost of natural gas sales in the accompanying Consolidated Statement of Comprehensive Income for 2018 , 2017 and 2016 is purchased gas cost from affiliates of $5.4 million, $3.9 million, and $4.3 million, respectively. All gas purchases are made at market or contract prices. We have no employees. Services necessary to operate our business are provided to us by Williams and certain affiliates of Williams. We reimburse Williams and its affiliates for all direct and indirect expenses incurred or payments made (including salary, bonus, incentive compensation and benefits) in connection with these services. Employees of Williams also provide general, administrative and management services to us, and we are charged for certain administrative expenses incurred by Williams. These charges are either directly identifiable or allocated to our assets. Direct charges are for goods and services provided by Williams at our request. Allocated charges are based on a three-factor formula, which considers revenues; property, plant and equipment; and payroll. In management’s estimation, the allocation methodologies used are reasonable and result in a reasonable allocation to us of our costs of doing business incurred by Williams. We were billed $395.3 million, $370.4 million, and $318.4 million during 2018 , 2017 and 2016 , respectively, for these services. Such expenses are primarily included in Administrative and general and Operation and maintenance expenses in the accompanying Consolidated Statement of Comprehensive Income. The amount billed to us during 2016 includes $7.4 million for severance and other related costs associated with a reduction in workforce primarily recognized in the first quarter. We provide services to certain of our affiliates. We recorded reductions in operating expenses for services provided to and reimbursed by our affiliates of $4.7 million, $3.7 million, and $4.3 million in 2018 , 2017 and 2016 , respectively. We made equity distributions of $490 million, $430 million and $440 million during 2018 , 2017 and 2016 , respectively. In January 2019, an additional distribution of $176 million was declared and paid. During 2018 , 2017 and 2016 , our parent made contributions totaling $340 million, $410 million and $502 million, respectively, to us to fund a portion of our expenditures for additions to property, plant and equipment. During July 2017, we recorded deferred revenue and recognized a non-cash distribution to our parent of $240 million associated with funds received by WPZ related to the March 2016 WPZ agreement with the member-sponsors of Sabal Trail regarding the Hillabee Expansion and Sabal Trail projects. Although the agreement was between WPZ and the member-sponsors, since the agreement was, in part, related to furthering the completion of Hillabee, this deferred revenue is assigned to our results of operations over the 25-year term of the capacity agreement with Sabal Trail. |
Asset Retirement Obligations (N
Asset Retirement Obligations (Notes) | 12 Months Ended |
Dec. 31, 2018 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | ASSET RETIREMENT OBLIGATIONS These accrued obligations relate to underground storage caverns, offshore platforms, pipelines, and gas transmission facilities. At the end of the useful life of each respective asset, we are legally obligated to plug storage caverns and remove any related surface equipment, to dismantle offshore platforms, to cap certain gathering pipelines at the wellhead connection and remove any related surface equipment, and to remove certain components of gas transmission facilities from the ground. During 2018 and 2017 , our overall asset retirement obligation changed as follows (in thousands): 2018 2017 Beginning balance $ 363,956 $ 275,452 Accretion (1) 32,924 104,659 New obligations 14,162 28,447 Changes in estimates of existing obligations (2) (8,054 ) (38,470 ) Property dispositions/obligations settled (8,665 ) (6,132 ) Ending balance $ 394,323 $ 363,956 (1) The decrease in accretion for 2018 is due to the 2017 cumulative effect of accretion adjustment associated with new AROs identified in our historical land agreements of $87 million that are not a component of new obligations. (2) Changes in estimates of existing obligations are primarily due to the annual review process, which considers various factors including inflation rate, current estimates for removal cost, discount rates, and the estimated remaining life of assets. The decrease in 2018 is primarily due to a decrease in current estimates for onshore removal costs. The decrease in 2017 is primarily due to a decrease in current estimates for offshore removal costs. We are entitled to collect in rates the amounts necessary to fund our ARO. All funds received for such retirements are deposited into an external trust account dedicated to funding our ARO. Under our current rate settlement our annual funding obligation is approximately $36.4 million , with installments to be deposited monthly (See Note 5). |
Regulatory Assets and Liabiliti
Regulatory Assets and Liabilities (Notes) | 12 Months Ended |
Dec. 31, 2018 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
Regulatory Assets and Liabilities | REGULATORY ASSETS AND LIABILITIES The regulatory assets and regulatory liabilities resulting from our application of the provisions of ASC Topic 980, Regulated Operations, included in the accompanying Consolidated Balance Sheet at December 31, 2018 and December 31, 2017 are as follows (in millions): Regulatory Assets 2018 2017 Grossed-up deferred taxes on equity funds used during construction $ 39.0 $ 37.9 Asset retirement obligations 171.9 168.7 Asset retirement costs - Eminence 45.5 49.5 Deferred taxes - asset 2.7 3.8 Deferred cash out 54.9 42.5 Deferred gas costs 4.0 6.0 Fuel cost 61.2 61.4 Other 6.0 3.7 Total Regulatory Assets $ 385.2 $ 373.5 Regulatory Liabilities 2018 2017 Negative salvage $ 444.5 $ 409.7 Deferred taxes - liability 450.2 471.1 Sentinel meter station depreciation 6.4 6.3 Postretirement benefits other than pension 79.8 73.9 Electric power cost 0.1 13.3 Pension - deferred collections 48.5 32.5 Other 2.5 0.3 Total Regulatory Liabilities $ 1,032.0 $ 1,007.1 The significant regulatory assets and liabilities include: Grossed-up deferred taxes on equity funds used during construction : Regulatory asset balance established to offset the deferred tax for the equity component of the allowance for funds used during the construction of long-lived assets. All amounts were generated during the period that we were a taxable entity. Taxes on capitalized funds used during construction and the offsetting deferred income taxes are included in the rate base and are recovered over the depreciable lives of the long-lived asset to which they relate. Asset retirement obligations : Regulatory asset balance established to offset depreciation of the ARO asset and changes in the ARO liability due to the passage of time. The regulatory asset is being recovered through our rates, and is being amortized to expense consistent with the amounts collected in rates (See Note 9). Asset retirement costs - Eminence : Regulatory asset balance associated with the Eminence Storage Field retirement costs. The regulatory asset is being recovered through our rates, and is being amortized to expense consistent with the amounts collected in rates. Deferred taxes - asset : Regulatory asset balance was established as a result of an increase to rate base deferred taxes due to an increase to the effective state income tax rate. The regulatory asset is being collected from rate payers over the remaining depreciable lives of the long-lived asset to which they relate. Deferred cash out : This amount represents the deferral of gains or losses on the purchases and sales of gas imbalances with shippers. These amounts are not included in the rate base but are expected to be recovered/refunded in subsequent annual cash out filing periods. Deferred gas costs : This amount arises from the movement of gas volumes between gas inventory accounts that have different valuations. These amounts are expected to be recovered/refunded in subsequent periods. Fuel cost : This amount represents the difference between the gas retained from our customers and the gas consumed in operations. These amounts are not included in the rate base but are expected to be recovered/refunded in subsequent annual fuel tracker filing periods. Negative salvage: Our rates include a component designed to recover certain future retirement costs for which we are not required to record an asset retirement obligation. We record a regulatory liability representing the cumulative residual amount of recoveries through rates, net of expenditures associated with these retirement costs. Sentinel meter station depreciation: This amount reflects the incremental depreciation being recorded related to the meter station modifications made for three of the Sentinel shippers. These modifications will be recovered through a surcharge over a defined period of time as stated in the Sentinel FERC order. The incremental depreciation represents the difference between the FERC granted depreciation rate for such facilities in the last rate case as compared to the depreciation rates in the Sentinel order which are based on the contractual terms in the surcharge agreements. The incremental depreciation will be recorded through the end of the contractual term and then will be amortized. Postretirement benefits: We recover the actuarially determined cost of postretirement benefits through rates that are set through periodic general rate filings. Any difference between the annual actuarially determined cost and the amount recovered in rates is recorded as a regulatory asset or liability to be collected or refunded through future rate adjustments. These amounts are not included in the rate base (See Note 7). Electric power cost : This amount represents the difference between the electric power costs recovered from our customers and the electric power costs incurred in operations. These amounts are not included in the rate base but are expected to be recovered/refunded in subsequent annual electric power tracker filing periods. Pension - deferred collections: We recover the actuarially determined pension cash contributions through rates that are set through periodic general rate filings. Effective with the RP12-993 Settlement, any amounts of annual contributions that exceed an upper threshold or fall below a lower threshold are recorded as adjustments to income and collected or refunded through future rate adjustments (See Note 7). Deferred taxes - liability : Regulatory liability balance was established as a result of a decrease to rate base deferred taxes due to a decrease to the effective federal income tax rate. The timing of the refund of the regulatory liability to rate payers will be subject to future discussions and negotiations with our customers in our next rate case. |
Other (Notes)
Other (Notes) | 12 Months Ended |
Dec. 31, 2018 | |
Other Income and Expenses [Abstract] | |
Other | OTHER The Advances for construction costs on the accompanying Consolidated Balance Sheet are primarily associated with advances received from a third party related to construction costs on the Atlantic Sunrise project. This balance increases as we receive additional advances. In October 2018, the project was placed into service and the related liabilities were reclassified to debt and reduced by payments we made to the third party under terms of the applicable lease agreement. |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Regulatory Accounting | Regulatory Accounting We are regulated by the Federal Energy Regulatory Commission (FERC). The Accounting Standards Codification (ASC) Regulated Operations (Topic 980), provides that rate-regulated public utilities account for and report regulatory assets and liabilities consistent with the economic effect of the way in which regulators establish rates if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. Accounting for businesses that are regulated and apply the provisions of Topic 980 can differ from the accounting requirements for non-regulated businesses. Transactions that are recorded differently as a result of regulatory accounting requirements include the capitalization of an equity return component on regulated capital projects, capitalization of other project costs, retirements of general plant assets, employee related benefits, environmental costs, negative salvage, asset retirement obligations (ARO), and other costs and taxes included in, or expected to be included in, future rates. As a rate-regulated entity, our management has determined that it is appropriate to apply the accounting prescribed by Topic 980 and, accordingly, the accompanying consolidated financial statements include the effects of the types of transactions described above that result from regulatory accounting requirements. In December 2017, the Tax Cuts and Jobs Act (Tax Reform) was enacted, which, among other things, reduced the federal corporate income tax rate from 35 percent to 21 percent. We have recognized a regulatory liability to reflect the probable return to certain customers through future rates of the future decrease in income taxes payable associated with Tax Reform. In determining the estimated liability that we currently believe is probable of return to certain customers through future rates, we considered the mix of services provided by us, taking into consideration that certain of these services are provided under contractually based rates, in lieu of recourse-based rates, that are designed to recover the cost of providing those services, with no expected future rate adjustment for the term of those contracts. The liability was recorded in December 2017 through a regulatory charge to operating income of $471.1 million, this regulatory charge was reduced by $20.9 million in 2018 mostly due to an updated weighted average state income tax rate. The timing and actual amount of such return will be subject to future negotiations regarding this matter and many other elements of cost-of-service rate proceedings, including other costs of providing service. Certain of our equity-method investees recorded similar regulatory liabilities, for which our Equity in (earnings) loss of unconsolidated affiliates on our Consolidated Statement of Comprehensive Income has been reduced by $2.0 and $10.3 million in 2018 and 2017, respectively, related to our proportionate share of the associated regulatory charges. Our regulatory asset associated with the effects of deferred taxes on equity funds used during construction was also impacted by Tax Reform and was reduced by $0.9 million and $32.7 million in 2018 and 2017, respectively, through a charge to Miscellaneous other (income) expenses, net on our Consolidated Statement of Comprehensive Income. |
Basis of Presentation | Basis of Presentation Williams’ acquisition of Transco Energy Company and its subsidiaries, including us, in 1995 was accounted for using the purchase method of accounting. Accordingly, an allocation of the purchase price was assigned to our assets and liabilities based on their estimated fair values. The purchase price allocation to us primarily consisted of a $1.5 billion allocation to property, plant and equipment and adjustments to deferred taxes based upon the book basis of the net assets recorded as a result of the acquisition. The amount allocated to property, plant and equipment is being depreciated on a straight-line basis over 40 years, the estimated useful lives of these assets at the date of acquisition, at approximately $35 million per year. At December 31, 2018 , the remaining property, plant and equipment allocation was approximately $0.6 billion. Current FERC policy does not permit us to recover through rates amounts in excess of original cost. |
Principles of Consolidation | Principles of Consolidation The consolidated financial statements include our accounts and the accounts of the subsidiaries we control. Companies in which we and our subsidiaries own 20 percent to 50 percent of the voting common stock or otherwise exercise significant influence over operating and financial policies of the company are accounted for under the equity method. The equity method investments as of December 31, 2018 and December 31, 2017 consist of Cardinal Pipeline Company, LLC (Cardinal) with ownership interest of approximately 45 percent and Pine Needle LNG Company, LLC (Pine Needle) with ownership interest of 35 percent. We received distributions associated with our equity method investments totaling $3.2 million, $8.0 million, and $8.6 million in 2018 , 2017 and 2016 , respectively. |
Use of Estimates | Use of Estimates The preparation of financial statements in conformity with U.S. generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates and assumptions which, in the opinion of management, are significant to the underlying amounts included in the financial statements and for which it would be reasonably possible that future events or information could change those estimates include: 1) revenues subject to refund; 2) litigation-related contingencies; 3) environmental remediation obligations; 4) impairment assessments of long-lived assets; 5) depreciation; 6) asset retirement obligations; and 7) regulatory deferred taxes. |
Revenue Recognition | Revenue Recognition (subsequent to the adoption of ASC 606) Our customers are comprised of public utilities, municipalities, gas marketers and producers, intrastate pipelines, direct industrial users, and electrical power generators. A performance obligation is a promise in a contract to transfer a distinct good or service (or integrated package of goods or services) to the customer. A contract’s transaction price is allocated to each distinct performance obligation and recognized as revenue, when, or as, the performance obligation is satisfied. A performance obligation is distinct if the product or service is separately identifiable from other items in the integrated package of services and if a customer can benefit from it on its own or with other resources that are readily available to the customer. Service revenue contracts contain a series of distinct services, with the majority of our contracts having a single performance obligation that is satisfied over time as the customer simultaneously receives and consumes the benefits provided by our performance. Most of our product sales contracts have a single performance obligation with revenue recognized at a point in time when the products have been sold and delivered to the customer. Certain customers reimburse us for costs we incur associated with construction of property, plant, and equipment utilized in our operations. As a rate-regulated entity applying Topic 980, we follow FERC guidelines with respect to reimbursement of construction costs. FERC tariffs only allow for cost reimbursement and are non-negotiable in nature; thus, in our judgment, the construction activities do not represent an ongoing major and central operation of our gas pipelines business and are not within the scope of Accounting Standards Update (ASU) 2014-09, Revenues from Contracts with Customers (ASC 606). Accordingly, cost reimbursements are treated as a reduction to the cost of the constructed asset. Service Revenues We are subject to regulation by certain state and federal authorities, including the FERC, with revenue derived from both firm and interruptible transportation and storage contracts. Firm transportation and storage agreements provide for a fixed reservation charge based on the pipeline or storage capacity reserved, and a commodity charge based on the volume of natural gas delivered/stored, each at rates specified in our FERC tariffs or as negotiated with our customers, with contract terms that are generally long-term in nature. Most of our long-term contracts contain an evergreen provision, which allows the contracts to be extended for periods primarily up to one year in length an indefinite number of times following the specified contract term and until terminated generally by either us or the customer. Interruptible transportation and storage agreements provide for a volumetric charge based on actual commodity transportation or storage utilized in the period in which those services are provided, and the contracts are generally limited to one month periods or less. Our performance obligations include the following: • Firm transportation or storage under firm transportation and storage contracts - an integrated package of services typically constituting a single performance obligation, which includes standing ready to provide such services and receiving, transporting or storing (as applicable), and redelivering commodities; • Interruptible transportation and storage under interruptible transportation and storage contracts - an integrated package of services typically constituting a single performance obligation once scheduled, which includes receiving, transporting or storing (as applicable), and redelivering commodities. In situations where, in our judgment, we consider the integrated package of services as a single performance obligation, which represents a majority of our contracts with customers, we do not consider there to be multiple performance obligations because the nature of the overall promise in the contract is to stand ready (with regard to firm transportation and storage contracts), receive, transport or store, and redeliver natural gas to the customer; therefore, revenue is recognized over time upon satisfaction of our daily stand ready performance obligation. We recognize revenues for reservation charges over the performance obligation period, which is the contract term, regardless of the volume of natural gas that is transported or stored. Revenues for commodity charges from both firm and interruptible transportation services and storage services are recognized when natural gas is delivered at the agreed upon delivery point or when natural gas is injected or withdrawn from the storage facility because they specifically relate to our efforts to provide these distinct services. Generally, reservation charges and commodity charges are recognized as revenue in the same period they are invoiced to our customers. As a result of the ratemaking process, certain amounts collected by us may be subject to refunds upon the issuance of final orders by the FERC in pending rate proceedings. We use judgment to record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel, and other risks. Product Sales In the course of providing transportation services to customers, we may receive different quantities of natural gas from customers than the quantities delivered on behalf of those customers. The resulting imbalances are primarily settled through the purchase or sale of natural gas with each customer under terms provided for in our FERC tariffs. Revenue is recognized from the sale of natural gas upon settlement of the transportation and exchange imbalances (See Gas Imbalances in this Note). Contract Liabilities Our contract liabilities consist of advance payments from customers, which include prepayments, and other billings for which future services are to be provided under the contract. These amounts are deferred until recognized in revenue when the associated performance obligation has been satisfied, which is primarily straight-line over the remaining contractual service periods, and are classified as current or non-current according to when such amounts are expected to be recognized. Current and non-current contract liabilities are included within Accrued Liabilities and Other Long-Term Liabilities - Deferred revenue , respectively, in our Consolidated Balance Sheet. Contracts requiring advance payments and the recognition of contract liabilities are evaluated to determine whether the advance payments provide us with a significant financing benefit. This determination is based on the combined effect of the expected length of time between when we transfer the promised good or service to the customer and when the customer pays for those goods or services and the prevailing interest rates. We have assessed our contracts and determined none of our contracts contain a significant financing component. |
Environmental Matters | Environmental Matters We are subject to federal, state, and local environmental laws and regulations. Environmental expenditures are expensed or capitalized depending on their economic benefit and potential for rate recovery. We believe that any expenditures required to meet applicable environmental laws and regulations are prudently incurred in the ordinary course of business and such expenditures would be permitted to be recovered through rates. |
Property, Plant and Equipment | Property, Plant and Equipment Property, plant and equipment is recorded at cost. The carrying values of these assets are also based on estimates, assumptions and judgments relative to capitalized costs, useful lives and salvage values. These estimates, assumptions and judgments reflect FERC regulations, as well as historical experience and expectations regarding future industry conditions and operations. The FERC identifies installation, construction and replacement costs that are to be capitalized. All other costs are expensed as incurred. Gains or losses from the ordinary sale or retirement of property, plant and equipment are credited or charged to accumulated depreciation; certain other gains or losses are recorded in operating income. We provide for depreciation under the composite (group) method at straight-line FERC prescribed rates that are applied to the cost of the group for transmission facilities, production and gathering facilities and storage facilities. Under this method, assets with similar lives and characteristics are grouped and depreciated as one asset. Included in our depreciation rates is a negative salvage component (net cost of removal) that we currently collect in rates. Our depreciation rates are subject to change each time we file a general rate case with the FERC. Depreciation rates used for major regulated gas plant facilities at December 31, 2018 , 2017 and 2016 are as follows: Category of Property 2018-2016 Gathering facilities 1.35% - 2.50% Storage facilities 2.10% - 2.25% Onshore transmission facilities 2.61% - 5.00% Offshore transmission facilities 1.20% - 1.20% We record a liability and increase the basis in the underlying asset for the present value of each expected future ARO at the time the liability is initially incurred, typically when the asset is acquired or constructed. Measurements of AROs include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market-risk premium. The ARO asset is depreciated in a manner consistent with the expected timing of the future abandonment of the underlying physical assets. We measure changes in the liability due to passage of time by applying an interest method of allocation. The depreciation of the ARO asset and accretion of the ARO liability are recognized as an increase to a regulatory asset, as management expects to recover such amounts in future rates. The regulatory asset is amortized commensurate with our collection of these costs in rates. |
Impairment of Long-Lived Assets | Impairment of Long-lived Assets We evaluate the long lived assets of identifiable business activities for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. When an indicator of a potential impairment has occurred we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred. We apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes including selling in the near term or holding for the remaining estimated useful life. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value. For assets identified to be disposed of in the future and considered held for sale in accordance with the ASC Property, Plant, and Equipment (Topic 360), we compare the carrying value to the estimated fair value less the cost to sell to determine if recognition of an impairment is required. Until the assets are disposed of, the estimated fair value, which includes estimated cash flows from operations until the assumed date of sale, is recalculated when related events or circumstances change. Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows used to determine recoverability of an asset and the estimate of an asset’s fair value used to calculate the amount of impairment to recognize. |
Allowance for Funds Used During Construction | Allowance for Funds Used During Construction Allowance for funds used during construction (AFUDC) represents the estimated cost of borrowed and equity funds applicable to utility plant in process of construction and are included as a cost of property, plant and equipment because it constitutes an actual cost of construction under established regulatory practices. The FERC has prescribed a formula to be used in computing separate allowances for borrowed and equity AFUDC. The allowance for borrowed funds used during construction was $29.2 million, $22.3 million and $12.5 million, for 2018 , 2017 and 2016 , respectively. The allowance for equity funds was $87.1 million, $69.7 million, and $56.5 million, for 2018 , 2017 and 2016 , respectively. |
Income Taxes | Income Taxes We are a natural gas company organized as a pass-through entity and our taxable income or loss is consolidated on the federal income tax return of our parent, Williams. We generally are treated as a pass-through entity for state and local income tax purposes, and those taxes are generally borne on a consolidated basis by Williams. Net income for financial statement purposes may differ significantly from taxable income of Williams as a result of differences between the tax basis and financial reporting basis of assets and liabilities. |
Accounts Receivable and Allowance for Doubtful Receivables | Accounts Receivable and Allowance for Doubtful Receivables Accounts receivable are stated at the historical carrying amount net of reserves or write-offs. We do not offer extended payment terms and typically receive payment within one month. We consider receivables past due if full payment is not received by the contractual due date. Our credit risk exposure in the event of nonperformance by the other parties is limited to the face value of the receivables. We perform ongoing credit evaluations of our customers’ financial condition and require collateral from our customers, if necessary. Due to our customer base, we have not historically experienced recurring credit losses in connection with our receivables. Receivables determined to be uncollectible are reserved or written off in the period of determination. |
Gas Imbalances | Gas Imbalances In the course of providing transportation services to customers, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. Additionally, we transport gas on various pipeline systems which may deliver different quantities of gas on behalf of us than the quantities of gas received from us. These transactions result in gas transportation and exchange imbalance receivables and payables which are recovered or repaid in cash or through the receipt or delivery of gas in the future and are recorded in the accompanying Consolidated Balance Sheet. Settlement of imbalances requires agreement between the pipelines and shippers as to allocations of volumes to specific transportation contracts and timing of delivery of gas based on operational conditions. Our tariff includes a method whereby most transportation imbalances are settled on a monthly basis. Each month a portion of the imbalances are not identified to specific parties and remain unsettled. These are generally identified to specific parties and settled in subsequent periods. We believe that amounts that remain unidentified to specific parties and unsettled at year end are valid balances that will be settled with no material adverse effect upon our financial position, results of operations or cash flows. Management has implemented a policy of continuing to carry any unidentified transportation and exchange imbalances on the books for a three-year period. At the end of the three year period a final assessment will be made of their continued validity. Absent a valid reason for maintaining the imbalance, any remaining balance will be recognized in income. Certain imbalances are being recovered or repaid in cash or through the receipt or delivery of gas upon agreement of the parties as to the allocation of the gas volumes, and as permitted by pipeline operating conditions. These imbalances have been classified as current assets and current liabilities at December 31, 2018 and 2017. We utilize the average cost method of accounting for gas imbalances. Deferred Cash Out Most transportation imbalances are settled in cash on a monthly basis (cash-out). In accordance with our tariff, revenues received from the cash-out of transportation imbalances in excess of costs incurred are deferred and offset by the deferral of costs incurred in excess of revenues received. At the end of each annual August through July reporting period, if the cumulative revenues received exceed the costs incurred, the over recovered amounts are refunded. If the cumulative revenues received are less than the costs incurred, the net under recovered amounts are carried forward and offset against any future net over recoveries that may occur in a subsequent annual reporting period. |
Inventory | Gas Inventory We utilize the last-in, first-out (LIFO) method of accounting for inventory gas in storage. At December 31, 2018 and 2017, Gas in Storage, at LIFO, was zero. The basis for determining current cost at the end of each year is the December monthly average gas price delivered to pipelines in Texas and Louisiana. We utilize the average cost method of accounting for gas available for customer nomination. Liquefied natural gas in storage is valued at original cost. Materials and Supplies Inventory All inventories are stated at average cost. We perform an annual review of Materials and Supplies inventories, including a quarterly analysis of parts that may no longer be useful due to planned replacements of compressor engines and other components on our system. Based on this assessment, we record a reserve for the value of the inventory which can no longer be used for maintenance and repairs on our pipeline. There was a minimal reserve at December 31, 2018 and 2017. |
Contingent Liabilities | Contingent Liabilities We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss is probable and the amount of the loss can be reasonably estimated. These liabilities are calculated based upon our assumptions and estimates with respect to the likelihood or amount of loss and upon advice of legal counsel, engineers, or other third parties regarding the probable outcomes of the matters. These calculations are made without consideration of any potential recovery from third-parties. We recognize insurance recoveries or reimbursements from others when realizable. Revisions to these liabilities are generally reflected in income when new or different facts or information become known or circumstances change that affect the previous assumptions or estimates. |
Pension and Other Postretirement Benefits | Pension and Other Postretirement Benefits We do not have employees. Certain of the costs charged to us by Williams associated with employees who directly support us include costs related to Williams’ pension and other postretirement benefit plans. (See Note 7.) Although the underlying benefit plans of Williams are single-employer plans, we follow multiemployer plan accounting whereby the amount charged to us and thus paid by us, is based on our share of net periodic benefit cost. |
Cash Equivalents | Cash Flows from Operating Activities and Cash Equivalents We use the indirect method to report cash flows from operating activities, which requires adjustments to net income to reconcile to net cash flows provided by operating activities. We include short-term, highly-liquid investments that have an original maturity of three months or less as cash equivalents. |
Fair Value Measurements (Polici
Fair Value Measurements (Policies) | 12 Months Ended |
Dec. 31, 2018 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | Fair Value Methods The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value: ARO Trust investments - We deposit a portion of our collected rates, pursuant to the terms of the Docket No. RP12-993 rate case settlement, into the ARO Trust which is specifically designated to fund future asset retirement obligations. The ARO Trust invests in a portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted prices in an active market and are reported in Other Assets-Other on the accompanying Consolidated Balance Sheet. However, both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities. See Note 5 for more information regarding the ARO Trust. Long-term debt - The disclosed fair value of our long-term debt is determined primarily by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments. The fair values of the financing obligations associated with our Dalton and Atlantic Sunrise expansions, which are included within long-term debt, were determined using an income approach (See Note 4 - Debt and Financing Agreements). Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No transfers between Level 1 and Level 2 occurred during the years ended December 31, 2018 or 2017 . |
Revenue Recognition Revenue Rec
Revenue Recognition Revenue Recognition (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Revenue Recognition [Abstract] | |
Contract with Customer, Asset and Liability [Table Text Block] | The following table presents a reconciliation of our contract liabilities: December 31, 2018 (Thousands) Balance at beginning of period $ 247,296 Payments received and deferred — Recognized in revenue (10,566 ) Balance at end of period $ 236,730 |
Contract with Customer, Liablity Expected Timing of Revenue Recognition [Table Text Block] | The following table presents the amount of the contract liabilities balance as of December 31, 2018 , expected to be recognized as revenue in each of the next five years as performance obligations are expected to be satisfied: (Thousands) 2019 $ 10,566 2020 10,568 2021 10,566 2022 10,566 2023 10,566 Thereafter 183,898 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Table Text Block] | The following table presents the transaction price allocated to the remaining performance obligations under certain contracts as of December 31, 2018 . These primarily include reservation charges on contracted capacity on our firm transportation and storage contracts with customers. Amounts from certain contracts included in the table below, which are subject to the periodic review and approval by the FERC, reflect the rates for such services in our current FERC tariffs for the life of the related contracts; however, these rates may change based on future tariffs approved by the FERC and the amount and timing of these changes is not currently known. As a practical expedient permitted by ASC 606, this table excludes the variable consideration component for commodity charges. It also excludes consideration that will be recognized in future periods (see above for Contract Liabilities and the expected recognition of those amounts within revenue). As noted above, certain of our contracts contain evergreen provisions for periods beyond the initial term of the contract. The remaining performance obligation as of December 31, 2018 , does not consider potential future performance obligations for which the renewal has not been exercised. The table below also does not include contracts with customers for which the underlying facilities have not received FERC authorization to be placed into service. (Thousands) 2019 $ 2,085,113 2020 1,956,772 2021 1,881,776 2022 1,520,358 2023 1,386,290 Thereafter 12,501,777 Total $ 21,332,086 |
Summary of Significant Accoun_3
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Depreciation rates | We provide for depreciation under the composite (group) method at straight-line FERC prescribed rates that are applied to the cost of the group for transmission facilities, production and gathering facilities and storage facilities. Under this method, assets with similar lives and characteristics are grouped and depreciated as one asset. Included in our depreciation rates is a negative salvage component (net cost of removal) that we currently collect in rates. Our depreciation rates are subject to change each time we file a general rate case with the FERC. Depreciation rates used for major regulated gas plant facilities at December 31, 2018 , 2017 and 2016 are as follows: Category of Property 2018-2016 Gathering facilities 1.35% - 2.50% Storage facilities 2.10% - 2.25% Onshore transmission facilities 2.61% - 5.00% Offshore transmission facilities 1.20% - 1.20% |
Debt, Financing Arrangements _2
Debt, Financing Arrangements and Leases (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Debt Disclosure [Abstract] | |
Long-term debt | At December 31, 2018 and 2017 , long-term debt outstanding was as follows (in thousands): 2018 2017 Debentures: 7.08% due 2026 $ 7,500 $ 7,500 7.25% due 2026 200,000 200,000 Total debentures 207,500 207,500 Notes: 6.05% due 2018 — 250,000 7.85% due 2026 1,000,000 1,000,000 4.0% due 2028 400,000 — 5.4% due 2041 375,000 375,000 4.45% due 2042 400,000 400,000 4.6% due 2048 600,000 — Total notes 2,775,000 2,025,000 Other financing obligation 1,067,286 230,926 Total long-term debt, including current portion 4,049,786 2,463,426 Unamortized debt issuance costs (24,242 ) (15,377 ) Unamortized debt premium and discount, net (11,137 ) (5,043 ) Long-term debt due within one year (15,419 ) (251,430 ) Total long-term debt $ 3,998,988 $ 2,191,576 |
Maturities of long-term debt | Aggregate minimum maturities (face value) applicable to long-term debt outstanding at December 31, 2018 , for the next five years, are as follows (in thousands): 2019: Other financing obligation $ 15,419 2020: Other financing obligation $ 17,042 2021: Other financing obligation $ 18,837 2022: Other financing obligation $ 20,821 2023: Other financing obligation $ 23,014 |
Future minimum lease payments | The future minimum lease payments under our various operating leases are as follows (in thousands): 2019 $ 9,044 2020 9,014 2021 8,865 2022 8,808 2023 8,829 Thereafter 65,107 Total net minimum obligations $ 109,667 |
ARO Trust (Tables)
ARO Trust (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Investments, Debt and Equity Securities [Abstract] | |
ARO Trust | Investments within the ARO Trust at fair value were as follows (in millions): December 31, 2018 December 31, 2017 Amortized Cost Basis Fair Value Amortized Cost Basis Fair Value Money Market Funds $ 21.7 $ 21.7 $ 12.6 $ 12.6 U.S. Equity Funds 46.4 56.8 35.9 50.5 International Equity Funds 21.9 21.4 20.7 24.6 Municipal Bond Funds 50.1 49.6 46.8 46.9 Total $ 140.1 $ 149.5 $ 116.0 $ 134.6 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Fair Value Disclosures [Abstract] | |
Schedule of fair value, assets and liabilities measured on recurring basis | The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities. The carrying values of short-term financial assets (advances to affiliate) that have variable interest rates, accounts receivable and accounts payable approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table. Fair Value Measurements Using Carrying Amount Fair Value Quoted Prices In Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) (Millions) Assets (liabilities) at December 31, 2018: Measured on a recurring basis: ARO Trust investments $ 149.5 $ 149.5 $ 149.5 $ — $ — Additional disclosures: Long-term debt, including current portion (4,014.4 ) (4,785.5 ) — (4,785.5 ) — Assets (liabilities) at December 31, 2017: Measured on a recurring basis: ARO Trust investments $ 134.6 $ 134.6 $ 134.6 $ — $ — Additional disclosures: Long-term debt (2,443.0 ) (3,103.3 ) — (3,103.3 ) — |
Transactions with Major Custo_2
Transactions with Major Customers and Affiliates (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Transactions with Major Customers and Affiliates [Abstract] | |
Schedule of revenue by major customers | Operating revenues received from three of our major customers in 2018 , 2017 and 2016 are as follows (in millions): 2018 2017 2016 Duke Energy Corporation $ 194.5 $ 198.4 $ 178.9 National Grid 186.1 177.4 166.3 The Southern Company, Inc. 166.2 160.0 69.6 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of change in asset retirement obligation | During 2018 and 2017 , our overall asset retirement obligation changed as follows (in thousands): 2018 2017 Beginning balance $ 363,956 $ 275,452 Accretion (1) 32,924 104,659 New obligations 14,162 28,447 Changes in estimates of existing obligations (2) (8,054 ) (38,470 ) Property dispositions/obligations settled (8,665 ) (6,132 ) Ending balance $ 394,323 $ 363,956 (1) The decrease in accretion for 2018 is due to the 2017 cumulative effect of accretion adjustment associated with new AROs identified in our historical land agreements of $87 million that are not a component of new obligations. (2) Changes in estimates of existing obligations are primarily due to the annual review process, which considers various factors including inflation rate, current estimates for removal cost, discount rates, and the estimated remaining life of assets. The decrease in 2018 is primarily due to a decrease in current estimates for onshore removal costs. The decrease in 2017 is primarily due to a decrease in current estimates for offshore removal costs. |
Regulatory Assets and Liabili_2
Regulatory Assets and Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
Schedule of Regulatory Assets [Table Text Block] | The regulatory assets and regulatory liabilities resulting from our application of the provisions of ASC Topic 980, Regulated Operations, included in the accompanying Consolidated Balance Sheet at December 31, 2018 and December 31, 2017 are as follows (in millions): Regulatory Assets 2018 2017 Grossed-up deferred taxes on equity funds used during construction $ 39.0 $ 37.9 Asset retirement obligations 171.9 168.7 Asset retirement costs - Eminence 45.5 49.5 Deferred taxes - asset 2.7 3.8 Deferred cash out 54.9 42.5 Deferred gas costs 4.0 6.0 Fuel cost 61.2 61.4 Other 6.0 3.7 Total Regulatory Assets $ 385.2 $ 373.5 |
Schedule of Regulatory Liabilities [Table Text Block] | Regulatory Liabilities 2018 2017 Negative salvage $ 444.5 $ 409.7 Deferred taxes - liability 450.2 471.1 Sentinel meter station depreciation 6.4 6.3 Postretirement benefits other than pension 79.8 73.9 Electric power cost 0.1 13.3 Pension - deferred collections 48.5 32.5 Other 2.5 0.3 Total Regulatory Liabilities $ 1,032.0 $ 1,007.1 |
Revenue Recognition Contract Li
Revenue Recognition Contract Liabilities (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Jan. 01, 2018 | |
Revenue Recognition [Abstract] | ||
Contract with Customer, Liability | $ 236,730 | $ 247,296 |
Contract with Customer, Liability, Cumulative Catch-up Adjustment to Revenue, Change in Estimate of Transaction Price | 0 | |
Contract with Customer, Liability, Revenue Recognized | (10,566) | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01 | Performance Obligations Related To Contract Liabilities [Member] | ||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | ||
Revenue, Remaining Performance Obligation, Amount | $ 10,566 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01 | Performance Obligations Related To Contract Liabilities [Member] | ||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | ||
Revenue, Remaining Performance Obligation, Amount | $ 10,568 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | Performance Obligations Related To Contract Liabilities [Member] | ||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | ||
Revenue, Remaining Performance Obligation, Amount | $ 10,566 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Performance Obligations Related To Contract Liabilities [Member] | ||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | ||
Revenue, Remaining Performance Obligation, Amount | $ 10,566 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Performance Obligations Related To Contract Liabilities [Member] | ||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | ||
Revenue, Remaining Performance Obligation, Amount | $ 10,566 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Performance Obligations Related To Contract Liabilities [Member] | ||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | ||
Revenue, Remaining Performance Obligation, Amount | $ 183,898 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year |
Revenue Recognition Remaining P
Revenue Recognition Remaining Performance Obligation (Details) - Remaining Performance Obligations [Member] $ in Thousands | Dec. 31, 2018USD ($) |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 2,085,113 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 1,956,772 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 1,881,776 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 1,520,358 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 1,386,290 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 21,332,086 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year |
Summary of Significant Accoun_4
Summary of Significant Accounting Policies (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | |||
Regulatory charge (credit) resulting from Tax Reform (Note 1) | $ (20,867) | $ 471,096 | $ 0 |
Purchase Price Allocation | |||
Purchase price allocation, gross | $ 1,500,000 | ||
Purchase price allocation, property, plant and equipment, estimated useful lIfe | 40 years | ||
Purchase price allocation, depreciation | $ 35,000 | ||
Purchase price allocation, remaining allocation | 600,000 | ||
Schedule of Equity Method Investments [Line Items] | |||
Proceeds from Equity Method Investment, Distribution | 3,250 | 8,036 | 8,631 |
Capitalized Interest Costs, Including Allowance for Funds Used During Construction [Abstract] | |||
Allowance for funds used during construction, borrowed | 29,200 | 22,300 | 12,500 |
Allowance for funds used during construction, equity | 87,111 | 69,653 | $ 56,468 |
Inventory Disclosure [Abstract] | |||
Gas in storage, LIFO | 0 | 0 | |
Operating Expense [Member] | |||
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | |||
Regulatory charge (credit) resulting from Tax Reform (Note 1) | (20,867) | 471,096 | |
Nonoperating Income (Expense) [Member] | |||
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | |||
Regulatory charge (credit) resulting from Tax Reform (Note 1) | 2,000 | 10,300 | |
Other Nonoperating Income (Expense) [Member] | |||
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | |||
Regulatory charge (credit) resulting from Tax Reform (Note 1) | $ 900 | $ 32,700 | |
Pine Needle LNG Company LLC [Member] | |||
Schedule of Equity Method Investments [Line Items] | |||
Equity method investment, ownership percentage | 35.00% | 35.00% | |
Cardinal Pipeline Company LLC [Member] | |||
Schedule of Equity Method Investments [Line Items] | |||
Equity method investment, ownership percentage | 45.00% | 45.00% | |
Minimum | |||
Schedule of Equity Method Investments [Line Items] | |||
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Percent | 21.00% | ||
Equity Method Investment, Description of Principal Activities | .20 | ||
Maximum | |||
Schedule of Equity Method Investments [Line Items] | |||
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Percent | 35.00% | ||
Equity Method Investment, Description of Principal Activities | .50 | ||
Gathering facilities | Minimum | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Depreciation rates | 1.35% | 1.35% | 1.35% |
Gathering facilities | Maximum | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Depreciation rates | 2.50% | 2.50% | 2.50% |
Storage facilities | Minimum | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Depreciation rates | 2.10% | 2.10% | 2.10% |
Storage facilities | Maximum | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Depreciation rates | 2.25% | 2.25% | 2.25% |
Onshore transmission facilities | Minimum | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Depreciation rates | 2.61% | 2.61% | 2.61% |
Onshore transmission facilities | Maximum | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Depreciation rates | 5.00% | 5.00% | 5.00% |
Offshore transmission facilities | Minimum | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Depreciation rates | 1.20% | 1.20% | 1.20% |
Offshore transmission facilities | Maximum | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Depreciation rates | 1.20% | 1.20% | 1.20% |
Accounting Standards Update 2016-15 [Member] | |||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||
Net Cash Provided by (Used in) Operating Activities | $ 3,900 | $ 2,800 | |
Accounting Standards Update 2016-02 [Member] | Maximum | |||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||
Operating Lease Liability Percentage Of Total Liabilities | 3.00% | ||
Operating Lease Right Of Use Asset Percentage Of Total Assets | 3.00% |
Contingent Liabilities and Co_2
Contingent Liabilities and Commitments (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Jun. 30, 2016 | |
Other Commitments [Abstract] | |||
Commitments for construction and acquisition of property, plant, and equipment | $ 137 | ||
Accrued Liabilities [Member] | |||
Site Contingency [Line Items] | |||
Notice of Penalty | 1.4 | $ 1.6 | |
Environmental assessment and remediation | |||
Site Contingency [Line Items] | |||
Accrued environmental assessment and remediation costs, total | 3.5 | $ 4 | |
Accrued environmental assessment and remediation costs, current | 1.5 | 1.8 | |
Accrued environmental assessment and remediation costs, noncurrent | 2 | $ 2.2 | |
Environmental assessment and remediation | Minimum | |||
Site Contingency [Line Items] | |||
Environmental assessment and remediation costs, best estimate | $ 5 | ||
Expected duration of environmental assessment and remediation spending | 4 years | ||
Environmental assessment and remediation | Maximum | |||
Site Contingency [Line Items] | |||
Environmental assessment and remediation costs, best estimate | $ 7 | ||
Expected duration of environmental assessment and remediation spending | 6 years | ||
Potentially responsible party at various Superfund and state waste disposal sites | Maximum | |||
Site Contingency [Line Items] | |||
Environmental assessment and remediation costs, best estimate | $ 0.5 |
Debt, Financing Arrangements _3
Debt, Financing Arrangements and Leases (Details) - USD ($) | Oct. 01, 2018 | Jun. 15, 2018 | Sep. 30, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Jul. 13, 2018 | Mar. 15, 2018 |
Debt Instrument [Line Items] | ||||||||
Total long-term debt, including current portion | $ 4,049,786,000 | $ 2,463,426,000 | ||||||
Other financing obligation | 1,067,286,000 | 230,926,000 | ||||||
Unamortized debt issuance costs | (24,242,000) | (15,377,000) | ||||||
Unamortized debt premium and discount, net | (11,137,000) | (5,043,000) | ||||||
Long-term debt due within one year | 15,419,000 | 251,430,000 | ||||||
Total long-term debt | 3,998,988,000 | 2,191,576,000 | ||||||
Long-term Debt, Fiscal Year Maturity [Abstract] | ||||||||
2,019 | 15,419,000 | |||||||
2,020 | 17,042,000 | |||||||
2,021 | 18,837,000 | |||||||
2,022 | 20,821,000 | |||||||
2,023 | 23,014,000 | |||||||
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract] | ||||||||
2,019 | 9,044,000 | |||||||
2,020 | 9,014,000 | |||||||
2,021 | 8,865,000 | |||||||
2,022 | 8,808,000 | |||||||
2,023 | 8,829,000 | |||||||
Thereafter | 65,107,000 | |||||||
Total net minimum obligations | 109,667,000 | |||||||
Operating leases, rent expense | 10,800,000 | 11,000,000 | $ 10,600,000 | |||||
6.05% due 2018 [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Long-term debt interest rate | 6.05% | |||||||
Long-Term Debt, retired | $ 250,000,000 | |||||||
4.0% due 2028 [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Long-term debt face amount | $ 400,000,000 | |||||||
Long-term debt interest rate | 4.00% | |||||||
4.6 % due 2048 [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Long-term debt face amount | $ 600,000,000 | |||||||
Long-term debt interest rate | 4.60% | |||||||
10% due 2052 [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Long-term debt interest rate | 9.00% | |||||||
Dalton Expansion Project [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Other financing obligation | $ 235,800,000 | 29,800,000 | ||||||
Long-term debt face amount | 258,100,000 | 229,400,000 | ||||||
Debt Instrument, Term | 35 years | |||||||
Other Long-term Debt, Current | $ 1,900,000 | 1,600,000 | ||||||
Percent Of Construction Costs Capitalized | 100.00% | |||||||
Atlantic Sunrise Project [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Other financing obligation | $ 810,300,000 | $ 20,500,000 | ||||||
Long-term debt face amount | 793,800,000 | |||||||
Long-term debt interest rate | 10.00% | |||||||
Debt Instrument, Term | 20 years | |||||||
Other Long-term Debt, Current | $ 13,500,000 | |||||||
Percent Of Construction Costs Capitalized | 100.00% | |||||||
Debentures | ||||||||
Debt Instrument [Line Items] | ||||||||
Total long-term debt, including current portion | $ 207,500,000 | 207,500,000 | ||||||
Debentures | 7.08% due 2026 [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Total long-term debt, including current portion | 7,500,000 | 7,500,000 | ||||||
Debentures | 7.25% due 2026 [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Total long-term debt, including current portion | 200,000,000 | 200,000,000 | ||||||
Notes | ||||||||
Debt Instrument [Line Items] | ||||||||
Total long-term debt, including current portion | 2,775,000,000 | 2,025,000,000 | ||||||
Notes | 6.05% due 2018 [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Total long-term debt, including current portion | 0 | 250,000,000 | ||||||
Notes | 7.85% due 2026 | ||||||||
Debt Instrument [Line Items] | ||||||||
Total long-term debt, including current portion | 1,000,000,000 | 1,000,000,000 | ||||||
Notes | 4.0% due 2028 [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Total long-term debt, including current portion | 400,000,000 | 0 | ||||||
Notes | 5.4% due 2041 [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Total long-term debt, including current portion | 375,000,000 | 375,000,000 | ||||||
Notes | 4.45% due 2042 [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Total long-term debt, including current portion | 400,000,000 | 400,000,000 | ||||||
Notes | 4.6 % due 2048 [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Total long-term debt, including current portion | 600,000,000 | $ 0 | ||||||
$4.5 billion credit facility [Member] | ||||||||
Line of Credit Facility [Line Items] | ||||||||
Line of credit facility, maximum borrowing capacity | $ 500,000,000 | |||||||
$4.5 billion credit facility [Member] | Williams Companies Inc [Member] | ||||||||
Line of Credit Facility [Line Items] | ||||||||
Letters of credit outstanding, amount | 0 | |||||||
Line of credit facility, amount outstanding | 160,000,000 | |||||||
Line of credit facility, maximum borrowing capacity | 4,500,000,000 | |||||||
Additional amount by which credit facility can be increased | 500,000,000 | |||||||
Swing Line Advances [Member] | Williams Companies Inc [Member] | ||||||||
Line of Credit Facility [Line Items] | ||||||||
Line of credit facility, maximum borrowing capacity | 200,000,000 | |||||||
Commercial paper [Member] | Williams Companies Inc [Member] | ||||||||
Line of Credit Facility [Line Items] | ||||||||
Line of credit facility, maximum borrowing capacity | 4,000,000,000 | |||||||
Commercial paper | $ 0 | |||||||
Letter of Credit [Member] | ||||||||
Line of Credit Facility [Line Items] | ||||||||
Line of credit facility, maximum borrowing capacity | 500,000,000 | |||||||
Letter of Credit [Member] | Williams Companies Inc [Member] | ||||||||
Line of Credit Facility [Line Items] | ||||||||
Line of credit facility, maximum borrowing capacity | $ 1,000,000,000 |
ARO Trust (Details)
ARO Trust (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Investments, Debt and Equity Securities [Abstract] | ||
Annual funding obligation | $ 36.4 | |
Debt Securities, Available-for-sale [Line Items] | ||
Trading Securities, Equity, Cost | 140.1 | $ 116 |
Trading Securities, Equity | 149.5 | 134.6 |
Money Market Funds [Member] | ||
Debt Securities, Available-for-sale [Line Items] | ||
Trading Securities, Equity, Cost | 21.7 | 12.6 |
Trading Securities, Equity | 21.7 | 12.6 |
U.S. Equity Funds [Member] | ||
Debt Securities, Available-for-sale [Line Items] | ||
Trading Securities, Equity, Cost | 46.4 | 35.9 |
Trading Securities, Equity | 56.8 | 50.5 |
International Equity Funds [Member] | ||
Debt Securities, Available-for-sale [Line Items] | ||
Trading Securities, Equity, Cost | 21.9 | 20.7 |
Trading Securities, Equity | 21.4 | 24.6 |
Municipal Bond Funds [Member] | ||
Debt Securities, Available-for-sale [Line Items] | ||
Trading Securities, Equity, Cost | 50.1 | 46.8 |
Trading Securities, Equity | $ 49.6 | $ 46.9 |
Fair Value Measurements (Detail
Fair Value Measurements (Details) - USD ($) | Dec. 31, 2018 | Dec. 31, 2017 |
Fair Value, Transfers Between Level 1 and Level 2, Description and Policy [Abstract] | ||
Fair Value, Assets, Level 1 to Level 2 Transfers, Amount | $ 0 | $ 0 |
Fair Value, Assets, Level 2 to Level 1 Transfers, Amount | 0 | 0 |
Fair Value, Liabilities, Level 1 to Level 2 Transfers, Amount | 0 | 0 |
Fair Value, Liabilities, Level 2 to Level 1 Transfers, Amount | 0 | 0 |
Fair Value, Inputs, Level 1 [Member] | ||
Additional Fair Value Elements [Abstract] | ||
Long-term Debt, Fair Value | 0 | 0 |
Fair Value, Inputs, Level 2 [Member] | ||
Additional Fair Value Elements [Abstract] | ||
Long-term Debt, Fair Value | (4,785,500,000) | (3,103,300,000) |
Fair Value, Inputs, Level 3 [Member] | ||
Additional Fair Value Elements [Abstract] | ||
Long-term Debt, Fair Value | 0 | 0 |
Reported Value Measurement [Member] | ||
Additional Fair Value Elements [Abstract] | ||
Long-term Debt, Fair Value | (4,014,400,000) | (2,443,000,000) |
Estimate of Fair Value Measurement [Member] | ||
Additional Fair Value Elements [Abstract] | ||
Long-term Debt, Fair Value | (4,785,500,000) | (3,103,300,000) |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Abstract] | ||
ARO Trust investments | 149,500,000 | 134,600,000 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Abstract] | ||
ARO Trust investments | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Abstract] | ||
ARO Trust investments | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Reported Value Measurement [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Abstract] | ||
ARO Trust investments | 149,500,000 | 134,600,000 |
Fair Value, Measurements, Recurring [Member] | Estimate of Fair Value Measurement [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Abstract] | ||
ARO Trust investments | $ 149,500,000 | $ 134,600,000 |
Employee Benefit Plans (Details
Employee Benefit Plans (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Defined Benefit Plan Disclosure [Line Items] | |||
Regulatory liabilities | $ 1,032 | $ 1,007.1 | |
Defined contribution plan, cost recognized | 7.9 | 7.7 | $ 6.5 |
Salary and Wage, Excluding Cost of Good and Service Sold [Abstract] | |||
Allocated share-based compensation expense | 6.3 | 5.7 | 4 |
Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Pension cost | 12.8 | 15.6 | 8.7 |
Pension Plan [Member] | Directly charged [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Pension cost charges to us by Williams | 2.7 | 7.6 | |
Pension Plan [Member] | Allocated corporate expenses [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Pension cost charges to us by Williams | 2.7 | 4.6 | |
Pension Costs [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Regulatory liability, deferred for future rate treatment | 48.5 | 32.5 | |
Other Postretirement Benefits Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Regulatory liability, deferred for future rate treatment | 73.9 | 65.4 | |
Other postretirement benefit (income) expense | (5.9) | (10.9) | $ (12) |
Regulatory liabilities | 79.8 | 73.9 | |
Regulatory liability, being amortized | $ 5.9 | $ 8.5 | |
Regulatory Liability, Amortization Period | 8 years |
Transactions with Major Custo_3
Transactions with Major Customers and Affiliates (Details) $ in Thousands | 1 Months Ended | 12 Months Ended | |||
Jan. 31, 2019USD ($) | Jul. 31, 2017USD ($) | Dec. 31, 2018USD ($)employee | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | |
Related Party Transaction [Line Items] | |||||
Advances to affiliate | $ 33,034 | $ 395,247 | |||
Related party transaction, rate | 2.24% | ||||
Entity number of employees | employee | 0 | ||||
Expenses, related party | $ 395,300 | 370,400 | $ 318,400 | ||
Severance Costs | 7,400 | ||||
Equity distributions | 490,000 | 430,000 | 440,000 | ||
Cash contributions from parent | 340,000 | 410,000 | 502,000 | ||
Duration Of Period For Deferred Revenue Recognition | 25 years | ||||
Subsequent Event [Member] | |||||
Related Party Transaction [Line Items] | |||||
Equity distributions | $ 176,000 | ||||
Hillabee Expansion Project [Member] | |||||
Related Party Transaction [Line Items] | |||||
Deferred Revenue, Additions | $ 240,000 | ||||
Affiliated Entity [Member] | |||||
Related Party Transaction [Line Items] | |||||
Operating revenues, related party | 10,100 | 10,300 | 11,200 | ||
Cost of natural gas sales, related party | 5,400 | 3,900 | 4,300 | ||
Expenses, related party | (4,700) | (3,700) | (4,300) | ||
Williams Companies Inc [Member] | |||||
Related Party Transaction [Line Items] | |||||
Advances to affiliate | 33,034 | 395,247 | |||
Duke Energy Corporation [Member] | |||||
Revenue, Major Customer [Line Items] | |||||
Operating revenues | 194,500 | 198,400 | 178,900 | ||
National Grid [Member] | |||||
Revenue, Major Customer [Line Items] | |||||
Operating revenues | 186,100 | 177,400 | 166,300 | ||
The Southern Company, Inc [Member] | |||||
Revenue, Major Customer [Line Items] | |||||
Operating revenues | $ 166,200 | $ 160,000 | $ 69,600 |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Beginning balance | $ 363,956 | $ 275,452 |
Accretion (1) | 32,924 | 104,659 |
New obligations | 14,162 | 28,447 |
Asset Retirement Obligation, Revision of Estimate | (8,054) | (38,470) |
Property dispositions/obligations settled | (8,665) | (6,132) |
Ending balance | 394,323 | 363,956 |
Annual funding obligation | 36,400 | |
Asset retirement obligation [Member] | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Accretion (1) | $ 87,000 | |
External ARO trust [Member] | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Annual funding obligation | $ 36,400 |
Regulatory Assets and Liabili_3
Regulatory Assets and Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Regulatory Assets [Line Items] | ||
Regulatory assets | $ 385.2 | $ 373.5 |
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 1,032 | 1,007.1 |
Negative salvage | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 444.5 | 409.7 |
Deferred taxes | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 450.2 | 471.1 |
Sentinel meter station depreciation | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 6.4 | 6.3 |
Postretirement benefits other than pension | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 79.8 | 73.9 |
Electric power cost | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 0.1 | 13.3 |
Pension- deferred collections | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 48.5 | 32.5 |
Other | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 2.5 | 0.3 |
Grossed-up deferred taxes on equity funds used during construction | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | 39 | 37.9 |
Asset retirement obligations | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | 171.9 | 168.7 |
Asset retirement costs - Eminence | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | 45.5 | 49.5 |
Deferred taxes | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | 2.7 | 3.8 |
Deferred cash out | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | 54.9 | 42.5 |
Deferred gas costs | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | 4 | 6 |
Fuel Cost | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | 61.2 | 61.4 |
Other | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | $ 6 | $ 3.7 |