Document and Entity Information
Document and Entity Information - shares | 6 Months Ended | |
Jun. 30, 2018 | Jul. 13, 2018 | |
Document and Entity Information [Abstract] | ||
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Jun. 30, 2018 | |
Document Fiscal Year Focus | 2,018 | |
Document Fiscal Period Focus | Q2 | |
Entity Registrant Name | Enable Midstream Partners, LP | |
Entity Central Index Key | 1,591,763 | |
Entity Filer Category | Large Accelerated Filer | |
Current Fiscal Year End Date | --12-31 | |
Entity Common Stock, Shares Outstanding | 433,068,427 |
Condensed Consolidated Statemen
Condensed Consolidated Statements of Income (Unaudited) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Revenues (including revenues from affiliates (Note 12)): | ||||
Total Revenues | $ 805 | $ 626 | $ 1,553 | $ 1,292 |
Cost of Goods and Services Sold | 444 | 279 | 819 | 587 |
Cost and Expenses (including expenses from affiliates (Note 12)): | ||||
Operation and maintenance | 97 | 97 | 191 | 186 |
General and administrative | 26 | 23 | 53 | 48 |
Depreciation and amortization | 96 | 89 | 192 | 177 |
Taxes other than income tax | 16 | 16 | 33 | 32 |
Total Cost and Expenses | 679 | 504 | 1,288 | 1,030 |
Operating Income | 126 | 122 | 265 | 262 |
Other Income (Expense): | ||||
Interest expense | (36) | (31) | (69) | (58) |
Equity in earnings of equity method affiliate | 7 | 7 | 13 | 14 |
Other Nonoperating Income (Expense) | (2) | (1) | 0 | 0 |
Total Other Expense | (31) | (25) | (56) | (44) |
Income Before Income Tax | ||||
Income Before Income Tax | 95 | 97 | 209 | 218 |
Income tax expense | 0 | 1 | 0 | 2 |
Net Income | ||||
Net Income | 95 | 96 | 209 | 216 |
Less: Net income attributable to noncontrolling interest | ||||
Less: Net income attributable to noncontrolling interest | 0 | 1 | 0 | 1 |
Net Income Attributable to Limited Partners | ||||
Net Income Attributable to Limited Partners | 95 | 95 | 209 | 215 |
Less: Series A Preferred Unit distributions (Note 6) | ||||
Less: Series A Preferred Unit distributions (Note 6) | 9 | 9 | 18 | 18 |
Net Income Attributable to Common and Subordinated Units (Note 5) | ||||
Net Income Attributable to Common and Subordinated Units (Note 5) | 86 | 86 | 191 | 197 |
Common Units | ||||
Net Income Attributable to Common and Subordinated Units (Note 5) | ||||
Net Income Attributable to Common and Subordinated Units (Note 5) | $ 86 | $ 45 | $ 191 | $ 102 |
Basic and Diluted earnings (loss) per unit and weighted average number of units outstanding | ||||
Basic earnings per unit (Note 5) | $ 0.20 | $ 0.20 | $ 0.44 | $ 0.45 |
Diluted earnings per unit (Note 5) | $ 0.20 | $ 0.20 | $ 0.44 | $ 0.45 |
Subordinated Units | ||||
Net Income Attributable to Common and Subordinated Units (Note 5) | ||||
Net Income Attributable to Common and Subordinated Units (Note 5) | $ 0 | $ 41 | $ 0 | $ 95 |
Basic and Diluted earnings (loss) per unit and weighted average number of units outstanding | ||||
Basic earnings per unit (Note 5) | $ 0 | $ 0.20 | $ 0 | $ 0.46 |
Diluted earnings per unit (Note 5) | $ 0 | $ 0.20 | $ 0 | $ 0.46 |
Product | ||||
Revenues (including revenues from affiliates (Note 12)): | ||||
Total Revenues | $ 501 | $ 354 | $ 944 | $ 740 |
Natural Gas, Gathering, Transportation, Marketing and Processing | ||||
Revenues (including revenues from affiliates (Note 12)): | ||||
Total Revenues | $ 304 | $ 272 | $ 609 | $ 552 |
Condensed Consolidated Balance
Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Millions | Jun. 30, 2018 | Dec. 31, 2017 |
Current Assets: | ||
Cash and cash equivalents | $ 7 | $ 5 |
Restricted cash (Note 1) | 14 | 14 |
Accounts receivable, net of allowance for doubtful accounts (Note 1) | 287 | 277 |
Accounts receivable—affiliated companies | 21 | 18 |
Inventory | 41 | 40 |
Gas imbalances | 29 | 37 |
Other current assets | 33 | 25 |
Total current assets | 432 | 416 |
Property, Plant and Equipment: | ||
Property, plant and equipment | 12,443 | 12,079 |
Less accumulated depreciation and amortization | 1,880 | 1,724 |
Property, plant and equipment, net | 10,563 | 10,355 |
Other Assets: | ||
Intangible assets, net | 429 | 451 |
Goodwill | 12 | 12 |
Investment in equity method affiliate | 315 | 324 |
Other | 41 | 35 |
Total other assets | 797 | 822 |
Total Assets | 11,792 | 11,593 |
Current Liabilities: | ||
Accounts payable | 244 | 263 |
Accounts payable—affiliated companies | 3 | 3 |
Current portion of long-term debt | 499 | 450 |
Short-term debt | 327 | 405 |
Taxes accrued | 39 | 32 |
Gas imbalances | 16 | 12 |
Other | 130 | 114 |
Total current liabilities | 1,258 | 1,279 |
Other Liabilities: | ||
Accumulated deferred income taxes, net | 6 | 6 |
Regulatory liabilities | 22 | 21 |
Other | 54 | 38 |
Total other liabilities | 82 | 65 |
Long-Term Debt | 2,881 | 2,595 |
Commitments and Contingencies (Note 13) | ||
Partners’ Equity: | ||
Series A Preferred Units (14,520,000 issued and outstanding at June 30, 2018 and December 31, 2017) | 362 | 362 |
Common units | 7,198 | 7,280 |
Noncontrolling interest | 11 | 12 |
Total Partners’ Equity | 7,571 | 7,654 |
Total Liabilities and Partners’ Equity | $ 11,792 | $ 11,593 |
Condensed Consolidated Balance4
Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - shares | Jun. 30, 2018 | Dec. 31, 2017 |
Common Units | ||
Common and Subordinated units issued | 433,064,636 | 432,584,080 |
Common units and Subordinated units outstanding | 433,064,636 | 432,584,080 |
Series A Preferred Units | ||
Preferred units issued | 14,520,000 | 14,520,000 |
Preferred units outstanding | 14,520,000 | 14,520,000 |
Condensed Consolidated Stateme5
Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Millions | 6 Months Ended | |
Jun. 30, 2018 | Jun. 30, 2017 | |
Cash Flows from Operating Activities: | ||
Net income | $ 209 | $ 216 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depreciation and amortization | 192 | 177 |
Deferred income taxes | 0 | 2 |
Loss on sale/retirement of assets | 0 | 5 |
Equity in earnings of equity method affiliate | (13) | (14) |
Return on investment in equity method affiliate | 13 | 14 |
Equity-based compensation | 8 | 8 |
Amortization of debt costs and discount (premium) | (1) | (1) |
Changes in other assets and liabilities: | ||
Accounts receivable, net | (9) | 29 |
Accounts receivable—affiliated companies | (3) | (1) |
Inventory | (2) | (1) |
Gas imbalance assets | 8 | 18 |
Other current assets | (15) | (2) |
Other assets | (5) | 3 |
Accounts payable | (19) | (46) |
Gas imbalance liabilities | 4 | (26) |
Other current liabilities | 22 | 3 |
Other liabilities | 16 | (2) |
Net cash provided by operating activities | 405 | 382 |
Cash Flows from Investing Activities: | ||
Capital expenditures | (375) | (148) |
Proceeds from sale of assets | 8 | 1 |
Proceeds from insurance | 1 | 0 |
Return of investment in equity method affiliate | 8 | 5 |
Net cash used in investing activities | (358) | (142) |
Cash Flows from Financing Activities: | ||
Decrease in short-term debt | (78) | 0 |
Repayment of long-term debt | (450) | 0 |
Proceeds from long-term debt, net of issuance costs | 787 | 691 |
Proceeds from Revolving Credit Facility | 0 | 394 |
Repayment of Revolving Credit Facility | 0 | (1,030) |
Distributions | (295) | (296) |
Cash taxes paid for employee equity-based compensation | (9) | (1) |
Net cash used in financing activities | (45) | (242) |
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash | 2 | (2) |
Cash, Cash Equivalents and Restricted Cash at Beginning of Period | 19 | 23 |
Cash, Cash Equivalents and Restricted Cash at End of Period | $ 21 | $ 21 |
Condensed Consolidated Stateme6
Condensed Consolidated Statements of Partners' Equity (Unaudited) - USD ($) shares in Millions, $ in Millions | Total | Noncontrolling Interest | Series A Preferred UnitsPreferred Units | Common UnitsPartners' Capital | Subordinated UnitsPartners' Capital |
Balance, beginning of period at Dec. 31, 2016 | $ 7,794 | $ 12 | $ 362 | $ 3,737 | $ 3,683 |
Balance, beginning of period, units at Dec. 31, 2016 | 15 | 224 | 208 | ||
Changes in Partners' Capital | |||||
Net Income | 216 | 1 | $ 18 | $ 102 | $ 95 |
Distributions | (295) | (1) | (18) | (144) | (132) |
Equity-based compensation, net of units for employee taxes | 7 | 7 | |||
Balance, end of period at Jun. 30, 2017 | 7,722 | 12 | $ 362 | $ 3,702 | $ 3,646 |
Balance, end of period, units at Jun. 30, 2017 | 15 | 224 | 208 | ||
Balance, beginning of period at Dec. 31, 2017 | 7,654 | 12 | $ 362 | $ 7,280 | $ 0 |
Balance, beginning of period, units at Dec. 31, 2017 | 15 | 433 | 0 | ||
Changes in Partners' Capital | |||||
Net Income | 209 | $ 18 | $ 191 | $ 0 | |
Distributions | (295) | (1) | (18) | (276) | 0 |
Equity-based compensation, net of units for employee taxes | 3 | 3 | |||
Balance, end of period at Jun. 30, 2018 | $ 7,571 | $ 11 | $ 362 | $ 7,198 | $ 0 |
Balance, end of period, units at Jun. 30, 2018 | 15 | 433 | 0 |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 6 Months Ended |
Jun. 30, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Summary of Significant Accounting Policies | Summary of Significant Accounting Policies Organization Enable Midstream Partners, LP is a Delaware limited partnership formed on May 1, 2013 by CenterPoint Energy, OGE Energy and ArcLight. The Partnership’s assets and operations are organized into two reportable segments: (i) gathering and processing and (ii) transportation and storage. The gathering and processing segment primarily provides natural gas and crude oil gathering and natural gas processing services to our producer customers. The transportation and storage segment provides interstate and intrastate natural gas pipeline transportation and storage services primarily to our producer, power plant, LDC and industrial end-user customers. The Partnership’s natural gas gathering and processing assets are primarily located in Oklahoma, Texas, Arkansas and Louisiana and serve natural gas production in the Anadarko, Arkoma and Ark-La-Tex Basins. Crude oil gathering assets are located in North Dakota and serve crude oil production in the Bakken Shale formation of the Williston Basin. The Partnership’s natural gas transportation and storage assets consist primarily of an interstate pipeline system extending from western Oklahoma and the Texas Panhandle to Louisiana, an interstate pipeline system extending from Louisiana to Illinois, an intrastate pipeline system in Oklahoma, and our investment in SESH, an interstate pipeline extending from Louisiana to Alabama. CenterPoint Energy and OGE Energy each have 50% of the management interests in Enable GP. Enable GP is the general partner of the Partnership and has no other operating activities. Enable GP is governed by a board made up of two representatives designated by each of CenterPoint Energy and OGE Energy, along with the Partnership’s Chief Executive Officer and three independent board members CenterPoint Energy and OGE Energy mutually agreed to appoint. CenterPoint Energy and OGE Energy also own a 40% and 60% interest, respectively, in the incentive distribution rights held by Enable GP. As of June 30, 2018 , CenterPoint Energy held approximately 54.0% or 233,856,623 of the Partnership’s common units, and OGE Energy held approximately 25.6% or 110,982,805 of the Partnership’s common units. Additionally, CenterPoint Energy holds 14,520,000 Series A Preferred Units. See Note 6 for further information related to the Series A Preferred Units. The limited partner interests of the Partnership have limited voting rights on matters affecting the business. As such, limited partners do not have rights to elect the Partnership’s general partner on an annual or continuing basis and may not remove Enable GP, its current general partner, without at least a 75% vote by all unitholders, including all units held by the Partnership’s limited partners, and Enable GP and its affiliates, voting together as a single class. As of June 30, 2018 , the Partnership owned a 50% interest in SESH. See Note 7 for further discussion of SESH. Basis of Presentation The accompanying condensed consolidated financial statements and related notes of the Partnership have been prepared pursuant to the rules and regulations of the SEC and GAAP. Pursuant to such rules and regulations, certain disclosures normally included in financial statements prepared in accordance with GAAP have been omitted. The accompanying condensed consolidated financial statements and related notes should be read in conjunction with the consolidated financial statements and related notes included in our Annual Report. The condensed consolidated financial statements and the related notes reflect all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position and results of operations for the respective periods. Amounts reported in the Partnership’s Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for a full-year period due to the effects of, among other things, (a) seasonal fluctuations in demand for energy and energy services, (b) changes in energy commodity prices, (c) timing of maintenance and other expenditures and (d) acquisitions and dispositions of businesses, assets and other interests. For a description of the Partnership’s reportable segments, see Note 15. Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Restricted Cash Restricted cash primarily consists of cash collateral which is provided as credit assurance by third parties. The Condensed Consolidated Balance Sheets have $14 million of restricted cash at each of June 30, 2018 and December 31, 2017 . Accounts Receivable and Allowance for Doubtful Accounts Accounts receivable are recorded at the invoiced amount and do not typically bear interest. The determination of the allowance for doubtful accounts requires management to make estimates and judgments regarding our customers’ ability to pay. The allowance for doubtful accounts is determined based upon specific identification and estimates of future uncollectable amounts. On an ongoing basis, management evaluates our customers’ financial strength based on aging of accounts receivable, payment history, and review of other relevant information, including ratings agency credit ratings and alerts, publicly available reports and news releases, and bank and trade references. It is the policy of management to review the outstanding accounts receivable at least quarterly, giving consideration to historical bad debt write-offs, the aging of receivables and specific customer circumstances that may impact their ability to pay the amounts due. Based on this review, management determined that a $2 million allowance for doubtful accounts was required at June 30, 2018 and a $3 million allowance at December 31, 2017 . Inventory Natural gas inventory is held, through the transportation and storage segment, to provide operational support for the intrastate pipeline deliveries and to manage leased intrastate storage capacity. Natural gas liquids inventory is held, through the gathering and processing segment, due to timing differences between the production of certain natural gas liquids and ultimate sale to third parties. Natural gas and natural gas liquids inventory is valued using moving average cost and is subsequently recorded at the lower of cost or net realizable value. The Partnership’s Inventory balance is net of $1 million and zero lower of cost or net realizable value adjustments as of June 30, 2018 and December 31, 2017 , respectively. Income Taxes The Partnership’s earnings are not subject to income tax (other than Texas state margin taxes and taxes associated with the Partnership’s corporate subsidiary, Enable Midstream Services) and are taxable at the individual partner level. We account for deferred income taxes related to the federal and state jurisdictions using the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future taxes attributable to the difference between financial statement carrying amounts of assets and liabilities and their respective tax basis. Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of tax net operating loss carryforwards. In the event future utilization is determined to be unlikely, a valuation allowance is provided to reduce the tax benefits from such assets. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the period in which the temporary differences and carryforwards are expected to be recovered or settled. The effect of a change in tax rates is recognized in the period which includes the enactment date. The Partnership recognizes interest and penalties as a component of income tax expense. |
New Accounting Pronouncements
New Accounting Pronouncements | 6 Months Ended |
Jun. 30, 2018 | |
Accounting Changes and Error Corrections [Abstract] | |
New Accounting Pronouncements | New Accounting Pronouncements Accounting Standards to be Adopted in Future Periods Leases In February 2016, the FASB issued ASU 2016-02, “Leases (ASC 842).” This standard requires, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. In January 2018, the FASB issued ASU 2018-01, “Land Easement Practical Expedient for Transition to Topic 842.” This standard permits an entity to elect an optional transition practical expedient to not evaluate land easements that exist or expire before the Partnership's adoption of ASC 842 and that were not previously accounted for as leases under ASC 840. The Partnership intends to elect this transition provision. In July 2018, the FASB issued ASU No. 2018-10, “Codification Improvements to Topic 842, Leases,” which finalizes Proposed Accounting Standards Update (ASU) No. 2017-310, Technical Corrections and Improvements to Recently Issued Standards-Accounting Standards Update No. 2016-02, Leases (Topic 842), to address implementation issues that could arise as organizations comply with ASU No. 2016-02, Leases (Topic 842). We are currently evaluating this ASU and its potential impact on our implementation. The Partnership continues to review contracts and easements relative to the provisions of the ASU 2016-02 lease standard, the ASU 2018-01 easement standard and the ASU 2018-10 codification improvements standard, as well as to monitor relevant emerging industry guidance regarding the implementation of the standards. As part of this analysis, we are evaluating the potential information technology and internal control changes that will be required for adoption based on the findings from our contract and easement review process. While we have not estimated the quantitative effect that ASC 842 will have on our consolidated financial statements, the adoption of ASC 842 will increase our asset and liability balances on the consolidated balance sheets due to the required recognition of right-of-use assets and corresponding lease liabilities for all lease obligations that are currently classified as operating leases. The Partnership expects to adopt these standards in the first quarter of 2019 and continues to evaluate the other impact of the standards on our Condensed Consolidated Financial Statements and related disclosures. Financial Instruments—Credit Losses In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” This standard requires entities to measure all expected credit losses of financial assets held at a reporting date based on historical experience, current conditions, and reasonable and supportable forecasts in order to record credit losses in a more timely matter. ASU 2016-13 also amends the accounting for credit losses on available-for-sale debt securities and purchased financial assets with credit deterioration. The standard is effective for interim and annual reporting periods beginning after December 15, 2019, although early adoption is permitted for interim and annual periods beginning after December 15, 2018. The Partnership does not expect the adoption of this standard to have a material impact on our Condensed Consolidated Financial Statements and related disclosures. Compensation—Stock Compensation In June 2018, the FASB issued ASU No. 2018-07, “Compensation-Stock Compensation (Topic 718): Improvements to Non-employee Share-Based Payment Accounting.” This standard requires entities to include share-based payment transactions for acquiring goods and services from non-employees. The standard is effective for interim and annual periods beginning after December 15, 2018. The Partnership does not expect the adoption of this standard to have a material impact on our Condensed Consolidated Financial Statements and related disclosures. |
Revenue
Revenue | 6 Months Ended |
Jun. 30, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Revenue | Revenues The Partnership adopted ASU No. 2014-09, “Revenue from Contracts with Customers” (ASC 606) on January 1, 2018 using the modified retrospective method. Upon adoption, the Partnership did not recognize a material cumulative adjustment to Partners’ Equity and there were no material changes in the timing of revenue recognition or our accounting policies. The Partnership has applied the standard to only contracts that were not expired as of January 1, 2018. The following table disaggregates total revenues by major source from contracts with customers and the gain (loss) on derivative activity for the three and six months ended June 30, 2018 , and 2017 . Three Months Ended June 30, 2018 Gathering and Transportation Eliminations Total (In millions) Revenues: Product sales: Natural gas $ 106 $ 143 $ (107 ) $ 142 Natural gas liquids 336 6 (6 ) 336 Condensate 37 — — 37 Total revenues from natural gas, natural gas liquids, and condensate 479 149 (113 ) 515 Gain (loss) on derivative activity (14 ) — — (14 ) Total Product sales $ 465 $ 149 $ (113 ) $ 501 Service revenues: Demand revenues $ 52 $ 113 $ — $ 165 Volume-dependent revenues 124 15 — 139 Total Service revenues $ 176 $ 128 $ — $ 304 Total Revenues $ 641 $ 277 $ (113 ) $ 805 Six Months Ended June 30, 2018 Gathering and Transportation Eliminations Total (In millions) Revenues: Product sales: Natural gas $ 212 $ 274 $ (216 ) $ 270 Natural gas liquids 615 13 (13 ) 615 Condensate 73 — — 73 Total revenues from natural gas, natural gas liquids, and condensate 900 287 (229 ) 958 Gain (loss) on derivative activity (17 ) 2 1 (14 ) Total Product sales $ 883 $ 289 $ (228 ) $ 944 Service revenues: Demand revenues $ 102 $ 233 $ — $ 335 Volume-dependent revenues 247 34 (7 ) 274 Total Service revenues $ 349 $ 267 $ (7 ) $ 609 Total Revenues $ 1,232 $ 556 $ (235 ) $ 1,553 Product Sales Natural Gas, NGLs or Condensate We deliver natural gas, NGLs and condensate to purchasers at contractually agreed-upon delivery points at which the purchaser takes custody, title, and risk of loss of the commodity. We recognize revenue when control transfers to the purchaser at the delivery point based on the contractually agreed upon fixed or index based price received. Gain (Loss) on Derivative Activity Included in Product sales are gains and losses on natural gas, natural gas liquids, and crude oil (for condensate) derivatives that are accounted for under guidance in ASC 815. See Note 9 for further discussion of our derivative and hedging activity. Service Revenues Demand revenues Our demand revenue arrangements are generally structured in one of the following ways: • Under a firm fee arrangement, a customer agrees to pay a fixed fee for a contractually agreed upon pipeline or storage capacity. Once the services have been completed, or the customer no longer has access to the contracted capacity, revenue is recognized. • Under a minimum volume commitment fee arrangement, a customer agrees to pay a contractually agreed upon gathering, compressing and treating fees for a minimum volume of natural gas or crude oil irrespective of whether or not the minimum volume of natural gas or crude oil is delivered. If the actual volumes exceed the minimum volume of natural gas or crude oil, the customer pays the contractually agreed upon gathering, compressing and treating fees for the excess volumes in addition to the fees paid for the minimum volume of natural gas or crude oil. Certain of our contracts provide our customers the option to elect to pay a higher gathering fee over the remaining term of the contract in lieu of making a contractually agreed upon shortfall payment. Once the services have been completed, or the customer no longer has the ability to utilize the services, revenue is recognized. Volume-dependent revenues Our volume-dependent revenues primarily consist of gathering, compressing, treating, processing, transportation or storage services fees on contracts that exceed their contractually committed volume or do not have firm fee arrangements or minimum volume commitments. These fees are dependent on throughput by third party customers, and revenue is recognized over time as the service is performed. Our other fee revenue arrangements have pricing terms that are generally structured in one of the following ways: (1) Contractually agreed upon monetary fee for service or (2) contractually agreed upon consideration received in the form of natural gas or natural gas liquids, which are valued at the current month index based price, which approximates fair value. Accounts Receivable Payments for all types of revenues are typically received within 30 days of invoice. Invoices for all revenue types are sent on at least a monthly basis, except for the shortfall provisions under certain minimum volume commitment contracts, which are typically invoiced annually. Accounts receivable includes accrued revenues associated with certain minimum volume commitments that will be invoiced at the conclusion of the measurement period specified under the respective contracts. June 30, December 31, (In millions) Accounts Receivable: Customers $ 289 $ 265 Contract assets (1) 13 27 Non-customers 6 3 Total Accounts Receivable (2) $ 308 $ 295 ____________________ (1) Contract assets include accrued minimum volume commitments and firm service transportation contracts with tiered rates. (2) Total Accounts Receivable includes Accounts receivables, net of allowance for doubtful accounts and Accounts receivable—affiliated companies. Contract Liabilities Our contract liabilities primarily consist of the following prepayments received from customers: • Under certain firm fee arrangements, customers pay their demand fee prior to the month of contracted capacity. These fees are applied to the subsequent month’s activity and are included in other liabilities on the Condensed Consolidated Balance Sheets. • Under certain demand and volume dependent arrangements, customers make contributions of aid in construction payments. For payments that are related to contracts under ASC 606, the payment is deferred and amortized over the life of the associated contract and the unamortized balance is included in other current or long-term liabilities on the Condensed Consolidated Balance Sheets. The table below summarizes the change in the contract liabilities for the six months ended June 30, 2018 : June 30, December 31, Amounts recognized in revenues (In millions) Deferred revenues $ 49 $ 34 $ 17 The table below summarizes the timing of recognition of these contract liabilities as of June 30, 2018 : 2018 2019 2020 2021 2022 and After (In millions) Deferred revenues $ 21 $ 5 $ 5 $ 5 $ 13 Remaining Performance Obligations Our remaining performance obligations consist primarily of firm fee and minimum volume commitment fee arrangements. Upon completion of the performance obligations associated with these arrangements, customers are invoiced and revenue is recognized as Service revenues in the Condensed Consolidated Statements of Income. The table below summarizes the timing of recognition of the remaining performance obligations as of June 30, 2018 : 2018 2019 2020 2021 2022 and After Transportation and Storage $ 235 $ 373 $ 272 $ 149 $ 746 Gathering and Processing 128 261 160 136 602 Total remaining performance obligations $ 363 $ 634 $ 432 $ 285 $ 1,348 Impact of Adoption Upon adoption of ASC 606, the recognition of revenues for certain contractual arrangements was impacted as follows: • Natural gas and natural gas liquids purchase arrangements - For certain arrangements within our gathering and processing segment, the Partnership purchases and controls the entire hydrocarbon stream at the point of receipt. As of January 1, 2018, these arrangements are considered supplier contracts rather than contracts with customers. Therefore, beginning January 1, 2018, the gathering and processing fees for these arrangements that were previously recognized as Service revenues under ASC 605 are recognized as reductions to Cost of natural gas and natural gas liquids. • Percent-of-proceeds and percent-of-liquids processing arrangements - Under percent-of-proceeds and percent-of-liquids arrangements within our gathering and processing segment, the Partnership has previously recognized the value of natural gas and natural gas liquids received in our purchase cost within Cost of natural gas and natural gas liquids. As of January 1, 2018, the Partnership recognizes the value of the natural gas and NGLs received as Service revenues and as an increase to Cost of natural gas and natural gas liquids when the natural gas or NGLs are sold and Product sales are recognized. • Keep-whole arrangements - Under keep-whole arrangements within our gathering and processing segment, the Partnership has previously recognized the value of NGLs received in Product sales and the value of the thermally equivalent quantity of natural gas provided in our purchase cost within Cost of natural gas and natural gas liquids. As of January 1, 2018, the Partnership recognizes the value of the NGLs received less the value of the thermal equivalent volume of natural gas provided as Service revenues and as an increase to Cost of natural gas and natural gas liquids when the NGLs are sold and Product sales are recognized. • Fixed fuel arrangements - Under certain gathering arrangements within our gathering and processing segment as well as under certain transportation arrangements within our transportation and storage segment we receive a fixed amount of fuel regardless of actual fuel usage. Previously, revenue for fuel in excess of actual usage was recognized when such fuel was received, and additional revenue was recognized when such fuel was sold. As of January 1, 2018, fuel in excess of actual usage is treated as a byproduct obtained through the fulfillment of a contract, and the Partnership will recognize revenue at the time the excess fuel is sold. This results in a reduction of Product sales and a corresponding reduction in Cost of natural gas and natural gas liquids. • Natural gas and natural gas liquids sales arrangements - For certain arrangements within our gathering and processing segment, the Partnership sells the entire hydrocarbon stream at the point of delivery to a third-party processing facility. As of January 1, 2018, these arrangements are considered sales once control has transferred to the third-party processing facility. Therefore, beginning January 1, 2018, the transportation and fractionation fees for these arrangements that were previously recognized as a component of cost of gas and natural gas liquids, are recognized as reductions to the transaction price under ASC 606. Below is a summary of the impact of the changes on revenues as it relates to the three and six months ended June 30, 2018 : Three Months Ended June 30, 2018 Under ASC 606 Under ASC 605 Increase/(Decrease) (In millions) Revenues: Product sales: Natural gas $ 142 $ 155 $ (13 ) Natural gas liquids 336 344 (8 ) Condensate 37 37 — Total revenues from natural gas, natural gas liquids, and condensate 515 536 (21 ) Gain (loss) on derivative activity (14 ) (14 ) — Total Product sales $ 501 $ 522 $ (21 ) Service revenues: Demand revenues $ 165 $ 165 — Volume-dependent revenues 139 139 — Total Service revenues $ 304 $ 304 $ — Total Revenues $ 805 $ 826 $ (21 ) Six Months Ended June 30, 2018 Under ASC 606 Under ASC 605 Increase/(Decrease) (In millions) Revenues: Product sales: Natural gas $ 270 $ 294 $ (24 ) Natural gas liquids 615 627 (12 ) Condensate 73 73 — Total revenues from natural gas, natural gas liquids, and condensate 958 994 (36 ) Gain (loss) on derivative activity (14 ) (14 ) — Total Product sales $ 944 $ 980 $ (36 ) Service revenues: Demand revenues $ 335 $ 335 — Volume-dependent revenues 274 273 1 Total Service revenues $ 609 $ 608 $ 1 Total Revenues $ 1,553 $ 1,588 $ (35 ) As described above, each of the identified increases/(decreases) in revenue resulted in a corresponding change in the Cost of natural gas and natural gas liquids. |
Acquisition
Acquisition | 6 Months Ended |
Jun. 30, 2018 | |
Business Combinations [Abstract] | |
Acquisition | Acquisition Align Acquisition On October 4, 2017, the Partnership acquired all of the equity interests in Align Midstream, LLC, a midstream service provider with natural gas gathering and processing facilities in the Cotton Valley and Haynesville plays of the Ark-La-Tex Basin, for approximately $298 million in cash. The acquisition includes approximately 190 miles of natural gas gathering pipelines across Rusk, Panola and Shelby counties in Texas and DeSoto Parish in Louisiana and a cryogenic natural gas processing plant in Panola County, Texas, with a capacity of 100 MMcf/d. The acquisition was accounted for as a business combination and funded with borrowings under the Revolving Credit Facility. During the fourth quarter of 2017, the Partnership finalized the purchase price allocation as of October 4, 2017. The following table presents the fair value of the identified assets acquired and liabilities assumed at the acquisition date: Purchase price allocation (in millions): Assets acquired: Accounts receivable $ 5 Property, plant and equipment 111 Intangibles 176 Goodwill 12 Liabilities assumed: Current liabilities 6 Total identifiable net assets $ 298 In connection with the acquisition, the Partnership recognized intangible assets related to customer relationships. The acquired intangible assets will be amortized on a straight-line basis over the estimated customer contract life of approximately 10 years. Goodwill recognized from the acquisition primarily relates to greater operating leverage in the Ark-La-Tex Basin and is allocated to the gathering and processing segment. The Partnership incurred approximately $2 million of acquisition costs associated with this transaction, which were included in General and administrative expense in the Consolidated Statements of Income in the fourth quarter of 2017. The Partnership determined not to include pro forma consolidated financial statements for the periods presented as the impact would not be material. |
Earnings Per Limited Partner Un
Earnings Per Limited Partner Unit | 6 Months Ended |
Jun. 30, 2018 | |
Earnings Per Share [Abstract] | |
Earnings Per Limited Partner Unit | Earnings Per Limited Partner Unit The following table illustrates the Partnership’s calculation of earnings per unit for common and subordinated units: Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 (In millions, except per unit data) Net income $ 95 $ 96 $ 209 $ 216 Net income attributable to noncontrolling interest — 1 — 1 Series A Preferred Unit distributions 9 9 18 18 General partner interest in net income — — — — Net income available to common and subordinated unitholders $ 86 $ 86 $ 191 $ 197 Net income allocable to common units $ 86 $ 45 $ 191 $ 102 Net income allocable to subordinated units — 41 — 95 Net income available to common and subordinated unitholders $ 86 $ 86 $ 191 $ 197 Net income allocable to common units $ 86 $ 45 $ 191 $ 102 Dilutive effect of Series A Preferred Unit distributions — — — — Diluted net income allocable to common units 86 45 191 102 Diluted net income allocable to subordinated units — 41 — 95 Total $ 86 $ 86 $ 191 $ 197 Basic weighted average number of outstanding Common units (1) 435 225 434 225 Subordinated units — 208 — 208 Total 435 433 434 433 Basic earnings per unit Common units $ 0.20 $ 0.20 $ 0.44 $ 0.45 Subordinated units $ — $ 0.20 $ — $ 0.46 Basic weighted average number of outstanding common units 435 225 434 225 Dilutive effect of Series A Preferred Units — — — — Dilutive effect of performance units 1 1 1 1 Diluted weighted average number of outstanding common units 436 226 435 226 Diluted weighted average number of outstanding subordinated units — 208 — 208 Total 436 434 435 434 Diluted earnings per unit Common units $ 0.20 $ 0.20 $ 0.44 $ 0.45 Subordinated units $ — $ 0.20 $ — $ 0.46 ____________________ (1) Basic weighted average number of outstanding common units for each of the three and six months ended June 30, 2018 and 2017 includes approximately one million time-based phantom units. See Note 6 for discussion of the expiration of the subordination period. The dilutive effect of the unit-based awards discussed in Note 14 was less than $0.01 per unit during each of the three and six months ended June 30, 2018 and 2017 . |
Partners' Equity
Partners' Equity | 6 Months Ended |
Jun. 30, 2018 | |
Equity [Abstract] | |
Partners' Equity | Partners’ Equity The Partnership Agreement requires that, within 60 days after the end of each quarter, the Partnership distribute all of its available cash (as defined in the Partnership Agreement) to unitholders of record on the applicable record date. The Partnership paid or has authorized payment of the following cash distributions to common and subordinated unitholders, as applicable, during 2017 and 2018 (in millions, except for per unit amounts): Three Months Ended Record Date Payment Date Per Unit Distribution Total Cash Distribution June 30, 2018 (1) August 21, 2018 August 28, 2018 $ 0.318 $ 138 March 31, 2018 May 22, 2018 May 29, 2018 $ 0.318 $ 138 December 31, 2017 February 20, 2018 February 27, 2018 $ 0.318 $ 138 September 30, 2017 November 14, 2017 November 21, 2017 $ 0.318 $ 138 June 30, 2017 August 22, 2017 August 29, 2017 $ 0.318 $ 138 March 31, 2017 May 23, 2017 May 30, 2017 $ 0.318 $ 137 December 31, 2016 February 21, 2017 February 28, 2017 $ 0.318 $ 137 _____________________ (1) The board of directors of Enable GP declared this $0.318 per common unit cash distribution on August 1, 2018 , to be paid on August 28, 2018 , to common unitholders of record at the close of business on August 21, 2018 . The Partnership paid or has authorized payment of the following cash distributions to holders of the Series A Preferred Units during 2017 and 2018 (in millions, except for per unit amounts): Three Months Ended Record Date Payment Date Per Unit Distribution Total Cash Distribution June 30, 2018 (1) August 1, 2018 August 14, 2018 $ 0.625 $ 9 March 31, 2018 May 1, 2018 May 15, 2018 $ 0.625 $ 9 December 31, 2017 February 9, 2018 February 15, 2018 $ 0.625 $ 9 September 30, 2017 October 31, 2017 November 14, 2017 $ 0.625 $ 9 June 30, 2017 July 31, 2017 August 14, 2017 $ 0.625 $ 9 March 31, 2017 May 2, 2017 May 12, 2017 $ 0.625 $ 9 December 31, 2016 February 10, 2017 February 15, 2017 $ 0.625 $ 9 _____________________ (1) The board of directors of Enable GP declared a $0.625 per Series A Preferred Unit cash distribution on August 1, 2018 , to be paid on August 14, 2018 , to Series A Preferred unitholders of record at the close of business on August 1, 2018 . General Partner Interest and Incentive Distribution Rights Enable GP owns a non-economic general partner interest in the Partnership and thus will not be entitled to distributions that the Partnership makes prior to the liquidation of the Partnership in respect of such general partner interest. Enable GP currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50.0% , of the cash the Partnership distributes from operating surplus (as defined in the Partnership Agreement) in excess of $0.330625 per unit per quarter. The maximum distribution of 50.0% does not include any distributions that Enable GP or its affiliates may receive on common units that they own. Expiration of Subordination Period The financial tests required for conversion of all subordinated units were met and the 207,855,430 outstanding subordinated units were converted into common units on a one -for-one basis on August 30, 2017. The conversion of the subordinated units did not change the aggregate amount of outstanding units, and the conversion of the subordinated units did not impact the amount of cash available for distribution by the Partnership. Series A Preferred Units On February 18, 2016, the Partnership completed a private placement of 14,520,000 Series A Preferred Units representing limited partner interests in the Partnership for a cash purchase price of $25.00 per Series A Preferred Unit, resulting in proceeds of $362 million , net of issuance costs. The Partnership incurred approximately $1 million of expenses related to the offering, which is shown as an offset to the proceeds. In connection with the closing of the private placement, the Partnership redeemed approximately $363 million of notes scheduled to mature in 2017 payable to a wholly-owned subsidiary of CenterPoint Energy. Pursuant to the Partnership Agreement , the Series A Preferred Units: • rank senior to the Partnership’s common units with respect to the payment of distributions and distribution of assets upon liquidation, dissolution and winding up; • have no stated maturity; • are not subject to any sinking fund; and • will remain outstanding indefinitely unless repurchased or redeemed by the Partnership or converted into its common units in connection with a change of control. If and when declared by our general partner, holders of the Series A Preferred Units receive a quarterly cash distribution on a non-cumulative basis equal to subject to certain adjustments, an annual rate of: 10% on the stated liquidation preference of $25.00 from the date of original issue to, but not including, the five year anniversary of the original issue date; and thereafter a percentage of the stated liquidation preference equal to the sum of the three-month LIBOR plus 8.5% . At any time on or after five years after the original issue date, the Partnership may redeem the Series A Preferred Units, in whole or in part, from any source of funds legally available for such purpose, by paying $25.50 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. In addition, the Partnership (or a third-party with its prior written consent) may redeem the Series A Preferred Units following certain changes in the methodology employed by ratings agencies, changes of control or fundamental transactions as set forth in the Partnership Agreement . If, upon a change of control or certain fundamental transactions, the Partnership (or a third-party with its prior written consent) does not exercise this option, then the holders of the Series A Preferred Units have the option to convert the Series A Preferred Units into a number of common units per Series A Preferred Unit as set forth in the Partnership Agreement . The Series A Preferred Units are also required to be redeemed in certain circumstances if they are not eligible for trading on the New York Stock Exchange. Holders of Series A Preferred Units have no voting rights except for limited voting rights with respect to potential amendments to the Partnership Agreement that have a material adverse effect on the existing terms of the Series A Preferred Units, the issuance by the Partnership of certain securities, approval of certain fundamental transactions and as required by law. Upon the transfer of any Series A Preferred Unit to a non-affiliate of CenterPoint Energy, the Series A Preferred Units will automatically convert into a new series of preferred units (the Series B Preferred Units) on the later of the date of transfer and the second anniversary of the date of issue. The Series B Preferred Units will have the same terms as the Series A Preferred Units except that unpaid distributions on the Series B Preferred Units will accrue on a cumulative basis until paid. On February 18, 2016, the Partnership entered into a registration rights agreement with CenterPoint Energy, pursuant to which, among other things, the Partnership gave CenterPoint Energy certain rights to require the Partnership to file and maintain a registration statement with respect to the resale of the Series A Preferred Units and any other series of preferred units or common units representing limited partner interests in the Partnership that are issuable upon conversion of the Series A Preferred Units. ATM Program On May 12, 2017, the Partnership entered into an ATM Equity Offering Sales Agreement, pursuant to which the Partnership may issue and sell common units having an aggregate offering price of up to $200 million , by sales methods and at prices determined by market conditions and other factors at the time of our offerings. The Partnership has no obligation to sell any common units under the ATM Program and the Partnership may suspend sales under the ATM Program at any time. During the six months ended June 30, 2018 and 2017 , the Partnership did not issue any common units under the ATM Program. |
Investment in Equity Method Aff
Investment in Equity Method Affiliate | 6 Months Ended |
Jun. 30, 2018 | |
Equity Method Investments and Joint Ventures [Abstract] | |
Investment in Equity Method Affiliate | Investment in Equity Method Affiliate The Partnership uses the equity method of accounting for investments in entities in which it has an ownership interest between 20% and 50% and exercises significant influence. SESH is owned 50% by Spectra Energy Partners, LP and 50% by the Partnership. Pursuant to the terms of the SESH LLC Agreement, if, at any time, CenterPoint Energy has a right to receive less than 50% of our distributions through its interest in the Partnership and its economic interest in Enable GP, or does not have the ability to exercise certain control rights, Spectra Energy Partners, LP may, under certain circumstances, have the right to purchase the Partnership’s interest in SESH at fair market value, subject to certain exceptions. The Partnership shares operations of SESH with Spectra Energy Partners, LP under service agreements. The Partnership is responsible for the field operations of SESH. SESH reimburses each party for actual costs incurred, which are billed based upon a combination of direct charges and allocations. The Partnership billed SESH $6 million during each of the three months ended June 30, 2018 and 2017 , and $8 million and $11 million during the six months ended June 30, 2018 and 2017 , respectively, associated with these service agreements. The Partnership includes equity in earnings of equity method affiliate under the Other Income (Expense) caption in the Condensed Consolidated Statements of Income for the three and six months ended June 30, 2018 and 2017 . Equity in Earnings of Equity Method Affiliate: Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 (In millions) SESH $ 7 $ 7 $ 13 $ 14 Distributions from Equity Method Affiliate: Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 (In millions) SESH (1) $ 8 $ 8 $ 21 $ 19 ___________________ (1) Distributions from equity method affiliate includes a $7 million return on investment and a $1 million return of investment for each of the three months ended June 30, 2018 and 2017 , respectively. Distributions from equity method affiliate includes a $13 million and $14 million return on investment and a $8 million and $5 million return of investment for the six months ended June 30, 2018 and 2017 , respectively. Summarized financial information of SESH: Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 (In millions) Income Statements: Revenues $ 28 $ 28 $ 56 $ 56 Operating income $ 16 $ 18 $ 33 $ 35 Net income $ 13 $ 13 $ 25 $ 26 |
Debt
Debt | 6 Months Ended |
Jun. 30, 2018 | |
Debt Disclosure [Abstract] | |
Debt | Debt The following table presents the Partnership’s outstanding debt as of June 30, 2018 and December 31, 2017 . June 30, 2018 December 31, 2017 Outstanding Principal Premium (Discount) Total Debt Outstanding Principal Premium (Discount) Total Debt (In millions) Commercial Paper $ 327 $ — $ 327 $ 405 $ — $ 405 Revolving Credit Facility — — — — — — 2015 Term Loan Agreement — — — 450 — 450 2019 Notes 500 — 500 500 — 500 2024 Notes 600 — 600 600 — 600 2027 Notes 700 (3 ) 697 700 (3 ) 697 2028 Notes 800 (6 ) 794 — — — 2044 Notes 550 — 550 550 — 550 EOIT Senior Notes 250 10 260 250 13 263 Total debt $ 3,727 $ 1 $ 3,728 $ 3,455 $ 10 $ 3,465 Less: Short-term debt (1) 327 405 Less: Current portion of long-term debt (2) 499 450 Less: Unamortized debt expense (3) 21 15 Total long-term debt $ 2,881 $ 2,595 ____________________ (1) Short-term debt includes $327 million and $405 million of outstanding commercial paper as of June 30, 2018 and December 31, 2017 , respectively. (2) As of June 30, 2018 , Current portion of long-term debt includes the $500 million outstanding balance of the 2019 Notes due May 15, 2019, net of approximately $1 million unamortized debt expense. As of December 31, 2017 , Current portion of long-term debt includes the $450 million outstanding balance of the 2015 Term Loan Agreement. (3) As of June 30, 2018 and December 31, 2017 , there was an additional $6 million and $3 million , respectively, of unamortized debt expense related to the Revolving Credit Facility included in Other long-term assets, not included above. Revolving Credit Facility On April 6, 2018, the Partnership amended and restated its Revolving Credit Facility. As amended and restated, the Revolving Credit Facility is a $1.75 billion , 5 -year senior unsecured revolving credit facility, which under certain circumstances may be increased from time to time up to an additional $875 million , in aggregate. The Revolving Credit Facility is scheduled to mature on April 6, 2023, subject to an extension option, which could be exercised two times to extend the term of the Revolving Credit Facility, in each case, for an additional one -year term. As of June 30, 2018 , there were no principal advances and $3 million in letters of credit outstanding under the Restated Revolving Credit Facility. The Revolving Credit Facility provides that outstanding borrowings bear interest at the LIBOR and/or an alternate base rate, at the Partnership’s election, plus an applicable margin. The applicable margin is based on the Partnership’s applicable credit ratings. As of June 30, 2018 , the applicable margin for LIBOR-based borrowings under the Revolving Credit Facility was 1.50% based on the Partnership’s credit ratings. In addition, the Revolving Credit Facility requires the Partnership to pay a fee on unused commitments. The commitment fee is based on the Partnership’s applicable credit rating from the rating agencies. As of June 30, 2018 , the commitment fee under the Restated Revolving Credit Facility was 0.20% per annum based on the Partnership’s credit ratings. The commitment fee is recorded as interest expense in the Partnership’s Condensed Consolidated Statements of Income. Commercial Paper The Partnership has a commercial paper program, pursuant to which the Partnership is authorized to issue up to $1.4 billion of commercial paper. The commercial paper program is supported by our Revolving Credit Facility, and outstanding commercial paper effectively reduces our borrowing capacity thereunder. There were $327 million and $405 million outstanding under our commercial paper program at June 30, 2018 and December 31, 2017 , respectively. The weighted average interest rate for the outstanding commercial paper was 2.76% as of June 30, 2018 . Term Loan Agreement On July 31, 2015, the Partnership entered into a Term Loan Agreement, providing for an unsecured three -year $450 million term loan agreement, which was scheduled to mature on July 31, 2018. The 2015 Term Loan Agreement is included as Current portion of long-term debt in the Partnership’s Condensed Consolidated Balance Sheets as of December 31, 2017. In May 2018, we used a portion of the proceeds from the issuance of the 2028 Notes to repay all amounts outstanding under the 2015 Term Loan Agreement. Senior Notes On May 10, 2018, the Partnership completed the public offering of $800 million aggregate principal amount of its 4.95% Senior Notes due 2028. The Partnership received net proceeds of approximately $787 million . The proceeds were used for general partnership purposes, including to repay all amounts outstanding under the 2015 Term Loan Agreement, as well as amounts outstanding under the commercial paper program. The 2028 Notes had an unamortized discount of $6 million and unamortized debt expense of $7 million at June 30, 2018 , resulting in an effective interest rate of 5.20% during the six months ended June 30, 2018 . In addition to the 2028 Notes, as of June 30, 2018 , the Partnership’s debt included the 2019 Notes, 2024 Notes, 2027 Notes, and 2044 Notes, which had $14 million of unamortized debt expense at June 30, 2018 , resulting in effective interest rates of 2.57% , 4.02% , 4.58% and 5.08% , respectively, during the six months ended June 30, 2018 . As of June 30, 2018 , the Partnership’s debt included $250 million aggregate principal amount of EOIT’s 6.25% senior notes due 2020 . The EOIT Senior Notes had $10 million of unamortized premium at June 30, 2018 , resulting in an effective interest rate of 3.81% during the six months ended June 30, 2018 . As of June 30, 2018 , the Partnership and EOIT were in compliance with all of their debt agreements, including financial covenants. |
Derivative Instruments and Hedg
Derivative Instruments and Hedging Activities | 6 Months Ended |
Jun. 30, 2018 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Instruments and Hedging Activities | Derivative Instruments and Hedging Activities The Partnership is exposed to certain risks relating to its ongoing business operations. The primary risk managed using derivative instruments is commodity price risk. The Partnership is also exposed to credit risk in its business operations. Commodity Price Risk The Partnership has used forward physical contracts, commodity price swap contracts and commodity price option features to manage the Partnership’s commodity price risk exposures in the past. Commodity derivative instruments used by the Partnership are as follows: • NGL put options, NGL futures and swaps, and WTI crude oil futures and swaps for condensate sales are used to manage the Partnership’s NGL and condensate exposure associated with its processing agreements; • natural gas futures and swaps are used to manage the Partnership’s natural gas exposure associated with its gathering, processing and transportation and storage assets; and • natural gas futures and swaps, natural gas options and natural gas commodity purchases and sales are used to manage the Partnership’s natural gas exposure associated with its storage and transportation contracts and asset management activities. Normal purchases and normal sales contracts are not recorded in Other Assets or Liabilities in the Condensed Consolidated Balance Sheets and earnings are recognized and recorded in the period in which physical delivery of the commodity occurs. Management applies normal purchases and normal sales treatment to: (i) commodity contracts for the purchase and sale of natural gas used in or produced by the Partnership’s operations and (ii) commodity contracts for the purchase and sale of NGLs produced by the Partnership’s gathering and processing business. The Partnership recognizes its non-exchange traded derivative instruments as Other Assets or Liabilities in the Condensed Consolidated Balance Sheets at fair value with such amounts classified as current or long-term based on their anticipated settlement. Exchange traded transactions are settled on a net basis daily through margin accounts with a clearing broker and are recorded as Other Assets or Liabilities in the Condensed Consolidated Balance Sheets at fair value on a net basis with such amounts classified as current or long-term based on their anticipated settlement. As of June 30, 2018 and December 31, 2017 , the Partnership had no derivative instruments that were designated as cash flow or fair value hedges for accounting purposes. Credit Risk The Partnership is exposed to certain credit risks relating to its ongoing business operations. Credit risk includes the risk that counterparties that owe the Partnership money or energy will breach their obligations. If the counterparties to these arrangements fail to perform, the Partnership may seek or be forced to enter into alternative arrangements. In that event, the Partnership’s financial results could be adversely affected, and the Partnership could incur losses. Derivatives Not Designated As Hedging Instruments Derivative instruments not designated as hedging instruments for accounting purposes are utilized in the Partnership’s asset management activities. For derivative instruments not designated as hedging instruments, the gain or loss on the derivative is recognized currently in earnings. Quantitative Disclosures Related to Derivative Instruments The majority of natural gas physical purchases and sales not designated as hedges for accounting purposes are priced based on a monthly or daily index, and the fair value is subject to little or no market price risk. Natural gas physical sales volumes exceed natural gas physical purchase volumes due to the marketing of natural gas volumes purchased via the Partnership’s processing contracts, which are not derivative instruments. As of June 30, 2018 and December 31, 2017 , the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes: June 30, 2018 December 31, 2017 Gross Notional Volume Purchases Sales Purchases Sales Natural gas— TBtu (1) Financial fixed futures/swaps 19 26 17 13 Financial basis futures/swaps 24 36 17 17 Physical purchases/sales 3 70 1 37 Crude oil (for condensate)— MBbl (2) Financial Futures/swaps — 934 — 564 Natural gas liquids— MBbl (3) Financial Futures/swaps 75 2,495 — 1,615 ____________________ (1) As of June 30, 2018 , 81.7% of the natural gas contracts had durations of one year or less, 13.7% had durations of more than one year and less than two years and 4.6% had durations of more than two years. As of December 31, 2017 , 67.7% of the natural gas contracts had durations of one year or less, 16.1% had durations of more than one year and less than two years and 16.2% had durations of more than two years. (2) As of June 30, 2018 , 67.9% of the crude oil (for condensate) contracts had durations of one year or less and 32.1% had durations of more than one year and less than two years. As of December 31, 2017 , 100% of the crude oil (for condensate) contracts had durations of one year or less. (3) As of June 30, 2018 , 74.3% of the natural gas liquids contracts had durations of one year or less and 25.7% had durations of more than one year and less than two years. As of December 31, 2017 , 100% of the natural gas liquid contracts had durations of one year or less. Balance Sheet Presentation Related to Derivative Instruments The fair value of the derivative instruments that are presented in the Partnership’s Condensed Consolidated Balance Sheets as of June 30, 2018 and December 31, 2017 that were not designated as hedging instruments for accounting purposes are as follows: June 30, 2018 December 31, 2017 Fair Value Instrument Balance Sheet Location Assets Liabilities Assets Liabilities (In millions) Natural gas Financial futures/swaps Other Current/Other $ 2 $ 8 $ 5 $ 4 Physical purchases/sales Other Current/Other 6 — 3 — Crude oil (for condensate) Financial futures/swaps Other Current/Other — 9 — 4 Natural gas liquids Financial Futures/swaps Other Current/Other 1 8 1 5 Total gross derivatives (1) $ 9 $ 25 $ 9 $ 13 _____________________ (1) See Note 10 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Condensed Consolidated Balance Sheets as of June 30, 2018 and December 31, 2017 . Income Statement Presentation Related to Derivative Instruments The following table presents the effect of derivative instruments on the Partnership’s Condensed Consolidated Statements of Income for the three and six months ended June 30, 2018 and 2017 : Amounts Recognized in Income Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 (In millions) Natural gas Financial futures/swaps (losses) gains $ (1 ) $ 5 $ (5 ) $ 16 Physical purchases/sales gains 2 2 5 7 Crude oil (for condensate) Financial futures/swaps (losses) gains (6 ) 2 (10 ) 5 Natural gas liquids Financial futures/swaps (losses) gains (9 ) — (4 ) 2 Total $ (14 ) $ 9 $ (14 ) $ 30 For derivatives not designated as hedges in the tables above, amounts recognized in income for the periods ended June 30, 2018 and 2017 , if any, are reported in Product sales. The following table presents the components of gain (loss) on derivative activity in the Partnership’s Condensed Consolidated Statements of Income for the three and six months ended June 30, 2018 and 2017 : Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 (In millions) Change in fair value of derivatives $ (10 ) $ 11 $ (12 ) $ 35 Realized gain (loss) on derivatives (4 ) (2 ) (2 ) (5 ) Gain (loss) on derivative activity $ (14 ) $ 9 $ (14 ) $ 30 Credit-Risk Related Contingent Features in Derivative Instruments In the event Moody’s Investors Services or Standard & Poor’s Ratings Services were to lower the Partnership’s senior unsecured debt rating to a below investment grade rating, the Partnership could be required to provide additional credit assurances to third parties, which could include letters of credit or cash collateral to satisfy its obligation under its financial and physical contracts relating to derivative instruments that are in a net liability position. As of June 30, 2018 , under these obligations, the Partnership has posted $2 million of cash collateral related to NGL and crude swaps and $14 million of additional collateral may be required to be posted by the Partnership in the event of a credit ratings downgrade to a below investment grade rating. |
Fair Value Measurements
Fair Value Measurements | 6 Months Ended |
Jun. 30, 2018 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | Fair Value Measurements Certain assets and liabilities are recorded at fair value in the Condensed Consolidated Balance Sheets and are categorized based upon the level of judgment associated with the inputs used to measure their value. Hierarchical levels, as defined below and directly related to the amount of subjectivity associated with the inputs to fair valuations of these assets and liabilities are as follows: Level 1: Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. Instruments classified as Level 1 include natural gas futures, swaps and options transactions for contracts traded on the NYMEX and settled through a NYMEX clearing broker. Level 2: Inputs, other than quoted prices included in Level 1, are observable for the asset or liability, either directly or indirectly. Level 2 inputs include quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities that are generally included in this category are derivatives with fair values based on inputs from actively quoted markets. Instruments classified as Level 2 include over-the-counter NYMEX natural gas swaps, natural gas basis swaps and natural gas purchase and sales transactions in markets such that the pricing is closely related to the NYMEX pricing, and over-the-counter WTI crude oil swaps for condensate sales. Level 3: Inputs are unobservable for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. Unobservable inputs reflect the Partnership’s judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. The Partnership develops these inputs based on the best information available, including the Partnership’s own data. The Partnership utilizes the market approach in determining the fair value of its derivative positions by using either NYMEX or WTI published market prices, independent broker pricing data or broker/dealer valuations. The valuations of derivatives with pricing based on NYMEX published market prices may be considered Level 1 if they are settled through a NYMEX clearing broker account with daily margining. Over-the-counter derivatives with NYMEX or WTI based prices are considered Level 2 due to the impact of counterparty credit risk. Valuations based on independent broker pricing or broker/dealer valuations may be classified as Level 2 only to the extent they may be validated by an additional source of independent market data for an identical or closely related active market. In certain less liquid markets or for longer-term contracts, forward prices are not as readily available. In these circumstances, contracts are valued using internally developed methodologies that consider historical relationships among various quoted prices in active markets that result in management’s best estimate of fair value. These contracts are classified as Level 3. The Partnership determines the appropriate level for each financial asset and liability on a quarterly basis and recognizes transfers between levels at the end of the reporting period. For the period ended June 30, 2018 , there were no transfers between levels. The impact to the fair value of derivatives due to credit risk is calculated using the probability of default based on Standard & Poor’s Ratings Services and/or internally generated ratings. The fair value of derivative assets is adjusted for credit risk. The fair value of derivative liabilities is adjusted for credit risk only if the impact is deemed material. Estimated Fair Value of Financial Instruments The fair values of all accounts receivable, notes receivable, accounts payable, commercial paper and other such financial instruments on the Condensed Consolidated Balance Sheets are estimated to be approximately equivalent to their carrying amounts due to their short-term nature and have been excluded from the table below. The following table summarizes the fair value and carrying amount of the Partnership’s financial instruments as of June 30, 2018 and December 31, 2017 . June 30, 2018 December 31, 2017 Carrying Amount Fair Value Carrying Amount Fair Value (In millions) Debt Revolving Credit Facility (Level 2) (1) $ — $ — $ — $ — 2015 Term Loan Agreement (Level 2) — — 450 450 2019 Notes (Level 2) 500 497 500 497 2024 Notes (Level 2) 600 578 600 602 2027 Notes (Level 2) 697 663 697 712 2028 Notes 794 780 — — 2044 Notes (Level 2) 550 487 550 550 EOIT Senior Notes (Level 2) 260 259 263 265 ____________________ (1) Borrowing capacity is effectively reduced by our borrowings outstanding under the commercial paper program. $327 million and $405 million of commercial paper was outstanding as of June 30, 2018 and December 31, 2017 , respectively. The fair value of the Partnership’s Revolving Credit Facility, 2015 Term Loan Agreement, 2019 Notes, 2024 Notes, 2027 Notes, 2028 Notes, 2044 Notes and EOIT Senior Notes is based on quoted market prices and estimates of current rates available for similar issues with similar maturities and is classified as Level 2 in the fair value hierarchy. Non-Financial Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Certain assets and liabilities are measured at fair value on a nonrecurring basis; that is, the assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances (e.g., when there is evidence of impairment). As of June 30, 2018 , no material fair value adjustments or fair value measurements were required for these non-financial assets or liabilities. Contracts with Master Netting Arrangements Fair value amounts recognized for forward, interest rate swap, option and other conditional or exchange contracts executed with the same counterparty under a master netting arrangement may be offset. The reporting entity’s choice to offset or not must be applied consistently. A master netting arrangement exists if the reporting entity has multiple contracts, whether for the same type of conditional or exchange contract or for different types of contracts, with a single counterparty that are subject to a contractual agreement that provides for the net settlement of all contracts through a single payment in a single currency in the event of default on or termination of any one contract. Offsetting the fair values recognized for forward, interest rate swap, option and other conditional or exchange contracts outstanding with a single counterparty results in the net fair value of the transactions being reported as an asset or a liability in the Condensed Consolidated Balance Sheets. The Partnership has presented the fair values of its derivative contracts under master netting agreements using a net fair value presentation. The following tables summarize the Partnership’s assets and liabilities that are measured at fair value on a recurring basis as of June 30, 2018 and December 31, 2017 : June 30, 2018 Commodity Contracts Gas Imbalances (1) Assets Liabilities Assets (2) Liabilities (3) (In millions) Quoted market prices in active market for identical assets (Level 1) $ 2 $ 6 $ — $ — Significant other observable inputs (Level 2) 6 11 15 15 Unobservable inputs (Level 3) 1 8 — — Total fair value 9 25 15 15 Netting adjustments (2 ) (2 ) — — Total $ 7 $ 23 $ 15 $ 15 December 31, 2017 Commodity Contracts Gas Imbalances (1) Assets Liabilities Assets (2) Liabilities (3) (In millions) Quoted market prices in active market for identical assets (Level 1) $ 5 $ 3 $ — $ — Significant other observable inputs (Level 2) 4 5 27 12 Unobservable inputs (Level 3) — 5 — — Total fair value 9 13 27 12 Netting adjustments (5 ) (5 ) — — Total $ 4 $ 8 $ 27 $ 12 ______________________ (1) The Partnership uses the market approach to fair value its gas imbalance assets and liabilities at individual, or where appropriate an average of, current market indices applicable to the Partnership’s operations, not to exceed net realizable value. Gas imbalances held by EOIT are valued using an average of the Inside FERC Gas Market Report for Panhandle Eastern Pipe Line Co. (Texas, Oklahoma Mainline), ONEOK (Oklahoma) and ANR Pipeline (Oklahoma) indices. There were no netting adjustments as of June 30, 2018 and December 31, 2017 . (2) Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $14 million and $10 million at June 30, 2018 and December 31, 2017 , respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created, and which are not subject to revaluation at fair market value. (3) Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $1 million and zero at June 30, 2018 and December 31, 2017 , respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created, and which are not subject to revaluation at fair market value. Changes in Level 3 Fair Value Measurements The following table provides a reconciliation of changes in the fair value of our Level 3 commodity contracts between the periods presented. Commodity Contracts Natural gas liquids financial futures/swaps (In millions) Balance at December 31, 2017 $ (5 ) Losses included in earnings (4 ) Settlements 2 Transfers out of Level 3 — Balance as of June 30, 2018 $ (7 ) Quantitative Information on Level 3 Fair Value Measurements The Partnership utilizes the market approach to measure the fair value of our commodity contracts. The significant unobservable inputs used in this approach to fair value are longer dated price quotes. Our sensitivity to these longer dated forward curve prices are presented in the table below. Significant changes in any of those inputs in isolation would result in significantly different fair value measurements, depending on our short or long position in contracts. June 30, 2018 Product Group Fair Value Forward Curve Range (In millions) (Per gallon) Natural gas liquids $ (7 ) $0.10 - $1.1113 |
Supplemental Disclosure of Cash
Supplemental Disclosure of Cash Flow Information | 6 Months Ended |
Jun. 30, 2018 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Disclosure of Cash Flow Information | Supplemental Disclosure of Cash Flow Information The following table provides information regarding supplemental cash flow information: Six Months Ended June 30, 2018 2017 (In millions) Supplemental Disclosure of Cash Flow Information: Cash Payments: Interest, net of capitalized interest $ 65 $ 50 Income taxes, net of refunds 1 — Non-cash transactions: Accounts payable related to capital expenditures 42 24 The following table reconciles cash and cash equivalents and restricted cash on the Condensed Consolidated Balance Sheets to cash, cash equivalents and restricted cash on the Condensed Consolidated Statements of Cash Flows: Six Months Ended June 30, 2018 2017 (In millions) Cash and cash equivalents $ 7 $ 7 Restricted cash 14 14 Cash, cash equivalents and restricted cash shown in the Condensed Consolidated Statements of Cash Flows $ 21 $ 21 |
Related Party Transactions
Related Party Transactions | 6 Months Ended |
Jun. 30, 2018 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | Related Party Transactions The material related party transactions with CenterPoint Energy, OGE Energy and their respective subsidiaries are summarized below. There were no material related party transactions with other affiliates. Transportation and Storage Agreements Transportation and Storage Agreements with CenterPoint Energy EGT provides the following services to CenterPoint Energy’s LDCs in Arkansas, Louisiana, Oklahoma and Northeast Texas. Those services include firm transportation with seasonal contract demand, firm storage, no notice transportation with associated storage and maximum rate firm transportation. Contracts for firm transportation with seasonal contract demand, firm storage, firm no notice transportation with storage for CenterPoint’s LDCs in Arkansas, Louisiana, Oklahoma and Northeast Texas are in effect through March 21, 2021 and will remain in effect thereafter unless and until terminated by either party upon 180 days’ prior written notice. Contracts for maximum firm rate transportation for CenterPoint’s LDCs in Oklahoma and portions of Northeast Texas are also in effect through March 21, 2021. Contracts for CenterPoint’s LDCs in Arkansas, Louisiana and Texarkana, Texas terminated on March 31, 2018. MRT provides transportation and storage services to CenterPoint Energy’s LDCs in Arkansas and Louisiana. Contracts for these services are in effect through May 15, 2023 and will remain in effect thereafter unless and until terminated by either party upon 12 months’ prior written notice. Transportation and Storage Agreement with OGE Energy EOIT provides no-notice load-following transportation and storage services to OGE Energy. On March 17, 2014, EOIT entered into a transportation agreement with OGE Energy, with a primary term of May 1, 2014 through April 30, 2019. Following the primary term, the agreement will remain in effect from year to year thereafter unless either party provides notice of termination to the other party at least 180 days prior to the commencement of the succeeding annual period. On December 6, 2016, EOIT entered into a transportation agreement with OGE Energy, with a primary term expected to begin in late 2018 and extend for 20 years. In connection with the agreement, an approximately 80 -mile pipeline will be built to expand the EOIT system. Gas Sales and Purchases Transactions The Partnership sells natural gas volumes to affiliates of CenterPoint Energy and OGE Energy or purchases natural gas volumes from affiliates of CenterPoint Energy through a combination of forward, monthly and daily transactions. The Partnership enters into these physical natural gas transactions in the normal course of business based upon relevant market prices. The Partnership’s revenues from affiliated companies accounted for 4% and 5% of total revenues during the three months ended June 30, 2018 and 2017 , respectively, and 5% and 6% of total revenues during the six months ended June 30, 2018 and 2017 , respectively. Amounts of revenues from affiliated companies included in the Partnership’s Condensed Consolidated Statements of Income are summarized as follows: Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 (In millions) Gas transportation and storage service revenues — CenterPoint Energy $ 24 $ 24 $ 57 $ 57 Natural gas product sales — CenterPoint Energy 2 1 8 1 Gas transportation and storage service revenues — OGE Energy 9 9 18 18 Natural gas product sales — OGE Energy 1 — 2 — Total revenues — affiliated companies $ 36 $ 34 $ 85 $ 76 Amounts of natural gas purchased from affiliated companies included in the Partnership’s Condensed Consolidated Statements of Income are summarized as follows: Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 (In millions) Cost of natural gas purchases — CenterPoint Energy $ — $ 1 $ 2 $ 1 Cost of natural gas purchases — OGE Energy 5 4 8 7 Total cost of natural gas purchases — affiliated companies $ 5 $ 5 $ 10 $ 8 Seconded employees, corporate services and operating lease expense As of June 30, 2018 , the Partnership had certain employees who are participants under OGE Energy’s defined benefit and retiree medical plans, who will remain seconded to the Partnership, subject to certain termination rights of the Partnership and OGE Energy. The Partnership’s reimbursement of OGE Energy for seconded employee costs arising out of OGE Energy’s defined benefit and retiree medical plans is fixed at actual cost subject to a cap of $5 million in 2018 and thereafter, unless and until secondment is terminated. The Partnership receives services and support functions from each of CenterPoint Energy and OGE Energy under services agreements for an initial term that ended on April 30, 2016. The services agreements automatically extend year-to-year at the end of the initial term, unless terminated by the Partnership with at least 90 days’ notice prior to the end of any extension. Additionally, the Partnership may terminate the services agreements at any time with 180 days’ notice, if approved by the Board of Enable GP. The Partnership reimburses CenterPoint Energy and OGE Energy for these services up to annual caps, which for 2018 are $4 million and $1 million , respectively. The Partnership leases office and data center space from an affiliate of CenterPoint Energy in Shreveport, Louisiana. The term of the lease commenced on October 1, 2016 and extends through December 31, 2019. The Partnership expects to incur approximately $3 million in rent and maintenance expenses during the initial term of the lease. As of June 30, 2018 , CenterPoint Energy continues to provide office and data center space to the Partnership in Houston, Texas, under the services agreement. During the first quarter of 2018 the Partnership provided notice to Centerpoint Energy of its intent to terminate the provision of office space in Houston, Texas on August 31, 2018. Amounts charged to the Partnership by affiliates for seconded employees, an operating lease and corporate services, included primarily in Operation and maintenance and General and administrative expenses in the Partnership’s Condensed Consolidated Statements of Income are as follows: Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 (In millions) Corporate Services — CenterPoint Energy $ — $ 1 $ 1 $ 2 Seconded Employee Costs — OGE Energy 7 9 15 16 Corporate Services — OGE Energy 1 1 1 2 Total corporate services and seconded employees expense $ 8 $ 11 $ 17 $ 20 Series A Preferred Units On February 18, 2016, the Partnership completed a private placement to CenterPoint Energy of 14,520,000 Series A Preferred Units representing limited partner interests in the Partnership for a cash purchase price of $25.00 per Series A Preferred Unit, resulting in proceeds of $362 million , net of issuance costs. See Note 6 for further discussion of the Series A Preferred Units. |
Commitments and Contingencies
Commitments and Contingencies | 6 Months Ended |
Jun. 30, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies The Partnership is involved in legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. Some of these proceedings involve substantial amounts. The Partnership regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. The Partnership does not expect the disposition of these matters to have a material adverse effect on its financial condition, results of operations or cash flows. On January 1, 2017, the Partnership entered into a 10 -year gathering and processing agreement, which became effective on July 1, 2018, with an affiliate of Energy Transfer Partners, LP for 400 MMcf/d of deliveries to the Godley Plant in Johnson County, Texas. As of June 30, 2018 , the Partnership estimates the associated 10 -year minimum volume commitment fee to be $226 million . |
Equity-Based Compensation
Equity-Based Compensation | 6 Months Ended |
Jun. 30, 2018 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Equity-Based Compensation | Equity-Based Compensation The following table summarizes the Partnership’s compensation expense for the three and six months ended June 30, 2018 and 2017 related to performance units, restricted units, and phantom units for the Partnership’s employees and independent directors: Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 (In millions) Performance units $ 2 $ 2 $ 5 $ 5 Restricted units — 1 1 1 Phantom units 1 1 2 2 Total compensation expense $ 3 $ 4 $ 8 $ 8 Units Outstanding The Partnership periodically grants performance units, restricted units and phantom units to certain employees under the Enable Midstream Partners, LP Long Term Incentive Plan. A summary of the activity for the Partnership’s performance units, restricted units, and phantom units applicable to the Partnership’s employees at June 30, 2018 and changes during 2018 are shown in the following table. Performance Units Restricted Units Phantom Units Number of Units Weighted Average Grant-Date Fair Value, Per Unit Number of Units Weighted Average Grant-Date Fair Value, Per Unit Number of Units Weighted Average Grant-Date Fair Value, Per Unit (In millions, except unit data) Units Outstanding at December 31, 2017 2,040,407 $ 13.86 222,434 $ 17.87 987,380 $ 11.38 Granted (1) 529,408 17.70 — — 503,285 14.04 Vested (2) (401,772 ) 16.59 (206,068 ) 17.46 (4,540 ) 8.87 Forfeited (62,465 ) 13.95 (1,366 ) 16.75 (43,341 ) 12.40 Units Outstanding at June 30, 2018 2,105,578 $ 14.30 15,000 $ 23.56 1,442,784 $ 12.29 Aggregate Intrinsic Value of Units Outstanding at June 30, 2018 $ 36 $ — $ 25 _____________________ (1) Performance units represents the target number of performance units granted. The actual number of performance units earned, if any, is dependent upon performance and may range from zero percent to 200 percent of the target. (2) Performance units vested as of June 30, 2018 include 401,772 units from the annual grant, which were approved by the Board of Directors in 2015 and paid out at 200% , or 803,544 units, based on the level of achievement of a performance goal established by the Board of Directors over the performance period. Unrecognized Compensation Cost A summary of the Partnership’s unrecognized compensation cost for its non-vested performance units, restricted units, and phantom units, and the weighted-average periods over which the compensation cost is expected to be recognized are shown in the following table. June 30, 2018 Unrecognized Compensation Cost (In millions) Weighted Average to be Recognized (In years) Performance Units $ 16 1.41 Restricted Units — 0.33 Phantom Units 11 1.61 Total $ 27 As of June 30, 2018 , there were 7,587,153 units available for issuance under the long-term incentive plan. |
Reportable Segments
Reportable Segments | 6 Months Ended | |
Jun. 30, 2018 | ||
Segment Reporting [Abstract] | ||
Reportable Segments | Reportable Segments The Partnership’s determination of reportable segments considers the strategic operating units under which it manages sales, allocates resources and assesses performance of various products and services to customers in differing regulatory environments. The accounting policies of the reportable segments are the same as those described in the summary of significant accounting policies excerpt in the Partnership’s audited 2017 consolidated financial statements included in the Annual Report. The Partnership uses operating income as the measure of profit or loss for its reportable segments. The Partnership’s assets and operations are organized into two reportable segments: (i) gathering and processing, which primarily provides natural gas and crude oil gathering and natural gas processing services to our producer customers, and (ii) transportation and storage, which provides interstate and intrastate natural gas pipeline transportation and storage service primarily to our producer, power plant, LDC and industrial end-user customers. Financial data for reportable segments are as follows: Three Months Ended June 30, 2018 Gathering and Transportation (1) Eliminations Total (In millions) Product sales $ 465 $ 149 $ (113 ) $ 501 Service revenues 176 128 — 304 Total Revenues 641 277 (113 ) 805 Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately) 411 147 (114 ) 444 Operation and maintenance, General and administrative 76 47 — 123 Depreciation and amortization 63 33 — 96 Taxes other than income tax 10 6 — 16 Operating income $ 81 $ 44 $ 1 $ 126 Capital expenditures $ 143 $ 42 $ — $ 185 Total assets $ 9,254 $ 5,681 $ (3,143 ) $ 11,792 Three Months Ended June 30, 2017 Gathering and Transportation (1) Eliminations Total (In millions) Product sales $ 336 $ 134 $ (116 ) $ 354 Service revenues 144 129 (1 ) 272 Total Revenues 480 263 (117 ) 626 Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately) 269 127 (117 ) 279 Operation and maintenance, General and administrative 75 45 — 120 Depreciation and amortization 55 34 — 89 Taxes other than income tax 9 7 — 16 Operating income $ 72 $ 50 $ — $ 122 Capital expenditures $ 39 $ 48 $ — $ 87 Total assets as of December 31, 2017 $ 9,079 $ 5,616 $ (3,102 ) $ 11,593 _____________________ (1) See Note 7 for discussion regarding ownership interests in SESH and related equity earnings included in the transportation and storage segment for the three and six months ended June 30, 2018 and 2017 . Six Months Ended June 30, 2018 Gathering and Processing Transportation and Storage (1) Eliminations Total (In millions) Product sales $ 883 $ 289 $ (228 ) $ 944 Service revenues 349 267 (7 ) 609 Total Revenues 1,232 556 (235 ) 1,553 Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately) 769 286 (236 ) 819 Operation and maintenance, General and administrative 152 93 (1 ) 244 Depreciation and amortization 125 67 — 192 Taxes other than income tax 20 13 — 33 Operating income $ 166 $ 97 $ 2 $ 265 Capital expenditures $ 291 $ 84 $ — $ 375 Total assets $ 9,254 $ 5,681 $ (3,143 ) $ 11,792 Six Months Ended June 30, 2017 Gathering and Processing Transportation and Storage (1) Eliminations Total (In millions) Product sales $ 687 $ 287 $ (234 ) $ 740 Service revenues 284 270 (2 ) 552 Total Revenues 971 557 (236 ) 1,292 Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately) 555 267 (235 ) 587 Operation and maintenance, General and administrative 145 90 (1 ) 234 Depreciation and amortization 111 66 — 177 Taxes other than income tax 18 14 — 32 Operating income $ 142 $ 120 $ — $ 262 Capital expenditures $ 90 $ 58 $ — $ 148 Total assets as of December 31, 2017 $ 9,079 $ 5,616 $ (3,102 ) $ 11,593 _____________________ (1) See Note 7 for discussion regarding ownership interests in SESH and related equity earnings included in the transportation and storage segment for the three and six months ended June 30, 2018 and 2017 . | [1] |
[1] | See Note 7 for discussion regarding ownership interests in SESH and related equity earnings included in the transportation and storage segment for the three and six months ended June 30, 2018 and 2017. |
Summary of Significant Accoun22
Summary of Significant Accounting Policies (Policies) | 6 Months Ended |
Jun. 30, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization | Organization Enable Midstream Partners, LP is a Delaware limited partnership formed on May 1, 2013 by CenterPoint Energy, OGE Energy and ArcLight. The Partnership’s assets and operations are organized into two reportable segments: (i) gathering and processing and (ii) transportation and storage. The gathering and processing segment primarily provides natural gas and crude oil gathering and natural gas processing services to our producer customers. The transportation and storage segment provides interstate and intrastate natural gas pipeline transportation and storage services primarily to our producer, power plant, LDC and industrial end-user customers. The Partnership’s natural gas gathering and processing assets are primarily located in Oklahoma, Texas, Arkansas and Louisiana and serve natural gas production in the Anadarko, Arkoma and Ark-La-Tex Basins. Crude oil gathering assets are located in North Dakota and serve crude oil production in the Bakken Shale formation of the Williston Basin. The Partnership’s natural gas transportation and storage assets consist primarily of an interstate pipeline system extending from western Oklahoma and the Texas Panhandle to Louisiana, an interstate pipeline system extending from Louisiana to Illinois, an intrastate pipeline system in Oklahoma, and our investment in SESH, an interstate pipeline extending from Louisiana to Alabama. CenterPoint Energy and OGE Energy each have 50% of the management interests in Enable GP. Enable GP is the general partner of the Partnership and has no other operating activities. Enable GP is governed by a board made up of two representatives designated by each of CenterPoint Energy and OGE Energy, along with the Partnership’s Chief Executive Officer and three independent board members CenterPoint Energy and OGE Energy mutually agreed to appoint. CenterPoint Energy and OGE Energy also own a 40% and 60% interest, respectively, in the incentive distribution rights held by Enable GP. As of June 30, 2018 , CenterPoint Energy held approximately 54.0% or 233,856,623 of the Partnership’s common units, and OGE Energy held approximately 25.6% or 110,982,805 of the Partnership’s common units. Additionally, CenterPoint Energy holds 14,520,000 Series A Preferred Units. See Note 6 for further information related to the Series A Preferred Units. The limited partner interests of the Partnership have limited voting rights on matters affecting the business. As such, limited partners do not have rights to elect the Partnership’s general partner on an annual or continuing basis and may not remove Enable GP, its current general partner, without at least a 75% vote by all unitholders, including all units held by the Partnership’s limited partners, and Enable GP and its affiliates, voting together as a single class. As of June 30, 2018 , the Partnership owned a 50% interest in SESH. See Note 7 for further discussion of SESH. |
Basis of Presentation | Basis of Presentation The accompanying condensed consolidated financial statements and related notes of the Partnership have been prepared pursuant to the rules and regulations of the SEC and GAAP. Pursuant to such rules and regulations, certain disclosures normally included in financial statements prepared in accordance with GAAP have been omitted. The accompanying condensed consolidated financial statements and related notes should be read in conjunction with the consolidated financial statements and related notes included in our Annual Report. The condensed consolidated financial statements and the related notes reflect all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position and results of operations for the respective periods. Amounts reported in the Partnership’s Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for a full-year period due to the effects of, among other things, (a) seasonal fluctuations in demand for energy and energy services, (b) changes in energy commodity prices, (c) timing of maintenance and other expenditures and (d) acquisitions and dispositions of businesses, assets and other interests. |
Use of Estimates | Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. |
Restricted Cash | Restricted Cash Restricted cash primarily consists of cash collateral which is provided as credit assurance by third parties. |
Accounts Receivable and Allowance for Doubtful Accounts | Accounts Receivable and Allowance for Doubtful Accounts Accounts receivable are recorded at the invoiced amount and do not typically bear interest. The determination of the allowance for doubtful accounts requires management to make estimates and judgments regarding our customers’ ability to pay. The allowance for doubtful accounts is determined based upon specific identification and estimates of future uncollectable amounts. On an ongoing basis, management evaluates our customers’ financial strength based on aging of accounts receivable, payment history, and review of other relevant information, including ratings agency credit ratings and alerts, publicly available reports and news releases, and bank and trade references. It is the policy of management to review the outstanding accounts receivable at least quarterly, giving consideration to historical bad debt write-offs, the aging of receivables and specific customer circumstances that may impact their ability to pay the amounts due. |
Inventory | Inventory Natural gas inventory is held, through the transportation and storage segment, to provide operational support for the intrastate pipeline deliveries and to manage leased intrastate storage capacity. Natural gas liquids inventory is held, through the gathering and processing segment, due to timing differences between the production of certain natural gas liquids and ultimate sale to third parties. Natural gas and natural gas liquids inventory is valued using moving average cost and is subsequently recorded at the lower of cost or net realizable value. |
Income Taxes | Income Taxes The Partnership’s earnings are not subject to income tax (other than Texas state margin taxes and taxes associated with the Partnership’s corporate subsidiary, Enable Midstream Services) and are taxable at the individual partner level. We account for deferred income taxes related to the federal and state jurisdictions using the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future taxes attributable to the difference between financial statement carrying amounts of assets and liabilities and their respective tax basis. Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of tax net operating loss carryforwards. In the event future utilization is determined to be unlikely, a valuation allowance is provided to reduce the tax benefits from such assets. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the period in which the temporary differences and carryforwards are expected to be recovered or settled. The effect of a change in tax rates is recognized in the period which includes the enactment date. The Partnership recognizes interest and penalties as a component of income tax expense. |
New Accounting Pronouncements | New Accounting Pronouncements Accounting Standards to be Adopted in Future Periods Leases In February 2016, the FASB issued ASU 2016-02, “Leases (ASC 842).” This standard requires, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. In January 2018, the FASB issued ASU 2018-01, “Land Easement Practical Expedient for Transition to Topic 842.” This standard permits an entity to elect an optional transition practical expedient to not evaluate land easements that exist or expire before the Partnership's adoption of ASC 842 and that were not previously accounted for as leases under ASC 840. The Partnership intends to elect this transition provision. In July 2018, the FASB issued ASU No. 2018-10, “Codification Improvements to Topic 842, Leases,” which finalizes Proposed Accounting Standards Update (ASU) No. 2017-310, Technical Corrections and Improvements to Recently Issued Standards-Accounting Standards Update No. 2016-02, Leases (Topic 842), to address implementation issues that could arise as organizations comply with ASU No. 2016-02, Leases (Topic 842). We are currently evaluating this ASU and its potential impact on our implementation. The Partnership continues to review contracts and easements relative to the provisions of the ASU 2016-02 lease standard, the ASU 2018-01 easement standard and the ASU 2018-10 codification improvements standard, as well as to monitor relevant emerging industry guidance regarding the implementation of the standards. As part of this analysis, we are evaluating the potential information technology and internal control changes that will be required for adoption based on the findings from our contract and easement review process. While we have not estimated the quantitative effect that ASC 842 will have on our consolidated financial statements, the adoption of ASC 842 will increase our asset and liability balances on the consolidated balance sheets due to the required recognition of right-of-use assets and corresponding lease liabilities for all lease obligations that are currently classified as operating leases. The Partnership expects to adopt these standards in the first quarter of 2019 and continues to evaluate the other impact of the standards on our Condensed Consolidated Financial Statements and related disclosures. Financial Instruments—Credit Losses In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” This standard requires entities to measure all expected credit losses of financial assets held at a reporting date based on historical experience, current conditions, and reasonable and supportable forecasts in order to record credit losses in a more timely matter. ASU 2016-13 also amends the accounting for credit losses on available-for-sale debt securities and purchased financial assets with credit deterioration. The standard is effective for interim and annual reporting periods beginning after December 15, 2019, although early adoption is permitted for interim and annual periods beginning after December 15, 2018. The Partnership does not expect the adoption of this standard to have a material impact on our Condensed Consolidated Financial Statements and related disclosures. Compensation—Stock Compensation In June 2018, the FASB issued ASU No. 2018-07, “Compensation-Stock Compensation (Topic 718): Improvements to Non-employee Share-Based Payment Accounting.” This standard requires entities to include share-based payment transactions for acquiring goods and services from non-employees. The standard is effective for interim and annual periods beginning after December 15, 2018. The Partnership does not expect the adoption of this standard to have a material impact on our Condensed Consolidated Financial Statements and related disclosures. |
Derivatives Instruments and Hedging Activities | The Partnership is exposed to certain risks relating to its ongoing business operations. The primary risk managed using derivative instruments is commodity price risk. The Partnership is also exposed to credit risk in its business operations. Commodity Price Risk The Partnership has used forward physical contracts, commodity price swap contracts and commodity price option features to manage the Partnership’s commodity price risk exposures in the past. Commodity derivative instruments used by the Partnership are as follows: • NGL put options, NGL futures and swaps, and WTI crude oil futures and swaps for condensate sales are used to manage the Partnership’s NGL and condensate exposure associated with its processing agreements; • natural gas futures and swaps are used to manage the Partnership’s natural gas exposure associated with its gathering, processing and transportation and storage assets; and • natural gas futures and swaps, natural gas options and natural gas commodity purchases and sales are used to manage the Partnership’s natural gas exposure associated with its storage and transportation contracts and asset management activities. Normal purchases and normal sales contracts are not recorded in Other Assets or Liabilities in the Condensed Consolidated Balance Sheets and earnings are recognized and recorded in the period in which physical delivery of the commodity occurs. Management applies normal purchases and normal sales treatment to: (i) commodity contracts for the purchase and sale of natural gas used in or produced by the Partnership’s operations and (ii) commodity contracts for the purchase and sale of NGLs produced by the Partnership’s gathering and processing business. The Partnership recognizes its non-exchange traded derivative instruments as Other Assets or Liabilities in the Condensed Consolidated Balance Sheets at fair value with such amounts classified as current or long-term based on their anticipated settlement. Exchange traded transactions are settled on a net basis daily through margin accounts with a clearing broker and are recorded as Other Assets or Liabilities in the Condensed Consolidated Balance Sheets at fair value on a net basis with such amounts classified as current or long-term based on their anticipated settlement. As of June 30, 2018 and December 31, 2017 , the Partnership had no derivative instruments that were designated as cash flow or fair value hedges for accounting purposes. Credit Risk The Partnership is exposed to certain credit risks relating to its ongoing business operations. Credit risk includes the risk that counterparties that owe the Partnership money or energy will breach their obligations. If the counterparties to these arrangements fail to perform, the Partnership may seek or be forced to enter into alternative arrangements. In that event, the Partnership’s financial results could be adversely affected, and the Partnership could incur losses. Derivatives Not Designated As Hedging Instruments Derivative instruments not designated as hedging instruments for accounting purposes are utilized in the Partnership’s asset management activities. For derivative instruments not designated as hedging instruments, the gain or loss on the derivative is recognized currently in earnings. Quantitative Disclosures Related to Derivative Instruments The majority of natural gas physical purchases and sales not designated as hedges for accounting purposes are priced based on a monthly or daily index, and the fair value is subject to little or no market price risk. Natural gas physical sales volumes exceed natural gas physical purchase volumes due to the marketing of natural gas volumes purchased via the Partnership’s processing contracts, which are not derivative instruments. |
Fair Value Measurements | Certain assets and liabilities are recorded at fair value in the Condensed Consolidated Balance Sheets and are categorized based upon the level of judgment associated with the inputs used to measure their value. Hierarchical levels, as defined below and directly related to the amount of subjectivity associated with the inputs to fair valuations of these assets and liabilities are as follows: Level 1: Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. Instruments classified as Level 1 include natural gas futures, swaps and options transactions for contracts traded on the NYMEX and settled through a NYMEX clearing broker. Level 2: Inputs, other than quoted prices included in Level 1, are observable for the asset or liability, either directly or indirectly. Level 2 inputs include quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities that are generally included in this category are derivatives with fair values based on inputs from actively quoted markets. Instruments classified as Level 2 include over-the-counter NYMEX natural gas swaps, natural gas basis swaps and natural gas purchase and sales transactions in markets such that the pricing is closely related to the NYMEX pricing, and over-the-counter WTI crude oil swaps for condensate sales. Level 3: Inputs are unobservable for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. Unobservable inputs reflect the Partnership’s judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. The Partnership develops these inputs based on the best information available, including the Partnership’s own data. The Partnership utilizes the market approach in determining the fair value of its derivative positions by using either NYMEX or WTI published market prices, independent broker pricing data or broker/dealer valuations. The valuations of derivatives with pricing based on NYMEX published market prices may be considered Level 1 if they are settled through a NYMEX clearing broker account with daily margining. Over-the-counter derivatives with NYMEX or WTI based prices are considered Level 2 due to the impact of counterparty credit risk. Valuations based on independent broker pricing or broker/dealer valuations may be classified as Level 2 only to the extent they may be validated by an additional source of independent market data for an identical or closely related active market. In certain less liquid markets or for longer-term contracts, forward prices are not as readily available. In these circumstances, contracts are valued using internally developed methodologies that consider historical relationships among various quoted prices in active markets that result in management’s best estimate of fair value. These contracts are classified as Level 3. The Partnership determines the appropriate level for each financial asset and liability on a quarterly basis and recognizes transfers between levels at the end of the reporting period. For the period ended June 30, 2018 , there were no transfers between levels. The impact to the fair value of derivatives due to credit risk is calculated using the probability of default based on Standard & Poor’s Ratings Services and/or internally generated ratings. The fair value of derivative assets is adjusted for credit risk. The fair value of derivative liabilities is adjusted for credit risk only if the impact is deemed material. Quantitative Information on Level 3 Fair Value Measurements The Partnership utilizes the market approach to measure the fair value of our commodity contracts. The significant unobservable inputs used in this approach to fair value are longer dated price quotes. Our sensitivity to these longer dated forward curve prices are presented in the table below. Significant changes in any of those inputs in isolation would result in significantly different fair value measurements, depending on our short or long position in contracts. |
Contracts with Master Netting Arrangements | Contracts with Master Netting Arrangements Fair value amounts recognized for forward, interest rate swap, option and other conditional or exchange contracts executed with the same counterparty under a master netting arrangement may be offset. The reporting entity’s choice to offset or not must be applied consistently. A master netting arrangement exists if the reporting entity has multiple contracts, whether for the same type of conditional or exchange contract or for different types of contracts, with a single counterparty that are subject to a contractual agreement that provides for the net settlement of all contracts through a single payment in a single currency in the event of default on or termination of any one contract. Offsetting the fair values recognized for forward, interest rate swap, option and other conditional or exchange contracts outstanding with a single counterparty results in the net fair value of the transactions being reported as an asset or a liability in the Condensed Consolidated Balance Sheets. The Partnership has presented the fair values of its derivative contracts under master netting agreements using a net fair value presentation. |
Reportable Segments | The Partnership’s determination of reportable segments considers the strategic operating units under which it manages sales, allocates resources and assesses performance of various products and services to customers in differing regulatory environments. The accounting policies of the reportable segments are the same as those described in the summary of significant accounting policies excerpt in the Partnership’s audited 2017 consolidated financial statements included in the Annual Report. The Partnership uses operating income as the measure of profit or loss for its reportable segments. The Partnership’s assets and operations are organized into two reportable segments: (i) gathering and processing, which primarily provides natural gas and crude oil gathering and natural gas processing services to our producer customers, and (ii) transportation and storage, which provides interstate and intrastate natural gas pipeline transportation and storage service primarily to our producer, power plant, LDC and industrial end-user customers. |
Revenue (Tables)
Revenue (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Disaggregation of Revenue | The following table disaggregates total revenues by major source from contracts with customers and the gain (loss) on derivative activity for the three and six months ended June 30, 2018 , and 2017 . Three Months Ended June 30, 2018 Gathering and Transportation Eliminations Total (In millions) Revenues: Product sales: Natural gas $ 106 $ 143 $ (107 ) $ 142 Natural gas liquids 336 6 (6 ) 336 Condensate 37 — — 37 Total revenues from natural gas, natural gas liquids, and condensate 479 149 (113 ) 515 Gain (loss) on derivative activity (14 ) — — (14 ) Total Product sales $ 465 $ 149 $ (113 ) $ 501 Service revenues: Demand revenues $ 52 $ 113 $ — $ 165 Volume-dependent revenues 124 15 — 139 Total Service revenues $ 176 $ 128 $ — $ 304 Total Revenues $ 641 $ 277 $ (113 ) $ 805 |
Schedule of Accounts Receivable | June 30, December 31, (In millions) Accounts Receivable: Customers $ 289 $ 265 Contract assets (1) 13 27 Non-customers 6 3 Total Accounts Receivable (2) $ 308 $ 295 ____________________ (1) Contract assets include accrued minimum volume commitments and firm service transportation contracts with tiered rates. (2) Total Accounts Receivable includes Accounts receivables, net of allowance for doubtful accounts and Accounts receivable—affiliated companies. |
Summary of Timing Recognition of Contract Liabilities | The table below summarizes the timing of recognition of these contract liabilities as of June 30, 2018 : 2018 2019 2020 2021 2022 and After (In millions) Deferred revenues $ 21 $ 5 $ 5 $ 5 $ 13 |
Summary of Timing Recognition of Remaining Performance Obligations | The table below summarizes the timing of recognition of the remaining performance obligations as of June 30, 2018 : 2018 2019 2020 2021 2022 and After Transportation and Storage $ 235 $ 373 $ 272 $ 149 $ 746 Gathering and Processing 128 261 160 136 602 Total remaining performance obligations $ 363 $ 634 $ 432 $ 285 $ 1,348 |
Schedule of New Accounting Pronouncements and Changes in Accounting Principles | Below is a summary of the impact of the changes on revenues as it relates to the three and six months ended June 30, 2018 : Three Months Ended June 30, 2018 Under ASC 606 Under ASC 605 Increase/(Decrease) (In millions) Revenues: Product sales: Natural gas $ 142 $ 155 $ (13 ) Natural gas liquids 336 344 (8 ) Condensate 37 37 — Total revenues from natural gas, natural gas liquids, and condensate 515 536 (21 ) Gain (loss) on derivative activity (14 ) (14 ) — Total Product sales $ 501 $ 522 $ (21 ) Service revenues: Demand revenues $ 165 $ 165 — Volume-dependent revenues 139 139 — Total Service revenues $ 304 $ 304 $ — Total Revenues $ 805 $ 826 $ (21 ) Six Months Ended June 30, 2018 Under ASC 606 Under ASC 605 Increase/(Decrease) (In millions) Revenues: Product sales: Natural gas $ 270 $ 294 $ (24 ) Natural gas liquids 615 627 (12 ) Condensate 73 73 — Total revenues from natural gas, natural gas liquids, and condensate 958 994 (36 ) Gain (loss) on derivative activity (14 ) (14 ) — Total Product sales $ 944 $ 980 $ (36 ) Service revenues: Demand revenues $ 335 $ 335 — Volume-dependent revenues 274 273 1 Total Service revenues $ 609 $ 608 $ 1 Total Revenues $ 1,553 $ 1,588 $ (35 ) The table below summarizes the change in the contract liabilities for the six months ended June 30, 2018 : June 30, December 31, Amounts recognized in revenues (In millions) Deferred revenues $ 49 $ 34 $ 17 |
Acquisition (Tables)
Acquisition (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Business Combinations [Abstract] | |
Schedule of Business Acquisitions, by Acquisition | The following table presents the fair value of the identified assets acquired and liabilities assumed at the acquisition date: Purchase price allocation (in millions): Assets acquired: Accounts receivable $ 5 Property, plant and equipment 111 Intangibles 176 Goodwill 12 Liabilities assumed: Current liabilities 6 Total identifiable net assets $ 298 |
Earnings Per Limited Partner 25
Earnings Per Limited Partner Unit (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Earnings Per Share [Abstract] | |
Schedule Of Earnings Per Unit For Common And Subordinated Limited Partner Units | The following table illustrates the Partnership’s calculation of earnings per unit for common and subordinated units: Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 (In millions, except per unit data) Net income $ 95 $ 96 $ 209 $ 216 Net income attributable to noncontrolling interest — 1 — 1 Series A Preferred Unit distributions 9 9 18 18 General partner interest in net income — — — — Net income available to common and subordinated unitholders $ 86 $ 86 $ 191 $ 197 Net income allocable to common units $ 86 $ 45 $ 191 $ 102 Net income allocable to subordinated units — 41 — 95 Net income available to common and subordinated unitholders $ 86 $ 86 $ 191 $ 197 Net income allocable to common units $ 86 $ 45 $ 191 $ 102 Dilutive effect of Series A Preferred Unit distributions — — — — Diluted net income allocable to common units 86 45 191 102 Diluted net income allocable to subordinated units — 41 — 95 Total $ 86 $ 86 $ 191 $ 197 Basic weighted average number of outstanding Common units (1) 435 225 434 225 Subordinated units — 208 — 208 Total 435 433 434 433 Basic earnings per unit Common units $ 0.20 $ 0.20 $ 0.44 $ 0.45 Subordinated units $ — $ 0.20 $ — $ 0.46 Basic weighted average number of outstanding common units 435 225 434 225 Dilutive effect of Series A Preferred Units — — — — Dilutive effect of performance units 1 1 1 1 Diluted weighted average number of outstanding common units 436 226 435 226 Diluted weighted average number of outstanding subordinated units — 208 — 208 Total 436 434 435 434 Diluted earnings per unit Common units $ 0.20 $ 0.20 $ 0.44 $ 0.45 Subordinated units $ — $ 0.20 $ — $ 0.46 ____________________ (1) Basic weighted average number of outstanding common units for each of the three and six months ended June 30, 2018 and 2017 includes approximately one million time-based phantom units. |
Partners' Equity (Tables)
Partners' Equity (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Equity [Abstract] | |
Schedule of Equity Transactions with Limited Partner | The Partnership paid or has authorized payment of the following cash distributions to common and subordinated unitholders, as applicable, during 2017 and 2018 (in millions, except for per unit amounts): Three Months Ended Record Date Payment Date Per Unit Distribution Total Cash Distribution June 30, 2018 (1) August 21, 2018 August 28, 2018 $ 0.318 $ 138 March 31, 2018 May 22, 2018 May 29, 2018 $ 0.318 $ 138 December 31, 2017 February 20, 2018 February 27, 2018 $ 0.318 $ 138 September 30, 2017 November 14, 2017 November 21, 2017 $ 0.318 $ 138 June 30, 2017 August 22, 2017 August 29, 2017 $ 0.318 $ 138 March 31, 2017 May 23, 2017 May 30, 2017 $ 0.318 $ 137 December 31, 2016 February 21, 2017 February 28, 2017 $ 0.318 $ 137 _____________________ (1) The board of directors of Enable GP declared this $0.318 per common unit cash distribution on August 1, 2018 , to be paid on August 28, 2018 , to common unitholders of record at the close of business on August 21, 2018 . |
Schedule of Cash Distributions to Series A Preferred Unitholders | The Partnership paid or has authorized payment of the following cash distributions to holders of the Series A Preferred Units during 2017 and 2018 (in millions, except for per unit amounts): Three Months Ended Record Date Payment Date Per Unit Distribution Total Cash Distribution June 30, 2018 (1) August 1, 2018 August 14, 2018 $ 0.625 $ 9 March 31, 2018 May 1, 2018 May 15, 2018 $ 0.625 $ 9 December 31, 2017 February 9, 2018 February 15, 2018 $ 0.625 $ 9 September 30, 2017 October 31, 2017 November 14, 2017 $ 0.625 $ 9 June 30, 2017 July 31, 2017 August 14, 2017 $ 0.625 $ 9 March 31, 2017 May 2, 2017 May 12, 2017 $ 0.625 $ 9 December 31, 2016 February 10, 2017 February 15, 2017 $ 0.625 $ 9 _____________________ (1) The board of directors of Enable GP declared a $0.625 per Series A Preferred Unit cash distribution on August 1, 2018 , to be paid on August 14, 2018 , to Series A Preferred unitholders of record at the close of business on August 1, 2018 . |
Investment in Equity Method A27
Investment in Equity Method Affiliate (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Equity Method Investments and Joint Ventures [Abstract] | |
Schedule of Investments Detail | Equity in Earnings of Equity Method Affiliate: Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 (In millions) SESH $ 7 $ 7 $ 13 $ 14 Distributions from Equity Method Affiliate: Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 (In millions) SESH (1) $ 8 $ 8 $ 21 $ 19 ___________________ (1) Distributions from equity method affiliate includes a $7 million return on investment and a $1 million return of investment for each of the three months ended June 30, 2018 and 2017 , respectively. Distributions from equity method affiliate includes a $13 million and $14 million return on investment and a $8 million and $5 million return of investment for the six months ended June 30, 2018 and 2017 , respectively. Summarized financial information of SESH: Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 (In millions) Income Statements: Revenues $ 28 $ 28 $ 56 $ 56 Operating income $ 16 $ 18 $ 33 $ 35 Net income $ 13 $ 13 $ 25 $ 26 |
Debt (Tables)
Debt (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Debt Disclosure [Abstract] | |
Schedule of Debt | The following table presents the Partnership’s outstanding debt as of June 30, 2018 and December 31, 2017 . June 30, 2018 December 31, 2017 Outstanding Principal Premium (Discount) Total Debt Outstanding Principal Premium (Discount) Total Debt (In millions) Commercial Paper $ 327 $ — $ 327 $ 405 $ — $ 405 Revolving Credit Facility — — — — — — 2015 Term Loan Agreement — — — 450 — 450 2019 Notes 500 — 500 500 — 500 2024 Notes 600 — 600 600 — 600 2027 Notes 700 (3 ) 697 700 (3 ) 697 2028 Notes 800 (6 ) 794 — — — 2044 Notes 550 — 550 550 — 550 EOIT Senior Notes 250 10 260 250 13 263 Total debt $ 3,727 $ 1 $ 3,728 $ 3,455 $ 10 $ 3,465 Less: Short-term debt (1) 327 405 Less: Current portion of long-term debt (2) 499 450 Less: Unamortized debt expense (3) 21 15 Total long-term debt $ 2,881 $ 2,595 ____________________ (1) Short-term debt includes $327 million and $405 million of outstanding commercial paper as of June 30, 2018 and December 31, 2017 , respectively. (2) As of June 30, 2018 , Current portion of long-term debt includes the $500 million outstanding balance of the 2019 Notes due May 15, 2019, net of approximately $1 million unamortized debt expense. As of December 31, 2017 , Current portion of long-term debt includes the $450 million outstanding balance of the 2015 Term Loan Agreement. (3) As of June 30, 2018 and December 31, 2017 , there was an additional $6 million and $3 million , respectively, of unamortized debt expense related to the Revolving Credit Facility included in Other long-term assets, not included above. |
Derivative Instruments and He29
Derivative Instruments and Hedging Activities (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of Derivative Instruments | As of June 30, 2018 and December 31, 2017 , the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes: June 30, 2018 December 31, 2017 Gross Notional Volume Purchases Sales Purchases Sales Natural gas— TBtu (1) Financial fixed futures/swaps 19 26 17 13 Financial basis futures/swaps 24 36 17 17 Physical purchases/sales 3 70 1 37 Crude oil (for condensate)— MBbl (2) Financial Futures/swaps — 934 — 564 Natural gas liquids— MBbl (3) Financial Futures/swaps 75 2,495 — 1,615 ____________________ (1) As of June 30, 2018 , 81.7% of the natural gas contracts had durations of one year or less, 13.7% had durations of more than one year and less than two years and 4.6% had durations of more than two years. As of December 31, 2017 , 67.7% of the natural gas contracts had durations of one year or less, 16.1% had durations of more than one year and less than two years and 16.2% had durations of more than two years. (2) As of June 30, 2018 , 67.9% of the crude oil (for condensate) contracts had durations of one year or less and 32.1% had durations of more than one year and less than two years. As of December 31, 2017 , 100% of the crude oil (for condensate) contracts had durations of one year or less. (3) As of June 30, 2018 , 74.3% of the natural gas liquids contracts had durations of one year or less and 25.7% had durations of more than one year and less than two years. As of December 31, 2017 , 100% of the natural gas liquid contracts had durations of one year or less. |
Schedule of Derivative Assets at Fair Value | The fair value of the derivative instruments that are presented in the Partnership’s Condensed Consolidated Balance Sheets as of June 30, 2018 and December 31, 2017 that were not designated as hedging instruments for accounting purposes are as follows: June 30, 2018 December 31, 2017 Fair Value Instrument Balance Sheet Location Assets Liabilities Assets Liabilities (In millions) Natural gas Financial futures/swaps Other Current/Other $ 2 $ 8 $ 5 $ 4 Physical purchases/sales Other Current/Other 6 — 3 — Crude oil (for condensate) Financial futures/swaps Other Current/Other — 9 — 4 Natural gas liquids Financial Futures/swaps Other Current/Other 1 8 1 5 Total gross derivatives (1) $ 9 $ 25 $ 9 $ 13 _____________________ (1) See Note 10 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Condensed Consolidated Balance Sheets as of June 30, 2018 and December 31, 2017 . |
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value | The following table presents the effect of derivative instruments on the Partnership’s Condensed Consolidated Statements of Income for the three and six months ended June 30, 2018 and 2017 : Amounts Recognized in Income Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 (In millions) Natural gas Financial futures/swaps (losses) gains $ (1 ) $ 5 $ (5 ) $ 16 Physical purchases/sales gains 2 2 5 7 Crude oil (for condensate) Financial futures/swaps (losses) gains (6 ) 2 (10 ) 5 Natural gas liquids Financial futures/swaps (losses) gains (9 ) — (4 ) 2 Total $ (14 ) $ 9 $ (14 ) $ 30 |
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location | The following table presents the components of gain (loss) on derivative activity in the Partnership’s Condensed Consolidated Statements of Income for the three and six months ended June 30, 2018 and 2017 : Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 (In millions) Change in fair value of derivatives $ (10 ) $ 11 $ (12 ) $ 35 Realized gain (loss) on derivatives (4 ) (2 ) (2 ) (5 ) Gain (loss) on derivative activity $ (14 ) $ 9 $ (14 ) $ 30 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Fair Value Disclosures [Abstract] | |
Schedule of Fair Value and Carrying Amount of Financial Instruments | The following table summarizes the fair value and carrying amount of the Partnership’s financial instruments as of June 30, 2018 and December 31, 2017 . June 30, 2018 December 31, 2017 Carrying Amount Fair Value Carrying Amount Fair Value (In millions) Debt Revolving Credit Facility (Level 2) (1) $ — $ — $ — $ — 2015 Term Loan Agreement (Level 2) — — 450 450 2019 Notes (Level 2) 500 497 500 497 2024 Notes (Level 2) 600 578 600 602 2027 Notes (Level 2) 697 663 697 712 2028 Notes 794 780 — — 2044 Notes (Level 2) 550 487 550 550 EOIT Senior Notes (Level 2) 260 259 263 265 |
Schedule of Assets and Liabilities Measured at Fair Value on a Recurring Basis | The following tables summarize the Partnership’s assets and liabilities that are measured at fair value on a recurring basis as of June 30, 2018 and December 31, 2017 : June 30, 2018 Commodity Contracts Gas Imbalances (1) Assets Liabilities Assets (2) Liabilities (3) (In millions) Quoted market prices in active market for identical assets (Level 1) $ 2 $ 6 $ — $ — Significant other observable inputs (Level 2) 6 11 15 15 Unobservable inputs (Level 3) 1 8 — — Total fair value 9 25 15 15 Netting adjustments (2 ) (2 ) — — Total $ 7 $ 23 $ 15 $ 15 December 31, 2017 Commodity Contracts Gas Imbalances (1) Assets Liabilities Assets (2) Liabilities (3) (In millions) Quoted market prices in active market for identical assets (Level 1) $ 5 $ 3 $ — $ — Significant other observable inputs (Level 2) 4 5 27 12 Unobservable inputs (Level 3) — 5 — — Total fair value 9 13 27 12 Netting adjustments (5 ) (5 ) — — Total $ 4 $ 8 $ 27 $ 12 ______________________ (1) The Partnership uses the market approach to fair value its gas imbalance assets and liabilities at individual, or where appropriate an average of, current market indices applicable to the Partnership’s operations, not to exceed net realizable value. Gas imbalances held by EOIT are valued using an average of the Inside FERC Gas Market Report for Panhandle Eastern Pipe Line Co. (Texas, Oklahoma Mainline), ONEOK (Oklahoma) and ANR Pipeline (Oklahoma) indices. There were no netting adjustments as of June 30, 2018 and December 31, 2017 . (2) Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $14 million and $10 million at June 30, 2018 and December 31, 2017 , respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created, and which are not subject to revaluation at fair market value. (3) Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $1 million and zero at June 30, 2018 and December 31, 2017 , respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created, and which are not subject to revaluation at fair market value. |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation | The following table provides a reconciliation of changes in the fair value of our Level 3 commodity contracts between the periods presented. Commodity Contracts Natural gas liquids financial futures/swaps (In millions) Balance at December 31, 2017 $ (5 ) Losses included in earnings (4 ) Settlements 2 Transfers out of Level 3 — Balance as of June 30, 2018 $ (7 ) |
Fair Value Inputs, Quantitative Information | The Partnership utilizes the market approach to measure the fair value of our commodity contracts. The significant unobservable inputs used in this approach to fair value are longer dated price quotes. Our sensitivity to these longer dated forward curve prices are presented in the table below. Significant changes in any of those inputs in isolation would result in significantly different fair value measurements, depending on our short or long position in contracts. June 30, 2018 Product Group Fair Value Forward Curve Range (In millions) (Per gallon) Natural gas liquids $ (7 ) $0.10 - $1.1113 |
Supplemental Disclosure of Ca31
Supplemental Disclosure of Cash Flow Information (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Supplemental Cash Flow Information [Abstract] | |
Schedule of Cash Flow, Supplemental Disclosures | The following table provides information regarding supplemental cash flow information: Six Months Ended June 30, 2018 2017 (In millions) Supplemental Disclosure of Cash Flow Information: Cash Payments: Interest, net of capitalized interest $ 65 $ 50 Income taxes, net of refunds 1 — Non-cash transactions: Accounts payable related to capital expenditures 42 24 |
Schedule of Restricted Cash and Cash Equivalents | The following table reconciles cash and cash equivalents and restricted cash on the Condensed Consolidated Balance Sheets to cash, cash equivalents and restricted cash on the Condensed Consolidated Statements of Cash Flows: Six Months Ended June 30, 2018 2017 (In millions) Cash and cash equivalents $ 7 $ 7 Restricted cash 14 14 Cash, cash equivalents and restricted cash shown in the Condensed Consolidated Statements of Cash Flows $ 21 $ 21 |
Schedule of Cash and Cash Equivalents | The following table reconciles cash and cash equivalents and restricted cash on the Condensed Consolidated Balance Sheets to cash, cash equivalents and restricted cash on the Condensed Consolidated Statements of Cash Flows: Six Months Ended June 30, 2018 2017 (In millions) Cash and cash equivalents $ 7 $ 7 Restricted cash 14 14 Cash, cash equivalents and restricted cash shown in the Condensed Consolidated Statements of Cash Flows $ 21 $ 21 |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Related Party Transactions [Abstract] | |
Schedule of Revenues from Related Parties | Amounts of revenues from affiliated companies included in the Partnership’s Condensed Consolidated Statements of Income are summarized as follows: Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 (In millions) Gas transportation and storage service revenues — CenterPoint Energy $ 24 $ 24 $ 57 $ 57 Natural gas product sales — CenterPoint Energy 2 1 8 1 Gas transportation and storage service revenues — OGE Energy 9 9 18 18 Natural gas product sales — OGE Energy 1 — 2 — Total revenues — affiliated companies $ 36 $ 34 $ 85 $ 76 |
Schedule of Natural Gas Purchased From Related Parties | Amounts of natural gas purchased from affiliated companies included in the Partnership’s Condensed Consolidated Statements of Income are summarized as follows: Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 (In millions) Cost of natural gas purchases — CenterPoint Energy $ — $ 1 $ 2 $ 1 Cost of natural gas purchases — OGE Energy 5 4 8 7 Total cost of natural gas purchases — affiliated companies $ 5 $ 5 $ 10 $ 8 |
Schedule of Amounts Charged to Partnership by Related Parties | Amounts charged to the Partnership by affiliates for seconded employees, an operating lease and corporate services, included primarily in Operation and maintenance and General and administrative expenses in the Partnership’s Condensed Consolidated Statements of Income are as follows: Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 (In millions) Corporate Services — CenterPoint Energy $ — $ 1 $ 1 $ 2 Seconded Employee Costs — OGE Energy 7 9 15 16 Corporate Services — OGE Energy 1 1 1 2 Total corporate services and seconded employees expense $ 8 $ 11 $ 17 $ 20 |
Equity-Based Compensation (Tabl
Equity-Based Compensation (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Disclosure of Share-based Compensation Arrangements by Share-based Payment Award | The following table summarizes the Partnership’s compensation expense for the three and six months ended June 30, 2018 and 2017 related to performance units, restricted units, and phantom units for the Partnership’s employees and independent directors: Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 (In millions) Performance units $ 2 $ 2 $ 5 $ 5 Restricted units — 1 1 1 Phantom units 1 1 2 2 Total compensation expense $ 3 $ 4 $ 8 $ 8 |
Schedule of Share-based Compensation, Activity | A summary of the activity for the Partnership’s performance units, restricted units, and phantom units applicable to the Partnership’s employees at June 30, 2018 and changes during 2018 are shown in the following table. Performance Units Restricted Units Phantom Units Number of Units Weighted Average Grant-Date Fair Value, Per Unit Number of Units Weighted Average Grant-Date Fair Value, Per Unit Number of Units Weighted Average Grant-Date Fair Value, Per Unit (In millions, except unit data) Units Outstanding at December 31, 2017 2,040,407 $ 13.86 222,434 $ 17.87 987,380 $ 11.38 Granted (1) 529,408 17.70 — — 503,285 14.04 Vested (2) (401,772 ) 16.59 (206,068 ) 17.46 (4,540 ) 8.87 Forfeited (62,465 ) 13.95 (1,366 ) 16.75 (43,341 ) 12.40 Units Outstanding at June 30, 2018 2,105,578 $ 14.30 15,000 $ 23.56 1,442,784 $ 12.29 Aggregate Intrinsic Value of Units Outstanding at June 30, 2018 $ 36 $ — $ 25 _____________________ (1) Performance units represents the target number of performance units granted. The actual number of performance units earned, if any, is dependent upon performance and may range from zero percent to 200 percent of the target. (2) Performance units vested as of June 30, 2018 include 401,772 units from the annual grant, which were approved by the Board of Directors in 2015 and paid out at 200% , or 803,544 units, based on the level of achievement of a performance goal established by the Board of Directors over the performance period. |
Schedule of Unrecognized Compensation Cost, Nonvested Awards | A summary of the Partnership’s unrecognized compensation cost for its non-vested performance units, restricted units, and phantom units, and the weighted-average periods over which the compensation cost is expected to be recognized are shown in the following table. June 30, 2018 Unrecognized Compensation Cost (In millions) Weighted Average to be Recognized (In years) Performance Units $ 16 1.41 Restricted Units — 0.33 Phantom Units 11 1.61 Total $ 27 |
Reportable Segments (Tables)
Reportable Segments (Tables) | 6 Months Ended | |
Jun. 30, 2018 | ||
Segment Reporting [Abstract] | ||
Schedule of Financial Data for Business Segments and Services | Financial data for reportable segments are as follows: Three Months Ended June 30, 2018 Gathering and Transportation (1) Eliminations Total (In millions) Product sales $ 465 $ 149 $ (113 ) $ 501 Service revenues 176 128 — 304 Total Revenues 641 277 (113 ) 805 Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately) 411 147 (114 ) 444 Operation and maintenance, General and administrative 76 47 — 123 Depreciation and amortization 63 33 — 96 Taxes other than income tax 10 6 — 16 Operating income $ 81 $ 44 $ 1 $ 126 Capital expenditures $ 143 $ 42 $ — $ 185 Total assets $ 9,254 $ 5,681 $ (3,143 ) $ 11,792 Three Months Ended June 30, 2017 Gathering and Transportation (1) Eliminations Total (In millions) Product sales $ 336 $ 134 $ (116 ) $ 354 Service revenues 144 129 (1 ) 272 Total Revenues 480 263 (117 ) 626 Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately) 269 127 (117 ) 279 Operation and maintenance, General and administrative 75 45 — 120 Depreciation and amortization 55 34 — 89 Taxes other than income tax 9 7 — 16 Operating income $ 72 $ 50 $ — $ 122 Capital expenditures $ 39 $ 48 $ — $ 87 Total assets as of December 31, 2017 $ 9,079 $ 5,616 $ (3,102 ) $ 11,593 _____________________ (1) See Note 7 for discussion regarding ownership interests in SESH and related equity earnings included in the transportation and storage segment for the three and six months ended June 30, 2018 and 2017 . Six Months Ended June 30, 2018 Gathering and Processing Transportation and Storage (1) Eliminations Total (In millions) Product sales $ 883 $ 289 $ (228 ) $ 944 Service revenues 349 267 (7 ) 609 Total Revenues 1,232 556 (235 ) 1,553 Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately) 769 286 (236 ) 819 Operation and maintenance, General and administrative 152 93 (1 ) 244 Depreciation and amortization 125 67 — 192 Taxes other than income tax 20 13 — 33 Operating income $ 166 $ 97 $ 2 $ 265 Capital expenditures $ 291 $ 84 $ — $ 375 Total assets $ 9,254 $ 5,681 $ (3,143 ) $ 11,792 Six Months Ended June 30, 2017 Gathering and Processing Transportation and Storage (1) Eliminations Total (In millions) Product sales $ 687 $ 287 $ (234 ) $ 740 Service revenues 284 270 (2 ) 552 Total Revenues 971 557 (236 ) 1,292 Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately) 555 267 (235 ) 587 Operation and maintenance, General and administrative 145 90 (1 ) 234 Depreciation and amortization 111 66 — 177 Taxes other than income tax 18 14 — 32 Operating income $ 142 $ 120 $ — $ 262 Capital expenditures $ 90 $ 58 $ — $ 148 Total assets as of December 31, 2017 $ 9,079 $ 5,616 $ (3,102 ) $ 11,593 _____________________ (1) See Note 7 for discussion regarding ownership interests in SESH and related equity earnings included in the transportation and storage segment for the three and six months ended June 30, 2018 and 2017 . | [1] |
[1] | See Note 7 for discussion regarding ownership interests in SESH and related equity earnings included in the transportation and storage segment for the three and six months ended June 30, 2018 and 2017. |
Summary of Significant Accoun35
Summary of Significant Accounting Policies - Narrative (Details) $ in Millions | 6 Months Ended | ||
Jun. 30, 2018USD ($)board_membersegmentshares | Dec. 31, 2017USD ($) | Jun. 30, 2017USD ($) | |
Significant Accounting Policies [Line Items] | |||
Number of reportable segments | segment | 2 | ||
Number of representatives designated by each of CenterPoint Energy and OGE Energy | board_member | 2 | ||
Number of independent board members | board_member | 3 | ||
Percentage vote by all unitholders (at least 75%) | 75.00% | ||
Restricted cash (Note 1) | $ | $ 14 | $ 14 | $ 14 |
Allowance for doubtful accounts | $ | 2 | 3 | |
Inventory adjustments | $ | $ 1 | $ 0 | |
SESH | |||
Significant Accounting Policies [Line Items] | |||
Ownership percentage | 50.00% | ||
Limited Partner | CenterPoint | |||
Significant Accounting Policies [Line Items] | |||
Percentage share of management rights | 50.00% | ||
Percentage share of incentive distribution rights | 40.00% | ||
Limited partner ownership interest percentage | 54.00% | ||
Limited Partner | CenterPoint | Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units | |||
Significant Accounting Policies [Line Items] | |||
Series A preferred units held by CenterPoint Energy | shares | 14,520,000 | ||
Limited Partner | CenterPoint | Common Units | |||
Significant Accounting Policies [Line Items] | |||
Units outstanding | shares | 233,856,623 | ||
Limited Partner | OGE Energy | |||
Significant Accounting Policies [Line Items] | |||
Percentage share of management rights | 50.00% | ||
Percentage share of incentive distribution rights | 60.00% | ||
Limited partner ownership interest percentage | 25.60% | ||
Limited Partner | OGE Energy | Common Units | |||
Significant Accounting Policies [Line Items] | |||
Units outstanding | shares | 110,982,805 |
Revenue - Disaggregation of Rev
Revenue - Disaggregation of Revenue (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Disaggregation of Revenue [Line Items] | ||||
Total revenues from natural gas, natural gas liquids, and condensate | $ 515 | $ 958 | ||
Gain (loss) on derivative activity | (14) | $ 9 | (14) | $ 30 |
Total Revenues | 805 | 626 | 1,553 | 1,292 |
Natural gas | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from natural gas, natural gas liquids, and condensate | 142 | 270 | ||
Natural gas liquids | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from natural gas, natural gas liquids, and condensate | 336 | 615 | ||
Condensate Natural Gas | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from natural gas, natural gas liquids, and condensate | 37 | 73 | ||
Product | ||||
Disaggregation of Revenue [Line Items] | ||||
Total Revenues | 501 | 354 | 944 | 740 |
Demand Service Revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Total Revenues | 165 | 335 | ||
Volume Dependant Service Revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Total Revenues | 139 | 274 | ||
Natural Gas, Gathering, Transportation, Marketing and Processing | ||||
Disaggregation of Revenue [Line Items] | ||||
Total Revenues | 304 | 272 | 609 | 552 |
Operating Segments | Gathering and Processing | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from natural gas, natural gas liquids, and condensate | 479 | 900 | ||
Gain (loss) on derivative activity | (14) | (17) | ||
Total Revenues | 641 | 480 | 1,232 | 971 |
Operating Segments | Gathering and Processing | Natural gas | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from natural gas, natural gas liquids, and condensate | 106 | 212 | ||
Operating Segments | Gathering and Processing | Natural gas liquids | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from natural gas, natural gas liquids, and condensate | 336 | 615 | ||
Operating Segments | Gathering and Processing | Condensate Natural Gas | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from natural gas, natural gas liquids, and condensate | 37 | 73 | ||
Operating Segments | Gathering and Processing | Product | ||||
Disaggregation of Revenue [Line Items] | ||||
Total Revenues | 465 | 336 | 883 | 687 |
Operating Segments | Gathering and Processing | Demand Service Revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Total Revenues | 52 | 102 | ||
Operating Segments | Gathering and Processing | Volume Dependant Service Revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Total Revenues | 124 | 247 | ||
Operating Segments | Gathering and Processing | Natural Gas, Gathering, Transportation, Marketing and Processing | ||||
Disaggregation of Revenue [Line Items] | ||||
Total Revenues | 176 | 144 | 349 | 284 |
Operating Segments | Transportation and Storage | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from natural gas, natural gas liquids, and condensate | 149 | 287 | ||
Gain (loss) on derivative activity | 0 | 2 | ||
Total Revenues | 277 | 263 | 556 | 557 |
Operating Segments | Transportation and Storage | Natural gas | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from natural gas, natural gas liquids, and condensate | 143 | 274 | ||
Operating Segments | Transportation and Storage | Natural gas liquids | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from natural gas, natural gas liquids, and condensate | 6 | 13 | ||
Operating Segments | Transportation and Storage | Condensate Natural Gas | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from natural gas, natural gas liquids, and condensate | 0 | 0 | ||
Operating Segments | Transportation and Storage | Product | ||||
Disaggregation of Revenue [Line Items] | ||||
Total Revenues | 149 | 134 | 289 | 287 |
Operating Segments | Transportation and Storage | Demand Service Revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Total Revenues | 113 | 233 | ||
Operating Segments | Transportation and Storage | Volume Dependant Service Revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Total Revenues | 15 | 34 | ||
Operating Segments | Transportation and Storage | Natural Gas, Gathering, Transportation, Marketing and Processing | ||||
Disaggregation of Revenue [Line Items] | ||||
Total Revenues | 128 | 129 | 267 | 270 |
Eliminations | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from natural gas, natural gas liquids, and condensate | (113) | (229) | ||
Gain (loss) on derivative activity | 0 | 1 | ||
Total Revenues | (113) | (117) | (235) | (236) |
Eliminations | Natural gas | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from natural gas, natural gas liquids, and condensate | (107) | (216) | ||
Eliminations | Natural gas liquids | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from natural gas, natural gas liquids, and condensate | (6) | (13) | ||
Eliminations | Condensate Natural Gas | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from natural gas, natural gas liquids, and condensate | 0 | 0 | ||
Eliminations | Product | ||||
Disaggregation of Revenue [Line Items] | ||||
Total Revenues | (113) | (116) | (228) | (234) |
Eliminations | Demand Service Revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Total Revenues | 0 | 0 | ||
Eliminations | Volume Dependant Service Revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Total Revenues | 0 | (7) | ||
Eliminations | Natural Gas, Gathering, Transportation, Marketing and Processing | ||||
Disaggregation of Revenue [Line Items] | ||||
Total Revenues | $ 0 | $ (1) | $ (7) | $ (2) |
Revenue - Accounts Receivable (
Revenue - Accounts Receivable (Details) - USD ($) $ in Millions | Jun. 30, 2018 | Dec. 31, 2017 |
Revenue from Contract with Customer [Abstract] | ||
Customers | $ 289 | $ 265 |
Accrued minimum volume commitments (contract assets) | 13 | 27 |
Non-customers | 6 | 3 |
Total Accounts Receivable | $ 308 | $ 295 |
Revenue - Summary of Recognitio
Revenue - Summary of Recognition Contract Liabilities (Details) $ in Millions | 6 Months Ended |
Jun. 30, 2018USD ($) | |
Revenue from Contract with Customer [Abstract] | |
2,018 | $ 21 |
2,019 | 5 |
2,020 | 5 |
2,021 | 5 |
2022 and After | $ 13 |
Revenue - Summary of Recognit39
Revenue - Summary of Recognition of Remaining Performance Obligations (Details) $ in Millions | Jun. 30, 2018USD ($) |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-07-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total remaining performance obligations | $ 363 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-07-01 | Transportation and Storage | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total remaining performance obligations | 235 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-07-01 | Gathering and Processing | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total remaining performance obligations | 128 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-07-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total remaining performance obligations | 634 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-07-01 | Transportation and Storage | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total remaining performance obligations | 373 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-07-01 | Gathering and Processing | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total remaining performance obligations | 261 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-07-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total remaining performance obligations | 432 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-07-01 | Transportation and Storage | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total remaining performance obligations | 272 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-07-01 | Gathering and Processing | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total remaining performance obligations | 160 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-07-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total remaining performance obligations | 285 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-07-01 | Transportation and Storage | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total remaining performance obligations | 149 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-07-01 | Gathering and Processing | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total remaining performance obligations | 136 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-07-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total remaining performance obligations | 1,348 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-07-01 | Transportation and Storage | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total remaining performance obligations | 746 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-07-01 | Gathering and Processing | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Total remaining performance obligations | $ 602 |
Revenue - Summary of the Impact
Revenue - Summary of the Impact of the Changes on Revenues (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||
Total revenues from natural gas, natural gas liquids, and condensate | $ 515 | $ 958 | ||
Total Revenues | 805 | $ 626 | 1,553 | $ 1,292 |
Gain (loss) on derivative activity | (14) | 9 | (14) | 30 |
Natural gas | ||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||
Total revenues from natural gas, natural gas liquids, and condensate | 142 | 270 | ||
Natural gas liquids | ||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||
Total revenues from natural gas, natural gas liquids, and condensate | 336 | 615 | ||
Condensate Natural Gas | ||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||
Total revenues from natural gas, natural gas liquids, and condensate | 37 | 73 | ||
Product | ||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||
Total Revenues | 501 | 354 | 944 | 740 |
Demand Service Revenue | ||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||
Total Revenues | 165 | 335 | ||
Volume Dependant Service Revenue | ||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||
Total Revenues | 139 | 274 | ||
Natural Gas, Gathering, Transportation, Marketing and Processing | ||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||
Total Revenues | 304 | $ 272 | 609 | $ 552 |
Calculated under Revenue Guidance in Effect before Topic 606 | ||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||
Total revenues from natural gas, natural gas liquids, and condensate | 536 | 994 | ||
Total Revenues | 826 | 1,588 | ||
Gain (loss) on derivative activity | (14) | (14) | ||
Calculated under Revenue Guidance in Effect before Topic 606 | Natural gas | ||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||
Total revenues from natural gas, natural gas liquids, and condensate | 155 | 294 | ||
Calculated under Revenue Guidance in Effect before Topic 606 | Natural gas liquids | ||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||
Total revenues from natural gas, natural gas liquids, and condensate | 344 | 627 | ||
Calculated under Revenue Guidance in Effect before Topic 606 | Condensate Natural Gas | ||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||
Total revenues from natural gas, natural gas liquids, and condensate | 37 | 73 | ||
Calculated under Revenue Guidance in Effect before Topic 606 | Product | ||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||
Total Revenues | 522 | 980 | ||
Calculated under Revenue Guidance in Effect before Topic 606 | Demand Service Revenue | ||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||
Total Revenues | 165 | 335 | ||
Calculated under Revenue Guidance in Effect before Topic 606 | Volume Dependant Service Revenue | ||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||
Total Revenues | 139 | 273 | ||
Calculated under Revenue Guidance in Effect before Topic 606 | Natural Gas, Gathering, Transportation, Marketing and Processing | ||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||
Total Revenues | 304 | 608 | ||
Difference between Revenue Guidance in Effect before and after Topic 606 | ||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||
Total revenues from natural gas, natural gas liquids, and condensate | (21) | (36) | ||
Total Revenues | (21) | (35) | ||
Gain (loss) on derivative activity | 0 | 0 | ||
Difference between Revenue Guidance in Effect before and after Topic 606 | Natural gas | ||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||
Total revenues from natural gas, natural gas liquids, and condensate | (13) | (24) | ||
Difference between Revenue Guidance in Effect before and after Topic 606 | Natural gas liquids | ||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||
Total revenues from natural gas, natural gas liquids, and condensate | (8) | (12) | ||
Difference between Revenue Guidance in Effect before and after Topic 606 | Condensate Natural Gas | ||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||
Total revenues from natural gas, natural gas liquids, and condensate | 0 | 0 | ||
Difference between Revenue Guidance in Effect before and after Topic 606 | Product | ||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||
Total Revenues | (21) | (36) | ||
Difference between Revenue Guidance in Effect before and after Topic 606 | Demand Service Revenue | ||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||
Total Revenues | 0 | 0 | ||
Difference between Revenue Guidance in Effect before and after Topic 606 | Volume Dependant Service Revenue | ||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||
Total Revenues | 0 | 1 | ||
Difference between Revenue Guidance in Effect before and after Topic 606 | Natural Gas, Gathering, Transportation, Marketing and Processing | ||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||
Total Revenues | $ 0 | $ 1 |
Revenue - Summary of Changes in
Revenue - Summary of Changes in Contract Liabilities (Details) - USD ($) $ in Millions | Jun. 30, 2018 | Dec. 31, 2017 |
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | ||
Deferred revenues | $ 49 | |
Calculated under Revenue Guidance in Effect before Topic 606 | ||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | ||
Deferred revenues | $ 34 | |
Accounting Standards Update 2014-09 | Difference between Revenue Guidance in Effect before and after Topic 606 | ||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | ||
Deferred revenues | $ 17 |
Acquisition - Narrative (Detail
Acquisition - Narrative (Details) - Align Midstream, LLC $ in Millions | Oct. 04, 2017USD ($)mi | Dec. 31, 2017USD ($) |
Business Acquisition [Line Items] | ||
Payment to acquire Align Midstream, LLC | $ 298 | |
General and Administrative Expense | ||
Business Acquisition [Line Items] | ||
Acquisition costs association with the transaction | $ 2 | |
Pipelines | ||
Business Acquisition [Line Items] | ||
Length of gather pipe (miles) | mi | 190 | |
Customer Relationships | ||
Business Acquisition [Line Items] | ||
Weighted average useful life (in years) | 10 years |
Acquisition - Schedule of Asset
Acquisition - Schedule of Assets and Liabilities Assumed (Details) - USD ($) $ in Millions | Jun. 30, 2018 | Dec. 31, 2017 | Oct. 04, 2017 |
Assets acquired: | |||
Goodwill | $ 12 | $ 12 | |
Align Midstream, LLC | |||
Assets acquired: | |||
Accounts receivable | $ 5 | ||
Property, plant and equipment | 111 | ||
Intangibles | 176 | ||
Goodwill | 12 | ||
Liabilities assumed: | |||
Current liabilities | 6 | ||
Total identifiable net assets | $ 298 |
Earnings Per Limited Partner 44
Earnings Per Limited Partner Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | 3 Months Ended | 6 Months Ended | |||||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | ||||
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items] | |||||||
Net income | $ 95 | $ 96 | $ 209 | $ 216 | |||
Net income attributable to noncontrolling interest | 0 | 1 | 0 | 1 | |||
Series A Preferred Unit distributions | 9 | 9 | 18 | 18 | |||
General partner interest in net income | 0 | 0 | 0 | 0 | |||
Net Income Attributable to Common and Subordinated Units (Note 5) | 86 | 86 | 191 | 197 | |||
Dilutive effect of Series A Preferred Unit distributions | 0 | 0 | 0 | 0 | |||
Diluted net income | $ 86 | $ 86 | $ 191 | $ 197 | |||
Basic weighted average number of outstanding | |||||||
Basic weighted average number of outstanding | 435 | 433 | 434 | 433 | |||
Basic earnings per unit | |||||||
Dilutive effect of Series A Preferred Units (in units) | 0 | 0 | 0 | 0 | |||
Dilutive effect of performance units (in units) | 1 | 1 | 1 | 1 | |||
Diluted weighted average number of outstanding units | 436 | 434 | 435 | 434 | |||
Performance Units, Restricted Units, and Phantom Units | |||||||
Basic earnings per unit | |||||||
Dilutive effect of unit-based awards (in dollars per unit) (less than $.01) | $ 0.01 | $ 0 | $ 0 | ||||
Phantom units | |||||||
Basic weighted average number of outstanding | |||||||
Basic weighted average number of outstanding | 1 | [1] | 1 | [1] | 0 | ||
Common Units | |||||||
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items] | |||||||
Net Income Attributable to Common and Subordinated Units (Note 5) | $ 86 | $ 45 | $ 191 | $ 102 | |||
Diluted net income | $ 86 | $ 45 | $ 191 | $ 102 | |||
Basic weighted average number of outstanding | |||||||
Basic weighted average number of outstanding | 435 | [1] | 225 | [1] | 434 | 225 | [1] |
Basic earnings per unit | |||||||
Basic earnings per unit | $ 0.20 | $ 0.20 | $ 0.44 | $ 0.45 | |||
Diluted weighted average number of outstanding units | 436 | 226 | 435 | 226 | |||
Diluted earnings per unit | $ 0.20 | $ 0.20 | $ 0.44 | $ 0.45 | |||
Subordinated Units | |||||||
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items] | |||||||
Net Income Attributable to Common and Subordinated Units (Note 5) | $ 0 | $ 41 | $ 0 | $ 95 | |||
Diluted net income | $ 0 | $ 41 | $ 0 | $ 95 | |||
Basic weighted average number of outstanding | |||||||
Basic weighted average number of outstanding | 0 | 208 | 0 | 208 | |||
Basic earnings per unit | |||||||
Basic earnings per unit | $ 0 | $ 0.20 | $ 0 | $ 0.46 | |||
Diluted weighted average number of outstanding units | 0 | 208 | 0 | 208 | |||
Diluted earnings per unit | $ 0 | $ 0.20 | $ 0 | $ 0.46 | |||
[1] | Basic weighted average number of outstanding common units for each of the three and six months ended June 30, 2018 and 2017 includes approximately one million time-based phantom units. |
Partners' Equity - Schedule of
Partners' Equity - Schedule of Cash Distributions (Details) - USD ($) $ / shares in Units, $ in Millions | Aug. 28, 2018 | Aug. 21, 2018 | Aug. 14, 2018 | Aug. 01, 2018 | May 29, 2018 | May 22, 2018 | May 15, 2018 | May 14, 2018 | May 01, 2018 | Feb. 27, 2018 | Feb. 20, 2018 | Feb. 15, 2018 | Feb. 09, 2018 | Nov. 21, 2017 | Nov. 14, 2017 | Oct. 31, 2017 | Aug. 29, 2017 | Aug. 22, 2017 | Aug. 14, 2017 | Jul. 31, 2017 | May 30, 2017 | May 23, 2017 | May 12, 2017 | May 02, 2017 | Feb. 28, 2017 | Feb. 21, 2017 | Feb. 15, 2017 | Feb. 10, 2017 | |
Distribution Made to Limited Partner [Line Items] | |||||||||||||||||||||||||||||
Record Date | May 22, 2018 | Feb. 20, 2018 | Nov. 14, 2017 | Aug. 22, 2017 | May 23, 2017 | Feb. 21, 2017 | |||||||||||||||||||||||
Payment Date | May 29, 2018 | Feb. 27, 2018 | Nov. 21, 2017 | Aug. 29, 2017 | May 30, 2017 | Feb. 28, 2017 | |||||||||||||||||||||||
Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units | Preferred Units | |||||||||||||||||||||||||||||
Distribution Made to Limited Partner [Line Items] | |||||||||||||||||||||||||||||
Record Date | May 1, 2018 | Feb. 9, 2018 | Oct. 31, 2017 | Jul. 31, 2017 | May 2, 2017 | Feb. 10, 2017 | |||||||||||||||||||||||
Payment Date | May 15, 2018 | Feb. 15, 2018 | Nov. 14, 2017 | Aug. 14, 2017 | May 12, 2017 | Feb. 15, 2017 | |||||||||||||||||||||||
Cash Distribution | |||||||||||||||||||||||||||||
Distribution Made to Limited Partner [Line Items] | |||||||||||||||||||||||||||||
Cash distribution declared (in dollars per unit) | $ 0.318 | $ 0.318 | $ 0.318 | $ 0.318 | $ 0.318 | $ 0.318 | |||||||||||||||||||||||
Distribution made to unitholders | $ 138 | $ 138 | $ 138 | $ 138 | $ 137 | $ 137 | |||||||||||||||||||||||
Cash Distribution | Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units | Preferred Units | |||||||||||||||||||||||||||||
Distribution Made to Limited Partner [Line Items] | |||||||||||||||||||||||||||||
Cash distribution declared (in dollars per unit) | $ 0.625 | $ 0.625 | $ 0.625 | $ 0.625 | $ 0.625 | $ 0.625 | |||||||||||||||||||||||
Distribution made to unitholders | $ 9 | $ 9 | $ 9 | $ 9 | $ 9 | $ 9 | |||||||||||||||||||||||
Subsequent Event | |||||||||||||||||||||||||||||
Distribution Made to Limited Partner [Line Items] | |||||||||||||||||||||||||||||
Record Date | [1] | Aug. 21, 2018 | |||||||||||||||||||||||||||
Payment Date | [1] | Aug. 28, 2018 | |||||||||||||||||||||||||||
Subsequent Event | Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units | Preferred Units | |||||||||||||||||||||||||||||
Distribution Made to Limited Partner [Line Items] | |||||||||||||||||||||||||||||
Record Date | [2] | Aug. 1, 2018 | |||||||||||||||||||||||||||
Payment Date | [2] | Aug. 14, 2018 | |||||||||||||||||||||||||||
Subsequent Event | Cash Distribution | |||||||||||||||||||||||||||||
Distribution Made to Limited Partner [Line Items] | |||||||||||||||||||||||||||||
Cash distribution (in dollars per unit) | [1] | $ 0.318 | |||||||||||||||||||||||||||
Cash distribution declared (in dollars per unit) | [1] | $ 0.318 | |||||||||||||||||||||||||||
Distribution made to unitholders | [1] | $ 138 | |||||||||||||||||||||||||||
Subsequent Event | Cash Distribution | Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units | |||||||||||||||||||||||||||||
Distribution Made to Limited Partner [Line Items] | |||||||||||||||||||||||||||||
Cash distribution declared (in dollars per unit) | 0.625 | ||||||||||||||||||||||||||||
Subsequent Event | Cash Distribution | Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units | Preferred Units | |||||||||||||||||||||||||||||
Distribution Made to Limited Partner [Line Items] | |||||||||||||||||||||||||||||
Cash distribution (in dollars per unit) | $ 0.625 | ||||||||||||||||||||||||||||
Cash distribution declared (in dollars per unit) | [2] | $ 0.625 | |||||||||||||||||||||||||||
Distribution made to unitholders | [2] | $ 9 | |||||||||||||||||||||||||||
[1] | The board of directors of Enable GP declared this $0.318 per common unit cash distribution on August 1, 2018, to be paid on August 28, 2018, to common unitholders of record at the close of business on August 21, 2018. | ||||||||||||||||||||||||||||
[2] | The board of directors of Enable GP declared a $0.625 per Series A Preferred Unit cash distribution on August 1, 2018, to be paid on August 14, 2018, to Series A Preferred unitholders of record at the close of business on August 1, 2018. |
Partners' Equity - Narrative (D
Partners' Equity - Narrative (Details) | May 12, 2017USD ($) | Feb. 18, 2016USD ($)$ / sharesshares | Jun. 30, 2018$ / shares | Aug. 30, 2017shares |
Distribution Made to Limited Partner [Line Items] | ||||
Limited partners' capital account, required quarterly distribution period | 60 days | |||
Subordinated Units | ||||
Distribution Made to Limited Partner [Line Items] | ||||
Units outstanding | shares | 207,855,430 | |||
Conversion basis | 1 | |||
CenterPoint | Limited Partner | ||||
Distribution Made to Limited Partner [Line Items] | ||||
Repayment of notes payable—affiliated companies | $ | $ 363,000,000 | |||
ATM Program | ||||
Distribution Made to Limited Partner [Line Items] | ||||
Aggregate offering price | $ | $ 200,000,000 | |||
Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units | ||||
Distribution Made to Limited Partner [Line Items] | ||||
Annual distribution percentage rate | 10.00% | |||
Liquidation preference (in dollars per unit) | $ / shares | $ 25 | |||
Period after date of original issue | 5 years | |||
Redemption price (in dollars per unit) | $ / shares | $ 25.50 | |||
Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units | LIBOR | ||||
Distribution Made to Limited Partner [Line Items] | ||||
Annual distribution percentage rate | 8.50% | |||
Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units | Private Placement | ||||
Distribution Made to Limited Partner [Line Items] | ||||
Issuance of Series A Preferred Units, units | shares | 14,520,000 | |||
Cash purchase price (in dollars per unit) | $ / shares | $ 25 | |||
Proceeds from issuance of Series A Preferred Units, net of issuance costs | $ | $ 362,000,000 | |||
Expenses related to the offering | $ | $ 1,000,000 | |||
Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units | Private Placement | CenterPoint | Limited Partner | ||||
Distribution Made to Limited Partner [Line Items] | ||||
Issuance of Series A Preferred Units, units | shares | 14,520,000 | |||
Cash purchase price (in dollars per unit) | $ / shares | $ 25 | |||
Proceeds from issuance of Series A Preferred Units, net of issuance costs | $ | $ 362,000,000 | |||
Maximum | ||||
Distribution Made to Limited Partner [Line Items] | ||||
Limited partners' capital account, incentive distribution rights, percentage | 50.00% | |||
Minimum | ||||
Distribution Made to Limited Partner [Line Items] | ||||
Incentive distribution, distribution (in dollars per unit) | $ / shares | $ 0.330625 |
Investment in Equity Method A47
Investment in Equity Method Affiliate - Narrative (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Schedule of Equity Method Investments [Line Items] | ||||
Amount billed associated with service agreements | $ 805 | $ 626 | $ 1,553 | $ 1,292 |
Return on investment in equity method affiliate | 13 | 14 | ||
Return of investment in equity method affiliate | $ 8 | 5 | ||
SESH | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Ownership percentage | 50.00% | 50.00% | ||
Percentage of distributions through limited partner interest | 50.00% | |||
Return on investment in equity method affiliate | $ 7 | 7 | $ 13 | 14 |
Return of investment in equity method affiliate | 1 | 1 | 8 | 5 |
SESH | Equity Method Investee | Shared Operations Service Agreements | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Amount billed associated with service agreements | $ 6 | $ 6 | $ 8 | $ 11 |
Investment in Equity Method A48
Investment in Equity Method Affiliate - Schedule of Investments (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |||
Equity in Earnings of Equity Method Affiliates: | ||||||
Equity in earnings of equity method affiliate | $ 7 | $ 7 | $ 13 | $ 14 | ||
Distributions from Equity Method Affiliates: | ||||||
Return on investment in equity method affiliate | 13 | 14 | ||||
Return of investment in equity method affiliate | 8 | 5 | ||||
SESH | ||||||
Equity in Earnings of Equity Method Affiliates: | ||||||
Equity in earnings of equity method affiliate | 7 | 7 | 13 | 14 | ||
Distributions from Equity Method Affiliates: | ||||||
Distributions from equity method affiliate | 8 | [1] | 8 | 21 | 19 | [1] |
Return on investment in equity method affiliate | 7 | 7 | 13 | 14 | ||
Return of investment in equity method affiliate | 1 | 1 | 8 | 5 | ||
Revenues | 28 | 28 | 56 | 56 | ||
Operating income | 16 | 18 | 33 | 35 | ||
Net income | $ 13 | $ 13 | $ 25 | $ 26 | ||
[1] | Distributions from equity method affiliate includes a $7 million return on investment and a $1 million return of investment for each of the three months ended June 30, 2018 and 2017, respectively. Distributions from equity method affiliate includes a $13 million and $14 million return on investment and a $8 million and $5 million return of investment for the six months ended June 30, 2018 and 2017, respectively. |
Debt - Schedule of Outstanding
Debt - Schedule of Outstanding Debt (Details) - USD ($) $ in Millions | Jun. 30, 2018 | Dec. 31, 2017 | |
Debt Instrument [Line Items] | |||
Outstanding Principal | $ 3,727 | $ 3,455 | |
Debt Instrument, Unamortized Discount (Premium), Net | (1) | (10) | |
Total Debt | 3,728 | 3,465 | |
Less: Unamortized debt expense | [1] | 21 | 15 |
Total long-term debt | 2,881 | 2,595 | |
2015 Term Loan Agreement | 2015 Term Loan Agreement | |||
Debt Instrument [Line Items] | |||
Outstanding Principal | 0 | 450 | |
Debt Instrument, Unamortized Discount (Premium), Net | 0 | 0 | |
Total Debt | 0 | 450 | |
Less: Current portion of long-term debt (2) | [2] | 499 | 450 |
Senior Notes | 2019 Notes | |||
Debt Instrument [Line Items] | |||
Outstanding Principal | 500 | 500 | |
Debt Instrument, Unamortized Discount (Premium), Net | 0 | 0 | |
Total Debt | 500 | 500 | |
Less: Current portion of long-term debt (2) | [2] | 500 | |
Unamortized debt expense related to Revolving Credit Facility | (1) | ||
Senior Notes | 2024 Notes | |||
Debt Instrument [Line Items] | |||
Outstanding Principal | 600 | 600 | |
Debt Instrument, Unamortized Discount (Premium), Net | 0 | 0 | |
Total Debt | 600 | 600 | |
Senior Notes | 2027 Notes | |||
Debt Instrument [Line Items] | |||
Outstanding Principal | 700 | 700 | |
Debt Instrument, Unamortized Discount (Premium), Net | 3 | 3 | |
Total Debt | 697 | 697 | |
Senior Notes | 2028 Notes | |||
Debt Instrument [Line Items] | |||
Outstanding Principal | 800 | 0 | |
Debt Instrument, Unamortized Discount (Premium), Net | 6 | 0 | |
Total Debt | 794 | 0 | |
Senior Notes | 2044 Notes | |||
Debt Instrument [Line Items] | |||
Outstanding Principal | 550 | 550 | |
Debt Instrument, Unamortized Discount (Premium), Net | 0 | 0 | |
Total Debt | 550 | 550 | |
Senior Notes | EOIT Senior Notes | EOIT | |||
Debt Instrument [Line Items] | |||
Outstanding Principal | 250 | 250 | |
Debt Instrument, Unamortized Discount (Premium), Net | (10) | (13) | |
Total Debt | 260 | 263 | |
Revolving Credit Facility | |||
Debt Instrument [Line Items] | |||
Outstanding Principal | 0 | 0 | |
Debt Instrument, Unamortized Discount (Premium), Net | 0 | 0 | |
Total Debt | 0 | 0 | |
Unamortized debt expense related to Revolving Credit Facility | 6 | ||
Commercial Paper | |||
Debt Instrument [Line Items] | |||
Short-term Debt | 327 | 405 | |
Debt Instrument, Unamortized Discount (Premium), Net | 0 | 0 | |
Short-term debt | [3] | $ 327 | 405 |
Revolving Credit Facility | |||
Debt Instrument [Line Items] | |||
Unamortized debt expense related to Revolving Credit Facility | $ 3 | ||
[1] | As of June 30, 2018 and December 31, 2017, there was an additional $6 million and $3 million, respectively, of unamortized debt expense related to the Revolving Credit Facility included in Other long-term assets, not included above. | ||
[2] | As of June 30, 2018, Current portion of long-term debt includes the $500 million outstanding balance of the 2019 Notes due May 15, 2019, net of approximately $1 million unamortized debt expense. As of December 31, 2017, Current portion of long-term debt includes the $450 million outstanding balance of the 2015 Term Loan Agreement. | ||
[3] | Short-term debt includes $327 million and $405 million of outstanding commercial paper as of June 30, 2018 and December 31, 2017, respectively. |
Debt - Narrative (Details)
Debt - Narrative (Details) | May 10, 2018USD ($) | Apr. 06, 2018USD ($)time | Jul. 31, 2015USD ($) | Jun. 30, 2018USD ($) | Dec. 31, 2017USD ($) | |
Debt Instrument [Line Items] | ||||||
Commercial paper, authorized | $ 1,400,000,000 | |||||
Premium (Discount) | 1,000,000 | $ 10,000,000 | ||||
Outstanding Principal | 3,727,000,000 | 3,455,000,000 | ||||
Term loan facility | 2015 Term Loan Agreement | ||||||
Debt Instrument [Line Items] | ||||||
Duration of term loan facility (in years) | 3 years | |||||
Amount of loan agreement | $ 450,000,000 | |||||
Senior Notes | 2027 Notes | ||||||
Debt Instrument [Line Items] | ||||||
Premium (Discount) | (3,000,000) | (3,000,000) | ||||
Outstanding Principal | $ 700,000,000 | 700,000,000 | ||||
Effective interest rate percentage | 4.58% | |||||
Senior Notes | 2028 Notes | ||||||
Debt Instrument [Line Items] | ||||||
Amount of loan agreement | $ 800,000,000 | |||||
Premium (Discount) | $ (6,000,000) | 0 | ||||
Fixed interest rate percentage | 4.95% | |||||
Net proceeds | $ 787,000,000 | |||||
Unamortized discount | (6,000,000) | |||||
Unamortized debt expense | 7,000,000 | |||||
Outstanding Principal | $ 800,000,000 | 0 | ||||
Effective interest rate percentage | 5.20% | |||||
Senior Notes | Senior Notes including 2019 Notes, 2024 Notes, and 2044 Notes | ||||||
Debt Instrument [Line Items] | ||||||
Unamortized debt expense | $ 14,000,000 | |||||
Senior Notes | 2019 Notes | ||||||
Debt Instrument [Line Items] | ||||||
Premium (Discount) | 0 | 0 | ||||
Outstanding Principal | $ 500,000,000 | 500,000,000 | ||||
Effective interest rate percentage | 2.57% | |||||
Senior Notes | 2024 Notes | ||||||
Debt Instrument [Line Items] | ||||||
Premium (Discount) | $ 0 | 0 | ||||
Outstanding Principal | $ 600,000,000 | 600,000,000 | ||||
Effective interest rate percentage | 4.02% | |||||
Senior Notes | 2044 Notes | ||||||
Debt Instrument [Line Items] | ||||||
Premium (Discount) | $ 0 | 0 | ||||
Outstanding Principal | $ 550,000,000 | 550,000,000 | ||||
Effective interest rate percentage | 5.08% | |||||
Senior Notes | EOIT Senior Notes | EOIT | ||||||
Debt Instrument [Line Items] | ||||||
Premium (Discount) | $ 10,000,000 | 13,000,000 | ||||
Fixed interest rate percentage | 6.25% | |||||
Outstanding Principal | $ 250,000,000 | 250,000,000 | ||||
Unamortized premium | $ 10,000,000 | |||||
Effective interest rate percentage | 3.81% | |||||
Commercial Paper | ||||||
Debt Instrument [Line Items] | ||||||
Commercial paper outstanding | $ 327,000,000 | 405,000,000 | ||||
Short-term debt, net of premium (discount) | [1] | $ 327,000,000 | 405,000,000 | |||
Weighted average interest rate percentage | 2.76% | |||||
Premium (Discount) | $ 0 | 0 | ||||
Revolving Credit Facility | ||||||
Debt Instrument [Line Items] | ||||||
Maximum borrowing capacity | $ 1,750,000,000 | |||||
Duration of term loan facility (in years) | 5 years | |||||
Increase in maximum borrowing capacity | $ 875,000,000 | |||||
Number of times option maybe exercised to extend term of Term Loan Facility | time | 2 | |||||
Extension period (in years) | 1 year | |||||
Letters of credit principal advances | 0 | |||||
Letters of credit outstanding amount | $ 3,000,000 | |||||
Commitment fee percentage | 0.20% | |||||
Premium (Discount) | $ 0 | 0 | ||||
Outstanding Principal | $ 0 | $ 0 | ||||
Revolving Credit Facility | LIBOR | ||||||
Debt Instrument [Line Items] | ||||||
Applicable margin percentage | 1.50% | |||||
[1] | Short-term debt includes $327 million and $405 million of outstanding commercial paper as of June 30, 2018 and December 31, 2017, respectively. |
Derivative Instruments and He51
Derivative Instruments and Hedging Activities (Details) - Not Designated as Hedging Instrument bbl in Millions, MMBTU in Millions | 6 Months Ended | 12 Months Ended | |
Jun. 30, 2018MMBTUbbl | Dec. 31, 2017MMBTUbbl | ||
Natural Gas, Financial fixed futures/swaps | Purchases | |||
Derivative [Line Items] | |||
Derivative, gross notional volume (TBtu) | [1] | 19 | 17 |
Natural Gas, Financial fixed futures/swaps | Sales | |||
Derivative [Line Items] | |||
Derivative, gross notional volume (TBtu) | [1] | 26 | 13 |
Natural gas, Financial basis futures/swaps | Purchases | |||
Derivative [Line Items] | |||
Derivative, gross notional volume (TBtu) | [1] | 24 | 17 |
Natural gas, Financial basis futures/swaps | Sales | |||
Derivative [Line Items] | |||
Derivative, gross notional volume (TBtu) | [1] | 36 | 17 |
Physical purchases/sales | Purchases | |||
Derivative [Line Items] | |||
Derivative, gross notional volume (TBtu) | [1] | 3 | 1 |
Physical purchases/sales | Sales | |||
Derivative [Line Items] | |||
Derivative, gross notional volume (TBtu) | [1] | 70 | 37 |
Crude oil, Financial Futures/swaps | Purchases | |||
Derivative [Line Items] | |||
Derivative, gross notional volume (MMbl) | bbl | [2] | 0 | 0 |
Crude oil, Financial Futures/swaps | Sales | |||
Derivative [Line Items] | |||
Derivative, gross notional volume (MMbl) | bbl | [2] | 1 | 1 |
Natural gas liquids, Financial Futures/swaps | Purchases | |||
Derivative [Line Items] | |||
Derivative, gross notional volume (MMbl) | bbl | [3] | 0 | 0 |
Natural gas liquids, Financial Futures/swaps | Sales | |||
Derivative [Line Items] | |||
Derivative, gross notional volume (MMbl) | bbl | [3] | 2 | 2 |
Natural gas | |||
Derivative [Line Items] | |||
Percent of contract with durations of one year or less | 81.70% | 67.70% | |
Percent of contracts with durations of more than one year and less than two years | 13.70% | 16.10% | |
Percent of contracts with durations of more than two years | 4.60% | 16.20% | |
Condensate | |||
Derivative [Line Items] | |||
Percent of contract with durations of one year or less | 67.90% | 100.00% | |
Percent of contracts with durations of more than one year and less than two years | 32.10% | ||
Natural gas liquids | |||
Derivative [Line Items] | |||
Percent of contract with durations of one year or less | 74.30% | 100.00% | |
Percent of contracts with durations of more than one year and less than two years | 25.70% | ||
[1] | As of June 30, 2018, 81.7% of the natural gas contracts had durations of one year or less, 13.7% had durations of more than one year and less than two years and 4.6% had durations of more than two years. As of December 31, 2017, 67.7% of the natural gas contracts had durations of one year or less, 16.1% had durations of more than one year and less than two years and 16.2% had durations of more than two years. | ||
[2] | As of June 30, 2018, 67.9% of the crude oil (for condensate) contracts had durations of one year or less and 32.1% had durations of more than one year and less than two years. As of December 31, 2017, 100% of the crude oil (for condensate) contracts had durations of one year or less. | ||
[3] | As of June 30, 2018, 74.3% of the natural gas liquids contracts had durations of one year or less and 25.7% had durations of more than one year and less than two years. As of December 31, 2017, 100% of the natural gas liquid contracts had durations of one year or less. |
Derivative Instruments and He52
Derivative Instruments and Hedging Activities - Balance Sheet Location (Details) - USD ($) | Jun. 30, 2018 | Dec. 31, 2017 | |
Designated as Hedging Instrument | |||
Derivatives, Fair Value [Line Items] | |||
Derivative instruments designated as cash flow hedges or fair value hedges | $ 0 | $ 0 | |
Not Designated as Hedging Instrument | |||
Derivatives, Fair Value [Line Items] | |||
Assets | [1] | 9,000,000 | 9,000,000 |
Liabilities | [1] | 25,000,000 | 13,000,000 |
Natural gas | Financial futures/swaps | Not Designated as Hedging Instrument | Other Current, Assets | |||
Derivatives, Fair Value [Line Items] | |||
Assets | 2,000,000 | 5,000,000 | |
Natural gas | Financial futures/swaps | Not Designated as Hedging Instrument | Other Current Liabilities | |||
Derivatives, Fair Value [Line Items] | |||
Liabilities | 8,000,000 | 4,000,000 | |
Natural gas | Physical purchases/sales | Not Designated as Hedging Instrument | Other Current, Assets | |||
Derivatives, Fair Value [Line Items] | |||
Assets | 6,000,000 | 3,000,000 | |
Natural gas | Physical purchases/sales | Not Designated as Hedging Instrument | Other Current Liabilities | |||
Derivatives, Fair Value [Line Items] | |||
Liabilities | 0 | 0 | |
Crude oil (for condensate) | Financial futures/swaps | Not Designated as Hedging Instrument | Other Current, Assets | |||
Derivatives, Fair Value [Line Items] | |||
Assets | 0 | 0 | |
Crude oil (for condensate) | Financial futures/swaps | Not Designated as Hedging Instrument | Other Current Liabilities | |||
Derivatives, Fair Value [Line Items] | |||
Liabilities | 9,000,000 | 4,000,000 | |
Natural gas liquids | Financial futures/swaps | Not Designated as Hedging Instrument | Other Current, Assets | |||
Derivatives, Fair Value [Line Items] | |||
Assets | 1,000,000 | 1,000,000 | |
Natural gas liquids | Financial futures/swaps | Not Designated as Hedging Instrument | Other Current Liabilities | |||
Derivatives, Fair Value [Line Items] | |||
Liabilities | $ 8,000,000 | $ 5,000,000 | |
[1] | See Note 10 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Condensed Consolidated Balance Sheets as of June 30, 2018 and December 31, 2017. |
Derivative Instruments and He53
Derivative Instruments and Hedging Activities - Amounts Recognized in Income (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (Loss) on derivative, net | $ (14) | $ 9 | $ (14) | $ 30 |
Change in fair value of derivatives | (10) | 11 | (12) | 35 |
Realized gain (loss) on derivatives | (4) | (2) | (2) | (5) |
Gain (loss) on derivative activity | (14) | 9 | (14) | 30 |
Cash collateral posted | 2 | 2 | ||
Cash collateral required if ratings are lowered | 14 | 14 | ||
Natural gas | Financial futures/swaps | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (Loss) on derivative, net | (1) | 5 | (5) | 16 |
Natural gas | Physical purchases/sales | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (Loss) on derivative, net | 2 | 2 | 5 | 7 |
Condensate | Financial futures/swaps | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (Loss) on derivative, net | (6) | 2 | (10) | 5 |
Natural gas liquids | Financial futures/swaps | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (Loss) on derivative, net | $ (9) | $ 0 | $ (4) | $ 2 |
Fair Value Measurements - Carry
Fair Value Measurements - Carrying and Fair Value Amounts (Details) - USD ($) $ in Millions | Jun. 30, 2018 | Dec. 31, 2017 | |
Carrying Amount | Senior Notes | 2028 Notes | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Senior Notes (Level 2) | $ 794 | $ 0 | |
Carrying Amount | Significant other observable inputs (Level 2) | 2015 Term Loan Agreement | 2015 Term Loan Agreement | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
2015 Term Loan Agreement (Level 2) | 0 | 450 | |
Carrying Amount | Significant other observable inputs (Level 2) | Senior Notes | 2019 Notes | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Senior Notes (Level 2) | 500 | 500 | |
Carrying Amount | Significant other observable inputs (Level 2) | Senior Notes | 2024 Notes | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Senior Notes (Level 2) | 600 | 600 | |
Carrying Amount | Significant other observable inputs (Level 2) | Senior Notes | 2027 Notes | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Senior Notes (Level 2) | 697 | 697 | |
Carrying Amount | Significant other observable inputs (Level 2) | Senior Notes | 2044 Notes | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Senior Notes (Level 2) | 550 | 550 | |
Carrying Amount | Significant other observable inputs (Level 2) | Senior Notes | EOIT Senior Notes | EOIT | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Senior Notes (Level 2) | 260 | 263 | |
Carrying Amount | Significant other observable inputs (Level 2) | Revolving Credit Facility | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Revolving Credit Facility (Level 2) | [1] | 0 | 0 |
Fair Value | Senior Notes | 2028 Notes | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Senior Notes (Level 2) | 780 | 0 | |
Fair Value | Significant other observable inputs (Level 2) | 2015 Term Loan Agreement | 2015 Term Loan Agreement | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
2015 Term Loan Agreement (Level 2) | 0 | 450 | |
Fair Value | Significant other observable inputs (Level 2) | Senior Notes | 2019 Notes | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Senior Notes (Level 2) | 497 | 497 | |
Fair Value | Significant other observable inputs (Level 2) | Senior Notes | 2024 Notes | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Senior Notes (Level 2) | 578 | 602 | |
Fair Value | Significant other observable inputs (Level 2) | Senior Notes | 2027 Notes | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Senior Notes (Level 2) | 663 | 712 | |
Fair Value | Significant other observable inputs (Level 2) | Senior Notes | 2044 Notes | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Senior Notes (Level 2) | 487 | 550 | |
Fair Value | Significant other observable inputs (Level 2) | Senior Notes | EOIT Senior Notes | EOIT | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Senior Notes (Level 2) | 259 | 265 | |
Fair Value | Significant other observable inputs (Level 2) | Revolving Credit Facility | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Revolving Credit Facility (Level 2) | [1] | 0 | 0 |
Commercial Paper | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Short-term Debt | $ 327 | $ 405 | |
[1] | Borrowing capacity is effectively reduced by our borrowings outstanding under the commercial paper program. $327 million and $405 million of commercial paper was outstanding as of June 30, 2018 and December 31, 2017, respectively. |
Fair Value Measurements - Fair
Fair Value Measurements - Fair Value Hierarchy (Details) - USD ($) $ in Millions | Jun. 30, 2018 | Dec. 31, 2017 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Retained fuel due from shippers | $ 14 | $ 10 | |
Over retained fuel due from shippers | 1 | 0 | |
Commodity Contracts | Recurring Measurement | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Assets, total fair value | 9 | 9 | |
Liabilities, total fair value | 25 | 13 | |
Assets | (2) | (5) | |
Liabilities | (2) | (5) | |
Assets | 7 | 4 | |
Liabilities | 23 | 8 | |
Commodity Contracts | Recurring Measurement | Quoted market prices in active market for identical assets (Level 1) | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Assets | 2 | 5 | |
Liabilities | 6 | 3 | |
Commodity Contracts | Recurring Measurement | Significant other observable inputs (Level 2) | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Assets | 6 | 4 | |
Liabilities | 11 | 5 | |
Commodity Contracts | Recurring Measurement | Unobservable inputs (Level 3) | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Assets | 1 | 0 | |
Liabilities | 8 | 5 | |
Gas Imbalances | Recurring Measurement | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Assets, total fair value | [1],[2] | 15 | 27 |
Liabilities, total fair value | [2],[3] | 15 | 12 |
Assets | [1],[2] | 0 | 0 |
Liabilities | [2],[3] | 0 | 0 |
Assets | [1],[2] | 15 | 27 |
Liabilities | [2],[3] | 15 | 12 |
Gas Imbalances | Recurring Measurement | Quoted market prices in active market for identical assets (Level 1) | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Assets | [1],[2] | 0 | 0 |
Liabilities | [2],[3] | 0 | 0 |
Gas Imbalances | Recurring Measurement | Significant other observable inputs (Level 2) | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Assets | [1],[2] | 15 | 27 |
Liabilities | [2],[3] | 15 | 12 |
Gas Imbalances | Recurring Measurement | Unobservable inputs (Level 3) | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Assets | [1],[2] | 0 | 0 |
Liabilities | [2],[3] | $ 0 | $ 0 |
[1] | Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $14 million and $10 million at June 30, 2018 and December 31, 2017, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created, and which are not subject to revaluation at fair market value. | ||
[2] | The Partnership uses the market approach to fair value its gas imbalance assets and liabilities at individual, or where appropriate an average of, current market indices applicable to the Partnership’s operations, not to exceed net realizable value. Gas imbalances held by EOIT are valued using an average of the Inside FERC Gas Market Report for Panhandle Eastern Pipe Line Co. (Texas, Oklahoma Mainline), ONEOK (Oklahoma) and ANR Pipeline (Oklahoma) indices. There were no netting adjustments as of June 30, 2018 and December 31, 2017. | ||
[3] | Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $1 million and zero at June 30, 2018 and December 31, 2017, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created, and which are not subject to revaluation at fair market value. |
Fair Value Measurements - Sched
Fair Value Measurements - Schedule of Changes in Fair Value of Level 3 Financial Instruments (Details) - Commodity Contracts - Natural gas liquids financial futures/swaps $ in Millions | 6 Months Ended |
Jun. 30, 2018USD ($) | |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward] | |
Balance at December 31, 2017 | $ (5) |
Losses included in earnings | (4) |
Settlements | 2 |
June 30, 2018 | (7) |
Transfers out of Level 3 | $ 0 |
Fair Value Measurements - Sch57
Fair Value Measurements - Schedule of Quantitative Information of Level 3 Inputs (Details) - Commodity Contracts - Natural gas liquids - Market Approach Valuation Technique - Unobservable inputs (Level 3) $ in Millions | 6 Months Ended |
Jun. 30, 2018USD ($)$ / gal | |
Fair Value Inputs, Assets, Quantitative Information [Line Items] (Deprecated 2018-01-31) | |
Liabilities | $ | $ (7) |
Minimum | |
Fair Value Inputs, Assets, Quantitative Information [Line Items] (Deprecated 2018-01-31) | |
Forward Curve Range (in dollars per gallon) | 0.10 |
Maximum | |
Fair Value Inputs, Assets, Quantitative Information [Line Items] (Deprecated 2018-01-31) | |
Forward Curve Range (in dollars per gallon) | 1.1113 |
Supplemental Disclosure of Ca58
Supplemental Disclosure of Cash Flow Information - Supplemental Disclosure of Cash Flow Information (Details) - USD ($) $ in Millions | 6 Months Ended | |
Jun. 30, 2018 | Jun. 30, 2017 | |
Supplemental Cash Flow Information [Abstract] | ||
Interest, net of capitalized interest | $ 65 | $ 50 |
Income taxes, net of refunds | 1 | 0 |
Accounts payable related to capital expenditures | $ 42 | $ 24 |
Supplemental Disclosure of Ca59
Supplemental Disclosure of Cash Flow Information - Reconciliation of Cash and Cash Equivalents and Restricted Cash (Details) - USD ($) $ in Millions | Jun. 30, 2018 | Dec. 31, 2017 | Jun. 30, 2017 | Dec. 31, 2016 |
Supplemental Cash Flow Elements [Abstract] | ||||
Cash and cash equivalents | $ 7 | $ 5 | $ 7 | |
Restricted cash (Note 1) | 14 | 14 | 14 | |
Cash, cash equivalents and restricted cash shown in the Condensed Consolidated Statements of Cash Flows | $ 21 | $ 19 | $ 21 | $ 23 |
Related Party Transactions - Na
Related Party Transactions - Narrative (Details) $ / shares in Units, $ in Millions | Dec. 06, 2016mi | Feb. 18, 2016USD ($)$ / sharesshares | Jun. 30, 2018USD ($) | Jun. 30, 2017 | Jun. 30, 2018USD ($) | Jun. 30, 2017 |
Related Party Transaction [Line Items] | ||||||
Partnership's revenues from affiliated companies as a percent of total revenues | 4.00% | 5.00% | 5.00% | 6.00% | ||
Private Placement | Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units | ||||||
Related Party Transaction [Line Items] | ||||||
Issuance of Series A Preferred Units, units | shares | 14,520,000 | |||||
Cash purchase price (in dollars per unit) | $ / shares | $ 25 | |||||
Proceeds from issuance of Series A Preferred Units, net of issuance costs | $ 362 | |||||
Subsidiary of Common Parent | OGE Energy | Transportation Agreement between OGE Energy and Enable Oklahoma Intrastate Transmission, LLC | Pipelines | ||||||
Related Party Transaction [Line Items] | ||||||
Term of transportation and storage agreement | 20 years | |||||
Length of pipeline (in miles) | mi | 80 | |||||
Subsidiary of Common Parent | CenterPoint | Three Services Included in Transportation and Storage Agreements | ||||||
Related Party Transaction [Line Items] | ||||||
Period of written notice | 180 days | |||||
CenterPoint and OGE Energy | Minimum | ||||||
Related Party Transaction [Line Items] | ||||||
Period notice of termination for reimbursements for all employee costs | 90 days | |||||
OGE Energy | ||||||
Related Party Transaction [Line Items] | ||||||
Period notice of termination prior to commencement of succeeding annual period | 180 days | |||||
OGE Energy | Minimum | ||||||
Related Party Transaction [Line Items] | ||||||
Period notice of termination prior to commencement of succeeding annual period | 180 days | |||||
OGE Energy | Defined Benefit and Retiree Medical Plans | ||||||
Related Party Transaction [Line Items] | ||||||
Expense reimbursement, 2018 and thereafter | $ 5 | |||||
OGE Energy | Certain Services and Support Functions | ||||||
Related Party Transaction [Line Items] | ||||||
Expense reimbursement annual caps | 1 | |||||
CenterPoint | Certain Services and Support Functions | ||||||
Related Party Transaction [Line Items] | ||||||
Expense reimbursement annual caps | 4 | |||||
Affiliated Entity | CenterPoint | Lease Agreement with Affiliate of CenterPoint Energy | ||||||
Related Party Transaction [Line Items] | ||||||
Rent and maintenance expenses | $ 3 | $ 3 | ||||
Limited Partner | CenterPoint | Private Placement | Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units | ||||||
Related Party Transaction [Line Items] | ||||||
Issuance of Series A Preferred Units, units | shares | 14,520,000 | |||||
Cash purchase price (in dollars per unit) | $ / shares | $ 25 | |||||
Proceeds from issuance of Series A Preferred Units, net of issuance costs | $ 362 |
Related Party Transactions - Re
Related Party Transactions - Related Party Activity (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Related Party Transaction [Line Items] | ||||
Revenues from affiliated companies | $ 36 | $ 34 | $ 85 | $ 76 |
Cost of goods sold from affiliate | 5 | 5 | 10 | 8 |
Charges to the Partnership by affiliates | 8 | 11 | 17 | 20 |
CenterPoint | ||||
Related Party Transaction [Line Items] | ||||
Cost of goods sold from affiliate | 0 | 1 | 2 | 1 |
CenterPoint | Gas Transportation and Storage | ||||
Related Party Transaction [Line Items] | ||||
Revenues from affiliated companies | 24 | 24 | 57 | 57 |
CenterPoint | Gas Sales | ||||
Related Party Transaction [Line Items] | ||||
Revenues from affiliated companies | 2 | 1 | 8 | 1 |
CenterPoint | Corporate Services | ||||
Related Party Transaction [Line Items] | ||||
Charges to the Partnership by affiliates | 0 | 1 | 1 | 2 |
OGE Energy | ||||
Related Party Transaction [Line Items] | ||||
Cost of goods sold from affiliate | 5 | 4 | 8 | 7 |
OGE Energy | Gas Transportation and Storage | ||||
Related Party Transaction [Line Items] | ||||
Revenues from affiliated companies | 9 | 9 | 18 | 18 |
OGE Energy | Gas Sales | ||||
Related Party Transaction [Line Items] | ||||
Revenues from affiliated companies | 1 | 0 | 2 | 0 |
OGE Energy | Corporate Services | ||||
Related Party Transaction [Line Items] | ||||
Charges to the Partnership by affiliates | 1 | 1 | 1 | 2 |
OGE Energy | Seconded Employee Costs | ||||
Related Party Transaction [Line Items] | ||||
Charges to the Partnership by affiliates | $ 7 | $ 9 | $ 15 | $ 16 |
Commitments and Contingencies (
Commitments and Contingencies (Details) $ in Millions | Jan. 01, 2017MMcf | Jun. 30, 2018USD ($) |
Commitments and Contingencies Disclosure [Abstract] | ||
Gathering and processing agreement term (in years) | 10 years | |
Energy deliveries (in MMcf/d) | MMcf | 400 | |
Minimum volume commitment fee | $ | $ 226 |
Equity-Based Compensation (Deta
Equity-Based Compensation (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Total compensation expense | $ 3 | $ 4 | $ 8 | $ 8 |
Performance units | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Total compensation expense | 2 | 2 | 5 | 5 |
Restricted units | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Total compensation expense | 0 | 1 | 1 | 1 |
Phantom units | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Total compensation expense | $ 1 | $ 1 | $ 2 | $ 2 |
Equity-Based Compensation - Equ
Equity-Based Compensation - Equity Units Activity (Details) $ / shares in Units, $ in Millions | 6 Months Ended | |
Jun. 30, 2018USD ($)$ / sharesshares | ||
Performance units | ||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | ||
Units Outstanding (in units) | 2,040,407,000,000 | |
Granted (in units) | 529,408,000,000 | [1] |
Vested (in units) | (401,772,000,000) | [2] |
Forfeited (in units) | (62,465,000,000) | |
Units Outstanding (in units) | 2,105,578,000,000 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract] | ||
Units Outstanding (in dollars per unit) | $ / shares | $ 13.86 | |
Granted (in dollars per unit) | $ / shares | 17.70 | [1] |
Vested (in dollars per unit) | $ / shares | 16.59 | [2] |
Forfeited (in dollars per unit) | $ / shares | 13.95 | |
Units Outstanding (in dollars per unit) | $ / shares | $ 14.30 | |
Aggregate Intrinsic Value of Units Outstanding | $ | $ 36 | |
Performance units | Minimum | ||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract] | ||
Payout percentage | 0.00% | |
Performance units | Maximum | ||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract] | ||
Payout percentage | 200.00% | |
Performance units | Annual Grant in 2015 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | ||
Granted (in units) | 401,772,000,000 | |
Vested (in units) | (803,544,000,000) | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract] | ||
Payout percentage | 200.00% | |
Restricted units | ||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | ||
Units Outstanding (in units) | 222,434,000,000 | |
Granted (in units) | 0 | [1] |
Vested (in units) | (206,068,000,000) | [2] |
Forfeited (in units) | (1,366,000,000) | |
Units Outstanding (in units) | 15,000,000,000 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract] | ||
Units Outstanding (in dollars per unit) | $ / shares | $ 17.87 | |
Granted (in dollars per unit) | $ / shares | 0 | [1] |
Vested (in dollars per unit) | $ / shares | 17.46 | [2] |
Forfeited (in dollars per unit) | $ / shares | 16.75 | |
Units Outstanding (in dollars per unit) | $ / shares | $ 23.56 | |
Aggregate Intrinsic Value of Units Outstanding | $ | $ 0 | |
Phantom units | ||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | ||
Units Outstanding (in units) | 987,380,000,000 | |
Granted (in units) | 503,285,000,000 | [1] |
Vested (in units) | (4,540,000,000) | [2] |
Forfeited (in units) | (43,341,000,000) | |
Units Outstanding (in units) | 1,442,784,000,000 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract] | ||
Units Outstanding (in dollars per unit) | $ / shares | $ 11.38 | |
Granted (in dollars per unit) | $ / shares | 14.04 | [1] |
Vested (in dollars per unit) | $ / shares | 8.87 | [2] |
Forfeited (in dollars per unit) | $ / shares | 12.40 | |
Units Outstanding (in dollars per unit) | $ / shares | $ 12.29 | |
Aggregate Intrinsic Value of Units Outstanding | $ | $ 25 | |
[1] | Performance units represents the target number of performance units granted. The actual number of performance units earned, if any, is dependent upon performance and may range from zero percent to 200 percent of the target. | |
[2] | Performance units vested as of June 30, 2018 include 401,772 units from the annual grant, which were approved by the Board of Directors in 2015 and paid out at 200%, or 803,544 units, based on the level of achievement of a performance goal established by the Board of Directors over the performance period. |
Equity-Based Compensation - Unr
Equity-Based Compensation - Unrecognized Compensation Cost (Details) $ in Millions | 6 Months Ended |
Jun. 30, 2018USD ($)shares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Unrecognized Compensation Cost (In millions) | $ 27 |
Performance units | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Unrecognized Compensation Cost (In millions) | $ 16 |
Weighted Average to be Recognized (In years) | 1 year 4 months 28 days |
Restricted units | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Unrecognized Compensation Cost (In millions) | $ 0 |
Weighted Average to be Recognized (In years) | 3 months 29 days |
Phantom units | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Unrecognized Compensation Cost (In millions) | $ 11 |
Weighted Average to be Recognized (In years) | 1 year 7 months 10 days |
Long Term Incentive Plan | Common Units | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Shares available for issuance | shares | 7,587,153 |
Reportable Segments - Schedule
Reportable Segments - Schedule of Financial Data for Business Segments and Services (Details) $ in Millions | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2018USD ($) | Jun. 30, 2017USD ($) | Jun. 30, 2018USD ($)segment | Jun. 30, 2017USD ($) | Dec. 31, 2017USD ($) | |
Segment Reporting Information [Line Items] | |||||
Number of reportable segments | segment | 2 | ||||
Total Revenues | $ 805 | $ 626 | $ 1,553 | $ 1,292 | |
Cost of Goods and Services Sold | 444 | 279 | 819 | 587 | |
Operation and maintenance, General and administrative | 123 | 120 | 244 | 234 | |
Depreciation and amortization | 96 | 89 | 192 | 177 | |
Taxes other than income tax | 16 | 16 | 33 | 32 | |
Operating Income | 126 | 122 | 265 | 262 | |
Capital expenditures | 185 | 87 | 375 | 148 | |
Total assets | 11,792 | 11,792 | $ 11,593 | ||
Operating Segments | Gathering and Processing | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 641 | 480 | 1,232 | 971 | |
Cost of Goods and Services Sold | 411 | 269 | 769 | 555 | |
Operation and maintenance, General and administrative | 76 | 75 | 152 | 145 | |
Depreciation and amortization | 63 | 55 | 125 | 111 | |
Taxes other than income tax | 10 | 9 | 20 | 18 | |
Operating Income | 81 | 72 | 166 | 142 | |
Capital expenditures | 143 | 39 | 291 | 90 | |
Total assets | 9,254 | 9,254 | 9,079 | ||
Operating Segments | Transportation and Storage | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 277 | 263 | 556 | 557 | |
Cost of Goods and Services Sold | 147 | 127 | 286 | 267 | |
Operation and maintenance, General and administrative | 47 | 45 | 93 | 90 | |
Depreciation and amortization | 33 | 34 | 67 | 66 | |
Taxes other than income tax | 6 | 7 | 13 | 14 | |
Operating Income | 44 | 50 | 97 | 120 | |
Capital expenditures | 42 | 48 | 84 | 58 | |
Total assets | 5,681 | 5,681 | 5,616 | ||
Eliminations | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | (113) | (117) | (235) | (236) | |
Cost of Goods and Services Sold | (114) | (117) | (236) | (235) | |
Operation and maintenance, General and administrative | 0 | 0 | (1) | (1) | |
Depreciation and amortization | 0 | 0 | 0 | 0 | |
Taxes other than income tax | 0 | 0 | 0 | 0 | |
Operating Income | 1 | 0 | 2 | 0 | |
Capital expenditures | 0 | 0 | 0 | 0 | |
Total assets | (3,143) | (3,143) | $ (3,102) | ||
Product | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 501 | 354 | 944 | 740 | |
Product | Operating Segments | Gathering and Processing | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 465 | 336 | 883 | 687 | |
Product | Operating Segments | Transportation and Storage | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 149 | 134 | 289 | 287 | |
Product | Eliminations | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | (113) | (116) | (228) | (234) | |
Natural Gas, Gathering, Transportation, Marketing and Processing | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 304 | 272 | 609 | 552 | |
Natural Gas, Gathering, Transportation, Marketing and Processing | Operating Segments | Gathering and Processing | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 176 | 144 | 349 | 284 | |
Natural Gas, Gathering, Transportation, Marketing and Processing | Operating Segments | Transportation and Storage | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 128 | 129 | 267 | 270 | |
Natural Gas, Gathering, Transportation, Marketing and Processing | Eliminations | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | $ 0 | $ (1) | $ (7) | $ (2) |