Document and Entity Information
Document and Entity Information - shares | 9 Months Ended | |
Sep. 30, 2016 | Oct. 14, 2016 | |
Document and Entity Information [Abstract] | ||
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Sep. 30, 2016 | |
Document Fiscal Year Focus | 2,016 | |
Document Fiscal Period Focus | Q3 | |
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 | 214,461,760 |
Condensed Consolidated Statemen
Condensed Consolidated Statements of Income (Unaudited) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Revenues (including revenues from affiliates (Note 11)): | ||||
Product sales | $ 326 | $ 357 | $ 837 | $ 1,043 |
Service revenue | 294 | 289 | 821 | 809 |
Total Revenues | 620 | 646 | 1,658 | 1,852 |
Cost and Expenses (including expenses from affiliates (Note 11)): | ||||
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately) | 268 | 287 | 717 | 856 |
Operation and maintenance | 87 | 101 | 275 | 313 |
General and Administrative | 21 | 29 | 68 | 78 |
Depreciation and amortization | 84 | 84 | 248 | 233 |
Impairments | 8 | 1,105 | 8 | 1,105 |
Taxes other than income taxes | 13 | 15 | 43 | 45 |
Total Cost and Expenses | 481 | 1,621 | 1,359 | 2,630 |
Operating Income (Loss) | 139 | (975) | 299 | (778) |
Other Income (Expense): | ||||
Interest expense (including expenses from affiliates (Note 11)) | (26) | (23) | (74) | (66) |
Equity in earnings of equity method affiliate | 8 | 7 | 22 | 21 |
Other, net | 0 | 0 | 0 | 2 |
Total Other Expense | (18) | (16) | (52) | (43) |
Income Before Income Taxes | ||||
Income Before Income Taxes | 121 | (991) | 247 | (821) |
Income tax expense | 2 | 0 | 3 | 2 |
Net Income (Loss) | ||||
Net Income (Loss) | 119 | (991) | 244 | (823) |
Less: Net income (loss) attributable to noncontrolling interest | ||||
Less: Net income (loss) attributable to noncontrolling interest | 0 | (6) | 0 | (6) |
Net Income (Loss) attributable to limited partners | ||||
Net Income (Loss) attributable to limited partners | 119 | (985) | 244 | (817) |
Less: Series A Preferred Unit distributions (Note 4) | ||||
Less: Series A Preferred Unit distributions (Note 4) | 9 | 0 | 13 | 0 |
Net Income (Loss) attributable to common and subordinated units (Note 3) | ||||
Net Income (Loss) attributable to common and subordinated units (Note 3) | 110 | (985) | 231 | (817) |
Common Units | ||||
Net Income (Loss) attributable to common and subordinated units (Note 3) | ||||
Net Income (Loss) attributable to common and subordinated units (Note 3) | $ 56 | $ (499) | $ 117 | $ (414) |
Basic and Diluted earnings (loss) per unit and weighted average number of units outstanding | ||||
Basic earnings (loss) per unit (Note 3) | $ 0.26 | $ (2.33) | $ 0.55 | $ (1.93) |
Diluted earnings (loss) per unit (Note 3) | $ 0.26 | $ (2.33) | $ 0.55 | $ (1.93) |
Subordinated Units | ||||
Net Income (Loss) attributable to common and subordinated units (Note 3) | ||||
Net Income (Loss) attributable to common and subordinated units (Note 3) | $ 54 | $ (486) | $ 114 | $ (403) |
Basic and Diluted earnings (loss) per unit and weighted average number of units outstanding | ||||
Basic earnings (loss) per unit (Note 3) | $ 0.26 | $ (2.34) | $ 0.55 | $ (1.94) |
Diluted earnings (loss) per unit (Note 3) | $ 0.26 | $ (2.34) | $ 0.55 | $ (1.94) |
Condensed Consolidated Stateme3
Condensed Consolidated Statements of Comprehensive Income (Unaudited) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Statement of Comprehensive Income [Abstract] | ||||
Net income (loss) | $ 119 | $ (991) | $ 244 | $ (823) |
Comprehensive income (loss) | 119 | (991) | 244 | (823) |
Less: Comprehensive income (loss) attributable to noncontrolling interest | 0 | (6) | 0 | (6) |
Comprehensive income (loss) attributable to Enable Midstream Partners, LP | $ 119 | $ (985) | $ 244 | $ (817) |
Condensed Consolidated Balance
Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Millions | Sep. 30, 2016 | Dec. 31, 2015 |
Current Assets: | ||
Cash and cash equivalents | $ 23 | $ 4 |
Accounts receivable, net of allowance for doubtful accounts | 278 | 245 |
Accounts receivable—affiliated companies | 13 | 21 |
Inventory | 42 | 53 |
Gas imbalances | 20 | 23 |
Other current assets | 32 | 35 |
Total current assets | 408 | 381 |
Property, Plant and Equipment: | ||
Property, plant and equipment | 11,523 | 11,293 |
Less accumulated depreciation and amortization | 1,367 | 1,162 |
Property, plant and equipment, net | 10,156 | 10,131 |
Other Assets: | ||
Intangible assets, net | 313 | 333 |
Investment in equity method affiliate | 326 | 344 |
Other | 38 | 37 |
Total other assets | 677 | 714 |
Total Assets | 11,241 | 11,226 |
Current Liabilities: | ||
Accounts payable | 144 | 248 |
Accounts payable—affiliated companies | 5 | 9 |
Short-term debt | 0 | 236 |
Taxes accrued | 51 | 30 |
Gas imbalances | 22 | 25 |
Other | 116 | 67 |
Total current liabilities | 338 | 615 |
Other Liabilities: | ||
Accumulated deferred income taxes, net | 12 | 8 |
Notes payable—affiliated companies | 0 | 363 |
Regulatory liabilities | 19 | 18 |
Other | 30 | 20 |
Total other liabilities | 61 | 409 |
Long-Term Debt | 3,113 | 2,671 |
Commitments and Contingencies (Note 12) | ||
Partners’ Equity: | ||
Common units | 3,635 | 3,714 |
Subordinated units | 3,721 | 3,805 |
Noncontrolling interest | 11 | 12 |
Total Partners’ Equity | 7,729 | 7,531 |
Total Liabilities and Partners’ Equity | 11,241 | 11,226 |
Series A Preferred Units | ||
Partners’ Equity: | ||
Series A Preferred Units (14,520,000 issued and outstanding at September 30, 2016 and 0 issued and outstanding at December 31, 2015) | $ 362 | $ 0 |
Condensed Consolidated Balance5
Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - shares | Sep. 30, 2016 | Dec. 31, 2015 |
Common Units | ||
Common and Subordinated units issued | 214,460,536 | 214,541,422 |
Common units and Subordinated units outstanding | 214,460,536 | 214,541,422 |
Subordinated Units | ||
Common and Subordinated units issued | 207,855,430 | 207,855,430 |
Common units and Subordinated units outstanding | 207,855,430 | 207,855,430 |
Series A Preferred Units | ||
Preferred units issued | 14,520,000 | 0 |
Preferred units outstanding | 14,520,000 | 0 |
Condensed Consolidated Stateme6
Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Millions | 9 Months Ended | |
Sep. 30, 2016 | Sep. 30, 2015 | |
Cash Flows from Operating Activities: | ||
Net income (loss) | $ 244 | $ (823) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||
Depreciation and amortization | 248 | 233 |
Deferred income taxes | 4 | 1 |
Impairments | 8 | 1,105 |
Loss on sale/retirement of assets | 9 | 2 |
Equity in earnings of equity method affiliate, net of distributions | 0 | 5 |
Equity based compensation | 9 | 7 |
Amortization of debt costs and discount (premium) | (2) | (2) |
Changes in other assets and liabilities: | ||
Accounts receivable, net | (33) | (37) |
Accounts receivable—affiliated companies | 8 | 2 |
Inventory | 11 | 11 |
Gas imbalance assets | 3 | 29 |
Other current assets | 3 | (1) |
Other assets | (1) | (5) |
Accounts payable | (84) | (56) |
Accounts payable—affiliated companies | (4) | (26) |
Gas imbalance liabilities | (3) | 4 |
Other current liabilities | 68 | 45 |
Other liabilities | 10 | (3) |
Net cash provided by operating activities | 498 | 491 |
Cash Flows from Investing Activities: | ||
Capital expenditures | (289) | (654) |
Acquisitions, net of cash acquired | 0 | (80) |
Proceeds from sale of assets | 1 | 1 |
Investment in equity method affiliate | 0 | (8) |
Return of investment in equity method affiliate | 18 | 11 |
Net cash used in investing activities | (270) | (730) |
Cash Flows from Financing Activities: | ||
Proceeds from long term debt, net of issuance costs | 0 | 450 |
Proceeds from revolving credit facility | 838 | 275 |
Repayment of revolving credit facility | (393) | (275) |
Increase (decrease) in short-term debt | (236) | 179 |
Repayment of notes payable—affiliated companies | (363) | 0 |
Proceeds from issuance of Series A Preferred Units, net of issuance costs | 362 | 0 |
Distributions | (417) | (397) |
Net cash provided by (used in) financing activities | (209) | 232 |
Net Increase (Decrease) in Cash and Cash Equivalents | 19 | (7) |
Cash and Cash Equivalents at Beginning of Period | 4 | 12 |
Cash and Cash Equivalents at End of Period | $ 23 | $ 5 |
Condensed Consolidated Stateme7
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, 2014 | $ 8,823 | $ 31 | $ 0 | $ 4,353 | $ 4,439 |
Balance, beginning of period, units at Dec. 31, 2014 | 0 | 214 | 208 | ||
Changes in Partners' Capital | |||||
Net income (loss) | (823) | (6) | $ (412) | $ (405) | |
Issuance of common units upon interest acquisition of SESH | 1 | 1 | |||
Distributions | (397) | (202) | (195) | ||
Equity based compensation | 7 | 7 | |||
Balance, end of period at Sep. 30, 2015 | 7,611 | 25 | $ 0 | $ 3,747 | $ 3,839 |
Balance, end of period, units at Sep. 30, 2015 | 0 | 214 | 208 | ||
Balance, beginning of period at Dec. 31, 2015 | 7,531 | 12 | $ 0 | $ 3,714 | $ 3,805 |
Balance, beginning of period, units at Dec. 31, 2015 | 0 | 214 | 208 | ||
Changes in Partners' Capital | |||||
Net income (loss) | 244 | $ 13 | $ 117 | $ 114 | |
Issuance of Series A Preferred Units | 362 | $ 362 | |||
Issuance of Series A Preferred Units, units | 15 | ||||
Distributions | (417) | (1) | $ (13) | (205) | (198) |
Equity based compensation | 9 | 9 | |||
Balance, end of period at Sep. 30, 2016 | $ 7,729 | $ 11 | $ 362 | $ 3,635 | $ 3,721 |
Balance, end of period, units at Sep. 30, 2016 | 15 | 214 | 208 |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 9 Months Ended |
Sep. 30, 2016 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Summary of Significant Accounting Policies | Summary of Significant Accounting Policies Organization Enable Midstream Partners, LP (Partnership) is a large-scale, growth-oriented Delaware limited partnership formed to own, operate and develop strategically located natural gas and crude oil infrastructure assets. The Partnership’s assets and operations are organized into two reportable segments: (i) Gathering and Processing, which primarily provides natural gas gathering, processing and fractionation services and crude oil gathering for our producer customers, and (ii) Transportation and Storage, which provides interstate and intrastate natural gas pipeline transportation and storage services primarily to natural gas producers, utilities and industrial customers. The natural gas gathering and processing assets are located in five states and serve natural gas production in the Anadarko, Arkoma and Ark-La-Tex basins. This segment also includes a crude oil gathering business in the Bakken Shale formation, principally located in the Williston basin. The natural gas transportation and storage assets extend from western Oklahoma and the Texas Panhandle to Alabama and from Louisiana to Illinois. The Partnership is controlled equally by CenterPoint Energy and OGE Energy, who each have 50% of the management rights of Enable GP. Enable GP was established by CenterPoint Energy and OGE Energy to govern the Partnership and has no other operating activities. Enable GP is governed by a board made up of an equal number of representatives designated by each of CenterPoint Energy and OGE Energy, along with the independent board members CenterPoint Energy and OGE Energy mutually agreed to appoint. Based on the 50 / 50 management ownership, with neither company having control, CenterPoint Energy and OGE Energy do not consolidate their interests in the Partnership. CenterPoint Energy and OGE Energy also own a 40% and 60% interest, respectively, in the incentive distribution rights held by Enable GP. As of September 30, 2016 , CenterPoint Energy held approximately 55.4% of the common and subordinated units in the Partnership, or 94,151,707 common units and 139,704,916 subordinated units, and OGE Energy held approximately 26.3% of the common and subordinated units in the Partnership, or 42,832,291 common units and 68,150,514 subordinated units. Additionally, CenterPoint Energy holds 14,520,000 Series A Preferred Units. See Note 4 for further information related to the Series A Preferred Units. For the period from December 31, 2014 through June 29, 2015, the financial statements reflect a 49.90% interest in SESH. On June 12, 2015, CenterPoint Energy exercised its put right with respect to a 0.1% interest in SESH. Pursuant to the put right, on June 30, 2015, CenterPoint Energy contributed its remaining 0.1% interest in SESH to the Partnership in exchange for 25,341 common units representing limited partner interests in the Partnership. As of September 30, 2016 , the Partnership owned a 50% interest in SESH. See Note 6 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 combined and consolidated financial statements and related notes included in our Annual Report. These condensed consolidated financial statements and the related financial statement disclosures 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 14. 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. 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, we evaluate 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 $3 million allowance for doubtful accounts was required as of September 30, 2016 , and no allowance for doubtful accounts was required as of December 31, 2015 . Third Amended and Restated Agreement of Limited Partnership of Enable Midstream Partners, LP On February 18, 2016, in connection with the closing of the private placement of 14,520,000 Series A Preferred Units and pursuant to the Purchase Agreement, the General Partner adopted the Third Amended and Restated Agreement of Limited Partnership which, among other things, authorized and established the terms of the Series A Preferred Units and the other series of preferred units that are issuable upon conversion of the Series A Preferred Units. For further information related to the issuance of the Series A Preferred Units, see Note 4. Fourth Amended and Restated Agreement of Limited Partnership of Enable Midstream Partners, LP On June 22, 2016, the General Partner adopted the Fourth Amended and Restated Agreement of Limited Partnership (the Partnership Agreement), which changed the last permitted distribution date with respect to each fiscal quarter from 45 days following the close of such quarter to 60 days following the close of such quarter. |
New Accounting Pronouncements
New Accounting Pronouncements | 9 Months Ended |
Sep. 30, 2016 | |
Accounting Changes and Error Corrections [Abstract] | |
New Accounting Pronouncements | New Accounting Pronouncements Revenue from Contracts with Customers In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” which supersedes the revenue recognition requirements in “Revenue Recognition (Topic 605),” and requires entities to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services. In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606)—Deferral of the Effective Date,” which deferred the effective date of ASU 2014-09 by one year to December 15, 2017 for annual reporting periods beginning after that date. The FASB also proposed permitting early adoption of the standard, but not before the original effective date of December 15, 2016. In March 2016, the FASB issued ASU No. 2016-08, “Revenue from Contracts with Customers (Topic 606)—Principal versus Agent Considerations (Reporting Revenue Gross versus Net)”. ASU No. 2016-08 requires an entity to determine whether the nature of its promise is to provide the specified good or service itself (i.e., the entity is a principal) or to arrange for that good or service to be provided by the other party (i.e., the entity is an agent) when another party is involved in providing goods or services to a customer. Additionally, the amendments in this ASU require an entity that is a principal to recognize revenue in the gross amount of consideration to which it expects to be entitled in exchange for the specified good or service transferred to the customer, and require an entity that is an agent to recognize revenue in the amount of any fee or commission to which it expects to be entitled in exchange for arranging for the specified good or service to be provided by the other party. In April 2016, the FASB issued ASU No. 2016-10, “Revenue from Contracts with Customers (Topic 606)—Identifying Performance Obligations and Licensing”. The amendments in ASU No. 2016-10 impact entities with transactions that include contracts with customers to transfer goods or services (that are an output of the entity’s ordinary activities) in exchange for consideration, and they require entities to recognize revenue by following certain steps, including (1) identifying the contract(s) with a customer; (2) identifying the performance obligations in a contract; (3) determining the transaction price; (4) allocating the transaction price to the performance obligations in the contract; and (5) recognizing revenue when, or as, the entity satisfies a performance obligation. Notably, ASU No. 2016-10 does not impact the core revenue recognition principles set forth in Topic 606, but rather clarifies the identification of performance obligations and the licensing implementation guidance, while retaining the related principles for those areas. The Partnership is currently evaluating the impact, if any, the adoption of these revenue standards will have on our Condensed Consolidated Financial Statements and related disclosures. In connection with our assessment work, we formed an implementation work team, completed training on the ASU No. 2016-10 revenue recognition model and are continuing our review of contracts with our customers relative to the provisions of these revenue standards. Leases In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 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. The Partnership expects to adopt this standard in the first quarter of 2019 and is currently evaluating the impact of this standard on our Condensed Consolidated Financial Statements and related disclosures. In connection with our assessment work, we formed an implementation work team and are continuing our review of our contracts relative to the provisions of the lease standard. Share-Based Compensation In March 2016, the FASB issued ASU No. 2016-09, “Compensation—Stock Compensation (Topic 718).” This standard makes several modifications to Topic 718 related to the accounting for forfeitures, employer tax withholding on share-based compensation and the financial statement presentation of excess tax benefits or deficiencies. ASU 2016-09 also clarifies the statement of cash flows presentation for certain components of share-based awards. The standard is effective for interim and annual reporting periods beginning after December 15, 2016, although early adoption is permitted. The Partnership will adopt the amendment in the fourth quarter of 2016 and has determined the adoption of this standard will not have a material impact 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 is currently evaluating the impact, if any, the adoption of this standard will have on our Condensed Consolidated Financial Statements and related disclosures. Statement of Cash Flows In August 2016, the FASB issued ASU No. 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments.” This standard is intended to reduce existing diversity in practice in how certain transactions are presented on the statement of cash flows. The standard is effective for interim and annual reporting periods beginning after December 15, 2017, although early adoption is permitted. The Partnership is currently evaluating the impact, if any, the adoption of this standard will have on our Condensed Consolidated Financial Statements and related disclosures. |
Earnings Per Limited Partner Un
Earnings Per Limited Partner Unit | 9 Months Ended |
Sep. 30, 2016 | |
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 Nine Months Ended 2016 2015 2016 2015 (In millions, except per unit data) Net income (loss) $ 119 $ (991 ) $ 244 $ (823 ) Net loss attributable to noncontrolling interest — (6 ) — (6 ) Series A Preferred Unit distribution 9 — 13 — General partner interest in net income — — — — Net income (loss) available to common and subordinated unitholders $ 110 $ (985 ) $ 231 $ (817 ) Net income (loss) allocable to common units $ 56 $ (499 ) $ 117 $ (414 ) Net income (loss) allocable to subordinated units 54 (486 ) 114 (403 ) Net income (loss) available to common and subordinated unitholders $ 110 $ (985 ) $ 231 $ (817 ) Net income (loss) allocable to common units $ 56 $ (499 ) $ 117 $ (414 ) Dilutive effect of Series A Preferred Unit distribution — — — — Dilutive effect of performance units — — — — Diluted net income (loss) allocable to common units 56 (499 ) 117 (414 ) Diluted net income (loss) allocable to subordinated units 54 (486 ) 114 (403 ) Total $ 110 $ (985 ) $ 231 $ (817 ) Basic weighted average number of outstanding Common units 214 214 214 214 Subordinated units 208 208 208 208 Total 422 422 422 422 Basic earnings (loss) per unit Common units $ 0.26 $ (2.33 ) $ 0.55 $ (1.93 ) Subordinated units $ 0.26 $ (2.34 ) $ 0.55 $ (1.94 ) Basic weighted average number of outstanding common units 214 214 214 214 Dilutive effect of Series A Preferred Units — — — — Dilutive effect of performance units — — — — Diluted weighted average number of outstanding common units 214 214 214 214 Diluted weighted average number of outstanding subordinated units 208 208 208 208 Total 422 422 422 422 Diluted earnings (loss) per unit Common units $ 0.26 $ (2.33 ) $ 0.55 $ (1.93 ) Subordinated units $ 0.26 $ (2.34 ) $ 0.55 $ (1.94 ) There was no dilutive effect of Series A Preferred Units during the three and nine months ended September 30, 2016 and 2015 . The dilutive effect of the unit-based awards discussed in Note 13 was less than $0.01 per unit during the three and nine months ended September 30, 2016 and 2015 . |
Partners' Equity
Partners' Equity | 9 Months Ended |
Sep. 30, 2016 | |
Equity [Abstract] | |
Partners' Equity | Partners’ Equity The Partnership Agreement requires that, within 60 days subsequent to 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 during 2015 and 2016 (in millions, except for per unit amounts): Quarter Ended Record Date Payment Date Per Unit Distribution Total Cash Distribution September 30, 2016 (1) November 14, 2016 November 22, 2016 $ 0.318 $ 134 June 30, 2016 August 16, 2016 August 23, 2016 $ 0.318 $ 134 March 31, 2016 May 6, 2016 May 13, 2016 $ 0.318 $ 134 December 31, 2015 February 2, 2016 February 12, 2016 $ 0.318 $ 134 September 30, 2015 November 3, 2015 November 13, 2015 $ 0.318 $ 134 June 30, 2015 August 3, 2015 August 13, 2015 $ 0.316 $ 134 March 31, 2015 May 5, 2015 May 15, 2015 $ 0.3125 $ 132 _____________________ (1) The board of directors of Enable GP declared this $0.318 per common unit cash distribution on November 1, 2016 , to be paid on November 22, 2016 , to common and subordinated unitholders of record at the close of business on November 14, 2016 . The Partnership paid or has authorized payment of the following cash distributions to holders of the Series A Preferred Units during 2016 (in millions, except for per unit amounts): Quarter Ended Record Date Payment Date Per Unit Distribution Total Cash Distribution September 30, 2016 (1) November 1, 2016 November 14, 2016 $ 0.625 $ 9 June 30, 2016 August 2, 2016 August 12, 2016 $ 0.625 $ 9 March 31, 2016 (2) May 6, 2016 May 13, 2016 $ 0.2917 $ 4 _____________________ (1) The board of directors of Enable GP declared a $0.625 per Series A Preferred Unit cash distribution on November 1, 2016 , to be paid on November 14, 2016 , to Series A Preferred unitholders of record at the close of business on November 1, 2016 . (2) The prorated quarterly distribution for the Series A Preferred Units is for a partial period beginning on February 18, 2016, and ending on March 31, 2016, which equates to $0.625 per unit on a full-quarter basis or $2.50 per unit on an annualized basis. 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 or subordinated units that they own. Subordinated Units Subordinated Unit Ownership All subordinated units are held by CenterPoint Energy and OGE Energy. These units are considered subordinated because for a period of time, defined by the Partnership Agreement as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received distributions of available cash each quarter from operating surplus in an amount equal to $0.2875 per common unit, which amount is defined in the Partnership Agreement as the minimum quarterly distribution, plus any arrearages on minimum quarterly distributions on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. In addition, during the subordination period, the subordinated units are not entitled to arrearages on minimum quarterly distributions. On the expiration of the subordination period, the subordinated units will convert to common units on a one-for-one basis. Subordination Period The subordination period began on the closing date of the Offering and expires on the first business day after the date on which the following tests are met: (1) distributions of available cash from operating surplus (as defined in the Partnership Agreement) on each of the outstanding common units and subordinated units equal or exceed $1.15 per unit (the annualized minimum quarterly distribution) for each of the three consecutive, non-overlapping four-quarter periods immediately preceding June 30, 2017 and (2) the adjusted operating surplus for each of the three consecutive, non-overlapping four-quarter periods immediately preceding such date equaled or exceeded the sum of the minimum quarterly distribution on all common units and subordinated units that were outstanding during such periods on a fully diluted weighted average basis. Also, if the Partnership has paid distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equal to or exceeding $1.725 per unit ( 150% of the annualized minimum quarterly distribution) and the related distribution on the incentive distribution rights, for any four-consecutive-quarter period ending on or after June 30, 2015, the subordination period will expire. Series A Preferred Units On February 18, 2016, the Partnership completed the 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. Holders of the Series A Preferred Units receive a quarterly cash distribution on a non-cumulative basis if and when declared by the General Partner, and subject to certain adjustments, equal to 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. |
Assessing Impairment of Long-li
Assessing Impairment of Long-lived Assets (including Intangible Assets) and Goodwill | 9 Months Ended |
Sep. 30, 2016 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Assessing Impairment of Long-lived Assets (including Intangible Assets) and Goodwill | Assessing Impairment of Long-lived Assets (including Intangible Assets) and Goodwill Impairment of Long-lived Assets (including Intangible Assets) The Partnership periodically evaluates long-lived assets, including property, plant and equipment, and specifically identifiable intangibles other than goodwill, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted cash flows attributable to the assets, as compared to the carrying value of the assets. During each of the three and nine months ended September 30, 2016 , the Partnership recorded an $8 million impairment and during each of the three and nine months ended September 30, 2015, the Partnership recorded a $6 million impairment, to our Service Star business line, which is included in Impairments on the Condensed Consolidated Statements of Income. The Service Star business line is a component of our gathering and processing segment, that provides measurement and communication services to third parties. The 2016 impairment, which impaired substantially all of the remaining net book value of the Service Star business line, was primarily driven by the impact of planned technology changes affecting Service Star and in 2015, the impairment was primarily driven by the expected loss of customers by Service Star. During each of the three and nine months ended September 30, 2015 , the Partnership recorded a $12 million impairment on jurisdictional pipelines in our transportation and storage segment. The Partnership recorded no other material impairments to long-lived assets in the three and nine months ended September 30, 2016 and 2015 . Based upon review of forecasted undiscounted cash flows, none of the other asset groups were at risk of failing step one of the impairment test. Further price declines, throughput declines, cost increases, regulatory or political environment changes, and other changes in market conditions could reduce forecast undiscounted cash flows. Impairment of Goodwill When the Partnership performed its goodwill impairment analysis as of October 1, 2015, the Partnership determined that goodwill was completely impaired in the amount of $1,087 million , which is included in Impairments on the Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2015 . As a result, the Partnership did not have any goodwill recorded as of September 30, 2016 or December 31, 2015 . |
Investment in Equity Method Aff
Investment in Equity Method Affiliate | 9 Months Ended |
Sep. 30, 2016 | |
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. For the period from December 31, 2014 through June 29, 2015, the Partnership held a 49.90% interest in SESH. On June 12, 2015, CenterPoint Energy exercised its put right with respect to its remaining 0.1% interest in SESH. Pursuant to the put right, on June 30, 2015, CenterPoint Energy contributed a 0.1% interest in SESH to the Partnership in exchange for 25,341 common units representing limited partner interests in the Partnership, which had a fair value of $1 million based upon the closing market price of the Partnership’s common units. Spectra Energy Partners, LP owns the remaining 50% interest in SESH. 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 our interest in SESH at fair market value. As of September 30, 2016 , the Partnership owned a 50% interest in SESH. 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 $3 million and $6 million during the three months ended September 30, 2016 and 2015 , respectively, and $12 million and $10 million during the nine months ended September 30, 2016 and 2015 , respectively, associated with these service agreements. Investment in Equity Method Affiliate: Nine Months Ended 2016 2015 (In millions) Balance as of December 31, $ 344 $ 348 Interest acquisition of SESH — 1 Equity in earnings of equity method affiliate 22 21 Contributions to equity method affiliate — 8 Distributions from equity method affiliate (1) (40 ) (37 ) Balance as of September 30, $ 326 $ 341 ____________________ (1) Distributions from equity method affiliate includes a $22 million and $26 million return on investment and a $18 million and $11 million return of investment for the nine months ended September 30, 2016 and 2015 , respectively. Equity in Earnings of Equity Method Affiliate: Three Months Ended Nine Months Ended 2016 2015 2016 2015 (In millions) SESH $ 8 $ 7 $ 22 $ 21 Distributions from Equity Method Affiliate: Three Months Ended Nine Months Ended 2016 2015 2016 2015 (In millions) SESH $ 13 $ 10 $ 40 $ 37 Summarized financial information of SESH: Three Months Ended Nine Months Ended 2016 2015 2016 2015 (In millions) Income Statements: Revenues $ 29 $ 29 $ 86 $ 86 Operating income 19 18 56 54 Net income 15 14 43 42 |
Debt
Debt | 9 Months Ended |
Sep. 30, 2016 | |
Debt Disclosure [Abstract] | |
Debt | Debt The following table presents the Partnership’s outstanding debt as of September 30, 2016 and December 31, 2015 . September 30, December 31, (In millions) Commercial Paper $ — $ 236 2015 Term Loan Agreement 450 450 Revolving Credit Facility 755 310 Notes payable — affiliated companies (Note 11) — 363 2019 Notes 500 500 2024 Notes 600 600 2044 Notes 550 550 EOIT Senior Notes 250 250 Premium (Discount) on long-term debt 19 23 Total debt 3,124 3,282 Less: Short-term debt (1) — 236 Less: Unamortized debt expense 11 12 Less: Notes payable—affiliated companies — 363 Total long-term debt $ 3,113 $ 2,671 ___________________ (1) There were no commercial paper borrowings outstanding as of September 30, 2016 . Short-term debt included $236 million of commercial paper as of December 31, 2015 . Revolving Credit Facility On June 18, 2015, the Partnership amended and restated its Revolving Credit Facility to, among other things, increase the borrowing capacity thereunder to $1.75 billion and extend its maturity date to June 18, 2020. As of September 30, 2016 , there was $755 million of principal advances and $3 million in letters of credit outstanding under the Revolving Credit Facility. The weighted average interest rate of the Revolving Credit Facility was 2.03% as of September 30, 2016 . The Revolving Credit Facility provides that outstanding borrowings bear interest at 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 September 30, 2016 , 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 September 30, 2016 , the commitment fee under the 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 was zero and $236 million outstanding under our commercial paper program as of September 30, 2016 and December 31, 2015 , respectively. On February 2, 2016, Standard & Poor’s Ratings Services lowered its credit rating on the Partnership from an investment grade rating to a non-investment grade rating. The short-term rating on the Partnership was also reduced from an investment grade rating to a non-investment grade rating. As a result of the downgrade, the Partnership repaid its outstanding borrowings under the commercial program upon maturity and did not issue any additional commercial paper. 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 (2015 Term Loan Agreement). The entire $450 million principal amount of the 2015 Term Loan Agreement was borrowed by the Partnership on July 31, 2015. The 2015 Term Loan Agreement contains an option, which may be exercised up to two times, to extend the term of the 2015 Term Loan Agreement, in each case, for an additional one -year term. The 2015 Term Loan Agreement provides an option to prepay, without penalty or premium, the amount outstanding, or any portion thereof, in a minimum amount of $1 million , or any multiple of $0.5 million in excess thereof. As of September 30, 2016 , there was $450 million outstanding under the 2015 Term Loan Agreement. As of September 30, 2016 , the weighted average interest rate of the 2015 Term Loan Agreement was 1.83% . The 2015 Term Loan Agreement provides that outstanding borrowings bear interest at LIBOR and/or an alternate base rate, at the Partnership’s election, plus an applicable margin. The applicable margin is based on our applicable credit ratings. As of September 30, 2016 , the applicable margin for LIBOR-based borrowings under the term loan agreement was 1.375% based on the Partnership’s credit ratings. Senior Notes In connection with the issuance of the 2019 Notes, 2024 Notes and 2044 Notes, the Partnership, CenterPoint Energy Resources Corp., as guarantor of the 2019 Notes and the 2024 Notes, and RBS Securities Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Credit Suisse Securities (USA) LLC, and RBC Capital Markets, LLC, as representatives of the initial purchasers, entered into a registration rights agreement whereby the Partnership and the guarantor agreed to file with the SEC a registration statement relating to a registered offer to exchange the 2019 Notes, 2024 Notes and 2044 Notes for new series of the Partnership’s notes in the same aggregate principal amount as, and with terms substantially identical in all respects to, the 2019 Notes, 2024 Notes and 2044 Notes. On December 29, 2015, the Partnership completed the exchange offer. A wholly owned subsidiary of CenterPoint Energy guaranteed collection of the Partnership’s obligations under the 2019 Notes and the 2024 Notes, which expired on May 1, 2016. As of September 30, 2016 , the Partnership’s debt included EOIT’s $250 million 6.25% senior notes due March 2020 (the EOIT Senior Notes). The EOIT Senior Notes have a $20 million unamortized premium at September 30, 2016 , resulting in an effective interest rate of 5.80% , during the nine months ended September 30, 2016 . These senior notes do not contain any financial covenants other than a limitation on liens. This limitation on liens is subject to certain exceptions and qualifications. Financing Costs Unamortized debt expense of $16 million and $18 million as of September 30, 2016 and December 31, 2015 , respectively, is classified as either a reduction to Long-Term Debt or Other Assets in the Condensed Consolidated Balance Sheets and is being amortized over the life of the respective debt. Unamortized premium, net of unamortized discount on long-term debt of $19 million and $23 million at September 30, 2016 and December 31, 2015 , respectively, is classified as either Long-Term Debt or Short-Term Debt, consistent with the underlying debt instrument, in the Condensed Consolidated Balance Sheets and is being amortized over the life of the respective debt. As of September 30, 2016 , the Partnership and EOIT were in compliance with all of their debt agreements, including financial covenants. |
Fair Value Measurements
Fair Value Measurements | 9 Months Ended |
Sep. 30, 2016 | |
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 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 September 30, 2016 , there were no transfers between Level 1, 2, and 3 investments. 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. 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 September 30, 2016 and December 31, 2015 : September 30, 2016 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 $ 9 $ — $ — Significant other observable inputs (Level 2) 1 1 17 16 Unobservable inputs (Level 3) — 5 — — Total fair value 3 15 17 16 Netting adjustments (1 ) (1 ) — — Total $ 2 $ 14 $ 17 $ 16 December 31, 2015 Commodity Contracts Gas Imbalances (1) Assets Liabilities Assets (2) Liabilities (3) (In millions) Quoted market prices in active market for identical assets (Level 1) $ 17 $ 3 $ — $ — Significant other observable inputs (Level 2) 10 — 17 20 Unobservable inputs (Level 3) 4 — — — Total fair value 31 3 17 20 Netting adjustments (3 ) (3 ) — — Total $ 28 $ — $ 17 $ 20 ______________________ (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 September 30, 2016 and December 31, 2015 . (2) Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $3 million and $6 million at September 30, 2016 and December 31, 2015 , 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 $6 million and $5 million at September 30, 2016 and December 31, 2015 , 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 as of December 31, 2015 $ 4 Losses included in earnings (8 ) Settlements (1 ) Balance as of September 30, 2016 $ (5 ) 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. September 30, 2016 Product Group Fair Value Forward Curve Range (In millions) (Per gallon) Natural gas liquids $ 5 $0.530 - $0.568 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 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 September 30, 2016 and December 31, 2015 . September 30, 2016 December 31, 2015 Carrying Amount Fair Value Carrying Amount Fair Value (In millions) Long-Term Debt Long-term notes payable — affiliated companies (Level 2) $ — $ — $ 363 $ 350 Revolving Credit Facility (Level 2) (1) 755 755 310 310 2015 Term Loan Agreement (Level 2) 450 450 450 450 EOIT Senior Notes (Level 2) 270 268 273 280 Enable Midstream Partners, LP 2019, 2024 and 2044 Notes (Level 2) 1,649 1,525 1,650 1,255 ___________________ (1) Borrowing capacity is effectively reduced by our borrowings outstanding under the commercial paper program. There was zero and $236 million of commercial paper outstanding as of September 30, 2016 and December 31, 2015 , respectively. The fair value of the Partnership’s Long-term notes payable—affiliated companies, Revolving Credit Facility, and 2015 Term Loan Agreement, along with the EOIT Senior Notes and Enable Midstream Partners, LP 2019, 2024 and 2044 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 September 30, 2016 , no other material fair value adjustments or fair value measurements were required for these non-financial assets or liabilities, with the exception of those discussed in Note 5. |
Derivative Instruments and Hedg
Derivative Instruments and Hedging Activities | 9 Months Ended |
Sep. 30, 2016 | |
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 and asset management activities; • 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, therefore, are recorded at fair value on a net basis in Other Current Assets in the Condensed Consolidated Balance Sheets. As of September 30, 2016 and December 31, 2015 , 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 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 September 30, 2016 and December 31, 2015 , the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes: September 30, 2016 December 31, 2015 Gross Notional Volume Purchases Sales Purchases Sales Natural gas— TBtu (1) Financial fixed futures/swaps 2 34 1 37 Financial basis futures/swaps 2 34 4 38 Physical purchases/sales — 39 2 51 Crude oil (for condensate)— MBbl (2) Financial Futures/swaps — 450 — 506 Natural gas liquids— MBbl (3) Financial Futures/swaps 75 1,248 75 1,011 ____________________ (1) As of September 30, 2016 , 94.0% of the natural gas contracts had durations of one year or less and 6.0% had durations of more than one year and less than two years. As of December 31, 2015 , 97.7% of the natural gas contracts had durations of one year or less and 2.3% had durations of more than one year and less than two years. (2) As of September 30, 2016 , 90.0% of the condensate contracts had durations of one year or less and 10.0% had durations of more than one year and less than two years. As of December 31, 2015 , 100% of the crude oil (for condensate) contracts had durations of one year or less. (3) As of September 30, 2016 , 89.8% of the natural gas liquids contracts had durations of one year or less and 10.2% had durations of more than one year and less than two years. As of December 31, 2015 , 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 September 30, 2016 and December 31, 2015 that were not designated as hedging instruments for accounting purposes are as follows: September 30, 2016 December 31, 2015 Fair Value Instrument Balance Sheet Location Assets Liabilities Assets Liabilities (In millions) Natural gas Financial futures/swaps Other Current $ 2 $ 9 $ 17 $ 3 Physical purchases/sales Other Current — — 1 — Crude Oil (for condensate) Financial futures/swaps Other Current 1 1 9 — Natural gas liquids Financial Futures/swaps Other Current — 5 4 — Total gross derivatives (1) $ 3 $ 15 $ 31 $ 3 _____________________ (1) See Note 8 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Condensed Consolidated Balance Sheets as of September 30, 2016 and December 31, 2015 . 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 nine months ended September 30, 2016 and 2015. Amounts Recognized in Income Three Months Ended Nine Months Ended 2016 2015 2016 2015 (In millions) Natural gas financial futures/swaps gains (losses) $ 6 $ 10 $ (5 ) $ 13 Natural gas physical purchases/sales gains (losses) 1 (1 ) (7 ) (5 ) Crude Oil (for condensate) financial futures/swaps gains (losses) 1 11 (2 ) 8 Natural gas liquids financial futures/swaps gains (losses) 1 1 (8 ) 7 Total $ 9 $ 21 $ (22 ) $ 23 For derivatives not designated as hedges in the tables above, amounts recognized in income for the periods ended September 30, 2016 and 2015 , 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 nine months ended September 30, 2016 and 2015 . Three Months Ended Nine Months Ended 2016 2015 2016 2015 (In millions) Change in fair value of derivatives $ 8 $ 6 $ (40 ) $ (11 ) Realized gain on derivatives 1 15 18 34 Gain (loss) on derivative activity $ 9 $ 21 $ (22 ) $ 23 Credit-Risk Related Contingent Features in Derivative Instruments Based upon the Partnership’s senior unsecured debt rating with Moody’s Investors Services or Standard & Poor’s Ratings Services, the Partnership could be required to provide 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 September 30, 2016 , under these obligations, no cash collateral has been posted. However, based on positions as of September 30, 2016 , approximately $2 million of additional collateral may be required to be posted by the Partnership. |
Supplemental Disclosure of Cash
Supplemental Disclosure of Cash Flow Information | 9 Months Ended |
Sep. 30, 2016 | |
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: Nine Months Ended 2016 2015 (In millions) Supplemental Disclosure of Cash Flow Information: Cash Payments: Interest, net of capitalized interest $ 67 $ 61 Income taxes, net of refunds 1 2 Non-cash transactions: Accounts payable related to capital expenditures 32 66 Issuance of common units upon interest acquisition of SESH (Note 6) — 1 |
Related Party Transactions
Related Party Transactions | 9 Months Ended |
Sep. 30, 2016 | |
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. The Partnership’s revenues from affiliated companies accounted for 6% and 6% of revenues during the three months ended September 30, 2016 and 2015 , respectively, and 7% and 7% of revenues during the nine months ended September 30, 2016 and 2015 , respectively. Amounts of revenues from affiliated companies included in the Partnership’s Condensed Consolidated Statements of Income are summarized as follows: Three Months Ended Nine Months Ended 2016 2015 2016 2015 (In millions) Gas transportation and storage service revenue — CenterPoint Energy $ 22 $ 23 $ 79 $ 79 Natural gas product sales — CenterPoint Energy — — 1 7 Gas transportation and storage service revenue — OGE Energy 10 10 28 28 Natural gas product sales — OGE Energy 4 3 10 7 Total revenues — affiliated companies $ 36 $ 36 $ 118 $ 121 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 Nine Months Ended 2016 2015 2016 2015 (In millions) Cost of natural gas purchases — CenterPoint Energy $ — $ 1 $ — $ 2 Cost of natural gas purchases — OGE Energy 4 5 9 12 Total cost of natural gas purchases — affiliated companies $ 4 $ 6 $ 9 $ 14 Prior to May 1, 2013, the Partnership had employees and reflected the associated benefit costs directly and not as corporate services. Under the terms of the MFA, effective May 1, 2013 the Partnership’s employees were seconded by CenterPoint Energy and OGE Energy, and the Partnership began reimbursing each of CenterPoint Energy and OGE Energy for all employee costs under the seconding agreements until the seconded employees transition from CenterPoint Energy and OGE Energy to the Partnership. The Partnership transitioned seconded employees from CenterPoint Energy and OGE Energy to the Partnership effective January 1, 2015, except for 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 employee costs arising out of OGE Energy’s defined benefit and retiree medical plans is fixed at $6 million in 2016, $5 million in 2017, and at actual cost subject to a cap of $5 million in 2018 and thereafter, in the event of continued secondment. Prior to May 1, 2013, the Partnership received certain services and support functions from CenterPoint Energy described below. Under the terms of the MFA, effective May 1, 2013, the Partnership receives services and support functions from each of CenterPoint Energy and OGE Energy under service agreements for an initial term that ended on April 30, 2016. The service 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 these service 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 2016 are $7 million and $6 million , respectively. Amounts charged to the Partnership by affiliates for seconded employees 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 Nine Months Ended 2016 2015 2016 2015 (In millions) Corporate Services — CenterPoint Energy $ 1 $ 5 $ 6 $ 12 Seconded Employee Costs — OGE Energy 5 12 22 30 Corporate Services — OGE Energy 1 2 4 8 Total corporate services and seconded employees expense $ 7 $ 19 $ 32 $ 50 The Partnership had outstanding long-term notes payable—affiliated companies to CenterPoint Energy at December 31, 2015 of $363 million , which were scheduled to mature in 2017 . On February 18, 2016, in connection with the private placement of the Series A Preferred Units, the Partnership redeemed the $363 million of notes payable—affiliated companies payable to a subsidiary of CenterPoint Energy. The Partnership recorded affiliated interest expense to CenterPoint Energy on notes payable—affiliated companies of zero and $2 million during the three months ended September 30, 2016 and 2015 , respectively, and $1 million and $6 million during the nine months ended September 30, 2016 and 2015 , respectively. On February 18, 2016, the Partnership completed the private placement, with 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 4 for further discussion. |
Commitments and Contingencies
Commitments and Contingencies | 9 Months Ended |
Sep. 30, 2016 | |
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. |
Equity Based Compensation
Equity Based Compensation | 9 Months Ended |
Sep. 30, 2016 | |
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 nine months ended September 30, 2016 and 2015 related to performance units, restricted units, and phantom units for the Partnership’s employees and independent directors: Three Months Ended Nine Months Ended 2016 2015 2016 2015 (In millions) Performance units $ 4 $ 1 $ 7 $ 3 Restricted units 1 2 2 5 Phantom units — — 1 1 Total compensation expense $ 5 $ 3 $ 10 $ 9 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 September 30, 2016 and changes during 2016 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, 2015 814,510 $ 20.67 581,772 $ 21.04 9,817 $ 12.70 Granted 1,235,429 10.80 — — 647,356 8.39 Vested (6,427 ) 20.77 (91,700 ) 22.84 (321 ) 8.12 Forfeited (56,664 ) 17.27 (53,935 ) 19.29 (8,421 ) 8.12 Units Outstanding at September 30, 2016 1,986,848 $ 15.24 436,137 $ 20.89 648,431 $ 8.46 Aggregate Intrinsic Value of Units Outstanding at September 30, 2016 $ 30 $ 7 $ 10 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. September 30, 2016 Unrecognized Compensation Cost (In millions) Weighted Average to be Recognized (In years) Performance Units $ 17 2.06 Restricted Units 3 1.32 Phantom Units 5 2.44 Total $ 25 As of September 30, 2016 , there were 9,292,500 units available for issuance under the long term incentive plan. |
Reportable Segments
Reportable Segments | 9 Months Ended |
Sep. 30, 2016 | |
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 2015 combined and 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 gathering, processing and fractionation services and crude oil gathering for our producer customers, and (ii) Transportation and Storage, which provides interstate and intrastate natural gas pipeline transportation and storage service primarily to natural gas producers, utilities and industrial customers. Financial data for reportable segments are as follows: Three Months Ended September 30, 2016 Gathering and Processing Transportation and Storage (1) Eliminations Total (In millions) Product sales $ 295 $ 150 $ (119 ) $ 326 Service revenue 160 135 (1 ) 294 Total Revenues 455 285 (120 ) 620 Cost of natural gas and natural gas liquids 246 141 (119 ) 268 Operation and maintenance, General and administrative 63 46 (1 ) 108 Depreciation and amortization 53 31 — 84 Impairments 8 — — 8 Taxes other than income tax 8 5 — 13 Operating income $ 77 $ 62 $ — $ 139 Total assets $ 7,502 $ 4,947 $ (1,208 ) $ 11,241 Capital expenditures $ 52 $ 16 $ — $ 68 Three Months Ended September 30, 2015 Gathering and Processing Transportation and Storage (1) Eliminations Total (In millions) Product sales $ 299 $ 166 $ (108 ) $ 357 Service revenue 157 133 (1 ) 289 Total Revenues 456 299 (109 ) 646 Cost of natural gas and natural gas liquids 235 161 (109 ) 287 Operation and maintenance, General and administrative 75 55 — 130 Depreciation and amortization 53 31 — 84 Impairments 514 591 — 1,105 Taxes other than income tax 8 7 — 15 Operating income (loss) $ (429 ) $ (546 ) $ — $ (975 ) Total assets as of December 31, 2015 $ 7,536 $ 4,976 $ (1,286 ) $ 11,226 Capital expenditures $ 167 $ 31 $ — $ 198 Nine Months Ended September 30, 2016 Gathering and Processing Transportation and Storage (1) Eliminations Total (In millions) Product sales $ 759 $ 348 $ (270 ) $ 837 Service revenue 416 408 (3 ) 821 Total Revenues 1,175 756 (273 ) 1,658 Cost of natural gas and natural gas liquids 642 346 (271 ) 717 Operation and maintenance, General and administrative 205 140 (2 ) 343 Depreciation and amortization 154 94 — 248 Impairments 8 — — 8 Taxes other than income tax 24 19 — 43 Operating income $ 142 $ 157 $ — $ 299 Total assets $ 7,502 $ 4,947 $ (1,208 ) $ 11,241 Capital expenditures $ 252 $ 37 $ — $ 289 Nine Months Ended September 30, 2015 Gathering and Processing Transportation and Storage (1) Eliminations Total (In millions) Product sales $ 875 $ 467 $ (299 ) $ 1,043 Service revenue 404 408 (3 ) 809 Total Revenues 1,279 875 (302 ) 1,852 Cost of natural gas and natural gas liquids 698 459 (301 ) 856 Operation and maintenance, General and administrative 229 163 (1 ) 391 Depreciation and amortization 141 92 — 233 Impairments 514 591 — 1,105 Taxes other than income tax 23 22 — 45 Operating income (loss) $ (326 ) $ (452 ) $ — $ (778 ) Total assets as of December 31, 2015 $ 7,536 $ 4,976 $ (1,286 ) $ 11,226 Capital expenditures $ 657 $ 77 $ — $ 734 _____________________ (1) See Note 6 for discussion regarding ownership interests in SESH and related equity earnings included in the Transportation and Storage segment for the three and nine months ended September 30, 2016 and 2015 . |
Summary of Significant Accoun22
Summary of Significant Accounting Policies (Policies) | 9 Months Ended |
Sep. 30, 2016 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization | Organization Enable Midstream Partners, LP (Partnership) is a large-scale, growth-oriented Delaware limited partnership formed to own, operate and develop strategically located natural gas and crude oil infrastructure assets. The Partnership’s assets and operations are organized into two reportable segments: (i) Gathering and Processing, which primarily provides natural gas gathering, processing and fractionation services and crude oil gathering for our producer customers, and (ii) Transportation and Storage, which provides interstate and intrastate natural gas pipeline transportation and storage services primarily to natural gas producers, utilities and industrial customers. The natural gas gathering and processing assets are located in five states and serve natural gas production in the Anadarko, Arkoma and Ark-La-Tex basins. This segment also includes a crude oil gathering business in the Bakken Shale formation, principally located in the Williston basin. The natural gas transportation and storage assets extend from western Oklahoma and the Texas Panhandle to Alabama and from Louisiana to Illinois. The Partnership is controlled equally by CenterPoint Energy and OGE Energy, who each have 50% of the management rights of Enable GP. Enable GP was established by CenterPoint Energy and OGE Energy to govern the Partnership and has no other operating activities. Enable GP is governed by a board made up of an equal number of representatives designated by each of CenterPoint Energy and OGE Energy, along with the independent board members CenterPoint Energy and OGE Energy mutually agreed to appoint. Based on the 50 / 50 management ownership, with neither company having control, CenterPoint Energy and OGE Energy do not consolidate their interests in the Partnership. CenterPoint Energy and OGE Energy also own a 40% and 60% interest, respectively, in the incentive distribution rights held by Enable GP. As of September 30, 2016 , CenterPoint Energy held approximately 55.4% of the common and subordinated units in the Partnership, or 94,151,707 common units and 139,704,916 subordinated units, and OGE Energy held approximately 26.3% of the common and subordinated units in the Partnership, or 42,832,291 common units and 68,150,514 subordinated units. Additionally, CenterPoint Energy holds 14,520,000 Series A Preferred Units. See Note 4 for further information related to the Series A Preferred Units. For the period from December 31, 2014 through June 29, 2015, the financial statements reflect a 49.90% interest in SESH. On June 12, 2015, CenterPoint Energy exercised its put right with respect to a 0.1% interest in SESH. Pursuant to the put right, on June 30, 2015, CenterPoint Energy contributed its remaining 0.1% interest in SESH to the Partnership in exchange for 25,341 common units representing limited partner interests in the Partnership. As of September 30, 2016 , the Partnership owned a 50% interest in SESH. See Note 6 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 combined and consolidated financial statements and related notes included in our Annual Report. These condensed consolidated financial statements and the related financial statement disclosures 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. |
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, we evaluate 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. |
New Accounting Pronouncements | Revenue from Contracts with Customers In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” which supersedes the revenue recognition requirements in “Revenue Recognition (Topic 605),” and requires entities to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services. In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606)—Deferral of the Effective Date,” which deferred the effective date of ASU 2014-09 by one year to December 15, 2017 for annual reporting periods beginning after that date. The FASB also proposed permitting early adoption of the standard, but not before the original effective date of December 15, 2016. In March 2016, the FASB issued ASU No. 2016-08, “Revenue from Contracts with Customers (Topic 606)—Principal versus Agent Considerations (Reporting Revenue Gross versus Net)”. ASU No. 2016-08 requires an entity to determine whether the nature of its promise is to provide the specified good or service itself (i.e., the entity is a principal) or to arrange for that good or service to be provided by the other party (i.e., the entity is an agent) when another party is involved in providing goods or services to a customer. Additionally, the amendments in this ASU require an entity that is a principal to recognize revenue in the gross amount of consideration to which it expects to be entitled in exchange for the specified good or service transferred to the customer, and require an entity that is an agent to recognize revenue in the amount of any fee or commission to which it expects to be entitled in exchange for arranging for the specified good or service to be provided by the other party. In April 2016, the FASB issued ASU No. 2016-10, “Revenue from Contracts with Customers (Topic 606)—Identifying Performance Obligations and Licensing”. The amendments in ASU No. 2016-10 impact entities with transactions that include contracts with customers to transfer goods or services (that are an output of the entity’s ordinary activities) in exchange for consideration, and they require entities to recognize revenue by following certain steps, including (1) identifying the contract(s) with a customer; (2) identifying the performance obligations in a contract; (3) determining the transaction price; (4) allocating the transaction price to the performance obligations in the contract; and (5) recognizing revenue when, or as, the entity satisfies a performance obligation. Notably, ASU No. 2016-10 does not impact the core revenue recognition principles set forth in Topic 606, but rather clarifies the identification of performance obligations and the licensing implementation guidance, while retaining the related principles for those areas. The Partnership is currently evaluating the impact, if any, the adoption of these revenue standards will have on our Condensed Consolidated Financial Statements and related disclosures. In connection with our assessment work, we formed an implementation work team, completed training on the ASU No. 2016-10 revenue recognition model and are continuing our review of contracts with our customers relative to the provisions of these revenue standards. Leases In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 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. The Partnership expects to adopt this standard in the first quarter of 2019 and is currently evaluating the impact of this standard on our Condensed Consolidated Financial Statements and related disclosures. In connection with our assessment work, we formed an implementation work team and are continuing our review of our contracts relative to the provisions of the lease standard. Share-Based Compensation In March 2016, the FASB issued ASU No. 2016-09, “Compensation—Stock Compensation (Topic 718).” This standard makes several modifications to Topic 718 related to the accounting for forfeitures, employer tax withholding on share-based compensation and the financial statement presentation of excess tax benefits or deficiencies. ASU 2016-09 also clarifies the statement of cash flows presentation for certain components of share-based awards. The standard is effective for interim and annual reporting periods beginning after December 15, 2016, although early adoption is permitted. The Partnership will adopt the amendment in the fourth quarter of 2016 and has determined the adoption of this standard will not have a material impact 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 is currently evaluating the impact, if any, the adoption of this standard will have on our Condensed Consolidated Financial Statements and related disclosures. Statement of Cash Flows In August 2016, the FASB issued ASU No. 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments.” This standard is intended to reduce existing diversity in practice in how certain transactions are presented on the statement of cash flows. The standard is effective for interim and annual reporting periods beginning after December 15, 2017, although early adoption is permitted. The Partnership is currently evaluating the impact, if any, the adoption of this standard will have on our Condensed Consolidated Financial Statements and related disclosures. |
Fair Value Measurements | 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. 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 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 September 30, 2016 , there were no transfers between Level 1, 2, and 3 investments. 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. |
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. |
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 and asset management activities; • 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, therefore, are recorded at fair value on a net basis in Other Current Assets in the Condensed Consolidated Balance Sheets. As of September 30, 2016 and December 31, 2015 , 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 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. |
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 2015 combined and 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 gathering, processing and fractionation services and crude oil gathering for our producer customers, and (ii) Transportation and Storage, which provides interstate and intrastate natural gas pipeline transportation and storage service primarily to natural gas producers, utilities and industrial customers. |
Earnings Per Limited Partner 23
Earnings Per Limited Partner Unit (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
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 Nine Months Ended 2016 2015 2016 2015 (In millions, except per unit data) Net income (loss) $ 119 $ (991 ) $ 244 $ (823 ) Net loss attributable to noncontrolling interest — (6 ) — (6 ) Series A Preferred Unit distribution 9 — 13 — General partner interest in net income — — — — Net income (loss) available to common and subordinated unitholders $ 110 $ (985 ) $ 231 $ (817 ) Net income (loss) allocable to common units $ 56 $ (499 ) $ 117 $ (414 ) Net income (loss) allocable to subordinated units 54 (486 ) 114 (403 ) Net income (loss) available to common and subordinated unitholders $ 110 $ (985 ) $ 231 $ (817 ) Net income (loss) allocable to common units $ 56 $ (499 ) $ 117 $ (414 ) Dilutive effect of Series A Preferred Unit distribution — — — — Dilutive effect of performance units — — — — Diluted net income (loss) allocable to common units 56 (499 ) 117 (414 ) Diluted net income (loss) allocable to subordinated units 54 (486 ) 114 (403 ) Total $ 110 $ (985 ) $ 231 $ (817 ) Basic weighted average number of outstanding Common units 214 214 214 214 Subordinated units 208 208 208 208 Total 422 422 422 422 Basic earnings (loss) per unit Common units $ 0.26 $ (2.33 ) $ 0.55 $ (1.93 ) Subordinated units $ 0.26 $ (2.34 ) $ 0.55 $ (1.94 ) Basic weighted average number of outstanding common units 214 214 214 214 Dilutive effect of Series A Preferred Units — — — — Dilutive effect of performance units — — — — Diluted weighted average number of outstanding common units 214 214 214 214 Diluted weighted average number of outstanding subordinated units 208 208 208 208 Total 422 422 422 422 Diluted earnings (loss) per unit Common units $ 0.26 $ (2.33 ) $ 0.55 $ (1.93 ) Subordinated units $ 0.26 $ (2.34 ) $ 0.55 $ (1.94 ) |
Partners' Equity (Tables)
Partners' Equity (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
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 during 2015 and 2016 (in millions, except for per unit amounts): Quarter Ended Record Date Payment Date Per Unit Distribution Total Cash Distribution September 30, 2016 (1) November 14, 2016 November 22, 2016 $ 0.318 $ 134 June 30, 2016 August 16, 2016 August 23, 2016 $ 0.318 $ 134 March 31, 2016 May 6, 2016 May 13, 2016 $ 0.318 $ 134 December 31, 2015 February 2, 2016 February 12, 2016 $ 0.318 $ 134 September 30, 2015 November 3, 2015 November 13, 2015 $ 0.318 $ 134 June 30, 2015 August 3, 2015 August 13, 2015 $ 0.316 $ 134 March 31, 2015 May 5, 2015 May 15, 2015 $ 0.3125 $ 132 _____________________ (1) The board of directors of Enable GP declared this $0.318 per common unit cash distribution on November 1, 2016 , to be paid on November 22, 2016 , to common and subordinated unitholders of record at the close of business on November 14, 2016 . |
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 2016 (in millions, except for per unit amounts): Quarter Ended Record Date Payment Date Per Unit Distribution Total Cash Distribution September 30, 2016 (1) November 1, 2016 November 14, 2016 $ 0.625 $ 9 June 30, 2016 August 2, 2016 August 12, 2016 $ 0.625 $ 9 March 31, 2016 (2) May 6, 2016 May 13, 2016 $ 0.2917 $ 4 _____________________ (1) The board of directors of Enable GP declared a $0.625 per Series A Preferred Unit cash distribution on November 1, 2016 , to be paid on November 14, 2016 , to Series A Preferred unitholders of record at the close of business on November 1, 2016 . (2) The prorated quarterly distribution for the Series A Preferred Units is for a partial period beginning on February 18, 2016, and ending on March 31, 2016, which equates to $0.625 per unit on a full-quarter basis or $2.50 per unit on an annualized basis |
Investment in Unconsolidated Af
Investment in Unconsolidated Affiliate (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Equity Method Investments and Joint Ventures [Abstract] | |
Schedule of Investments Detail | Investment in Equity Method Affiliate: Nine Months Ended 2016 2015 (In millions) Balance as of December 31, $ 344 $ 348 Interest acquisition of SESH — 1 Equity in earnings of equity method affiliate 22 21 Contributions to equity method affiliate — 8 Distributions from equity method affiliate (1) (40 ) (37 ) Balance as of September 30, $ 326 $ 341 ____________________ (1) Distributions from equity method affiliate includes a $22 million and $26 million return on investment and a $18 million and $11 million return of investment for the nine months ended September 30, 2016 and 2015 , respectively. Equity in Earnings of Equity Method Affiliate: Three Months Ended Nine Months Ended 2016 2015 2016 2015 (In millions) SESH $ 8 $ 7 $ 22 $ 21 Distributions from Equity Method Affiliate: Three Months Ended Nine Months Ended 2016 2015 2016 2015 (In millions) SESH $ 13 $ 10 $ 40 $ 37 Summarized financial information of SESH: Three Months Ended Nine Months Ended 2016 2015 2016 2015 (In millions) Income Statements: Revenues $ 29 $ 29 $ 86 $ 86 Operating income 19 18 56 54 Net income 15 14 43 42 |
Debt (Tables)
Debt (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Debt Disclosure [Abstract] | |
Schedule of Debt | The following table presents the Partnership’s outstanding debt as of September 30, 2016 and December 31, 2015 . September 30, December 31, (In millions) Commercial Paper $ — $ 236 2015 Term Loan Agreement 450 450 Revolving Credit Facility 755 310 Notes payable — affiliated companies (Note 11) — 363 2019 Notes 500 500 2024 Notes 600 600 2044 Notes 550 550 EOIT Senior Notes 250 250 Premium (Discount) on long-term debt 19 23 Total debt 3,124 3,282 Less: Short-term debt (1) — 236 Less: Unamortized debt expense 11 12 Less: Notes payable—affiliated companies — 363 Total long-term debt $ 3,113 $ 2,671 ___________________ (1) There were no commercial paper borrowings outstanding as of September 30, 2016 . Short-term debt included $236 million of commercial paper as of December 31, 2015 . |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Fair Value Disclosures [Abstract] | |
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 September 30, 2016 and December 31, 2015 : September 30, 2016 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 $ 9 $ — $ — Significant other observable inputs (Level 2) 1 1 17 16 Unobservable inputs (Level 3) — 5 — — Total fair value 3 15 17 16 Netting adjustments (1 ) (1 ) — — Total $ 2 $ 14 $ 17 $ 16 December 31, 2015 Commodity Contracts Gas Imbalances (1) Assets Liabilities Assets (2) Liabilities (3) (In millions) Quoted market prices in active market for identical assets (Level 1) $ 17 $ 3 $ — $ — Significant other observable inputs (Level 2) 10 — 17 20 Unobservable inputs (Level 3) 4 — — — Total fair value 31 3 17 20 Netting adjustments (3 ) (3 ) — — Total $ 28 $ — $ 17 $ 20 ______________________ (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 September 30, 2016 and December 31, 2015 . (2) Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $3 million and $6 million at September 30, 2016 and December 31, 2015 , 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 $6 million and $5 million at September 30, 2016 and December 31, 2015 , 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 as of December 31, 2015 $ 4 Losses included in earnings (8 ) Settlements (1 ) Balance as of September 30, 2016 $ (5 ) |
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. September 30, 2016 Product Group Fair Value Forward Curve Range (In millions) (Per gallon) Natural gas liquids $ 5 $0.530 - $0.568 |
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 September 30, 2016 and December 31, 2015 . September 30, 2016 December 31, 2015 Carrying Amount Fair Value Carrying Amount Fair Value (In millions) Long-Term Debt Long-term notes payable — affiliated companies (Level 2) $ — $ — $ 363 $ 350 Revolving Credit Facility (Level 2) (1) 755 755 310 310 2015 Term Loan Agreement (Level 2) 450 450 450 450 EOIT Senior Notes (Level 2) 270 268 273 280 Enable Midstream Partners, LP 2019, 2024 and 2044 Notes (Level 2) 1,649 1,525 1,650 1,255 ___________________ (1) Borrowing capacity is effectively reduced by our borrowings outstanding under the commercial paper program. There was zero and $236 million of commercial paper outstanding as of September 30, 2016 and December 31, 2015 , respectively. |
Derivative Instruments and He28
Derivative Instruments and Hedging Activities (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of Derivative Instruments | As of September 30, 2016 and December 31, 2015 , the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes: September 30, 2016 December 31, 2015 Gross Notional Volume Purchases Sales Purchases Sales Natural gas— TBtu (1) Financial fixed futures/swaps 2 34 1 37 Financial basis futures/swaps 2 34 4 38 Physical purchases/sales — 39 2 51 Crude oil (for condensate)— MBbl (2) Financial Futures/swaps — 450 — 506 Natural gas liquids— MBbl (3) Financial Futures/swaps 75 1,248 75 1,011 ____________________ (1) As of September 30, 2016 , 94.0% of the natural gas contracts had durations of one year or less and 6.0% had durations of more than one year and less than two years. As of December 31, 2015 , 97.7% of the natural gas contracts had durations of one year or less and 2.3% had durations of more than one year and less than two years. (2) As of September 30, 2016 , 90.0% of the condensate contracts had durations of one year or less and 10.0% had durations of more than one year and less than two years. As of December 31, 2015 , 100% of the crude oil (for condensate) contracts had durations of one year or less. (3) As of September 30, 2016 , 89.8% of the natural gas liquids contracts had durations of one year or less and 10.2% had durations of more than one year and less than two years. As of December 31, 2015 , 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 September 30, 2016 and December 31, 2015 that were not designated as hedging instruments for accounting purposes are as follows: September 30, 2016 December 31, 2015 Fair Value Instrument Balance Sheet Location Assets Liabilities Assets Liabilities (In millions) Natural gas Financial futures/swaps Other Current $ 2 $ 9 $ 17 $ 3 Physical purchases/sales Other Current — — 1 — Crude Oil (for condensate) Financial futures/swaps Other Current 1 1 9 — Natural gas liquids Financial Futures/swaps Other Current — 5 4 — Total gross derivatives (1) $ 3 $ 15 $ 31 $ 3 _____________________ (1) See Note 8 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Condensed Consolidated Balance Sheets as of September 30, 2016 and December 31, 2015 . |
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 nine months ended September 30, 2016 and 2015. Amounts Recognized in Income Three Months Ended Nine Months Ended 2016 2015 2016 2015 (In millions) Natural gas financial futures/swaps gains (losses) $ 6 $ 10 $ (5 ) $ 13 Natural gas physical purchases/sales gains (losses) 1 (1 ) (7 ) (5 ) Crude Oil (for condensate) financial futures/swaps gains (losses) 1 11 (2 ) 8 Natural gas liquids financial futures/swaps gains (losses) 1 1 (8 ) 7 Total $ 9 $ 21 $ (22 ) $ 23 |
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 nine months ended September 30, 2016 and 2015 . Three Months Ended Nine Months Ended 2016 2015 2016 2015 (In millions) Change in fair value of derivatives $ 8 $ 6 $ (40 ) $ (11 ) Realized gain on derivatives 1 15 18 34 Gain (loss) on derivative activity $ 9 $ 21 $ (22 ) $ 23 |
Supplemental Disclosure of Ca29
Supplemental Disclosure of Cash Flow Information (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Supplemental Cash Flow Information [Abstract] | |
Schedule of Cash Flow, Supplemental Disclosures | The following table provides information regarding supplemental cash flow information: Nine Months Ended 2016 2015 (In millions) Supplemental Disclosure of Cash Flow Information: Cash Payments: Interest, net of capitalized interest $ 67 $ 61 Income taxes, net of refunds 1 2 Non-cash transactions: Accounts payable related to capital expenditures 32 66 Issuance of common units upon interest acquisition of SESH (Note 6) — 1 |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
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 Nine Months Ended 2016 2015 2016 2015 (In millions) Gas transportation and storage service revenue — CenterPoint Energy $ 22 $ 23 $ 79 $ 79 Natural gas product sales — CenterPoint Energy — — 1 7 Gas transportation and storage service revenue — OGE Energy 10 10 28 28 Natural gas product sales — OGE Energy 4 3 10 7 Total revenues — affiliated companies $ 36 $ 36 $ 118 $ 121 |
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 Nine Months Ended 2016 2015 2016 2015 (In millions) Cost of natural gas purchases — CenterPoint Energy $ — $ 1 $ — $ 2 Cost of natural gas purchases — OGE Energy 4 5 9 12 Total cost of natural gas purchases — affiliated companies $ 4 $ 6 $ 9 $ 14 |
Schedule of Amounts Charged to Partnership by Related Parties | Amounts charged to the Partnership by affiliates for seconded employees 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 Nine Months Ended 2016 2015 2016 2015 (In millions) Corporate Services — CenterPoint Energy $ 1 $ 5 $ 6 $ 12 Seconded Employee Costs — OGE Energy 5 12 22 30 Corporate Services — OGE Energy 1 2 4 8 Total corporate services and seconded employees expense $ 7 $ 19 $ 32 $ 50 |
Equity Based Compensation (Tabl
Equity Based Compensation (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
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 nine months ended September 30, 2016 and 2015 related to performance units, restricted units, and phantom units for the Partnership’s employees and independent directors: Three Months Ended Nine Months Ended 2016 2015 2016 2015 (In millions) Performance units $ 4 $ 1 $ 7 $ 3 Restricted units 1 2 2 5 Phantom units — — 1 1 Total compensation expense $ 5 $ 3 $ 10 $ 9 |
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 September 30, 2016 and changes during 2016 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, 2015 814,510 $ 20.67 581,772 $ 21.04 9,817 $ 12.70 Granted 1,235,429 10.80 — — 647,356 8.39 Vested (6,427 ) 20.77 (91,700 ) 22.84 (321 ) 8.12 Forfeited (56,664 ) 17.27 (53,935 ) 19.29 (8,421 ) 8.12 Units Outstanding at September 30, 2016 1,986,848 $ 15.24 436,137 $ 20.89 648,431 $ 8.46 Aggregate Intrinsic Value of Units Outstanding at September 30, 2016 $ 30 $ 7 $ 10 |
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. September 30, 2016 Unrecognized Compensation Cost (In millions) Weighted Average to be Recognized (In years) Performance Units $ 17 2.06 Restricted Units 3 1.32 Phantom Units 5 2.44 Total $ 25 |
Reportable Segments (Tables)
Reportable Segments (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Segment Reporting [Abstract] | |
Schedule of Financial Data for Business Segments and Services | Financial data for reportable segments are as follows: Three Months Ended September 30, 2016 Gathering and Processing Transportation and Storage (1) Eliminations Total (In millions) Product sales $ 295 $ 150 $ (119 ) $ 326 Service revenue 160 135 (1 ) 294 Total Revenues 455 285 (120 ) 620 Cost of natural gas and natural gas liquids 246 141 (119 ) 268 Operation and maintenance, General and administrative 63 46 (1 ) 108 Depreciation and amortization 53 31 — 84 Impairments 8 — — 8 Taxes other than income tax 8 5 — 13 Operating income $ 77 $ 62 $ — $ 139 Total assets $ 7,502 $ 4,947 $ (1,208 ) $ 11,241 Capital expenditures $ 52 $ 16 $ — $ 68 Three Months Ended September 30, 2015 Gathering and Processing Transportation and Storage (1) Eliminations Total (In millions) Product sales $ 299 $ 166 $ (108 ) $ 357 Service revenue 157 133 (1 ) 289 Total Revenues 456 299 (109 ) 646 Cost of natural gas and natural gas liquids 235 161 (109 ) 287 Operation and maintenance, General and administrative 75 55 — 130 Depreciation and amortization 53 31 — 84 Impairments 514 591 — 1,105 Taxes other than income tax 8 7 — 15 Operating income (loss) $ (429 ) $ (546 ) $ — $ (975 ) Total assets as of December 31, 2015 $ 7,536 $ 4,976 $ (1,286 ) $ 11,226 Capital expenditures $ 167 $ 31 $ — $ 198 Nine Months Ended September 30, 2016 Gathering and Processing Transportation and Storage (1) Eliminations Total (In millions) Product sales $ 759 $ 348 $ (270 ) $ 837 Service revenue 416 408 (3 ) 821 Total Revenues 1,175 756 (273 ) 1,658 Cost of natural gas and natural gas liquids 642 346 (271 ) 717 Operation and maintenance, General and administrative 205 140 (2 ) 343 Depreciation and amortization 154 94 — 248 Impairments 8 — — 8 Taxes other than income tax 24 19 — 43 Operating income $ 142 $ 157 $ — $ 299 Total assets $ 7,502 $ 4,947 $ (1,208 ) $ 11,241 Capital expenditures $ 252 $ 37 $ — $ 289 Nine Months Ended September 30, 2015 Gathering and Processing Transportation and Storage (1) Eliminations Total (In millions) Product sales $ 875 $ 467 $ (299 ) $ 1,043 Service revenue 404 408 (3 ) 809 Total Revenues 1,279 875 (302 ) 1,852 Cost of natural gas and natural gas liquids 698 459 (301 ) 856 Operation and maintenance, General and administrative 229 163 (1 ) 391 Depreciation and amortization 141 92 — 233 Impairments 514 591 — 1,105 Taxes other than income tax 23 22 — 45 Operating income (loss) $ (326 ) $ (452 ) $ — $ (778 ) Total assets as of December 31, 2015 $ 7,536 $ 4,976 $ (1,286 ) $ 11,226 Capital expenditures $ 657 $ 77 $ — $ 734 _____________________ (1) See Note 6 for discussion regarding ownership interests in SESH and related equity earnings included in the Transportation and Storage segment for the three and nine months ended September 30, 2016 and 2015 . |
Summary of Significant Accoun33
Summary of Significant Accounting Policies - Narrative (Details) | Jun. 22, 2016 | Jun. 21, 2016 | Feb. 18, 2016shares | Jun. 12, 2015 | Jun. 29, 2015 | Sep. 30, 2016USD ($)statesegmentshares | Dec. 31, 2015USD ($) |
Significant Accounting Policies [Line Items] | |||||||
Number of reportable segments | segment | 2 | ||||||
Number of states | state | 5 | ||||||
Allowance for doubtful accounts | $ | $ 3,000,000 | $ 0 | |||||
Limited partners' capital account, required quarterly distribution period | 60 days | 45 days | 60 days | ||||
SESH | |||||||
Significant Accounting Policies [Line Items] | |||||||
Limited partner ownership interest percentage | 49.90% | ||||||
Ownership percentage | 50.00% | ||||||
Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units | |||||||
Significant Accounting Policies [Line Items] | |||||||
Issuance of Series A Preferred Units, units | 14,520,000 | ||||||
Limited Partner | SESH | CenterPoint | Put Option | |||||||
Significant Accounting Policies [Line Items] | |||||||
Limited partner ownership interest percentage | 0.10% | ||||||
Limited partner units that may be issued (in units) | 25,341 | ||||||
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 | 55.40% | ||||||
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 | 14,520,000 | ||||||
Limited Partner | CenterPoint | Common Units | |||||||
Significant Accounting Policies [Line Items] | |||||||
Units outstanding | 94,151,707 | ||||||
Limited Partner | CenterPoint | Subordinated Units | |||||||
Significant Accounting Policies [Line Items] | |||||||
Units outstanding | 139,704,916 | ||||||
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 | 26.30% | ||||||
Limited Partner | OGE Energy | Common Units | |||||||
Significant Accounting Policies [Line Items] | |||||||
Units outstanding | 42,832,291 | ||||||
Limited Partner | OGE Energy | Subordinated Units | |||||||
Significant Accounting Policies [Line Items] | |||||||
Units outstanding | 68,150,514 |
Earnings Per Limited Partner 34
Earnings Per Limited Partner Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items] | ||||
Net income (loss) | $ 119 | $ (991) | $ 244 | $ (823) |
Net loss attributable to noncontrolling interest | 0 | (6) | 0 | (6) |
Series A Preferred Unit distribution | 9 | 0 | 13 | 0 |
General partner interest in net income | 0 | 0 | 0 | 0 |
Net Income (Loss) attributable to common and subordinated units (Note 3) | 110 | (985) | 231 | (817) |
Dilutive effect of Series A Preferred Unit distribution | 0 | 0 | 0 | 0 |
Dilutive effect of performance units | 0 | 0 | 0 | 0 |
Diluted net income | $ 110 | $ (985) | $ 231 | $ (817) |
Basic weighted average number of outstanding | ||||
Basic weighted average number of outstanding | 422 | 422 | 422 | 422 |
Basic earnings (loss) per unit | ||||
Dilutive effect of Series A Preferred Units (in units) | 0 | 0 | 0 | 0 |
Dilutive effect of performance units (in units) | 0 | 0 | 0 | 0 |
Diluted weighted average number of outstanding units | 422 | 422 | 422 | 422 |
Performance Units, Restricted Units, and Phantom Units | ||||
Basic earnings (loss) per unit | ||||
Dilutive effect of unit-based awards (in dollars per unit) (less than $.01) | $ 0.01 | $ 0.01 | $ 0.01 | $ 0.01 |
Common Units | ||||
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items] | ||||
Net Income (Loss) attributable to common and subordinated units (Note 3) | $ 56 | $ (499) | $ 117 | $ (414) |
Diluted net income | $ 56 | $ (499) | $ 117 | $ (414) |
Basic weighted average number of outstanding | ||||
Basic weighted average number of outstanding | 214 | 214 | 214 | 214 |
Basic earnings (loss) per unit | ||||
Basic earnings (loss) per unit | $ 0.26 | $ (2.33) | $ 0.55 | $ (1.93) |
Diluted weighted average number of outstanding units | 214 | 214 | 214 | 214 |
Diluted earnings per unit | $ 0.26 | $ (2.33) | $ 0.55 | $ (1.93) |
Subordinated Units | ||||
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items] | ||||
Net Income (Loss) attributable to common and subordinated units (Note 3) | $ 54 | $ (486) | $ 114 | $ (403) |
Diluted net income | $ 54 | $ (486) | $ 114 | $ (403) |
Basic weighted average number of outstanding | ||||
Basic weighted average number of outstanding | 208 | 208 | 208 | 208 |
Basic earnings (loss) per unit | ||||
Basic earnings (loss) per unit | $ 0.26 | $ (2.34) | $ 0.55 | $ (1.94) |
Diluted weighted average number of outstanding units | 208 | 208 | 208 | 208 |
Diluted earnings per unit | $ 0.26 | $ (2.34) | $ 0.55 | $ (1.94) |
Partners' Equity -Schedule of C
Partners' Equity -Schedule of Cash Distributions (Details) - USD ($) $ / shares in Units, $ in Millions | Nov. 22, 2016 | Nov. 14, 2016 | Nov. 01, 2016 | Aug. 23, 2016 | Aug. 16, 2016 | Aug. 12, 2016 | Aug. 02, 2016 | May 13, 2016 | May 06, 2016 | Feb. 12, 2016 | Feb. 02, 2016 | Nov. 13, 2015 | Nov. 03, 2015 | Aug. 13, 2015 | Aug. 03, 2015 | May 15, 2015 | May 05, 2015 | |||
Distribution Made to Limited Partner [Line Items] | ||||||||||||||||||||
Record Date | Aug. 16, 2016 | May 6, 2016 | Feb. 2, 2016 | Nov. 3, 2015 | Aug. 3, 2015 | May 5, 2015 | ||||||||||||||
Payment Date | Aug. 23, 2016 | May 13, 2016 | Feb. 12, 2016 | Nov. 13, 2015 | Aug. 13, 2015 | May 15, 2015 | ||||||||||||||
Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units | Preferred Units | ||||||||||||||||||||
Distribution Made to Limited Partner [Line Items] | ||||||||||||||||||||
Record Date | Aug. 2, 2016 | May 6, 2016 | [1] | |||||||||||||||||
Payment Date | Aug. 12, 2016 | May 13, 2016 | [1] | |||||||||||||||||
Cash Distribution | ||||||||||||||||||||
Distribution Made to Limited Partner [Line Items] | ||||||||||||||||||||
Per unit distribution, paid (in dollars per unit) | $ 0.318 | $ 0.318 | $ 0.318 | $ 0.318 | $ 0.316 | $ 0.3125 | ||||||||||||||
Distribution made to unitholders | $ 134 | $ 134 | $ 134 | $ 134 | $ 134 | $ 132 | ||||||||||||||
Cash Distribution | Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units | Preferred Units | ||||||||||||||||||||
Distribution Made to Limited Partner [Line Items] | ||||||||||||||||||||
Per unit distribution, paid (in dollars per unit) | $ 0.625 | $ 0.2917 | [1] | |||||||||||||||||
Distribution made to unitholders | $ 9 | $ 4 | [1] | |||||||||||||||||
Full quarter equivalent distribution declared (in dollars per unit) | $ 0.625 | |||||||||||||||||||
Annualized distribution declared (in dollars per unit) | $ 2.50 | |||||||||||||||||||
Subsequent Event | Cash Distribution | ||||||||||||||||||||
Distribution Made to Limited Partner [Line Items] | ||||||||||||||||||||
Cash distribution declared (in dollars per unit) | $ 0.318 | |||||||||||||||||||
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 declared (in dollars per unit) | $ 0.625000000 | |||||||||||||||||||
Subsequent Event | Scenario, Forecast | ||||||||||||||||||||
Distribution Made to Limited Partner [Line Items] | ||||||||||||||||||||
Record Date | [2] | Nov. 14, 2016 | ||||||||||||||||||
Payment Date | [2] | Nov. 22, 2016 | ||||||||||||||||||
Subsequent Event | Scenario, Forecast | Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units | Preferred Units | ||||||||||||||||||||
Distribution Made to Limited Partner [Line Items] | ||||||||||||||||||||
Record Date | [3] | Nov. 1, 2016 | ||||||||||||||||||
Payment Date | [3] | Nov. 14, 2016 | ||||||||||||||||||
Subsequent Event | Scenario, Forecast | Cash Distribution | ||||||||||||||||||||
Distribution Made to Limited Partner [Line Items] | ||||||||||||||||||||
Per unit distribution, paid (in dollars per unit) | [2] | $ 0.318 | ||||||||||||||||||
Distribution made to unitholders | [2] | $ 134 | ||||||||||||||||||
Subsequent Event | Scenario, Forecast | Cash Distribution | Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units | Preferred Units | ||||||||||||||||||||
Distribution Made to Limited Partner [Line Items] | ||||||||||||||||||||
Per unit distribution, paid (in dollars per unit) | [3] | $ 0.625 | ||||||||||||||||||
Distribution made to unitholders | [3] | $ 9 | ||||||||||||||||||
[1] | The prorated quarterly distribution for the Series A Preferred Units is for a partial period beginning on February 18, 2016, and ending on March 31, 2016, which equates to $0.625 per unit on a full-quarter basis or $2.50 per unit on an annualized basis. | |||||||||||||||||||
[2] | The board of directors of Enable GP declared this $0.318 per common unit cash distribution on November 1, 2016, to be paid on November 22, 2016, to common and subordinated unitholders of record at the close of business on November 14, 2016. | |||||||||||||||||||
[3] | The board of directors of Enable GP declared a $0.625 per Series A Preferred Unit cash distribution on November 1, 2016, to be paid on November 14, 2016, to Series A Preferred unitholders of record at the close of business on November 1, 2016. |
Partners' Equity Textual (Detai
Partners' Equity Textual (Details) - USD ($) $ / shares in Units, $ in Millions | Jun. 22, 2016 | Jun. 21, 2016 | Feb. 18, 2016 | Sep. 30, 2016 | Sep. 30, 2015 |
Distribution Made to Limited Partner [Line Items] | |||||
Limited partners' capital account, required quarterly distribution period | 60 days | 45 days | 60 days | ||
Limited partners capital account, minimum quarterly distribution, annualized | 150.00% | ||||
Proceeds from issuance of Series A Preferred Units, net of issuance costs | $ 362 | $ 0 | |||
Repayment of notes payable—affiliated companies | $ 363 | $ 0 | |||
CenterPoint | Limited Partner | |||||
Distribution Made to Limited Partner [Line Items] | |||||
Repayment of notes payable—affiliated companies | $ 363 | ||||
Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units | |||||
Distribution Made to Limited Partner [Line Items] | |||||
Issuance of Series A Preferred Units, units | 14,520,000 | ||||
Annual distribution percentage rate | 10.00% | ||||
Liquidation preference (in dollars per unit) | $ 25 | ||||
Period after date of original issue | 5 years | ||||
Redemption price (in dollars per unit) | $ 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 | 14,520,000 | ||||
Cash purchase price (in dollars per unit) | $ 25 | ||||
Proceeds from issuance of Series A Preferred Units, net of issuance costs | $ 362 | ||||
Expenses related to the offering | $ 1 | ||||
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 | 14,520,000 | ||||
Cash purchase price (in dollars per unit) | $ 25 | ||||
Proceeds from issuance of Series A Preferred Units, net of issuance costs | $ 362 | ||||
Subordinated Units | |||||
Distribution Made to Limited Partner [Line Items] | |||||
Minimum quarterly distribution (in dollars per common unit) | $ 0.2875 | ||||
Distribution Subordination Period 1 | |||||
Distribution Made to Limited Partner [Line Items] | |||||
Limited partners' capital account, minimum annualized quarterly distribution (in dollars per unit) | 1.15 | ||||
Distribution Subordination Period 2 | |||||
Distribution Made to Limited Partner [Line Items] | |||||
Limited partners' capital account, maximum annualized quarterly distribution (in dollars per unit) | $ 1.725 | ||||
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) | $ 0.330625 |
Assessing Impairment of Long-37
Assessing Impairment of Long-lived Assets (including Intangible Assets) and Goodwill - Impairment of Long-lived Assets (including Intangible Assets) (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Gathering and Processing | Service Star Business Line | ||||
Impaired Long-Lived Assets Held and Used [Line Items] | ||||
Amount of impairment | $ 8 | $ 6 | $ 8 | $ 6 |
Transportation and Storage | Pipelines | ||||
Impaired Long-Lived Assets Held and Used [Line Items] | ||||
Amount of impairment | $ 12 | $ 12 |
Assessing Impairment of Long-38
Assessing Impairment of Long-lived Assets (including Intangible Assets) and Goodwill - Impairment of Goodwill (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended |
Sep. 30, 2015 | Sep. 30, 2015 | |
Goodwill and Intangible Assets Disclosure [Abstract] | ||
Amount of goodwill impairment | $ 1,087 | $ 1,087 |
Investment in Equity Method A39
Investment in Equity Method Affiliate - Narrative (Details) - SESH - USD ($) $ in Millions | Jun. 12, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | Jun. 29, 2015 | Sep. 30, 2016 | Sep. 30, 2015 |
Schedule of Equity Method Investments [Line Items] | ||||||
Limited partner ownership interest percentage | 49.90% | |||||
Fair value of limited partner interests | $ 1 | $ 1 | ||||
Ownership percentage | 50.00% | 50.00% | ||||
Percentage of distributions through limited partner interest | 50.00% | |||||
Limited Partner | CenterPoint | Put Option | ||||||
Schedule of Equity Method Investments [Line Items] | ||||||
Limited partner ownership interest percentage | 0.10% | |||||
Limited partner units that may be issued (in units) | 25,341 | 25,341 | ||||
Equity Method Investee | Shared Operations Service Agreements | ||||||
Schedule of Equity Method Investments [Line Items] | ||||||
Amount billed associated with service agreements | $ 3 | $ 6 | $ 12 | $ 10 |
Investment in Equity Method A40
Investment in Equity Method Affiliate - Schedule of Investments (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | ||
Investments in and Advances to Affiliates, at Fair Value [Roll Forward] | |||||
Balance as of December 31, | $ 344 | ||||
September 30 | $ 326 | 326 | |||
Return of investment in equity method affiliate | 18 | $ 11 | |||
Equity in Earnings of Equity Method Affiliates: | |||||
Equity in earnings of equity method affiliate | 8 | $ 7 | 22 | 21 | |
SESH | |||||
Investments in and Advances to Affiliates, at Fair Value [Roll Forward] | |||||
Distributions from equity method affiliate | (13) | (10) | (40) | (37) | |
Return on investment in equity method affiliates | 22 | 26 | |||
Return of investment in equity method affiliate | 18 | 11 | |||
Distributions from Equity Method Affiliates: | |||||
Distributions from equity method affiliate | 13 | 10 | 40 | 37 | |
Revenues | 29 | 29 | 86 | 86 | |
Operating income | 19 | 18 | 56 | 54 | |
Net income | 15 | 14 | 43 | 42 | |
SESH | Other Income (Expense) | |||||
Equity in Earnings of Equity Method Affiliates: | |||||
Equity in earnings of equity method affiliate | 8 | 7 | 22 | 21 | |
SESH | Investments in Equity Method Affiliates | |||||
Investments in and Advances to Affiliates, at Fair Value [Roll Forward] | |||||
Balance as of December 31, | 344 | 348 | |||
Interest acquisition of SESH | 0 | 1 | |||
Capital contributions from partners | 0 | 8 | |||
Distributions from equity method affiliate | [1] | (40) | (37) | ||
September 30 | $ 326 | $ 341 | 326 | 341 | |
Equity in Earnings of Equity Method Affiliates: | |||||
Equity in earnings of equity method affiliate | 22 | 21 | |||
Distributions from Equity Method Affiliates: | |||||
Distributions from equity method affiliate | [1] | $ 40 | $ 37 | ||
[1] | Distributions from equity method affiliate includes a $22 million and $26 million return on investment and a $18 million and $11 million return of investment for the nine months ended September 30, 2016 and 2015, respectively. |
Debt - Schedule of Outstanding
Debt - Schedule of Outstanding Debt (Details) - USD ($) $ in Millions | Sep. 30, 2016 | Dec. 31, 2015 | |
Debt Instrument [Line Items] | |||
Premium (Discount) on long-term debt | $ 19 | $ 23 | |
Total debt | 3,124 | 3,282 | |
Less: Short-term debt | [1] | 0 | 236 |
Less: Unamortized debt expense | 11 | 12 | |
Less: Notes payable—affiliated companies | 0 | 363 | |
Total long-term debt | 3,113 | 2,671 | |
Senior Notes | |||
Debt Instrument [Line Items] | |||
Premium (Discount) on long-term debt | 19 | 23 | |
Senior Notes | 2019 Notes | |||
Debt Instrument [Line Items] | |||
Amount of debt outstanding | 500 | 500 | |
Senior Notes | 2024 Notes | |||
Debt Instrument [Line Items] | |||
Amount of debt outstanding | 600 | 600 | |
Senior Notes | 2044 Notes | |||
Debt Instrument [Line Items] | |||
Amount of debt outstanding | 550 | 550 | |
Senior Notes | EOIT Senior Notes | |||
Debt Instrument [Line Items] | |||
Amount of debt outstanding | 250 | 250 | |
Premium (Discount) on long-term debt | 20 | ||
2015 Term Loan Agreement | |||
Debt Instrument [Line Items] | |||
Amount of debt outstanding | 450 | 450 | |
Revolving Credit Facility | |||
Debt Instrument [Line Items] | |||
Amount of debt outstanding | 755 | 310 | |
Commercial Paper | |||
Debt Instrument [Line Items] | |||
Less: Short-term debt | $ 0 | $ 236 | |
[1] | There were no commercial paper borrowings outstanding as of September 30, 2016. Short-term debt included $236 million of commercial paper as of December 31, 2015. |
Debt - Narrative (Details)
Debt - Narrative (Details) | Jul. 31, 2015USD ($)time | Sep. 30, 2016USD ($) | Dec. 31, 2015USD ($) | |
Debt Instrument [Line Items] | ||||
Commercial paper, authorized | $ 1,400,000,000 | |||
Commercial paper outstanding | [1] | 0 | $ 236,000,000 | |
Unamortized premium | 19,000,000 | 23,000,000 | ||
Other Assets | ||||
Debt Instrument [Line Items] | ||||
Unamortized debt expense | $ 16,000,000 | 18,000,000 | ||
Term loan facility | 2015 Term Loan Agreement | ||||
Debt Instrument [Line Items] | ||||
Weighted average interest rate percentage | 1.83% | |||
Duration of term loan facility | 3 years | |||
Amount of term loan agreement | $ 450,000,000 | |||
Number of times option maybe exercised to extend term of Term Loan Facility | time | 2 | |||
Extension period | 1 year | |||
Minimum prepayment amount of option to prepay without penalty or premium (minimum amount of $1 million) | $ 1,000,000 | |||
Multiple amount of prepayment in excess of minimum prepayment | $ 500,000 | |||
Term loan facility | $ 450,000,000 | |||
Term loan facility | LIBOR | 2015 Term Loan Agreement | ||||
Debt Instrument [Line Items] | ||||
Applicable margin percentage | 1.375% | |||
Senior Notes | ||||
Debt Instrument [Line Items] | ||||
Unamortized premium | $ 19,000,000 | 23,000,000 | ||
Senior Notes | EOIT Senior Notes | ||||
Debt Instrument [Line Items] | ||||
Amount of debt outstanding | $ 250,000,000 | 250,000,000 | ||
Fixed interest rate percentage | 6.25% | |||
Unamortized premium | $ 20,000,000 | |||
Effective interest rate percentage | 5.80% | |||
Commercial Paper | ||||
Debt Instrument [Line Items] | ||||
Commercial paper outstanding | $ 0 | 236,000,000 | ||
Revolving Credit Facility | ||||
Debt Instrument [Line Items] | ||||
Maximum borrowing capacity | 1,750,000,000 | |||
Letters of credit principal advances | 755,000,000 | |||
Letters of credit outstanding amount | $ 3,000,000 | |||
Weighted average interest rate percentage | 2.03% | |||
Commitment fee percentage | 0.20% | |||
Amount of debt outstanding | $ 755,000,000 | $ 310,000,000 | ||
Revolving Credit Facility | LIBOR | ||||
Debt Instrument [Line Items] | ||||
Applicable margin percentage | 1.50% | |||
[1] | There were no commercial paper borrowings outstanding as of September 30, 2016. Short-term debt included $236 million of commercial paper as of December 31, 2015. |
Fair Value Measurements - Fair
Fair Value Measurements - Fair Value Hierarchy (Details) - USD ($) $ in Millions | Sep. 30, 2016 | Dec. 31, 2015 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Retained fuel due from shippers | $ 3 | $ 6 | |
Over retained fuel due from shippers | 6 | 5 | |
Commodity Contracts | Recurring Measurement | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Assets, total fair value | 3 | 31 | |
Liabilities, total fair value | 15 | 3 | |
Assets | (1) | (3) | |
Liabilities | (1) | (3) | |
Assets | 2 | 28 | |
Liabilities | 14 | 0 | |
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 | 17 | |
Liabilities | 9 | 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 | 1 | 10 | |
Liabilities | 1 | 0 | |
Commodity Contracts | Recurring Measurement | Unobservable inputs (Level 3) | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Assets | 0 | 4 | |
Liabilities | 5 | 0 | |
Gas Imbalances | Recurring Measurement | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Assets, total fair value | [1],[2] | 17 | 17 |
Liabilities, total fair value | [2],[3] | 16 | 20 |
Assets | [1],[2] | 0 | 0 |
Liabilities | [2],[3] | 0 | 0 |
Assets | [1],[2] | 17 | 17 |
Liabilities | [2],[3] | 16 | 20 |
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] | 17 | 17 |
Liabilities | [2],[3] | 16 | 20 |
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 $3 million and $6 million at September 30, 2016 and December 31, 2015, 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 September 30, 2016 and December 31, 2015. | ||
[3] | Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $6 million and $5 million at September 30, 2016 and December 31, 2015, 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 | 9 Months Ended |
Sep. 30, 2016USD ($) | |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward] | |
Balance as of December 31, 2015 | $ 4 |
Losses included in earnings | (8) |
Settlements | (1) |
Balance as of September 30, 2016 | $ (5) |
Fair Value Measurements - Sch45
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 | 9 Months Ended |
Sep. 30, 2016USD ($)$ / gal | |
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |
Liabilities | $ | $ 5 |
Minimum | |
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |
Forward Curve Range (in dollars per gallon) | 0.530 |
Maximum | |
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |
Forward Curve Range (in dollars per gallon) | 0.568 |
Fair Value Measurements - Carry
Fair Value Measurements - Carrying and Fair Value Amounts (Details) - USD ($) $ in Millions | Sep. 30, 2016 | Dec. 31, 2015 | |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Carrying Amount | $ 3,113 | $ 2,671 | |
Carrying value | 0 | 236 | |
Carrying Amount | Significant other observable inputs (Level 2) | Long-term notes payable—affiliated companies (Level 2) | Affiliated Companies | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Carrying Amount | 0 | 363 | |
Carrying Amount | Significant other observable inputs (Level 2) | Revolving Credit Facility (Level 2) | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Carrying Amount | [1] | 755 | 310 |
Carrying Amount | Significant other observable inputs (Level 2) | 2015 Term Loan Agreement (Level 2) | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Carrying Amount | 450 | 450 | |
Carrying Amount | Significant other observable inputs (Level 2) | EOIT Senior Notes (Level 2) | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Carrying Amount | 270 | 273 | |
Carrying Amount | Significant other observable inputs (Level 2) | Enable Midstream Partners, LP 2019, 2024 and 2044 Notes (Level 2) | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Carrying Amount | 1,649 | 1,650 | |
Fair Value | Significant other observable inputs (Level 2) | Long-term notes payable—affiliated companies (Level 2) | Affiliated Companies | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Fair Value | 0 | 350 | |
Fair Value | Significant other observable inputs (Level 2) | Revolving Credit Facility (Level 2) | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Fair Value | [1] | 755 | 310 |
Fair Value | Significant other observable inputs (Level 2) | 2015 Term Loan Agreement (Level 2) | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Fair Value | 450 | 450 | |
Fair Value | Significant other observable inputs (Level 2) | EOIT Senior Notes (Level 2) | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Fair Value | 268 | 280 | |
Fair Value | Significant other observable inputs (Level 2) | Enable Midstream Partners, LP 2019, 2024 and 2044 Notes (Level 2) | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Fair Value | $ 1,525 | $ 1,255 | |
[1] | Borrowing capacity is effectively reduced by our borrowings outstanding under the commercial paper program. There was zero and $236 million of commercial paper outstanding as of September 30, 2016 and December 31, 2015, respectively. |
Derivative Instruments and He47
Derivative Instruments and Hedging Activities (Details) - Not Designated as Hedging Instrument bbl in Thousands, MMBTU in Millions | 9 Months Ended | |||
Sep. 30, 2016MMBTUbbl | Sep. 30, 2015MMBTUbbl | Dec. 31, 2015 | ||
Natural gas | ||||
Derivative [Line Items] | ||||
Percent of contract with durations of one year or less | 94.00% | 97.70% | ||
Percent of contracts with durations of more than one year and less than two years | 6.00% | 2.30% | ||
Natural gas | Financial fixed futures/swaps | Purchases | ||||
Derivative [Line Items] | ||||
Derivative, gross notional volume (TBtu) | [1] | 2 | 1 | |
Natural gas | Financial fixed futures/swaps | Sales | ||||
Derivative [Line Items] | ||||
Derivative, gross notional volume (TBtu) | [1] | 34 | 37 | |
Natural gas | Financial basis futures/swaps | Purchases | ||||
Derivative [Line Items] | ||||
Derivative, gross notional volume (TBtu) | [1] | 2 | 4 | |
Natural gas | Financial basis futures/swaps | Sales | ||||
Derivative [Line Items] | ||||
Derivative, gross notional volume (TBtu) | [1] | 34 | 38 | |
Natural gas | Physical purchases/sales | Purchases | ||||
Derivative [Line Items] | ||||
Derivative, gross notional volume (TBtu) | [1] | 0 | 2 | |
Natural gas | Physical purchases/sales | Sales | ||||
Derivative [Line Items] | ||||
Derivative, gross notional volume (TBtu) | [1] | 39 | 51 | |
Condensate | ||||
Derivative [Line Items] | ||||
Percent of contract with durations of one year or less | 90.00% | 100.00% | ||
Percent of contracts with durations of more than one year and less than two years | 10.00% | |||
Condensate | Financial Futures/swaps | Purchases | ||||
Derivative [Line Items] | ||||
Derivative, gross notional volume (MMbl) | bbl | [2] | 0 | 0 | |
Condensate | Financial Futures/swaps | Sales | ||||
Derivative [Line Items] | ||||
Derivative, gross notional volume (MMbl) | bbl | [2] | 450 | 506 | |
Natural gas liquids | ||||
Derivative [Line Items] | ||||
Percent of contract with durations of one year or less | 89.80% | 100.00% | ||
Percent of contracts with durations of more than one year and less than two years | 10.20% | |||
Natural gas liquids | Financial Futures/swaps | Purchases | ||||
Derivative [Line Items] | ||||
Derivative, gross notional volume (MMbl) | bbl | [3] | 75 | 75 | |
Natural gas liquids | Financial Futures/swaps | Sales | ||||
Derivative [Line Items] | ||||
Derivative, gross notional volume (MMbl) | bbl | [3] | 1,248 | 1,011 | |
[1] | As of September 30, 2016, 94.0% of the natural gas contracts had durations of one year or less and 6.0% had durations of more than one year and less than two years. As of December 31, 2015, 97.7% of the natural gas contracts had durations of one year or less and 2.3% had durations of more than one year and less than two years. | |||
[2] | As of September 30, 2016, 90.0% of the condensate contracts had durations of one year or less and 10.0% had durations of more than one year and less than two years. As of December 31, 2015, 100% of the crude oil (for condensate) contracts had durations of one year or less. | |||
[3] | As of September 30, 2016, 89.8% of the natural gas liquids contracts had durations of one year or less and 10.2% had durations of more than one year and less than two years. As of December 31, 2015, 100% of the natural gas liquid contracts had durations of one year or less. |
Derivative Instruments and He48
Derivative Instruments and Hedging Activities - Balance Sheet Location (Details) - USD ($) | Sep. 30, 2016 | Dec. 31, 2015 | |
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] | 3,000,000 | 31,000,000 |
Liabilities | [1] | 15,000,000 | 3,000,000 |
Natural gas | Financial futures/swaps | Not Designated as Hedging Instrument | Other Current, Assets | |||
Derivatives, Fair Value [Line Items] | |||
Assets | 2,000,000 | 17,000,000 | |
Natural gas | Financial futures/swaps | Not Designated as Hedging Instrument | Other Current Liabilities | |||
Derivatives, Fair Value [Line Items] | |||
Liabilities | 9,000,000 | 3,000,000 | |
Natural gas | Physical purchases/sales | Not Designated as Hedging Instrument | Other Current, Assets | |||
Derivatives, Fair Value [Line Items] | |||
Assets | 0 | 1,000,000 | |
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 | 1,000,000 | 9,000,000 | |
Crude Oil (for condensate) | Financial futures/swaps | Not Designated as Hedging Instrument | Other Current Liabilities | |||
Derivatives, Fair Value [Line Items] | |||
Liabilities | 1,000,000 | 0 | |
Natural gas liquids | Financial futures/swaps | Not Designated as Hedging Instrument | Other Current, Assets | |||
Derivatives, Fair Value [Line Items] | |||
Assets | 0 | 4,000,000 | |
Natural gas liquids | Financial futures/swaps | Not Designated as Hedging Instrument | Other Current Liabilities | |||
Derivatives, Fair Value [Line Items] | |||
Liabilities | $ 5,000,000 | $ 0 | |
[1] | See Note 8 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Condensed Consolidated Balance Sheets as of September 30, 2016 and December 31, 2015. |
Derivative Instruments and He49
Derivative Instruments and Hedging Activities - Amounts Recognized in Income (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (Loss) on derivative, net | $ 9 | $ 21 | $ (22) | $ 23 |
Change in fair value of derivatives | 8 | 6 | (40) | (11) |
Realized gain on derivatives | 1 | 15 | 18 | 34 |
Gain (loss) on derivative activity | 9 | 21 | (22) | 23 |
Cash collateral posted | 0 | 0 | ||
Cash collateral required if ratings are lowered | 2 | 2 | ||
Natural gas | Financial futures/swaps | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (Loss) on derivative, net | 6 | 10 | (5) | 13 |
Natural gas | Physical purchases/sales | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (Loss) on derivative, net | 1 | (1) | (7) | (5) |
Condensate | Financial futures/swaps | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (Loss) on derivative, net | 1 | 11 | (2) | 8 |
Natural gas liquids | Financial futures/swaps | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (Loss) on derivative, net | $ 1 | $ 1 | $ (8) | $ 7 |
Supplemental Disclosure of Ca50
Supplemental Disclosure of Cash Flow Information - (Details) - USD ($) $ in Millions | 9 Months Ended | |
Sep. 30, 2016 | Sep. 30, 2015 | |
Supplemental Cash Flow Information [Abstract] | ||
Interest, net of capitalized interest | $ 67 | $ 61 |
Income taxes, net of refunds | 1 | 2 |
Accounts payable related to capital expenditures | 32 | 66 |
Issuance of common units upon interest acquisition of SESH (Note 6) | $ 0 | $ 1 |
Related Party Transactions - Na
Related Party Transactions - Narrative (Details) - USD ($) $ / shares in Units, $ in Millions | Feb. 18, 2016 | Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | Dec. 31, 2015 |
Related Party Transaction [Line Items] | ||||||
Partnership's revenues from affiliated companies as a percent of total revenues | 6.00% | 6.00% | 7.00% | 7.00% | ||
Notes payable affiliated companies outstanding | $ 0 | $ 0 | $ 363 | |||
Proceeds from issuance of Series A Preferred Units, net of issuance costs | $ 362 | $ 0 | ||||
Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units | ||||||
Related Party Transaction [Line Items] | ||||||
Issuance of Series A Preferred Units, units | 14,520,000 | |||||
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 | 14,520,000 | |||||
Cash purchase price (in dollars per unit) | $ 25 | |||||
Proceeds from issuance of Series A Preferred Units, net of issuance costs | $ 362 | |||||
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 | Defined Benefit and Retiree Medical Plans | ||||||
Related Party Transaction [Line Items] | ||||||
Expense reimbursement, remainder of fiscal year | $ 6 | |||||
Expense reimbursement, second year | 5 | |||||
Expense reimbursement, third year | 5 | |||||
Expense reimbursement, thereafter | 5 | |||||
OGE Energy | Certain Services and Support Functions | ||||||
Related Party Transaction [Line Items] | ||||||
Expense reimbursement annual caps | 6 | |||||
CenterPoint | ||||||
Related Party Transaction [Line Items] | ||||||
Notes payable affiliated companies outstanding | $ 363 | |||||
Affiliate interest expense | $ 0 | $ 2 | 1 | $ 6 | ||
CenterPoint | Certain Services and Support Functions | ||||||
Related Party Transaction [Line Items] | ||||||
Expense reimbursement annual caps | $ 7 | |||||
Limited Partner | Private Placement | Series A 10% Fixed to Floating Non Cumulative Redeemable Perpetual Preferred Units | CenterPoint | ||||||
Related Party Transaction [Line Items] | ||||||
Issuance of Series A Preferred Units, units | 14,520,000 | |||||
Cash purchase price (in dollars per unit) | $ 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 | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Related Party Transaction [Line Items] | ||||
Revenues from affiliated companies | $ 36 | $ 36 | $ 118 | $ 121 |
Cost of goods sold from affiliate | 4 | 6 | 9 | 14 |
Charges to the Partnership by affiliates | 7 | 19 | 32 | 50 |
CenterPoint | ||||
Related Party Transaction [Line Items] | ||||
Cost of goods sold from affiliate | 0 | 1 | 0 | 2 |
CenterPoint | Gas Transportation and Storage | ||||
Related Party Transaction [Line Items] | ||||
Revenues from affiliated companies | 22 | 23 | 79 | 79 |
CenterPoint | Gas Sales | ||||
Related Party Transaction [Line Items] | ||||
Revenues from affiliated companies | 0 | 0 | 1 | 7 |
CenterPoint | Corporate Services | ||||
Related Party Transaction [Line Items] | ||||
Charges to the Partnership by affiliates | 1 | 5 | 6 | 12 |
OGE Energy | ||||
Related Party Transaction [Line Items] | ||||
Cost of goods sold from affiliate | 4 | 5 | 9 | 12 |
OGE Energy | Gas Transportation and Storage | ||||
Related Party Transaction [Line Items] | ||||
Revenues from affiliated companies | 10 | 10 | 28 | 28 |
OGE Energy | Gas Sales | ||||
Related Party Transaction [Line Items] | ||||
Revenues from affiliated companies | 4 | 3 | 10 | 7 |
OGE Energy | Corporate Services | ||||
Related Party Transaction [Line Items] | ||||
Charges to the Partnership by affiliates | 1 | 2 | 4 | 8 |
OGE Energy | Seconded Employee Costs | ||||
Related Party Transaction [Line Items] | ||||
Charges to the Partnership by affiliates | $ 5 | $ 12 | $ 22 | $ 30 |
Equity Based Compensation (Deta
Equity Based Compensation (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Total compensation expense | $ 5 | $ 3 | $ 10 | $ 9 |
Performance units | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Total compensation expense | 4 | 1 | 7 | 3 |
Restricted units | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Total compensation expense | 1 | 2 | 2 | 5 |
Phantom units | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Total compensation expense | $ 0 | $ 0 | $ 1 | $ 1 |
Equity Based Compensation - Equ
Equity Based Compensation - Equity Units Activity (Details) $ / shares in Units, $ in Millions | 9 Months Ended |
Sep. 30, 2016USD ($)$ / 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 at December 31, 2015 (in units) | shares | 814,510 |
Granted (in units) | shares | 1,235,429 |
Vested (in units) | shares | (6,427) |
Forfeited (in units) | shares | (56,664) |
September 30, 2016 (in units) | shares | 1,986,848 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract] | |
Units Outstanding at December 31, 2015 (in dollars per unit) | $ / shares | $ 20.67 |
Granted (in dollars per unit) | $ / shares | 10.80 |
Vested (in dollars per unit) | $ / shares | 20.77 |
Forfeited (in dollars per unit) | $ / shares | 17.27 |
September 30, 2016 (in dollars per unit) | $ / shares | $ 15.24 |
Aggregate Intrinsic Value of Units Outstanding at September 30, 2016 | $ | $ 30 |
Restricted units | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |
Units Outstanding at December 31, 2015 (in units) | shares | 581,772 |
Granted (in units) | shares | 0 |
Vested (in units) | shares | (91,700) |
Forfeited (in units) | shares | (53,935) |
September 30, 2016 (in units) | shares | 436,137 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract] | |
Units Outstanding at December 31, 2015 (in dollars per unit) | $ / shares | $ 21.04 |
Granted (in dollars per unit) | $ / shares | 0 |
Vested (in dollars per unit) | $ / shares | 22.84 |
Forfeited (in dollars per unit) | $ / shares | 19.29 |
September 30, 2016 (in dollars per unit) | $ / shares | $ 20.89 |
Aggregate Intrinsic Value of Units Outstanding at September 30, 2016 | $ | $ 7 |
Phantom units | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |
Units Outstanding at December 31, 2015 (in units) | shares | 9,817 |
Granted (in units) | shares | 647,356 |
Vested (in units) | shares | (321) |
Forfeited (in units) | shares | (8,421) |
September 30, 2016 (in units) | shares | 648,431 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract] | |
Units Outstanding at December 31, 2015 (in dollars per unit) | $ / shares | $ 12.70 |
Granted (in dollars per unit) | $ / shares | 8.39 |
Vested (in dollars per unit) | $ / shares | 8.12 |
Forfeited (in dollars per unit) | $ / shares | 8.12 |
September 30, 2016 (in dollars per unit) | $ / shares | $ 8.46 |
Aggregate Intrinsic Value of Units Outstanding at September 30, 2016 | $ | $ 10 |
Equity Based Compensation - Unr
Equity Based Compensation - Unrecognized Compensation Cost (Details) $ in Millions | 9 Months Ended |
Sep. 30, 2016USD ($)shares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Unrecognized Compensation Cost (In millions) | $ 25 |
Performance units | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Unrecognized Compensation Cost (In millions) | $ 17 |
Weighted Average to be Recognized (In years) | 2 years 22 days |
Restricted units | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Unrecognized Compensation Cost (In millions) | $ 3 |
Weighted Average to be Recognized (In years) | 1 year 3 months 26 days |
Phantom units | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Unrecognized Compensation Cost (In millions) | $ 5 |
Weighted Average to be Recognized (In years) | 2 years 5 months 9 days |
Long Term Incentive Plan | Common Units | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Shares available for issuance | shares | 9,292,500 |
Reportable Segments - Schedule
Reportable Segments - Schedule of Financial Data for Business Segments and Services (Details) $ in Millions | 3 Months Ended | 9 Months Ended | ||||
Sep. 30, 2016USD ($) | Sep. 30, 2015USD ($) | Sep. 30, 2016USD ($)segment | Sep. 30, 2015USD ($) | Dec. 31, 2015USD ($) | ||
Segment Reporting Information [Line Items] | ||||||
Number of reportable segments | segment | 2 | |||||
Product sales | $ 326 | $ 357 | $ 837 | $ 1,043 | ||
Service revenue | 294 | 289 | 821 | 809 | ||
Total Revenues | 620 | 646 | 1,658 | 1,852 | ||
Cost of goods sold, excluding depreciation and amortization | 268 | 287 | 717 | 856 | ||
Operation and maintenance, General and administrative | 108 | 130 | 343 | 391 | ||
Depreciation and amortization | 84 | 84 | 248 | 233 | ||
Impairments | 8 | 1,105 | 8 | 1,105 | ||
Taxes other than income tax | 13 | 15 | 43 | 45 | ||
Operating Income (Loss) | 139 | (975) | 299 | (778) | ||
Total assets | 11,241 | 11,241 | $ 11,226 | |||
Capital expenditures | 68 | 198 | 289 | 654 | ||
Capital expenditures | 734 | |||||
Gathering and Processing | ||||||
Segment Reporting Information [Line Items] | ||||||
Product sales | 295 | 299 | 759 | 875 | ||
Service revenue | 160 | 157 | 416 | 404 | ||
Total Revenues | 455 | 456 | 1,175 | 1,279 | ||
Cost of goods sold, excluding depreciation and amortization | 246 | 235 | 642 | 698 | ||
Operation and maintenance, General and administrative | 63 | 75 | 205 | 229 | ||
Depreciation and amortization | 53 | 53 | 154 | 141 | ||
Impairments | 8 | 514 | 8 | 514 | ||
Taxes other than income tax | 8 | 8 | 24 | 23 | ||
Operating Income (Loss) | 77 | (429) | 142 | (326) | ||
Total assets | 7,502 | 7,502 | 7,536 | |||
Capital expenditures | 52 | 167 | 252 | |||
Capital expenditures | 657 | |||||
Transportation and Storage | ||||||
Segment Reporting Information [Line Items] | ||||||
Product sales | [1] | 150 | 166 | 348 | 467 | |
Service revenue | [1] | 135 | 133 | 408 | 408 | |
Total Revenues | [1] | 285 | 299 | 756 | 875 | |
Cost of goods sold, excluding depreciation and amortization | [1] | 141 | 161 | 346 | 459 | |
Operation and maintenance, General and administrative | [1] | 46 | 55 | 140 | 163 | |
Depreciation and amortization | [1] | 31 | 31 | 94 | 92 | |
Impairments | [1] | 0 | 591 | 0 | 591 | |
Taxes other than income tax | [1] | 5 | 7 | 19 | 22 | |
Operating Income (Loss) | [1] | 62 | (546) | 157 | (452) | |
Total assets | [1] | 4,947 | 4,947 | 4,976 | ||
Capital expenditures | [1] | 16 | 31 | 37 | ||
Capital expenditures | [1] | 77 | ||||
Eliminations | ||||||
Segment Reporting Information [Line Items] | ||||||
Product sales | (119) | (108) | (270) | (299) | ||
Service revenue | (1) | (1) | (3) | (3) | ||
Total Revenues | (120) | (109) | (273) | (302) | ||
Cost of goods sold, excluding depreciation and amortization | (119) | (109) | (271) | (301) | ||
Operation and maintenance, General and administrative | (1) | 0 | (2) | (1) | ||
Depreciation and amortization | 0 | 0 | 0 | 0 | ||
Impairments | 0 | 0 | 0 | 0 | ||
Taxes other than income tax | 0 | 0 | 0 | 0 | ||
Operating Income (Loss) | 0 | 0 | 0 | 0 | ||
Total assets | (1,208) | (1,208) | $ (1,286) | |||
Capital expenditures | $ 0 | $ 0 | $ 0 | |||
Capital expenditures | $ 0 | |||||
[1] | See Note 6 for discussion regarding ownership interests in SESH and related equity earnings included in the Transportation and Storage segment for the three and nine months ended September 30, 2016 and 2015. |