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•	changes in general economic conditions;

•	competitive conditions in our industry;

•	actions taken by our customers and competitors;

•	the supply and demand for natural gas, NGLs, crude oil and midstream services;

•	our ability to successfully implement our business plan;

•	our ability to complete internal growth projects on time and on budget;

•	the price and availability of debt and equity financing;

•	strategic decisions by CenterPoint Energy and OGE Energy regarding their ownership of us and our General Partner;

•	operating hazards and other risks incidental to transporting, storing, gathering and processing natural gas, NGLs, crude oil and midstream products;

•	natural disasters, weather-related delays, casualty losses and other matters beyond our control;

•	interest rates;

•	labor relations;

•	large customer defaults;

•	changes in the availability and cost of capital;

•	changes in tax status;

•	the effects of existing and future laws and governmental regulations;

•	changes in insurance markets impacting costs and the level and types of coverage available;

•	the timing and extent of changes in commodity prices;

•	the suspension, reduction or termination of our customers’ obligations under our commercial agreements;

•	disruptions due to equipment interruption or failure at our facilities, or third-party facilities on which our business is dependent;

•	the effects of future litigation; and

•	other factors set forth in this report and our other filings with the SEC.

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Capitalize on Organic Growth Opportunities Associated with Our Strategically Located Assets: We own and operate assets servicing four of the largest basins in the United States, including some of the most productive shale plays in these basins. We intend to grow our business by utilizing a disciplined approach emphasizing capital efficiency when developing new midstream energy infrastructure projects to support new and existing customers in these areas.

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Maintain Strong Customer Relationships to Attract New Volumes and Expand Beyond Our Existing Asset Footprint and Business Lines: Management believes that we have built a strong and loyal customer base through exemplary customer service and reliable project execution. We have invested in organic growth projects in support of our existing and new customers. We work to maintain and build relationships with key producers and suppliers in an effort to attract new volumes and expansion opportunities.

•	Continue to Minimize Direct Commodity Price Exposure Through Fee-Based Contracts: We continually seek ways to minimize our exposure to commodity price risk. Management believes that focusing on fee-based revenues reduces our direct commodity price exposure. We intend to maintain our focus on increasing the percentage of long-term, fee-based contracts with our customers.

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•	Grow Through Accretive Acquisitions. We continually evaluate potential acquisitions of complementary assets with the potential for attractive returns in new operating areas or midstream business lines. We will continue to analyze acquisition opportunities using disciplined financial and operating practices, including evaluating and managing risks to cash distributions.

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Anadarko Basin (Oklahoma, Texas Panhandle). We have natural gas gathering and processing operations in those portions of the Anadarko Basin located in Oklahoma and the Texas Panhandle where, as of December 31, 2017, we served over 210 producers. Our operations include gathering and processing natural gas produced from the Granite Wash, Cleveland, Marmaton, Tonkawa, Cana Woodford, SCOOP, STACK and Mississippi Lime plays. The current focus of our Anadarko Basin gathering and processing operations is primarily on rich gas production.

•	Arkoma Basin (Oklahoma, Arkansas). In the Arkoma Basin, our operations primarily serve the Woodford Shale play located in Oklahoma and the Fayetteville Shale play located in Arkansas. Our Arkoma Basin gathering and processing

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Ark-La-Tex Basin (Arkansas, Louisiana and Texas). We have gathering and processing operations in the Ark-La-Tex Basin located in Arkansas, Louisiana and Texas. Our Ark-La-Tex gathering and processing operations primarily serve the Haynesville, Cotton Valley and the lower Bossier plays. As of December 31, 2017, we served over 100 producers in the Ark-La-Tex Basin where our gathering and processing operations provide service for both rich and lean gas production.

•	Williston Basin (North Dakota). In the Williston Basin, we have operations in the Bakken Shale that are located in North Dakota. The focus of our operations in the Williston Basin is the gathering of crude oil and produced water for XTO Energy Inc. (XTO), an affiliate of ExxonMobil Corporation, with pipeline gathering systems in Dunn, McKenzie, Williams and Mountrail Counties of North Dakota.

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(1)	Ark-La-Tex Basin assets also include 14,500 Bbl/d of fractionation capacity and 6,300 Bbl/d of ethane pipeline capacity, which are not listed in the table.

(1)	Excludes condensate capacity.

(2)	Average daily inlet volumes and inlet capacity includes 20 MMcf/d and 25 MMcf/d, respectively, related to a separate cryogenic unit.

(3)	A processing plant has been in operation on the Waskom plant site since 1940. The Waskom plant was upgraded to cryogenic in 1995.

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•	Under a typical fee-based processing arrangement, we process the raw natural gas to extract the NGLs, purchase the NGLs from the producer less a fee, return the processed natural gas to the producer and sell the NGLs for our own account.

•	Under a typical percent-of-liquids processing arrangement, we process the raw natural gas to extract the NGLs, purchase the NGLs from the producer at a discount, return the processed natural gas to the producer and sell the NGLs for our own account.

•	Under a typical percent-of-proceeds processing arrangement, we process the raw natural gas to extract the NGLs, purchase the NGLs and an agreed upon percentage of the processed natural gas from the producer at a discount, return the remaining processed natural gas to the producer and sell the purchased natural gas and NGLs for our own account.

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•	Under a typical keep-whole arrangement, we process raw natural gas to extract the NGLs, return a quantity of the processed natural gas to the producer that is equivalent to the raw natural gas on a Btu basis and retain and sell the NGLs for our own account.

(1)	Represents the percentage of gathering and processing gross margin from gathering contracts with minimum volume commitments that were attributable to shortfall payments.

(2)	Under the Williston Basin contracts, if the customer ships in excess of the minimum volume, this volume commitment could end before the expiration of the contract term.

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(1)	Actual volumes transported per day may be less than total firm contracted capacity based on demand.

(2)	Transportation Firm Contracted Capacity includes contracts with affiliates and our subsidiaries.

(3)	Our EOIT pipeline system is a web-like configuration with multidirectional flow capabilities between numerous receipt and delivery points, which limits our ability to determine an overall system capacity. During the year ended December 31, 2017, the peak daily throughput was 2.3 TBtu/d or, on a volumetric basis, 2.3 Bcf/d.

(4)	SESH has 1.09 Bcf/d of transportation capacity from Perryville, Louisiana to its endpoint in Mobile County, Alabama.

(5)	We own a 50% interest in SESH and as such, do not include certain information regarding its transportation and storage assets in the table set forth above.

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•	rates, terms and conditions of service and service contracts;

•	certification and construction of new facilities or expansion of existing facilities;

•	abandonment of facilities;

•	maintenance of accounts and records;

•	acquisition and disposition of facilities;

•	initiation, extension or abandonment of services;

•	accounting, depreciation and amortization policies;

•	conduct and relationship with certain affiliates;

•	market manipulation in connection with the purchase or sale of natural gas or transportation in interstate commerce; and

•	various other matters.

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•	the overall cost of service, including operating costs and overhead;

•	the allocation of overhead and other administrative and general expenses to the regulated entity;

•	the appropriate capital structure to be utilized in calculating rates;

•	the appropriate rate of return on equity and interest rates on debt;

•	the rate base, including the proper starting rate base;

•	the throughput underlying the rate; and

•	the proper allowance for federal and state income taxes.

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•	the fees and gross margins we realize with respect to the volume of natural gas, NGLs and crude oil that we handle;

•	the prices of, levels of production of, and demand for natural gas, NGLs and crude oil;

•	the volume of natural gas, NGLs and crude oil we gather, compress, treat, dehydrate, process, fractionate, transport and store;

•	the relationship among prices for natural gas, NGLs and crude oil;

•	cash calls and settlements of hedging positions;

•	margin requirements on open price risk management assets and liabilities;

•	the level of competition from other companies offering midstream services;

•	adverse effects of governmental and environmental regulation;

•	the level of our operation and maintenance expenses and general and administrative costs; and

•	prevailing economic conditions.

•	the level and timing of capital expenditures we make;

•	the cost of acquisitions;

•	our debt service requirements and other liabilities;

•	fluctuations in working capital needs;

•	our ability to borrow funds and access capital markets;

•	restrictions contained in our debt agreements;

•	the amount of cash reserves established by our general partner;

•	distributions paid on our Series A Preferred Units; and

•	other business risks affecting our cash levels.

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•	the availability and cost of capital;

•	prevailing and projected commodity prices, including the prices of natural gas, NGLs and crude oil;

•	demand for natural gas, NGLs and crude oil;

•	levels of reserves;

•	geological considerations;

•	environmental or other governmental regulations, including the availability of drilling permits and the regulation of hydraulic fracturing; and

•	the availability of drilling rigs and other costs of production and equipment.

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•	our joint venture partners may share certain approval rights over major decisions;

•	our joint venture partners may not pay their share of the joint venture’s obligations, leaving us liable for their shares of joint venture liabilities;

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•	we may be unable to control the amount of cash we will receive from the joint venture;

•	we may incur liabilities as a result of an action taken by our joint venture partners;

•	we may be required to devote significant management time to the requirements of and matters relating to the joint ventures;

•	our insurance policies may not fully cover loss or damage incurred by both us and our joint venture partners in certain circumstances;

•	our joint venture partners may be in a position to take actions contrary to our instructions or requests or contrary to our policies or objectives; and

•	disputes between us and our joint venture partners may result in delays, litigation or operational impasses.

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•	damage to pipelines and plants, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires, earthquakes and other natural disasters, acts of terrorism and actions by third parties;

•	inadvertent damage from construction, vehicles, farm and utility equipment;

•	leaks of natural gas, NGLs, crude oil and other hydrocarbons or losses of natural gas, NGLs and crude oil as a result of the malfunction of equipment or facilities;

•	ruptures, fires and explosions; and

•	other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.

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•	acquired businesses or assets may not produce revenues, earnings or cash flow at anticipated levels;

•	acquired businesses or assets could have environmental, permitting or other problems for which contractual protections prove inadequate;

•	we may assume liabilities that were not disclosed to us, that exceed our estimates, or for which our rights to indemnification from the seller are limited;

•	we may be unable to integrate acquired businesses successfully and realize anticipated economic, operational and other benefits in a timely manner, which could result in substantial costs and delays or other operational, technical or financial problems; and

•	acquisitions, or the pursuit of acquisitions, could disrupt our ongoing businesses, distract management, divert resources and make it difficult to maintain our current business standards, controls and procedures.

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•	the ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or the financing may not be available on favorable terms, if at all;

•	a portion of cash flows will be required to make interest payments on the debt, reducing the funds that would otherwise be available for operations, future business opportunities and distributions;

•	our debt level will make us more vulnerable to competitive pressures or a downturn in our business or the economy generally; and

•	our debt level may limit our flexibility in responding to changing business and economic conditions.

•	permit our subsidiaries to incur or guarantee additional debt;

•	incur or permit to exist certain liens on assets;

•	dispose of assets;

•	merge or consolidate with another company or engage in a change of control;

•	enter into transactions with affiliates on non-arm’s length terms; and

•	change the nature of our business.

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•	rates, operating terms, conditions of service and service contracts;

•	certification and construction of new facilities;

•	extension or abandonment of services and facilities or expansion of existing facilities;

•	maintenance of accounts and records;

•	acquisition and disposition of facilities;

•	initiation and discontinuation of services;

•	depreciation and amortization policies;

•	conduct and relationship with certain affiliates;

•	market manipulation in connection with interstate sales, purchases or natural gas transportation; and

•	various other matters.

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•	perform ongoing assessments of pipeline integrity;

•	develop a baseline plan to prioritize the assessment of a covered pipeline segment;

•	identify and characterize applicable threats that could impact a high consequence area;

•	improve data collection, integration, and analysis;

•	repair and remediate pipelines as necessary; and

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•	implement preventive and mitigating action.

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Neither the Partnership Agreement nor any other agreement requires CenterPoint Energy or OGE Energy to pursue a business strategy that favors us. The directors and officers of CenterPoint Energy and OGE Energy have a fiduciary duty to make decisions in the best interests of the stockholders of their respective companies, which may be contrary to our interests. CenterPoint Energy and OGE Energy may choose to shift the focus of their investment and growth to areas not served by our assets. In addition, CenterPoint Energy is the holder of our Series A Preferred Units and may favor its interests in voting in favor of actions relating to such units, including voting in favor of making distributions on such Series A Preferred Units even if no distributions are made on the common units.

•	Our general partner is allowed to take into account the interests of parties other than us, such as CenterPoint Energy and OGE Energy, in resolving conflicts of interest.

•	Some of the directors of our general partner are also officers and/or directors of CenterPoint Energy or OGE Energy and will owe fiduciary duties to their respective companies. These individuals may also devote significant time to the business of CenterPoint Energy and OGE Energy.

•	The Partnership Agreement replaces the fiduciary duties that would otherwise be owed to us by our general partner with contractual standards governing its duties, limits our general partner’s liabilities and restricts the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty.

•	Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

•	Disputes may arise under our commercial agreements with CenterPoint Energy and OGE Energy.

•	Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership units and the creation, reduction or increase of cash reserves, each of which can affect the amount of distributable cash flow.

•	Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion or investment capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders.

•	Our general partner determines which costs incurred by it and its affiliates are reimbursable by us.

•	Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make incentive distributions.

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•	The Partnership Agreement permits us to classify up to $300 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions to our general partner in respect of the incentive distribution rights.

•	The Partnership Agreement does not prohibit our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.

•	Our general partner intends to limit its liability regarding our contractual and other obligations.

•	Our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 90% of the common units. If our general partner and its affiliates reduce their ownership percentage to below 70% of the outstanding units, the ownership threshold to exercise the call right will be permanently reduced to 80%.

•	Our general partner controls the enforcement of the obligations that it and its affiliates owe to us.

•	Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

•	Our general partner may transfer its incentive distribution rights without unitholder approval.

•	Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of the Board of Directors or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

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•	how to allocate corporate opportunities among us and its other affiliates;

•	whether to exercise its limited call right;

•	whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the Board of Directors;

•	whether to elect to reset target distribution levels;

•	whether to transfer the incentive distribution rights to a third party; and

•	whether or not to consent to any merger or consolidation of the Partnership or amendment to the Partnership Agreement.

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whenever our general partner, the Board of Directors or any committee thereof (including the conflicts committee) makes a determination or takes, or declines to take, any other action in their respective capacities, our general partner, the Board of Directors and any committee thereof (including the conflicts committee), as applicable, is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was in the best interests of the Partnership, and, except as specifically provided by our Partnership Agreement, will not be subject to any other or different standard imposed by our Partnership Agreement, Delaware law, or any other law, rule or regulation, or at equity;

•	our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith;

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our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

•	our general partner will not be in breach of its obligations under the Partnership Agreement (including any duties to us or our unitholders) if a transaction with an affiliate or the resolution of a conflict of interest is:

•	approved by the conflicts committee of the Board of Directors, although our general partner is not obligated to seek such approval;

•	approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates;

•	determined by the Board of Directors to be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

•	determined by the Board of Directors to be fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

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•	our existing unitholders’ proportionate ownership interest in us will decrease;

•	the amount of distributable cash flow on each unit may decrease;

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•	because the amount payable to holders of incentive distribution rights is based on a percentage of the total distributable cash flow, the distributions to holders of incentive distribution rights will increase even if the per unit distribution on common units remains the same;

•	the ratio of taxable income to distributions may increase;

•	the relative voting strength of each previously outstanding unit may be diminished; and

•	the market price of the common units may decline.

•	we were conducting business in a state but had not complied with that particular state’s partnership statute; or

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•	a unitholder’s right to act with other unitholders to remove or replace our general partner, to approve some amendments to our Partnership Agreement or to take other actions under our Partnership Agreement constitutes “control” of our business.

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•	less, the amount of cash reserves established by our general partner to:

•	provide for the proper conduct of our business (including cash reserves for our future capital expenditures, future acquisitions and anticipated future debt service requirements and refunds of collected rates reasonably likely to be refunded as a result of a settlement or hearing related to FERC rate proceedings or rate proceedings under applicable law subsequent to that quarter);

•	comply with applicable law, any of our debt instruments or other agreements;

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provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for distributions if the effect of the establishment of such reserves will prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for the current quarter); or

•	provide funds for distributions on our preferred units;

•	plus, if our general partner so determines, all or any portion of the cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter.

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(1)	Net income (loss) attributable to common and subordinated units and basic and diluted earnings per unit reflect net income (loss) attributable to Enable Midstream Partners, LP subsequent to its formation as a limited partnership on May 1, 2013, as no limited partner units were outstanding prior to this date.

(2)	Historical basic and diluted earnings per common limited partner unit reflects the 1 for 1.279082616 reverse unit split effected on March 25, 2014.

(3)

Basic and diluted earnings per subordinated unit reflect net income (loss) attributable to the Partnership for periods subsequent to its IPO, as no subordinated units were outstanding prior to this date. The financial tests required for conversion of all subordinated units were met and the 207,855,430 outstanding subordinated units converted into common units on a one-for-one basis on August 30, 2017.

(4)	Distributions attributable to periods prior to the IPO are in accordance with the First Amended and Restated Agreement of Limited Partnership. Distributions declared per unit prior to the IPO relate to common units, as no subordinated units were outstanding prior to the date of the IPO.

(5)	Distributions attributable to periods subsequent to the IPO are in accordance with the Partnership Agreement. Distributions declared per unit relate to common and subordinated units.

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(1)	See “Reconciliation of Non-GAAP Financial Measures” in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a reconciliation of Gross margin, Adjusted EBITDA and DCF to their most directly comparable financial measure calculated and presented in accordance with GAAP.

(2)	Excludes condensate.

(3)	NGLs sold includes volumes of NGLs withdrawn from inventory or purchased for system balancing purposes.

(4)	Initial operation of our crude oil gathering system began on November 1, 2013.

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(1)	Gross margin is a non-GAAP measure and is defined and reconciled to its most directly comparable financial measures calculated and presented below under the caption Reconciliations of Non-GAAP Financial Measures.

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(1)	Excludes condensate.

(2)	NGLs sold includes volumes of NGLs withdrawn from inventory or purchased for system balancing purposes.

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(1)	Other non-cash losses includes loss on sale of assets and write-downs of materials and supplies.

(2)

This amount represents the quarterly cash distributions on the Series A Preferred Units declared for the year ended December 31, 2017. The year ended December 31, 2016 amount includes the prorated quarterly cash distribution on the Series A Preferred Units declared on April 26, 2016. In accordance with the Partnership Agreement, the Series A Preferred Unit distributions are deemed to have been paid out of available cash with respect to the quarter immediately preceding the quarter in which the distribution is made.

(3)	Distributions for phantom and performance units represent distribution equivalent rights paid in cash. Phantom unit distribution equivalent rights are paid during the vesting period and performance unit distribution equivalent rights are paid at vesting.

(4)	See below for a reconciliation of Adjusted interest expense to Interest expense.

(5)	Represents cash distributions declared for common and subordinated units outstanding as of each respective period.  Amounts for 2017 reflect estimated cash distributions for common units outstanding for the quarter ended December 31, 2017.

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(1)	Other non-cash items includes amortization of debt expense, discount and premium on long-term debt and write-downs of materials and supplies.

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•	cash on hand;

•	cash generated from operations;

•	proceeds from commercial paper issuances and borrowings under our Revolving Credit facility; and

•	capital raised through debt and equity markets.

•	maintenance capital expenditures, which are cash expenditures (including expenditures for the construction or development of new capital assets or the replacement, improvement or expansion of existing capital assets) made to maintain, over the long-term, our operating capacity or operating income; and

•	expansion capital expenditures, which are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term.

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(1)	The board of directors of Enable GP declared this $0.318 per common unit cash distribution on February 9, 2018, to be paid on February 27, 2018, to unitholders of record at the close of business on February 20, 2018.

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(1)	The board of directors of Enable GP declared a $0.625 per Series A Preferred Unit cash distribution on February 9, 2018, which was paid on February 15, 2018 to Series A Preferred unitholders of record at the close of business on February 9, 2018.

(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.

(1)	Contractual interest payments associated with long-term debt are $117 million, $193 million, $163 million and $765 million in 2018, 2019 through 2020, 2021 through 2022 and after 2022, respectively. The 2015 Term Loan Agreement estimated contractual interest payments are calculated utilizing the variable interest rate as of December 31, 2017.

(2)	Excludes premium (discount) on long-term debt of $10 million.

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Natural gas and natural gas liquids purchase arrangements - For certain arrangements within our gathering and processing segment, the Partnership purchases and controls the entire hydrocarbon stream at the point of receipt. Under Topic 606, these arrangements are considered supplier contracts rather than contracts with customers. Therefore, upon adoption of Topic 606, the gathering and processing fees for these arrangements that were previously recognized as Service revenue under Topic 605 will now be recognized as reductions to Cost of natural gas and natural gas liquids.

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Percent-of-proceeds and percent-of-liquids processing arrangements - Under percent-of-proceeds and percent-of-liquids arrangements within our gathering and processing segment, we have recognized the value of natural gas and natural gas liquids received in our purchase cost within Cost of natural gas and natural gas liquids. Under Topic 606, the Partnership will recognize the value of the natural gas and NGLs received as Service revenue and as an increase to Cost of natural gas and natural gas liquids when the natural gas or NGLs are sold and Product sales are recognized.

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Keep-whole arrangements - Under keep-whole arrangements within our gathering and processing segment, the Partnership recognized the value of NGLs received in Product revenue and the value of the thermally equivalent quantity of natural gas provided in our purchase cost within Cost of natural gas and natural gas liquids. Under Topic 606, the Partnership will recognize the value of the NGLs received less the value of the thermal equivalent volume of natural gas provided as Service revenue and as an increase to Cost of natural gas and natural gas liquids when the NGLs are sold and Product sales are recognized.

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Fixed fuel arrangements - Under certain gathering arrangements within our gathering and processing segment as well as under certain transportation arrangements within our transportation and storage segment we receive a fixed amount of fuel regardless of actual fuel usage. Historically, revenue for fuel in excess of actual usage was recognized when such fuel was received, and additional revenue was recognized when such fuel was sold. Under Topic 606, fuel in excess of actual usage will be treated as a byproduct obtained through the fulfillment of a contract, and the Partnership will recognize revenue at the time the excess fuel is sold. This will result in a reduction of Product sales and a corresponding reduction in Cost of natural gas and natural gas liquids.

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(1)	Basic weighted average number of outstanding common units for the year ended December 31, 2017 includes approximately one million time-based phantom units.

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(1)	The board of directors of Enable GP declared this $0.318 per common unit cash distribution on February 9, 2018, to be paid on February 27, 2018, to common unitholders of record at the close of business on February 20, 2018.

(1)	The board of directors of Enable GP declared this $0.625 per Series A Preferred Unit cash distribution on February 9, 2018, which was paid on February 15, 2018 to Series A Preferred unitholders of record at the close of business on February 9, 2018.

(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.

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•	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.

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(1)	See Note 3 for discussion of the acquisition of Align Midstream, LLC during the year ended December 31, 2017.

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(1)	See Note 3 for further discussion.

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(1)	Distributions from equity method affiliate includes a $28 million, $28 million and $34 million return on investment and a $5 million, $15 million and $8 million return of investment for the years ended December 31, 2017, 2016 and 2015, respectively.

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(1)	Unamortized premium (discount) on long-term debt is amortized over the life of the respective debt.

(2)	Short-term debt includes $405 million of commercial paper as of December 31, 2017. There was no commercial paper outstanding as of December 31, 2016.

(3)	As of December 31, 2017 and 2016, there was an additional $3 million and $5 million, respectively, of unamortized debt expense related to the Revolving Credit Facility included in Other long-term assets, not included above. Unamortized debt expense is amortized over the life of the respective debt.

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•	NGL put options, NGL futures and swaps, and WTI crude oil futures and swaps for condensate sales are used to manage the Partnership’s NGL and condensate exposure associated with its processing agreements;

•	natural gas futures and swaps are used to manage the Partnership’s natural gas exposure associated with its gathering, processing and transportation and storage assets; and

•	natural gas futures and swaps, natural gas options and natural gas commodity purchases and sales are used to manage the Partnership’s natural gas exposure associated with its storage and transportation contracts and asset management activities.

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(1)	As of December 31, 2017, 67.7% of the natural gas contracts have durations of one year or less, 16.1% have durations of more than one year and less than two years and 16.2% have durations of more than two years. As of December 31, 2016, 100.0% of the natural gas contracts had durations of one year or less.

(2)	As of December 31, 2017 and 2016, 100% of the crude oil (for condensate) contracts have durations of one year or less.

(3)	As of December 31, 2017 and 2016, 100.0% of the natural gas liquid contracts have durations of one year or less.

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(1)	See Note 12 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Consolidated Balance Sheets as of December 31, 2017 and 2016.

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(1)	Borrowing capacity is effectively reduced by our borrowings outstanding under the commercial paper program. $405 million and zero of commercial paper was outstanding as of December 31, 2017 and 2016, respectively.

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(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 December 31, 2017 and 2016.

(2)	Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $10 million and zero at December 31, 2017 and 2016, 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 zero and $5 million at December 31, 2017 and 2016, 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.

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(1)	For performance units, this represents the target number of performance units granted. The actual number of performance units earned, if any, is dependent upon performance and may range from 0 percent to 200 percent of the target.

(2)	Performance units vested as of December 31, 2017 include 334,682 units from the 2014 annual grant, which vested on June 1, 2017 and paid out at 91.5% of target, or 306,170 units, based on the level of achievement of a performance goal established by the Board of Directors over the performance period.

(3)

Performance units outstanding as of December 31, 2017 include 402,586 units from the 2015 annual grant, which were approved by the Board of Directors in 2015. The results of the performance units were certified by the Compensation Committee in February 2018, at a 200% payout based on the level of achievement of a performance goal established by the Board of Directors over a performance period of January 1, 2015 through December 31, 2017. The increase in outstanding units for a payout percentage of an amount other than 100% is not reflected above until the vesting date.

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(1)	Equity in earnings of equity method affiliate is included in Other Income (Expense) on the Consolidated Statements of Income, and is not included in the table above. See Note 9 for discussion regarding ownership interest in SESH and related equity earnings included in the transportation and storage segment for the years ended December 31, 2017, 2016 and 2015.

(2)	The Partnership had no external customers accounting for 10% or more of revenues in periods shown. See Note 14 for revenues from affiliated companies.

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(1)	See Note 5 for discussion of the conversion of the subordinated units.

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•	possesses appropriate skills and professional experience;

•	has a reputation for integrity and other qualities;

•	possesses expertise, including industry knowledge, determined in the context of the needs of the Board of Directors;

•	has experience in positions with a high degree of responsibility;

•	is a leader in the organizations with which he or she is affiliated;

•	is diverse in terms of geography, gender, ethnicity and age;

•	has the time, energy, interest and willingness to serve as a member of the Board of Directors; and

•	meets such standards of independence and financial knowledge as may be required or desirable.

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(1)	One Leadership Square, 211 North Robinson Avenue, Suite 150, Oklahoma City, Oklahoma 73102

(2)	321 North Harvey, P.O. Box 321, Oklahoma City, Oklahoma 73101

(3)	1111 Louisiana Street, Houston, Texas 77002

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(1)

Amounts in this column reflect the aggregate grant date fair value amount of the Partnership equity-based unit awards granted to each named executive officer. The grant date fair value amount of performance unit awards is computed in accordance with FASB ASC Topic 718 based on the probable achievement level of the underlying performance conditions as of the grant date. Please refer to the Grants of Plan-Based Awards table for 2017 and the accompanying footnotes. Assuming achievement of the performance goals at the maximum level, the grant date fair value of the performance units granted in 2017 and included in this column would be $2,969,584 for Mr. Sailor, $1,020,578 for Mr. Laws, $676,724 for Mr. Brewer, $668,129 for Mr. C. Harris, and $696,572 for Mr. Schroeder. Assuming achievement of the performance goals at the maximum level, the grant date fair value of the performance units granted in 2016 and included in this column would be $4,324,134 for Mr. Sailor, $1,324,256 for Mr. Laws, $1,498,802 for Mr. C. Harris, and $975,938 for Mr. Schroeder. Assuming achievement of the performance goals at the maximum level, the grant date fair value of the performance units granted in 2015 and included in this column would be $1,765,939 for Mr. Sailor and $797,150 for Mr. Schroeder. The grant date fair value amount of phantom unit awards and restricted unit awards are computed in accordance with FASB ASC Topic 718. See Note 17 to the financial statements for a discussion of the valuation assumptions used for these awards.

(2)	Amounts in this column reflect amounts earned under the Partnership’s Short-Term Incentive Plan.

(3)	The following table sets forth the elements of All Other Compensation for 2017, 2016 and 2015.

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(4)	Represents salary from hire date on September 6, 2016 to December 31, 2016.

(5)	Amounts include an award of 19,276 phantom units Mr. C. Harris received upon employment with the Partnership, of which 9,638 units vested on September 6, 2017 and 9,638 units will vest on September 6, 2018. Awards granted to Mr. C. Harris in 2016 were calculated based on the closing price of the Partnership’s common units, as reported on the NYSE on the grant date.

(6)	Other than Mr. C. Harris, none of our named executive officers received perquisites valued in excess of $10,000 in 2017.

(7)	Amounts include $28,000 of travel allowance in 2017 and $14,000 of travel allowance in 2016 for Mr. C. Harris and $1,046 of tax gross up for Mr. Laws in 2016.

(1)

Amounts in columns (c), (d) and (e) of the Grants of Plan-Based Awards Table for 2017 above represent the threshold, target and maximum amounts that would be payable to named executive officers pursuant to the 2017 annual incentive awards made under the Enable Midstream Partners, LP Short-Term Incentive Plan. The short-term incentive plan was designed with a funding trigger that requires threshold performance for the plan to payout. If threshold performance is not met, no payments will be made. For each performance measure, established thresholds were set (at which 50% payout

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(2)

Amounts in columns (f), (g) and (h) above represent awards of performance units under Enable Midstream Partners, LP Long-Term Incentive Plan. All payouts of such performance units will be made in units and any accumulated distribution equivalent rights will be paid in cash. Due to their variable nature, accumulated distribution equivalent rights are not disclosed in the table above. The conditions of the 2017 award provide that the executive officer will receive from 0% to 200% of the performance units awarded depending upon the Partnership’s total unitholder return of a group of 16 peer companies over a performance period from January 1, 2017 through December 31, 2019. Total unit holder return includes both price appreciation and cash distributions over the performance period. Price appreciation is determined by comparing the average closing price of units of the Partnership or any company in the peer group for the 20 trading days preceding the performance period and for the last 20 trading days during the performance period. Cash distributions for the Partnership or any company in the peer group are assumed to have been reinvested in additional units on the date two days prior to the distribution record date. At the end of the performance period, the terms of these performance units provide for payout of 100% of the performance units initially granted if the Partnership’s total unitholder return is at the 50th percentile of the peer group, with higher payouts for performance above the 50th percentile up to 200% of the performance units granted if total unitholder return is at or above the 90th percentile of the peer group. The terms of these performance units provide for payouts of less than 100% of the performance units granted if the Partnership’s total unitholder return is below the 50th percentile of the peer group, with no payout for performance below the 30th percentile.

(3)	Amounts in column (i) above represent the number of phantom unit awards granted to each of our named executive officers under the Enable Midstream Partners, LP Long-Term Incentive Plan.

(4)	Amounts reflect the grant date fair value based on a probable value of these awards or target value, of 100% payout. See Note 17 to the financial statements for further information.

(1)	This amount represents a time-based phantom unit award under the Enable Midstream Partners long-term incentive plan scheduled to vest on March 1, 2020. Values were calculated based on a $14.22 closing price of the Partnership’s common units, as reported on the NYSE at December 31, 2017.

(2)	This amount represents a time-based phantom unit award under the Enable Midstream Partners long-term incentive plan scheduled to vest on April 1, 2019. Values were calculated based on a $14.22 closing price of the Partnership’s common units, as reported on the NYSE at December 31, 2017.

(3)	This amount represents a restricted unit award under the Enable Midstream Partners long-term incentive plan which will vest on April 16, 2018. Values were calculated based on a $14.22 closing price of the Partnership’s common units, as reported on the NYSE at December 31, 2017.

(4)	This amount represents a restricted unit award under the Enable Midstream Partners long-term incentive plan. On February 14, 2018, our Compensation Committee accelerated the vesting of this award from June 1, 2018 to March 1, 2018. Values were calculated based on a $14.22 closing price of the Partnership’s common units, as reported on the NYSE at December 31, 2017.

(5)	This amount represents a time-based phantom unit award under the Enable Midstream Partners long-term incentive plan, which will vest on September 6, 2018. Values were calculated based on a $14.22 closing price of the Partnership’s common units, as reported on the NYSE at December 31, 2017.

(6)

This amount represents a performance unit award under the Enable Midstream Partners long-term incentive plan. The performance cycle began on January 1, 2017 and ends December 31, 2019. The number of units listed reflects the number of units paid at maximum performance. The value of the awards was calculated based on maximum payout of 200% and a $14.22 closing price of the Partnership’s common units, as reported on the NYSE on December 31, 2017. This award will vest on March 1, 2020.

(7)

This amount represents a performance unit award under the Enable Midstream Partners long-term incentive plan. The performance cycle began on January 1, 2016 and ends December 31, 2018. The number of units listed reflects the number of units paid at maximum performance. The value of the awards was calculated based on maximum payout of 200% and a $14.22 closing price of the Partnership’s common units, as reported on the NYSE on

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(8)

This amount represents a performance unit award under the Enable Midstream Partners long-term incentive plan. The performance cycle began on January 1, 2015 and ends December 31, 2017. The number of units listed reflects the number of units paid at maximum performance. The value of the awards was calculated based on maximum payout of 200% and a $14.22 closing price of the Partnership’s common units, as reported on the NYSE on December 31, 2017. On February 14, 2018, our Compensation Committee accelerated the vesting of this award from June 1, 2018 to March 1, 2018.

(9)

This amount represents a performance unit award under the Enable Midstream Partners long-term incentive plan granted on September 6, 2016. The performance cycle began on January 1, 2016 and ends December 31, 2018. The number of units listed reflects the number of units paid at maximum performance. The value of the awards was calculated based on maximum payout of 200% and a $14.22 closing price of the Partnership's common units, as reported on the NYSE on December 31, 2017. This award will vest on September 6, 2019.

(1)	The value of the awards was calculated based on the closing price of the Partnership’s common units, as reported on the NYSE on the date of vesting.

(2)	These amounts reflect the payout of performance units granted on June 2, 2014. The units vested on June 2, 2017. Performance was based on the Partnership's total unitholder return over a period of April 11, 2014 to December 31, 2016.

(3)	This amount reflects the distribution of time-based restricted units granted on June 2, 2014. The units vested on June 2, 2017.

(4)	This amount reflects the distribution of time-based phantom units granted on September 6, 2016. The units vested on September 6, 2017.

(1)	The amounts disclosed in this column also are disclosed in the “All Other Compensation” column of the Summary Compensation Table and are further described in the All Other Compensation Table.

(2)	Represents earnings on invested funds in each Executive’s individual account.

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•	for the President and Chief Executive Officer, a lump-sum cash payment of 2.99 times his annual base salary and short-term incentive plan award target;

•	for each Executive Vice President, a lump-sum cash payment of 2.0 times his or her annual base salary and short-term incentive plan award target; and

•	for any other officer who is not an Executive Vice President, a lump-sum cash payment of 1.5 times his or her annual base salary and short-term incentive plan award target.

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(1)	Reflects the lump-sum cash payment of the change of control benefit, plus any accrued salary and vacation. The change of control benefit for Mr. Sailor reflects 2.99 times his base salary and short-term incentive target; all other named executive officers change of control benefit reflects 2.00 times their base salary and short-term incentive target.

(2)	Reflects the lump-sum cash payment of each named executive officers target short-term incentive bonus.

(3)	Reflects the lump-sum cash payment for health and welfare benefit coverage. The benefit for Mr. Sailor reflects the sum of the Employer’s portion of the annual premium for medical, dental and vision times 2.99; all other named executive officers reflects the sum of the Employer’s portion of the annual premium for medical, dental and vision times 2.00.

(4)	Reflects the lump-sum cash payment for outplacement assistance.

(5)

Amounts above include the value of all unvested restricted unit awards and phantom unit awards and, if applicable, the value of any distribution equivalent rights. All performance unit awards will vest and be paid out as if the applicable performance goals had been satisfied at target levels or actual performance, whichever is greater. The amounts above include the value of all unvested performance unit awards, assuming target level payout and, if applicable, the value of any distribution equivalent rights.

(1)	Reflects the cash payment of 1.0 times his annual base salary of $650,000 and his short-term incentive plan award target of $650,000 as of December 31, 2017.

(2)	Reflects the pro-rata vested amount of a restricted unit award to Mr. Sailor as of December 31, 2017.

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(1)	Reflects the aggregate grant date fair value of 2017 unit awards computed in accordance with FASB ASC Topic 718. Awards granted to independent directors vested immediately. See Note 17 to the financial statements for further information.

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*	Less than 1%

(1)	1111 Louisiana Street, Houston, Texas 77002

(2)	321 North Harvey, P.O. Box 321, Oklahoma City, OK 73101

(3)	200 Clarendon Street, 55th Floor Boston, MA 02116

(4)	One Leadership Square, 211 North Robinson Avenue, Suite 150, Oklahoma City, Oklahoma 73102

(5)

Based on a Schedule 13D/A filed with the SEC pursuant to the Exchange Act on August 31, 2017. The common units reported represent the aggregated beneficial ownership by CenterPoint Energy, together with its wholly owned subsidiaries. CenterPoint Energy may be deemed to have sole voting power with respect to 233,856,623 common units. CenterPoint Energy has no shared voting or dispositive power with respect to any of the common units shown. CenterPoint Energy also holds14,520,000 Series A Preferred Units.

(6)

Based on a Schedule 13G filed with the SEC pursuant to the Exchange Act on February 11, 2015. The common units reported represent the aggregated beneficial ownership by OGE Energy Corp., together with its wholly owned subsidiaries. OGE Energy Corp. may be deemed to have sole voting power with respect to 110,982,805 common units. OGE Energy Corp. has no shared voting or dispositive power with respect to any of the common units shown.

(7)

Based on a Form 4 filed with the SEC pursuant to the Exchange Act on July 17, 2017, 43,238,773 common units are held by Bronco Midstream Infrastructure, LLC. ArcLight Capital Partners, LLC is the investment advisor for, and ArcLight Capital Holdings, LLC is the managing partner of the general partner of each of ArcLight Energy Partners Fund V, L.P., ArcLight Energy Partners Fund IV, L.P. and Bronco Midstream Partners, LP. Bronco Midstream Infrastructure, LLC is an indirect wholly owned subsidiary of Enogex Holdings LLC. ArcLight Capital Partners, LLC has ultimate voting and investment control over the common units held by Bronco Midstream Infrastructure LLC and thus may be deemed to indirectly beneficially own such securities. Due to certain voting rights granted to Mr. Revers as a member of the investment committee of ArcLight Capital Partners, LLC, Mr. Revers may be deemed to indirectly beneficially own the common units attributable to ArcLight Capital Partners, LLC, but disclaims any such ownership except to the extent of his pecuniary interest therein.

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(1)	Our Long-Term Incentive Plan was adopted by our general partner for the benefit of our officers, directors and employees. See Item 11. “Executive Compensation-Compensation Discussion and Analysis.” The plan provides for the issuance of a total of 13,100,000 common units under the plan.

(2)	The number of securities remaining available for future issuance includes 222,434 restricted units that have been granted under our long-term incentive plan that have not vested.

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•	Such party intends to cease using the midstream operations assets of the business within 12 months of the acquisition of such business; or

•	Such party acquires a business with midstream operations having a value in excess of $50 million (or $100 million in the aggregate with any of such party’s other midstream operations assets), and it offers to us the opportunity to acquire the midstream operations assets of such business.

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(1)	Includes non-cash impairment on goodwill and long-lived assets of $1,134 million for the year ended December 31, 2015.

(2)	Earnings were inadequate to cover fixed charges by $761 million for the year ended December 31, 2015.

(3)	No preferred units were outstanding for the years ended December 31, 2015, 2014, or 2013. No historical ratios of earnings to combined fixed charges and preferred unit distributions are presented for these years.

a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.