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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

_______________________________________

FORM 10-Q

_______________________________________

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2018

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____to_____

Commission File No. 1-36413

_______________________________________

ENABLE MIDSTREAM PARTNERS, LP

(Exact name of registrant as specified in its charter)

_______________________________________



Delaware		72-1252419
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

One Leadership Square

211 North Robinson Avenue

Suite 150

Oklahoma City, Oklahoma 73102

(Address of principal executive offices)

(Zip Code)

(405) 525-7788

Registrant’s telephone number, including area code

_______________________________________

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. þ Yes ¨ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). þ Yes ¨ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.



Large accelerated filer	þ	Accelerated filer	¨

Non-accelerated filer	¨ (Do not check if a smaller reporting company)	Smaller reporting company	¨

		Emerging growth company	¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨ Yes þ No

As of April 13, 2018, there were 433,074,409 common units outstanding.

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ENABLE MIDSTREAM PARTNERS, LP

FORM 10-Q

TABLE OF CONTENTS



	Page
GLOSSARY OF TERMS	1
FORWARD-LOOKING STATEMENTS	3

Part I - FINANCIAL INFORMATION
Item 1. Financial Statements (Unaudited)
Condensed Consolidated Statements of Income	4
Condensed Consolidated Balance Sheets	5
Condensed Consolidated Statements of Cash Flows	6
Condensed Consolidated Statements of Partners' Equity	7
Notes to Condensed Consolidated Financial Statements	8
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations	31
Item 3. Quantitative and Qualitative Disclosures About Market Risk	44
Item 4. Controls and Procedures	44

Part II - OTHER INFORMATION
Item 1. Legal Proceedings	45
Item 1A. Risk Factors	45
Item 6. Exhibits	47

Signature	49

AVAILABLE INFORMATION

Our website is www.enablemidstream.com. On the investor relations tab of our website, http://investors.enablemidstream.com, we make available free of charge a variety of information to investors. Our goal is to maintain the investor relations tab of our website as a portal through which investors can easily find or navigate to pertinent information about us, including but not limited to:


•	our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports as soon as reasonably practicable after we electronically file that material with or furnish it to the SEC;


•	press releases on quarterly distributions, quarterly earnings, and other developments;


•	governance information, including our governance guidelines, committee charters, and code of ethics and business conduct;


•	information on events and presentations, including an archive of available calls, webcasts, and presentations;


•	news and other announcements that we may post from time to time that investors may find useful or interesting; and


•	opportunities to sign up for email alerts and RSS feeds to have information pushed in real time.

Information contained on our website or any other website is not incorporated by reference into this report and does not constitute a part of this report.

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GLOSSARY OF TERMS



2015 Term Loan Agreement.	$450 million unsecured term loan agreement.
2019 Notes.	$500 million aggregate principal amount of the Partnership’s 2.400% senior notes due 2019.
2024 Notes.	$600 million aggregate principal amount of the Partnership’s 3.900% senior notes due 2024.
2027 Notes.	$700 million aggregate principal amount of the Partnership’s 4.400% senior notes due 2027.
2044 Notes.	$550 million aggregate principal amount of the Partnership’s 5.000% senior notes due 2044.
Adjusted EBITDA.	A non-GAAP measure calculated as net income attributable to limited partners plus depreciation and amortization expense, interest expense, net of interest income, income tax expense, distributions received from equity method affiliate in excess of equity earnings, non-cash equity-based compensation, changes in fair value of derivatives, certain other non-cash gains and losses (including gains and losses on sales of assets and write-downs of materials and supplies) and impairments, less the noncontrolling interest allocable to Adjusted EBITDA.
Adjusted interest expense.	A non-GAAP measure calculated as interest expense plus amortization of premium on long-term debt and capitalized interest on expansion capital, less amortization of debt costs and discount on long-term debt.
Annual Report.	Annual Report on Form 10-K for the year ended December 31, 2017.
ArcLight.	ArcLight Capital Partners, LLC, a Delaware limited liability company, its affiliated entities ArcLight Energy Partners Fund V, L.P., ArcLight Energy Partners Fund IV, L.P., Bronco Midstream Partners, L.P., Bronco Midstream Infrastructure LLC and Enogex Holdings LLC, and their respective general partners and subsidiaries.
ASC.	Accounting Standards Codification.
ASU.	Accounting Standards Update.
ATM Program.	The offer and sale, from time to time, of common units representing limited partner interest having an aggregate offering price of up to $200 million in quantities, by sales methods and at prices determined by market conditions and other factors at the time of such sales, pursuant to that certain ATM Equity Offering Sales Agreement, entered into on May 12, 2017.
Barrel.	42 U.S. gallons of petroleum products.
Bbl.	Barrel.
Bbl/d.	Barrels per day.
Bcf/d.	Billion cubic feet per day.
Btu.	British thermal unit. When used in terms of volume, Btu refers to the amount of natural gas required to raise the temperature of one pound of water by one degree Fahrenheit at one atmospheric pressure.
CenterPoint Energy.	CenterPoint Energy, Inc., a Texas corporation, and its subsidiaries.
Condensate.	A natural gas liquid with a low vapor pressure, mainly composed of propane, butane, pentane and heavier hydrocarbon fractions.
DCF.	A non-GAAP measure calculated as Adjusted EBITDA, as further adjusted for Series A Preferred Unit distributions, distributions for phantom and performance units, Adjusted interest expense, maintenance capital expenditures and current income taxes.
Distribution coverage ratio.	A non-GAAP measure calculated as DCF divided by distributions related to common and subordinated unitholders.
DRIP.	Distribution Reinvestment Plan entered into on June 23, 2016, which offers owners of our common units the ability to purchase additional common units by reinvesting all or a portion of the cash distributions paid to them on their common units.
EGT.	Enable Gas Transmission, LLC, a wholly owned subsidiary of the Partnership that operates an approximately 5,900-mile interstate pipeline that provides natural gas transportation and storage services to customers principally in the Anadarko, Arkoma and Ark-La-Tex Basins in Oklahoma, Texas, Arkansas, Louisiana and Kansas.
Enable GP.	Enable GP, LLC, a Delaware limited liability company and the general partner of Enable Midstream Partners, LP.
EOIT.	Enable Oklahoma Intrastate Transmission, LLC, formerly Enogex LLC, a wholly owned subsidiary of the Partnership that operates an approximately 2,200-mile intrastate pipeline that provides natural gas transportation and storage services to customers in Oklahoma.
EOIT Senior Notes.	$250 million 6.25% senior notes due 2020.
Exchange Act.	Securities Exchange Act of 1934, as amended.

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FASB.	Financial Accounting Standards Board.
FERC.	Federal Energy Regulatory Commission.
Fractionation.	The separation of the heterogeneous mixture of extracted NGLs into individual components for end-use sale.
GAAP.	Generally accepted accounting principles in the United States.
Gas imbalance.	The difference between the actual amounts of natural gas delivered from or received by a pipeline, as compared to the amounts scheduled to be delivered or received.
Gross margin.	A non-GAAP measure calculated as Total revenues minus Cost of natural gas and natural gas liquids, excluding depreciation and amortization.
LDC.	Local distribution company involved in the delivery of natural gas to consumers within a specific geographic area.
LIBOR.	London Interbank Offered Rate.
MBbl.	Thousand barrels.
MBbl/d.	Thousand barrels per day.
MFA.	Master Formation Agreement dated as of March 14, 2013.
MMcf.	Million cubic feet of natural gas.
MMcf/d.	Million cubic feet per day.
MRT.	Enable Mississippi River Transmission, LLC, a wholly owned subsidiary of the Partnership that operates a 1,600-mile interstate pipeline that provides natural gas transportation and storage services principally in Texas, Arkansas, Louisiana, Missouri and Illinois.
NGLs.	Natural gas liquids, which are the hydrocarbon liquids contained within natural gas including condensate.
NYMEX.	New York Mercantile Exchange.
OGE Energy.	OGE Energy Corp., an Oklahoma corporation, and its subsidiaries.
Partnership.	Enable Midstream Partners, LP, and its subsidiaries.
Partnership Agreement.	Fifth Amended and Restated Agreement of Limited Partnership of Enable Midstream Partners, LP dated as of November 14, 2017.
Revolving Credit Facility.	$1.75 billion senior unsecured revolving credit facility.
SEC.	Securities and Exchange Commission.
Second Amended and Restated Revolving Credit Facility.	$1.75 billion senior unsecured revolving credit facility entered into on April 6, 2018, which amended and restated the Revolving Credit Facility.
Series A Preferred Units.	10% Series A Fixed-to-Floating Non-Cumulative Redeemable Perpetual Preferred Units representing limited partner interests in the Partnership.
SESH.	Southeast Supply Header, LLC, in which the Partnership owns a 50% interest, that operates an approximately 290-mile interstate natural gas pipeline from Perryville, Louisiana to southwestern Alabama near the Gulf Coast.
TBtu.	Trillion British thermal units.
TBtu/d.	Trillion British thermal units per day.
WTI.	West Texas Intermediate.

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FORWARD-LOOKING STATEMENTS

Some of the information in this report may contain forward-looking statements. Forward-looking statements give our current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as “could,” “will,” “should,” “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this report include our expectations of plans, strategies, objectives, growth and anticipated financial and operational performance, including revenue projections, capital expenditures and tax position. Forward-looking statements can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed.

A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, when considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this report and in our Annual Report. Those risk factors and other factors noted throughout this report and in our Annual Report could cause our actual results to differ materially from those disclosed in any forward-looking statement. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:


•	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 Enable GP;


•	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, including our Annual Report.

Forward-looking statements speak only as of the date on which they are made. We expressly disclaim any obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by law.

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ENABLE MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)



	Three Months Ended March 31,
	2018			2017
	(In millions, except per unit data)
Revenues (including revenues from affiliates (Note 12)):
Product sales	$	443		$	386
Service revenues	305			280
Total Revenues	748			666
Cost and Expenses (including expenses from affiliates (Note 12)):
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	375			308
Operation and maintenance	94			89
General and administrative	27			25
Depreciation and amortization	96			88
Taxes other than income tax	17			16
Total Cost and Expenses	609			526
Operating Income	139			140
Other Income (Expense):
Interest expense	(33		)	(27		)
Equity in earnings of equity method affiliate	6			7
Other, net	2			1
Total Other Expense	(25		)	(19		)
Income Before Income Tax	114			121
Income tax expense	—			1
Net Income	$	114		$	120
Less: Net income attributable to noncontrolling interest	—			—
Net Income Attributable to Limited Partners	$	114		$	120
Less: Series A Preferred Unit distributions (Note 6)	9			9
Net Income Attributable to Common and Subordinated Units (Note 5)	$	105		$	111

Basic earnings per unit (Note 5)
Common units	$	0.24		$	0.26
Subordinated units	$	—		$	0.25
Diluted earnings per unit (Note 5)
Common units	$	0.24		$	0.26
Subordinated units	$	—		$	0.25

See Notes to the Unaudited Condensed Consolidated Financial Statements

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ENABLE MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	March 31, 2018		December 31, 2017
	(In millions)
Current Assets:
Cash and cash equivalents	$	30	$	5
Restricted cash	14		14
Accounts receivable, net of allowance for doubtful accounts	253		277
Accounts receivable—affiliated companies	19		18
Inventory	39		40
Gas imbalances	35		37
Other current assets	23		25
Total current assets	413		416
Property, Plant and Equipment:
Property, plant and equipment	12,273		12,079
Less accumulated depreciation and amortization	1,805		1,724
Property, plant and equipment, net	10,468		10,355
Other Assets:
Intangible assets, net	440		451
Goodwill	12		12
Investment in equity method affiliate	317		324
Other	37		35
Total other assets	806		822
Total Assets	$	11,687	$	11,593
Current Liabilities:
Accounts payable	$	209	$	263
Accounts payable—affiliated companies	5		3
Current portion of long-term debt	450		450
Short-term debt	595		405
Taxes accrued	26		32
Gas imbalances	8		12
Other	111		114
Total current liabilities	1,404		1,279
Other Liabilities:
Accumulated deferred income taxes, net	6		6
Regulatory liabilities	21		21
Other	43		38
Total other liabilities	70		65
Long-Term Debt	2,594		2,595
Commitments and Contingencies (Note 13)
Partners’ Equity:
Series A Preferred Units (14,520,000 issued and outstanding at March 31, 2018 and December 31, 2017)	362		362
Common units (433,072,001 issued and outstanding at March 31, 2018 and 432,584,080 issued and outstanding at December 31, 2017, respectively)	7,246		7,280
Noncontrolling interest	11		12
Total Partners’ Equity	7,619		7,654
Total Liabilities and Partners’ Equity	$	11,687	$	11,593

See Notes to the Unaudited Condensed Consolidated Financial Statements

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ENABLE MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Three Months Ended March 31,
	2018			2017
	(In millions)
Cash Flows from Operating Activities:
Net income	$	114		$	120
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	96			88
Deferred income taxes	—			1
Loss on sale/retirement of assets	1			1
Equity in earnings of equity method affiliate	(6		)	(7		)
Return on investment in equity method affiliate	6			7
Equity-based compensation	5			4
Amortization of debt costs and discount (premium)	—			(1		)
Changes in other assets and liabilities:
Accounts receivable, net	24			18
Accounts receivable—affiliated companies	(1		)	(8		)
Inventory	1			1
Gas imbalance assets	2			17
Other current assets	(4		)	1
Other assets	(3		)	2
Accounts payable	(62		)	(55		)
Accounts payable—affiliated companies	2			—
Gas imbalance liabilities	(4		)	(17		)
Other current liabilities	(6		)	(16		)
Other liabilities	1			—
Net cash provided by operating activities	166			156
Cash Flows from Investing Activities:
Capital expenditures	(190		)	(61		)
Proceeds from sale of assets	7			1
Return of investment in equity method affiliate	7			4
Net cash used in investing activities	(176		)	(56		)
Cash Flows from Financing Activities:
Proceeds from long term debt, net of issuance costs	—			691
Proceeds from revolving credit facility	—			264
Repayment of revolving credit facility	—			(900		)
Increase in short-term debt	190			—
Distributions	(150		)	(147		)
Cash taxes paid for employee equity-based compensation	(5		)	—
Net cash provided by (used in) financing activities	35			(92		)
Net Increase in Cash, Cash Equivalents and Restricted Cash	25			8
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	19			23
Cash, Cash Equivalents and Restricted Cash at End of Period	$	44		$	31

See Notes to the Unaudited Condensed Consolidated Financial Statements

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ENABLE MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY

(Unaudited)



	Series A Preferred Units				Common Units				Subordinated Units				Noncontrolling Interest			Total Partners’ Equity
	Units	Value			Units	Value			Units	Value			Value			Value
	(In millions)
Balance as of December 31, 2016	15	$	362		224	$	3,737		208	$	3,683		$	12		$	7,794
Net income	—	9			—	58			—	53			—			120
Distributions	—	(9		)	—	(72		)	—	(66		)	—			(147		)
Equity-based compensation, net of units for employee taxes	—	—			—	4			—	—			—			4
Balance as of March 31, 2017	15	$	362		224	$	3,727		208	$	3,670		$	12		$	7,771

Balance as of December 31, 2017	15	$	362		433	$	7,280		—	$	—		$	12		$	7,654
Net income	—	9			—	105			—	—			—			114
Distributions	—	(9		)	—	(139		)	—	—			(1		)	(149		)
Equity-based compensation, net of units for employee taxes	—	—			—	—			—	—			—			—
Balance as of March 31, 2018	15	$	362		433	$	7,246		—	$	—		$	11		$	7,619

See Notes to the Unaudited Condensed Consolidated Financial Statements

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ENABLE MIDSTREAM PARTNERS, LP

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(1) Summary of Significant Accounting Policies

Organization

Enable Midstream Partners, LP is a Delaware limited partnership formed on May 1, 2013 by CenterPoint Energy, OGE Energy and ArcLight. The Partnership’s assets and operations are organized into two reportable segments: (i) gathering and processing and (ii) transportation and storage. The gathering and processing segment primarily provides natural gas and crude oil gathering and natural gas processing services to our producer customers. The transportation and storage segment provides interstate and intrastate natural gas pipeline transportation and storage services primarily to our producer, power plant, LDC and industrial end-user customers. The Partnership’s natural gas gathering and processing assets are primarily located in Oklahoma, Texas, Arkansas and Louisiana and serve natural gas production in the Anadarko, Arkoma and Ark-La-Tex Basins. Crude oil gathering assets are located in North Dakota and serve crude oil production in the Bakken Shale formation of the Williston Basin. The Partnership’s natural gas transportation and storage assets consist primarily of an interstate pipeline system extending from western Oklahoma and the Texas Panhandle to Louisiana, an interstate pipeline system extending from Louisiana to Illinois, an intrastate pipeline system in Oklahoma, and our investment in SESH, an interstate pipeline extending from Louisiana to Alabama.

CenterPoint Energy and OGE Energy each have 50% of the management interests in Enable GP. Enable GP is the general partner of the Partnership and has no other operating activities. Enable GP is governed by a board made up of two representatives designated by each of CenterPoint Energy and OGE Energy, along with the Partnership’s Chief Executive Officer and three independent board members CenterPoint Energy and OGE Energy mutually agreed to appoint. CenterPoint Energy and OGE Energy also own a 40% and 60% interest, respectively, in the incentive distribution rights held by Enable GP.

As of March 31, 2018, CenterPoint Energy held approximately 54.0% or 233,856,623 of the Partnership’s common units, and OGE Energy held approximately 25.6% or 110,982,805 of the Partnership’s common units. Additionally, CenterPoint Energy holds 14,520,000 Series A Preferred Units. See Note 6 for further information related to the Series A Preferred Units. The limited partner interests of the Partnership have limited voting rights on matters affecting the business. As such, limited partners do not have rights to elect the Partnership’s general partner on an annual or continuing basis and may not remove Enable GP, its current general partner, without at least a 75% vote by all unitholders, including all units held by the Partnership’s limited partners, and Enable GP and its affiliates, voting together as a single class.

As of March 31, 2018, the Partnership owned a 50% interest in SESH. See Note 7 for further discussion of SESH.

Basis of Presentation

The accompanying condensed consolidated financial statements and related notes of the Partnership have been prepared pursuant to the rules and regulations of the SEC and GAAP. Pursuant to such rules and regulations, certain disclosures normally included in financial statements prepared in accordance with GAAP have been omitted. The accompanying condensed consolidated financial statements and related notes should be read in conjunction with the consolidated financial statements and related notes included in our Annual Report.

The condensed consolidated financial statements and the related notes reflect all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position and results of operations for the respective periods. Amounts reported in the Partnership’s Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for a full-year period due to the effects of, among other things, (a) seasonal fluctuations in demand for energy and energy services, (b) changes in energy commodity prices, (c) timing of maintenance and other expenditures and (d) acquisitions and dispositions of businesses, assets and other interests.

For a description of the Partnership’s reportable segments, see Note 15.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

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Restricted Cash

Restricted cash primarily consists of cash collateral which is provided as credit assurance by third parties. The Condensed Consolidated Balance Sheets have $14 million of restricted cash at each of March 31, 2018 and December 31, 2017.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable are recorded at the invoiced amount and do not typically bear interest. The determination of the allowance for doubtful accounts requires management to make estimates and judgments regarding our customers’ ability to pay. The allowance for doubtful accounts is determined based upon specific identification and estimates of future uncollectable amounts. On an ongoing basis, management evaluates our customers’ financial strength based on aging of accounts receivable, payment history, and review of other relevant information, including ratings agency credit ratings and alerts, publicly available reports and news releases, and bank and trade references. It is the policy of management to review the outstanding accounts receivable at least quarterly, giving consideration to historical bad debt write-offs, the aging of receivables and specific customer circumstances that may impact their ability to pay the amounts due. Based on this review, management determined that a $2 million allowance for doubtful accounts was required at March 31, 2018 and a $3 million allowance at December 31, 2017.

Inventory

Natural gas inventory is held, through the transportation and storage segment, to provide operational support for the intrastate pipeline deliveries and to manage leased intrastate storage capacity. Natural gas liquids inventory is held, through the gathering and processing segment, due to timing differences between the production of certain natural gas liquids and ultimate sale to third parties. Natural gas and natural gas liquids inventory is valued using moving average cost and is subsequently recorded at the lower of cost or net realizable value. The Partnership recorded a $3 million and zero lower of cost or net realizable value adjustment in the three months ended March 31, 2018 and 2017, respectively.

Income Taxes

The Partnership’s earnings are not subject to income tax (other than Texas state margin taxes and taxes associated with the Partnership’s corporate subsidiary, Enable Midstream Services) and are taxable at the individual partner level. We account for deferred income taxes related to the federal and state jurisdictions using the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future taxes attributable to the difference between financial statement carrying amounts of assets and liabilities and their respective tax basis. Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of tax net operating loss carryforwards. In the event future utilization is determined to be unlikely, a valuation allowance is provided to reduce the tax benefits from such assets. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the period in which the temporary differences and carryforwards are expected to be recovered or settled. The effect of a change in tax rates is recognized in the period which includes the enactment date. The Partnership recognizes interest and penalties as a component of income tax expense.

(2) New Accounting Pronouncements

Accounting Standards to be Adopted in Future Periods

Leases

In February 2016, the FASB issued ASU 2016-02, “Leases (ASC 842).” This standard requires, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements.

In January 2018, the FASB issued ASU 2018-01, “Land Easement Practical Expedient for Transition to Topic 842.” This standard permits an entity to elect an optional transition practical expedient to not evaluate land easements that exist or expire before the Partnership's adoption of ASC 842 and that were not previously accounted for as leases under ASC 840. The Partnership intends to elect this transition provision.

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The Partnership continues to review contracts and easements relative to the provisions of the ASU 2016-02 lease standard and the ASU 2018-01 easement standard as well as to monitor relevant emerging industry guidance regarding the implementation of the standards. The Partnership expects to adopt these standards in the first quarter of 2019 and is currently evaluating the overall impact of the standards on our Condensed Consolidated Financial Statements and related disclosures.

Financial Instruments—Credit Losses

In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” This standard requires entities to measure all expected credit losses of financial assets held at a reporting date based on historical experience, current conditions, and reasonable and supportable forecasts in order to record credit losses in a more timely matter. ASU 2016-13 also amends the accounting for credit losses on available-for-sale debt securities and purchased financial assets with credit deterioration. The standard is effective for interim and annual reporting periods beginning after December 15, 2019, although early adoption is permitted for interim and annual periods beginning after December 15, 2018. The Partnership does not expect the adoption of this standard to have a material impact on our Condensed Consolidated Financial Statements and related disclosures.

(3) Revenue

The Partnership adopted ASU No. 2014-09, “Revenue from Contracts with Customers” (ASC 606) on January 1, 2018 using the modified retrospective method. Upon adoption, the Partnership did not recognize a material cumulative adjustment to Partners’ Equity and there were no material changes in the timing of revenue recognition or our accounting policies. The Partnership has applied the standard to only contracts that were not expired as of January 1, 2018.

The following table disaggregates total revenues by major source from contracts with customers and the change in fair value of derivatives.



	Three Months Ended March 31, 2018
	Gathering and Processing			Transportation and Storage		Eliminations			Total
	(In millions)
Revenues:
Product sales:
Natural gas	$	106		$	131	$	(109	)	$	128
Natural gas liquids	279			7		(7		)	279
Condensate	36			—		—			36
Total revenues from natural gas, natural gas liquids, and condensate	421			138		(116		)	443
Gain (loss) on derivative activity	(3		)	2		1			—
Total Product sales	$	418		$	140	$	(115	)	$	443
Service revenues:
Demand revenues	$	50		$	120	$	—		$	170
Volume-dependent revenues	123			19		(7		)	135
Total Service revenues	$	173		$	139	$	(7	)	$	305
Total Revenues	$	591		$	279	$	(122	)	$	748

Product Sales

Natural Gas, NGLs or Condensate

We deliver natural gas, NGLs and condensate to purchasers at contractually agreed-upon delivery points at which the purchaser takes custody, title, and risk of loss of the commodity. We recognize revenue when control transfers to the purchaser at the delivery point based on the contractually agreed upon fixed or index based price received.

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Gain (loss) on Derivative Activity

Included in Product sales are gains and losses on natural gas, natural gas liquids, and crude oil (for condensate) derivatives that are accounted for under guidance in ASC 815. See Note 9 for further discussion of our derivative and hedging activity.

Service Revenues

Demand revenues

Our demand revenue arrangements are generally structured in one of the following ways:


•	Under a firm fee arrangement, a customer agrees to pay a fixed fee for a contractually agreed upon pipeline or storage capacity. Once the services have been completed, or the customer no longer has access to the contracted capacity, revenue is recognized.

•

Under a minimum volume commitment fee arrangement, a customer agrees to either deliver a contractually agreed upon minimum volume of natural gas or crude oil to our system for service at a contractually agreed upon gathering fee or to pay the contractually agreed upon gathering, compressing and treating fees for the minimum volume of natural gas or crude oil irrespective of whether or not the minimum volume of natural gas or crude oil is delivered. Certain of our contracts provide our customers the option to elect to pay a higher gathering fee over the remaining term of the contract in lieu of making a contractually agreed upon shortfall payment. Once the services have been completed, or the customer no longer has the ability to utilize the services, revenue is recognized.

Volume-dependent revenues

Our volume-dependent revenues primarily consist of gathering, compressing, treating, processing, transportation or storage services fees on contracts that exceed their contractually committed volume or do not have firm fee arrangements or minimum volume commitments. These fees are dependent on throughput by third party customers, and revenue is recognized over time as the service is performed. Our other fee revenue arrangements have pricing terms that are generally structured in one of the following ways: (1) Contractually agreed upon monetary fee for service or (2) contractually agreed upon consideration received in the form of natural gas or natural gas liquids, which are valued at the current month index based price, which approximates fair value.

Accounts Receivable

Payments for all types of revenues are typically received within 30 days of invoice. Invoices for all revenue types are sent on at least a monthly basis, except for the shortfall provisions under certain minimum volume commitment contracts, which are typically invoiced annually. Accounts receivable includes accrued revenues associated with certain minimum volume commitments that will be invoiced at the conclusion of the measurement period specified under the respective contracts.



	March 31, 2018		December 31, 2017
	(In millions)
Accounts Receivable:
Customers	$	233	$	265
Accrued minimum volume commitments (contract assets)	34		27
Non-customers	5		3
Total Accounts Receivable ⁽¹⁾	$	272	$	295

____________________

(1)Total Accounts Receivable includes Accounts receivables, net of allowance for doubtful accounts and Accounts receivable—affiliated companies.

Contract Liabilities

Our contract liabilities primarily consist of the following prepayments received from customers:


•	Under certain firm fee arrangements, customers pay their demand fee prior to the month of contracted capacity. These fees are applied to the subsequent month’s activity and are included in other liabilities on the Condensed Consolidated Balance Sheets.

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•	Under certain demand and volume dependent arrangements, customers make contributions of aid in construction payments. For payments that are related to contracts under ASC 606, the payment is deferred and amortized over the life of the associated contract and the unamortized balance is included in other current or long-term liabilities on the Condensed Consolidated Balance Sheets.

The table below summarizes the change in the contract liabilities for the three months ended March 31, 2018:



	March 31, 2018		December 31, 2017		Amounts recognized in revenues
	(In millions)
Deferred revenues	$	41	$	34	$	15

The table below summarizes the timing of recognition of these contract liabilities as of March 31, 2018:



	2018		2019		2020		2021		2022 and After
	(In millions)
Deferred revenues	$	19	$	4	$	4	$	4	$	10

Remaining Performance Obligations

Our remaining performance obligations consist primarily of firm fee and minimum volume commitment fee arrangements. Upon completion of the performance obligations associated with these arrangements, customers are invoiced and revenue is recognized as Service revenues in the Condensed Consolidated Statements of Income.

The table below summarizes the timing of recognition of the remaining performance obligations as of March 31, 2018:



	2018		2019		2020		2021		2022 and After
Transportation and Storage	$	325	$	329	$	244	$	123	$	608
Gathering and Processing	175		221		118		94		328
Total remaining performance obligations	$	500	$	550	$	362	$	217	$	936

Impact of Adoption

Upon adoption of ASC 606, the recognition of revenues for certain contractual arrangements was impacted as follows:

•

Natural gas and natural gas liquids purchase arrangements - For certain arrangements within our gathering and processing segment, the Partnership purchases and controls the entire hydrocarbon stream at the point of receipt. As of January 1, 2018, these arrangements are considered supplier contracts rather than contracts with customers. Therefore, beginning January 1, 2018, the gathering and processing fees for these arrangements that were previously recognized as Service revenues under ASC 605 are recognized as reductions to Cost of natural gas and natural gas liquids.

•

Percent-of-proceeds and percent-of-liquids processing arrangements - Under percent-of-proceeds and percent-of-liquids arrangements within our gathering and processing segment, the Partnership has previously recognized the value of natural gas and natural gas liquids received in our purchase cost within Cost of natural gas and natural gas liquids. As of January 1, 2018, the Partnership recognizes the value of the natural gas and NGLs received as Service revenues and as an increase to Cost of natural gas and natural gas liquids when the natural gas or NGLs are sold and Product sales are recognized.

•

Keep-whole arrangements - Under keep-whole arrangements within our gathering and processing segment, the Partnership has previously recognized the value of NGLs received in Product sales and the value of the thermally equivalent quantity of natural gas provided in our purchase cost within Cost of natural gas and natural gas liquids. As of January 1, 2018, the Partnership recognizes the value of the NGLs received less the value of the thermal equivalent volume of natural gas provided as Service revenues and as an increase to Cost of natural gas and natural gas liquids when the NGLs are sold and Product sales are recognized.


•	Fixed fuel arrangements - Under certain gathering arrangements within our gathering and processing segment as well as under certain transportation arrangements within our transportation and storage segment we receive a fixed amount of fuel regardless of actual fuel usage. Previously, revenue for fuel in excess of actual usage was recognized

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when such fuel was received, and additional revenue was recognized when such fuel was sold. As of January 1, 2018, fuel in excess of actual usage is treated as a byproduct obtained through the fulfillment of a contract, and the Partnership will recognize revenue at the time the excess fuel is sold. This results in a reduction of Product sales and a corresponding reduction in Cost of natural gas and natural gas liquids.

•

Natural gas and natural gas liquids sales arrangements - For certain arrangements within our gathering and processing segment, the Partnership sells the entire hydrocarbon stream at the point of delivery to a third-party processing facility. As of January 1, 2018, these arrangements are considered sales once control has transferred to the third-party processing facility. Therefore, beginning January 1, 2018, the transportation and fractionation fees for these arrangements that were previously recognized as a component of cost of gas and natural gas liquids, are recognized as reductions to the transaction price under ASC 606.

Below is a summary of the impact of the changes on revenues as it relates to the three months ended March 31, 2018:



	Three Months Ended March 31, 2018
	Under ASC 606		Under ASC 605		Increase/(Decrease)
	(In millions)
Revenues:
Product sales:
Natural gas	$	128	$	139	$	(11	)
Natural gas liquids	279		283		(4		)
Condensate	36		36		—
Total revenues from natural gas, natural gas liquids, and condensate	443		458		(15		)
Gain (loss) on derivative activity	—		—		—
Total Product sales	$	443	$	458	$	(15	)
Service revenues:
Demand revenues	$	170	$	170	—
Volume-dependent revenues	135		134		1
Total Service revenues	$	305	$	304	$	1
Total Revenues	$	748	$	762	$	(14	)

As described above, each of the identified increases/(decreases) in revenue resulted in a corresponding change in the Cost of natural gas and natural gas liquids.

(4) Acquisition

Align Acquisition

On October 4, 2017, the Partnership acquired all of the equity interests in Align Midstream, LLC, a midstream service provider with natural gas gathering and processing facilities in the Cotton Valley and Haynesville plays of the Ark-La-Tex Basin, for approximately $298 million in cash. The acquisition includes approximately 190 miles of natural gas gathering pipelines across Rusk, Panola and Shelby counties in Texas and DeSoto Parish in Louisiana and a cryogenic natural gas processing plant in Panola County, Texas, with a capacity of 100 MMcf/d. The acquisition was accounted for as a business combination and funded with borrowings under the Revolving Credit Facility. During the fourth quarter of 2017, the Partnership finalized the purchase price allocation as of October 4, 2017.

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The following table presents the fair value of the identified assets acquired and liabilities assumed at the acquisition date:



Purchase price allocation (in millions):
Assets acquired:
Accounts receivable	$	5
Property, plant and equipment	111
Intangibles	176
Goodwill	12
Liabilities assumed:
Current liabilities	6
Total identifiable net assets	$	298

In connection with the acquisition, the Partnership recognized intangible assets related to customer relationships. The acquired intangible assets will be amortized on a straight-line basis over the estimated customer contract life of approximately 10 years. Goodwill recognized from the acquisition primarily relates to greater operating leverage in the Ark-La-Tex Basin and is allocated to the gathering and processing segment. The Partnership incurred approximately $2 million of acquisition costs associated with this transaction, which were included in General and administrative expense in the Consolidated Statements of Income in the fourth quarter of 2017. The Partnership determined not to include pro forma consolidated financial statements for the periods presented as the impact would not be material.

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(5) 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 March 31,
	2018		2017
	(In millions, except per unit data)
Net income	$	114	$	120
Net income attributable to noncontrolling interest	—		—
Series A Preferred Unit distributions	9		9
General partner interest in net income	—		—
Net income available to common and subordinated unitholders	$	105	$	111

Net income allocable to common units	$	105	$	58
Net income allocable to subordinated units	—		53
Net income available to common and subordinated unitholders	$	105	$	111

Net income allocable to common units	$	105	$	58
Dilutive effect of Series A Preferred Unit distributions	—		—
Diluted net income allocable to common units	105		58
Diluted net income allocable to subordinated units	—		53
Total	$	105	$	111

Basic weighted average number of outstanding
Common units ⁽¹⁾	434		225
Subordinated units	—		208
Total	434		433

Basic earnings per unit
Common units	$	0.24	$	0.26
Subordinated units	$	—	$	0.25

Basic weighted average number of outstanding common units	434		225
Dilutive effect of Series A Preferred Units	—		—
Dilutive effect of performance units	1		1
Diluted weighted average number of outstanding common units	435		226
Diluted weighted average number of outstanding subordinated units	—		208
Total	435		434

Diluted earnings per unit
Common units	$	0.24	$	0.26
Subordinated units	$	—	$	0.25

____________________


(1)	Basic weighted average number of outstanding common units for each of the three months ended March 31, 2018 and 2017 includes approximately one million time-based phantom units.

See Note 6 for discussion of the expiration of the subordination period.

The dilutive effect of the unit-based awards discussed in Note 14 was less than $0.01 per unit during each of the three months ended March 31, 2018 and 2017.

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(6) Partners’ Equity

The Partnership Agreement requires that, within 60 days after the end of each quarter, the Partnership distribute all of its available cash (as defined in the Partnership Agreement) to unitholders of record on the applicable record date.

The Partnership paid or has authorized payment of the following cash distributions to common and subordinated unitholders, as applicable, during 2017 and 2018 (in millions, except for per unit amounts):



Three Months Ended	Record Date	Payment Date	Per Unit Distribution		Total Cash Distribution
March 31, 2018⁽¹⁾	May 22, 2018	May 29, 2018	$	0.318	$	138
December 31, 2017	February 20, 2018	February 27, 2018	$	0.318	$	138
September 30, 2017	November 14, 2017	November 21, 2017	$	0.318	$	138
June 30, 2017	August 22, 2017	August 29, 2017	$	0.318	$	138
March 31, 2017	May 23, 2017	May 30, 2017	$	0.318	$	137
December 31, 2016	February 21, 2017	February 28, 2017	$	0.318	$	137

_____________________


(1)	The board of directors of Enable GP declared this 0.318 per common unit cash distribution on May 1, 2018, to be paid on May 29, 2018, to common unitholders of record at the close of business on May 22, 2018.

The Partnership paid or has authorized payment of the following cash distributions to holders of the Series A Preferred Units during 2017 and 2018 (in millions, except for per unit amounts):



Three Months Ended	Record Date	Payment Date	Per Unit Distribution		Total Cash Distribution
March 31, 2018⁽¹⁾	May 1, 2018	May 15, 2018	$	0.625	$	9
December 31, 2017	February 9, 2018	February 15, 2018	$	0.625	$	9
September 30, 2017	October 31, 2017	November 14, 2017	$	0.625	$	9
June 30, 2017	July 31, 2017	August 14, 2017	$	0.625	$	9
March 31, 2017	May 2, 2017	May 12, 2017	$	0.625	$	9
December 31, 2016	February 10, 2017	February 15, 2017	$	0.625	$	9

_____________________


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

General Partner Interest and Incentive Distribution Rights

Enable GP owns a non-economic general partner interest in the Partnership and thus will not be entitled to distributions that the Partnership makes prior to the liquidation of the Partnership in respect of such general partner interest. Enable GP currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50.0%, of the cash the Partnership distributes from operating surplus (as defined in the Partnership Agreement) in excess of $0.330625 per unit per quarter. The maximum distribution of 50.0% does not include any distributions that Enable GP or its affiliates may receive on common units that they own.

Expiration of Subordination Period

The financial tests required for conversion of all subordinated units were met and the 207,855,430 outstanding subordinated units were converted into common units on a one-for-one basis on August 30, 2017. The conversion of the subordinated units did not change the aggregate amount of outstanding units, and the conversion of the subordinated units did not impact the amount of cash available for distribution by the Partnership.

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Series A Preferred Units

On February 18, 2016, the Partnership completed a private placement of 14,520,000 Series A Preferred Units representing limited partner interests in the Partnership for a cash purchase price of $25.00 per Series A Preferred Unit, resulting in proceeds of $362 million, net of issuance costs. The Partnership incurred approximately $1 million of expenses related to the offering, which is shown as an offset to the proceeds. In connection with the closing of the private placement, the Partnership redeemed approximately $363 million of notes scheduled to mature in 2017 payable to a wholly-owned subsidiary of CenterPoint Energy.

Pursuant to the Partnership Agreement, the Series A Preferred Units:


•	rank senior to the Partnership’s common units with respect to the payment of distributions and distribution of assets upon liquidation, dissolution and winding up;


•	have no stated maturity;


•	are not subject to any sinking fund; and


•	will remain outstanding indefinitely unless repurchased or redeemed by the Partnership or converted into its common units in connection with a change of control.

If and when declared by our general partner, holders of the Series A Preferred Units receive a quarterly cash distribution on a non-cumulative basis equal to subject to certain adjustments, an annual rate of: 10% on the stated liquidation preference of $25.00 from the date of original issue to, but not including, the five year anniversary of the original issue date; and thereafter a percentage of the stated liquidation preference equal to the sum of the three-month LIBOR plus 8.5%.

At any time on or after five years after the original issue date, the Partnership may redeem the Series A Preferred Units, in whole or in part, from any source of funds legally available for such purpose, by paying $25.50 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. In addition, the Partnership (or a third-party with its prior written consent) may redeem the Series A Preferred Units following certain changes in the methodology employed by ratings agencies, changes of control or fundamental transactions as set forth in the Partnership Agreement. If, upon a change of control or certain fundamental transactions, the Partnership (or a third-party with its prior written consent) does not exercise this option, then the holders of the Series A Preferred Units have the option to convert the Series A Preferred Units into a number of common units per Series A Preferred Unit as set forth in the Partnership Agreement. The Series A Preferred Units are also required to be redeemed in certain circumstances if they are not eligible for trading on the New York Stock Exchange.

Holders of Series A Preferred Units have no voting rights except for limited voting rights with respect to potential amendments to the Partnership Agreement that have a material adverse effect on the existing terms of the Series A Preferred Units, the issuance by the Partnership of certain securities, approval of certain fundamental transactions and as required by law.

Upon the transfer of any Series A Preferred Unit to a non-affiliate of CenterPoint Energy, the Series A Preferred Units will automatically convert into a new series of preferred units (the Series B Preferred Units) on the later of the date of transfer and the second anniversary of the date of issue. The Series B Preferred Units will have the same terms as the Series A Preferred Units except that unpaid distributions on the Series B Preferred Units will accrue on a cumulative basis until paid.

On February 18, 2016, the Partnership entered into a registration rights agreement with CenterPoint Energy, pursuant to which, among other things, the Partnership gave CenterPoint Energy certain rights to require the Partnership to file and maintain a registration statement with respect to the resale of the Series A Preferred Units and any other series of preferred units or common units representing limited partner interests in the Partnership that are issuable upon conversion of the Series A Preferred Units.

ATM Program

On May 12, 2017, the Partnership entered into an ATM Equity Offering Sales Agreement, pursuant to which the Partnership may issue and sell common units having an aggregate offering price of up to $200 million, by sales methods and at prices determined by market conditions and other factors at the time of our offerings. The Partnership has no obligation to sell any common units under the ATM Program and the Partnership may suspend sales under the ATM Program at any time. During the three months ended March 31, 2018, the Partnership did not issue any common units under the ATM Program.

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(7) Investment in Equity Method Affiliate

The Partnership uses the equity method of accounting for investments in entities in which it has an ownership interest between 20% and 50% and exercises significant influence.

SESH is owned 50% by Spectra Energy Partners, LP and 50% by the Partnership. Pursuant to the terms of the SESH LLC Agreement, if, at any time, CenterPoint Energy has a right to receive less than 50% of our distributions through its interest in the Partnership and its economic interest in Enable GP, or does not have the ability to exercise certain control rights, Spectra Energy Partners, LP may, under certain circumstances, have the right to purchase the Partnership’s interest in SESH at fair market value, subject to certain exceptions.

The Partnership shares operations of SESH with Spectra Energy Partners, LP under service agreements. The Partnership is responsible for the field operations of SESH. SESH reimburses each party for actual costs incurred, which are billed based upon a combination of direct charges and allocations. The Partnership billed SESH $2 million and $5 million during the three months ended March 31, 2018 and 2017, respectively, associated with these service agreements.

The Partnership includes equity in earnings of equity method affiliate under the Other Income (Expense) caption in the Condensed Consolidated Statements of Income for the three months ended March 31, 2018 and 2017.

Equity in Earnings of Equity Method Affiliate:



	Three Months Ended March 31,
	2018		2017
	(In millions)
SESH	$	6	$	7

Distributions from Equity Method Affiliate:



	Three Months Ended March 31,
	2018		2017
	(In millions)
SESH ⁽¹⁾	$	13	$	11

___________________


(1)	Distributions from equity method affiliate includes a $6 million and $7 million return on investment and a $7 million and $4 million return of investment for the three months ended March 31, 2018 and 2017, respectively.

Summarized financial information of SESH:



	Three Months Ended March 31,
	2018		2017
	(In millions)
Income Statements:
Revenues	$	28	$	28
Operating income	$	17	$	17
Net income	$	12	$	13

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(8) Debt

The following table presents the Partnership’s outstanding debt as of March 31, 2018 and December 31, 2017.



	March 31, 2018							December 31, 2017
	Outstanding Principal		Premium (Discount)			Total Debt		Outstanding Principal		Premium (Discount)			Total Debt
	(In millions)
Commercial Paper	$	596	$	(1	)	$	595	$	405	$	—		$	405
Revolving Credit Facility	—		—			—		—		—			—
2015 Term Loan Agreement	450		—			450		450		—			450
2019 Notes	500		—			500		500		—			500
2024 Notes	600		—			600		600		—			600
2027 Notes	700		(3		)	697		700		(3		)	697
2044 Notes	550		—			550		550		—			550
EOIT Senior Notes	250		11			261		250		13			263
Total debt	$	3,646	$	7		$	3,653	$	3,455	$	10		$	3,465
Less: Current portion of long-term debt						450							450
Less: Short-term debt ⁽¹⁾						595							405
Less: Unamortized debt expense⁽²⁾						14							15
Total long-term debt						$	2,594						$	2,595

____________________


(1)	Short-term debt includes $596 million and $405 million of outstanding commercial paper as of March 31, 2018 and December 31, 2017, respectively.


(2)	As of March 31, 2018 and December 31, 2017, there was an additional $3 million of unamortized debt expense related to the Revolving Credit Facility included in Other long-term assets, not included above.

Revolving Credit Facility

On June 18, 2015, the Partnership entered into the $1.75 billion Revolving Credit Facility, which was scheduled to mature on June 18, 2020, subject to an extension option, which could be exercised two times to extend the term of the Revolving Credit Facility, in each case, for an additional one-year term. As of March 31, 2018, there were no principal advances and $3 million in letters of credit outstanding under the Revolving Credit Facility.

The Revolving Credit Facility provided 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 was based on the Partnership’s applicable credit ratings. As of March 31, 2018, the applicable margin for LIBOR-based borrowings under the Revolving Credit Facility was 1.50% based on the Partnership’s credit ratings. In addition, the Revolving Credit Facility required the Partnership to pay a fee on unused commitments. The commitment fee was based on the Partnership’s applicable credit rating from the rating agencies. As of March 31, 2018, 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.

On April 6, 2018, the Partnership amended and restated the Revolving Credit Facility. See Note 16 for a discussion of the Second Amended and Restated Revolving Credit Agreement.

Commercial Paper

The Partnership has a commercial paper program, pursuant to which the Partnership is authorized to issue up to $1.4 billion of commercial paper. The commercial paper program is supported by our Revolving Credit Facility, and outstanding commercial paper effectively reduces our borrowing capacity thereunder. There were $596 million and $405 million outstanding under our commercial paper program at March 31, 2018 and December 31, 2017, respectively. The weighted average interest rate for the outstanding commercial paper was 2.72% as of March 31, 2018.

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Term Loan Agreement

On July 31, 2015, the Partnership entered into a Term Loan Agreement, providing for an unsecured three-year $450 million term loan agreement, which is scheduled to mature on July 31, 2018. 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 March 31, 2018, there was $450 million outstanding under the 2015 Term Loan Agreement, which is included as Current portion of long-term debt in the Partnership’s Condensed Consolidated Balance Sheets.

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 March 31, 2018, the applicable margin for LIBOR-based borrowings under the 2015 Term Loan Agreement was 1.375% based on the Partnership’s credit ratings. For the three months ended March 31, 2018, the weighted average interest rate of the 2015 Term Loan Agreement was 2.98%.

Senior Notes

On March 9, 2017, the Partnership completed the public offering of $700 million aggregate principal amount of the Partnership’s 4.400% Senior Notes due 2027. The Partnership received net proceeds of approximately $691 million. The proceeds were used for general partnership purposes, including to repay amounts outstanding under the Revolving Credit Facility. The 2027 Notes had an unamortized discount of $3 million and unamortized debt expense of $5 million at March 31, 2018, resulting in an effective interest rate of 4.58% during the three months ended March 31, 2018.

In addition to the 2027 Notes, as of March 31, 2018, the Partnership’s debt included the 2019 Notes, 2024 Notes and 2044 Notes, which had $9 million of unamortized debt expense at March 31, 2018, resulting in effective interest rates of 2.57%, 4.02% and 5.08%, respectively, during the three months ended March 31, 2018.

As of March 31, 2018, the Partnership’s debt included $250 million aggregate principal amount of EOIT’s 6.25% senior notes due 2020. The EOIT Senior Notes had $11 million of unamortized premium at March 31, 2018, resulting in an effective interest rate of 3.80% during the three months ended March 31, 2018.

As of March 31, 2018, the Partnership and EOIT were in compliance with all of their debt agreements, including financial covenants.

(9) Derivative Instruments and Hedging Activities

The Partnership is exposed to certain risks relating to its ongoing business operations. The primary risk managed using derivative instruments is commodity price risk. The Partnership is also exposed to credit risk in its business operations.

Commodity Price Risk

The Partnership has used forward physical contracts, commodity price swap contracts and commodity price option features to manage the Partnership’s commodity price risk exposures in the past. Commodity derivative instruments used by the Partnership are as follows:


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


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


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

Normal purchases and normal sales contracts are not recorded in Other Assets or Liabilities in the Condensed Consolidated Balance Sheets and earnings are recognized and recorded in the period in which physical delivery of the commodity occurs. Management applies normal purchases and normal sales treatment to: (i) commodity contracts for the purchase and sale

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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 March 31, 2018 and December 31, 2017, the Partnership had no derivative instruments that were designated as cash flow or fair value hedges for accounting purposes.

Credit Risk

The Partnership is exposed to certain credit risks relating to its ongoing business operations. Credit risk includes the risk that counterparties that owe the Partnership money or energy will breach their obligations. If the counterparties to these arrangements fail to perform, the Partnership may seek or be forced to enter into alternative arrangements. In that event, the Partnership’s financial results could be adversely affected, and the Partnership could incur losses.

Derivatives Not Designated As Hedging Instruments

Derivative instruments not designated as hedging instruments for accounting purposes are utilized in the Partnership’s asset management activities. For derivative instruments not designated as hedging instruments, the gain or loss on the derivative is recognized currently in earnings.

Quantitative Disclosures Related to Derivative Instruments

The majority of natural gas physical purchases and sales not designated as hedges for accounting purposes are priced based on a monthly or daily index, and the fair value is subject to little or no market price risk. Natural gas physical sales volumes exceed natural gas physical purchase volumes due to the marketing of natural gas volumes purchased via the Partnership’s processing contracts, which are not derivative instruments.

As of March 31, 2018 and December 31, 2017, the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes:



	March 31, 2018		December 31, 2017
	Gross Notional Volume
	Purchases	Sales	Purchases	Sales
Natural gas—TBtu⁽¹⁾
Financial fixed futures/swaps	19	22	17	13
Financial basis futures/swaps	27	31	17	17
Physical purchases/sales	—	81	1	37
Crude oil (for condensate)—MBbl⁽²⁾
Financial Futures/swaps	—	874	—	564
Natural gas liquids—MBbl⁽³⁾
Financial Futures/swaps	—	2,195	—	1,615

____________________

(1)

As of March 31, 2018, 82.4% of the natural gas contracts had durations of one year or less, 10.7% had durations of more than one year and less than two years and 6.9% had durations of more than two years. As of December 31, 2017, 67.7% of the natural gas contracts had durations of one year or less, 16.1% had durations of more than one year and less than two years and 16.2% had durations of more than two years.


(2)	As of March 31, 2018, 69.1% of the crude oil (for condensate) contracts had durations of one year or less and 30.9% had durations of more than one year and less than two years. As of December 31, 2017, 100% of the crude oil (for condensate) contracts had durations of one year or less.


(3)	As of March 31, 2018, 72.0% of the natural gas liquids contracts had durations of one year or less and 28.0% had durations of more than one year and less than two years. As of December 31, 2017, 100% of the natural gas liquid contracts had durations of one year or less.

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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 March 31, 2018 and December 31, 2017 that were not designated as hedging instruments for accounting purposes are as follows:



		March 31, 2018				December 31, 2017
		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
		(In millions)
Natural gas
Financial futures/swaps	Other Current/Other	$	3	$	9	$	5	$	4
Physical purchases/sales	Other Current/Other	6		1		3		—
Crude oil (for condensate)
Financial futures/swaps	Other Current/Other	—		5		—		4
Natural gas liquids
Financial Futures/swaps	Other Current/Other	2		2		1		5
Total gross derivatives ⁽¹⁾		$	11	$	17	$	9	$	13

_____________________


(1)	See Note 10 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Condensed Consolidated Balance Sheets as of March 31, 2018 and December 31, 2017.

Income Statement Presentation Related to Derivative Instruments

The following table presents the effect of derivative instruments on the Partnership’s Condensed Consolidated Statements of Income for the three months ended March 31, 2018 and 2017:



	Amounts Recognized in Income
	Three Months Ended March 31,
	2018			2017
	(In millions)
Natural gas
Financial futures/swaps (losses) gains	$	(3	)	$	11
Physical purchases/sales gains	2			5
Crude oil (for condensate)
Financial futures/swaps (losses) gains	(3		)	3
Natural gas liquids
Financial futures/swaps gains	4			2
Total	$	—		$	21

For derivatives not designated as hedges in the tables above, amounts recognized in income for the periods ended March 31, 2018 and 2017, if any, are reported in Product sales.

The following table presents the components of gain (loss) on derivative activity in the Partnership’s Condensed Consolidated Statements of Income for the three months ended March 31, 2018 and 2017:



	Three Months Ended March 31,
	2018			2017
	(In millions)
Change in fair value of derivatives	$	(2	)	$	24
Realized gain (loss) on derivatives	2			(3		)
Gain on derivative activity	$	—		$	21

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Credit-Risk Related Contingent Features in Derivative Instruments

In the event Moody’s Investors Services or Standard & Poor’s Ratings Services were to lower the Partnership’s senior unsecured debt rating to a below investment grade rating, at March 31, 2018, the Partnership would have been required to post $7 million of cash collateral to satisfy its obligation under its financial and physical contracts relating to derivative instruments that are in a net liability position at March 31, 2018. In addition, the Partnership could be required to provide additional credit assurances in future dealings with third parties, which could include letters of credit or cash collateral.

(10) Fair Value Measurements

Certain assets and liabilities are recorded at fair value in the Condensed Consolidated Balance Sheets and are categorized based upon the level of judgment associated with the inputs used to measure their value. Hierarchical levels, as defined below and directly related to the amount of subjectivity associated with the inputs to fair valuations of these assets and liabilities are as follows:

Level 1: Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. Instruments classified as Level 1 include natural gas futures, swaps and options transactions for contracts traded on the NYMEX and settled through a NYMEX clearing broker.

Level 2: Inputs, other than quoted prices included in Level 1, are observable for the asset or liability, either directly or indirectly. Level 2 inputs include quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities that are generally included in this category are derivatives with fair values based on inputs from actively quoted markets. Instruments classified as Level 2 include over-the-counter NYMEX natural gas swaps, natural gas basis swaps and natural gas purchase and sales transactions in markets such that the pricing is closely related to the NYMEX pricing, and over-the-counter WTI crude oil swaps for condensate sales.

Level 3: Inputs are unobservable for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. Unobservable inputs reflect the Partnership’s judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. The Partnership develops these inputs based on the best information available, including the Partnership’s own data.

The Partnership utilizes the market approach in determining the fair value of its derivative positions by using either NYMEX or WTI published market prices, independent broker pricing data or broker/dealer valuations. The valuations of derivatives with pricing based on NYMEX published market prices may be considered Level 1 if they are settled through a NYMEX clearing broker account with daily margining. Over-the-counter derivatives with NYMEX or WTI based prices are considered Level 2 due to the impact of counterparty credit risk. Valuations based on independent broker pricing or broker/dealer valuations may be classified as Level 2 only to the extent they may be validated by an additional source of independent market data for an identical or closely related active market. In certain less liquid markets or for longer-term contracts, forward prices are not as readily available. In these circumstances, contracts are valued using internally developed methodologies that consider historical relationships among various quoted prices in active markets that result in management’s best estimate of fair value. These contracts are classified as Level 3.

The Partnership determines the appropriate level for each financial asset and liability on a quarterly basis and recognizes transfers between levels at the end of the reporting period. For the period ended March 31, 2018, there were no transfers between levels.

The impact to the fair value of derivatives due to credit risk is calculated using the probability of default based on Standard & Poor’s Ratings Services and/or internally generated ratings. The fair value of derivative assets is adjusted for credit risk. The fair value of derivative liabilities is adjusted for credit risk only if the impact is deemed material.

Estimated Fair Value of Financial Instruments

The fair values of all accounts receivable, notes receivable, accounts payable, commercial paper and other such financial instruments on the Condensed Consolidated Balance Sheets are estimated to be approximately equivalent to their carrying amounts due to their short-term nature and have been excluded from the table below. The following table summarizes the fair value and carrying amount of the Partnership’s financial instruments as of March 31, 2018 and December 31, 2017.



	March 31, 2018				December 31, 2017
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Debt
Revolving Credit Facility (Level 2) ⁽¹⁾	$	—	$	—	$	—	$	—
2015 Term Loan Agreement (Level 2)	450		450		450		450
2019 Notes (Level 2)	500		494		500		497
2024 Notes (Level 2)	600		588		600		602
2027 Notes (Level 2)	697		687		697		712
2044 Notes (Level 2)	550		523		550		550
EOIT Senior Notes (Level 2)	261		261		263		265

____________________


(1)	Borrowing capacity is effectively reduced by our borrowings outstanding under the commercial paper program. $596 million and $405 million of commercial paper was outstanding as of March 31, 2018 and December 31, 2017, respectively.

The fair value of the Partnership’s Revolving Credit Facility, 2015 Term Loan Agreement, EOIT Senior Notes, 2019 Notes, 2024 Notes, 2027 Notes 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 March 31, 2018, no material fair value adjustments or fair value measurements were required for these non-financial assets or liabilities.

Contracts with Master Netting Arrangements

Fair value amounts recognized for forward, interest rate swap, option and other conditional or exchange contracts executed with the same counterparty under a master netting arrangement may be offset. The reporting entity’s choice to offset or not must be applied consistently. A master netting arrangement exists if the reporting entity has multiple contracts, whether for the same type of conditional or exchange contract or for different types of contracts, with a single counterparty that are subject to a contractual agreement that provides for the net settlement of all contracts through a single payment in a single currency in the event of default on or termination of any one contract. Offsetting the fair values recognized for forward, interest rate swap, option and other conditional or exchange contracts outstanding with a single counterparty results in the net fair value of the transactions being reported as an asset or a liability in the Condensed Consolidated Balance Sheets. The Partnership has presented the fair values of its derivative contracts under master netting agreements using a net fair value presentation.

The following tables summarize the Partnership’s assets and liabilities that are measured at fair value on a recurring basis as of March 31, 2018 and December 31, 2017:



March 31, 2018	Commodity Contracts						Gas Imbalances ⁽¹⁾
	Assets			Liabilities			Assets ⁽²⁾		Liabilities ⁽³⁾
	(In millions)
Quoted market prices in active market for identical assets (Level 1)	$	3		$	7		$	—	$	—
Significant other observable inputs (Level 2)	6			8			19		8
Unobservable inputs (Level 3)	2			2			—		—
Total fair value	11			17			19		8
Netting adjustments	(3		)	(3		)	—		—
Total	$	8		$	14		$	19	$	8



December 31, 2017	Commodity Contracts						Gas Imbalances ⁽¹⁾
	Assets			Liabilities			Assets ⁽²⁾		Liabilities ⁽³⁾
	(In millions)
Quoted market prices in active market for identical assets (Level 1)	$	5		$	3		$	—	$	—
Significant other observable inputs (Level 2)	4			5			27		12
Unobservable inputs (Level 3)	—			5			—		—
Total fair value	9			13			27		12
Netting adjustments	(5		)	(5		)	—		—
Total	$	4		$	8		$	27	$	12

______________________

(1)

The Partnership uses the market approach to fair value its gas imbalance assets and liabilities at individual, or where appropriate an average of, current market indices applicable to the Partnership’s operations, not to exceed net realizable value. Gas imbalances held by EOIT are valued using an average of the Inside FERC Gas Market Report for Panhandle Eastern Pipe Line Co. (Texas, Oklahoma Mainline), ONEOK (Oklahoma) and ANR Pipeline (Oklahoma) indices. There were no netting adjustments as of March 31, 2018 and December 31, 2017.


(2)	Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $16 million and $10 million at March 31, 2018 and December 31, 2017, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.


(3)	Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of zero at March 31, 2018 and December 31, 2017, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

Changes in Level 3 Fair Value Measurements

The following table provides a reconciliation of changes in the fair value of our Level 3 commodity contracts between the periods presented.



	Commodity Contracts
	Natural gas liquids financial futures/swaps
	(In millions)
Balance at December 31, 2017	$	(5	)
Gains included in earnings	4
Settlements	1
Transfers out of Level 3	—
Balance as of March 31, 2018	$	—

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.



	March 31, 2018
Product Group	Fair Value		Forward Curve Range
	(In millions)		(Per gallon)
Natural gas liquids	$	—	$0.2663 - $0.8963

(11) Supplemental Disclosure of Cash Flow Information

The following table provides information regarding supplemental cash flow information:



	Three Months Ended March 31,
	2018		2017
	(In millions)
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	29	$	14
Income taxes, net of refunds	2		—
Non-cash transactions:
Accounts payable related to capital expenditures	50		20

The following table reconciles cash and cash equivalents and restricted cash on the Condensed Consolidated Balance Sheets to cash, cash equivalents and restricted cash on the Condensed Consolidated Statements of Cash Flows:



	Three Months Ended March 31,
	2018		2017
	(In millions)
Cash and cash equivalents	$	30	$	17
Restricted cash	14		14
Cash, cash equivalents and restricted cash shown in the Condensed Consolidated Statements of Cash Flows	$	44	$	31

(12) Related Party Transactions

The material related party transactions with CenterPoint Energy, OGE Energy and their respective subsidiaries are summarized below. There were no material related party transactions with other affiliates.

Transportation and Storage Agreements

Transportation and Storage Agreements with CenterPoint Energy

EGT provides the following services to CenterPoint Energy’s LDCs in Arkansas, Louisiana, Oklahoma and Northeast Texas. Those services include firm transportation with seasonal contract demand, firm storage, no notice transportation with associated storage and maximum rate firm transportation. Contracts for firm transportation with seasonal contract demand, firm storage, firm no notice transportation with storage for CenterPoint’s LDCs in Arkansas, Louisiana, Oklahoma and Northeast Texas are in effect through March 21, 2021 and will remain in effect thereafter unless and until terminated by either party upon 180 days’ prior written notice. Contracts for maximum firm rate transportation for CenterPoint’s LDCs in Oklahoma and portions of Northeast Texas are also in effect through March 21, 2021. Contracts for CenterPoint’s LDCs in Arkansas, Louisiana and Texarkana, Texas terminated on March 31, 2018. MRT provides transportation and storage services to CenterPoint Energy’s LDCs in Arkansas and Louisiana.

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Contracts for these services are in effect through May 15, 2023 and will remain in effect thereafter unless and until terminated by either party upon 12 months’ prior written notice.

Transportation and Storage Agreement with OGE Energy

EOIT provides no-notice load-following transportation and storage services to OGE Energy. On March 17, 2014, EOIT entered into a transportation agreement with OGE Energy, with a primary term of May 1, 2014 through April 30, 2019. Following the primary term, the agreement will remain in effect from year to year thereafter unless either party provides notice of termination to the other party at least 180 days prior to the commencement of the succeeding annual period.

On December 6, 2016, EOIT entered into a transportation agreement with OGE Energy, with a primary term expected to begin in late 2018 and extend for 20 years. In connection with the agreement, an approximately 80-mile pipeline will be built to expand the EOIT system.

Gas Sales and Purchases Transactions

The Partnership sells natural gas volumes to affiliates of CenterPoint Energy and OGE Energy or purchases natural gas volumes from affiliates of CenterPoint Energy through a combination of forward, monthly and daily transactions. The Partnership enters into these physical natural gas transactions in the normal course of business based upon relevant market prices.

The Partnership’s revenues from affiliated companies accounted for 7% and 6% of total revenues during the three months ended March 31, 2018 and 2017, respectively. Amounts of revenues from affiliated companies included in the Partnership’s Condensed Consolidated Statements of Income are summarized as follows:



	Three Months Ended March 31,
	2018		2017
	(In millions)
Gas transportation and storage service revenue — CenterPoint Energy	$	33	$	33
Natural gas product sales — CenterPoint Energy	6		—
Gas transportation and storage service revenue — OGE Energy	9		9
Natural gas product sales — OGE Energy	1		—
Total revenues — affiliated companies	$	49	$	42

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 March 31,
	2018		2017
	(In millions)
Cost of natural gas purchases — CenterPoint Energy	$	2	$	—
Cost of natural gas purchases — OGE Energy	3		3
Total cost of natural gas purchases — affiliated companies	$	5	$	3

Seconded employees, corporate services and operating lease expense

As of March 31, 2018, the Partnership had certain employees who are participants under OGE Energy’s defined benefit and retiree medical plans, who will remain seconded to the Partnership, subject to certain termination rights of the Partnership and OGE Energy. The Partnership’s reimbursement of OGE Energy for seconded employee costs arising out of OGE Energy’s defined benefit and retiree medical plans is fixed at actual cost subject to a cap of $5 million in 2018 and thereafter, unless and until secondment is terminated.

The Partnership receives services and support functions from each of CenterPoint Energy and OGE Energy under services agreements for an initial term that ended on April 30, 2016. The services agreements automatically extend year-to-year at the end of the initial term, unless terminated by the Partnership with at least 90 days’ notice prior to the end of any extension. Additionally, the Partnership may terminate the services agreements at any time with 180 days’ notice, if approved by the Board of Enable GP.

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The Partnership reimburses CenterPoint Energy and OGE Energy for these services up to annual caps, which for 2018 are $4 million and $1 million, respectively.

The Partnership leases office and data center space from an affiliate of CenterPoint Energy in Shreveport, Louisiana. The term of the lease commenced on October 1, 2016 and extends through December 31, 2019. The Partnership expects to incur approximately $3 million in rent and maintenance expenses during the initial term of the lease. As of March 31, 2018, CenterPoint Energy continues to provide office and data center space to the Partnership in Houston, Texas, under the services agreement. During the first quarter of 2018 the Partnership provided notice to Centerpoint Energy of its intent to terminate the provision of office space in Houston, Texas on August 31, 2018.

Amounts charged to the Partnership by affiliates for seconded employees, an operating lease and corporate services, included primarily in Operation and maintenance and General and administrative expenses in the Partnership’s Condensed Consolidated Statements of Income are as follows:



	Three Months Ended March 31,
	2018		2017
	(In millions)
Corporate Services — CenterPoint Energy	$	1	$	1
Operating Lease — CenterPoint Energy	—		—
Seconded Employee Costs — OGE Energy	8		7
Corporate Services — OGE Energy	—		1
Total corporate services and seconded employees expense	$	9	$	9

Series A Preferred Units

On February 18, 2016, the Partnership completed a private placement to CenterPoint Energy of 14,520,000 Series A Preferred Units representing limited partner interests in the Partnership for a cash purchase price of $25.00 per Series A Preferred Unit, resulting in proceeds of $362 million, net of issuance costs. See Note 6 for further discussion of the Series A Preferred Units.

(13) 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.

(14) Equity-Based Compensation

The following table summarizes the Partnership’s compensation expense for the three months ended March 31, 2018 and 2017 related to performance units, restricted units, and phantom units for the Partnership’s employees and independent directors:



	Three Months Ended March 31,
	2018		2017
	(In millions)
Performance units	$	3	$	3
Restricted units	1		—
Phantom units	1		1
Total compensation expense	$	5	$	4

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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 March 31, 2018 and changes during 2018 are shown in the following table.



	Performance Units					Restricted Units					Phantom Units
	Number of Units			Weighted Average Grant-Date Fair Value, Per Unit		Number of Units			Weighted Average Grant-Date Fair Value, Per Unit		Number of Units			Weighted Average Grant-Date Fair Value, Per Unit
	(In millions, except unit data)
Units Outstanding at December 31, 2017	2,040,407			$	13.86	222,434			$	17.87	987,380			$	11.38
Granted ⁽¹⁾	529,408			17.70		—			—		494,072			14.04
Vested ⁽²⁾	(401,772		)	16.59		(181,068		)	16.75		—			—
Forfeited	(3,725		)	13.87		(1,366		)	16.75		(7,375		)	11.90
Units Outstanding at March 31, 2018	2,164,318			$	13.95	40,000			$	22.96	1,474,077			$	12.27
Aggregate Intrinsic Value of Units Outstanding at March 31, 2018	$	30				$	1				$	20

_____________________


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

(2)

Performance units vested as of March 31, 2018 include 401,772 units from the annual grant, which were approved by the Board of Directors in 2015 and paid out at 200%, or 803,544 units, based on the level of achievement of a performance goal established by the Board of Directors over the performance period. The Board of Directors approved the accelerated vesting of the 2015 grant from June 1, 2018 to March 1, 2018.

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.



	March 31, 2018
	Unrecognized Compensation Cost (In millions)		Weighted Average to be Recognized (In years)
Performance Units	$	19	1.66
Restricted Units	—		0.22
Phantom Units	12		1.86
Total	$	31

As of March 31, 2018, there were 7,504,634 units available for issuance under the long-term incentive plan.

(15) Reportable Segments

The Partnership’s determination of reportable segments considers the strategic operating units under which it manages sales, allocates resources and assesses performance of various products and services to customers in differing regulatory environments. The accounting policies of the reportable segments are the same as those described in the summary of significant accounting policies excerpt in the Partnership’s audited 2017 consolidated financial statements included in the Annual Report. The Partnership uses operating income as the measure of profit or loss for its reportable segments.

The Partnership’s assets and operations are organized into two reportable segments: (i) gathering and processing, which primarily provides natural gas and crude oil gathering and natural gas processing services to our producer customers, and

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(ii) transportation and storage, which provides interstate and intrastate natural gas pipeline transportation and storage service primarily to our producer, power plant, LDC and industrial end-user customers.

Financial data for reportable segments are as follows:



Three Months Ended March 31, 2018	Gathering and Processing		Transportation and Storage ⁽¹⁾		Eliminations			Total
	(In millions)
Product sales	$	418	$	140	$	(115	)	$	443
Service revenue	173		139		(7		)	305
Total Revenues	591		279		(122		)	748
Cost of natural gas and natural gas liquids	358		139		(122		)	375
Operation and maintenance, General and administrative	76		46		(1		)	121
Depreciation and amortization	62		34		—			96
Taxes other than income tax	10		7		—			17
Operating income	$	85	$	53	$	1		$	139
Capital expenditures	$	147	$	43	$	—		$	190
Total assets	$	9,212	$	5,652	$	(3,177	)	$	11,687


Three Months Ended March 31, 2017	Gathering and Processing		Transportation and Storage ⁽¹⁾		Eliminations			Total
	(In millions)
Product sales	$	351	$	153	$	(118	)	$	386
Service revenue	140		141		(1		)	280
Total Revenues	491		294		(119		)	666
Cost of natural gas and natural gas liquids	286		140		(118		)	308
Operation and maintenance, General and administrative	70		45		(1		)	114
Depreciation and amortization	56		32		—			88
Taxes other than income tax	9		7		—			16
Operating income	$	70	$	70	$	—		$	140
Capital expenditures	$	51	$	10	$	—		$	61
Total assets as of December 31, 2017	$	9,079	$	5,616	$	(3,102	)	$	11,593

_____________________


(1)	See Note 7 for discussion regarding ownership interests in SESH and related equity earnings included in the transportation and storage segment for the three months ended March 31, 2018 and 2017.

(16) Subsequent Event

On April 6, 2018, the Partnership amended and restated the Revolving Credit Facility in its entirety. The amended and restated Revolving Credit Facility is a $1.75 billion 5-year senior unsecured revolving credit facility, which under certain circumstances may be increased from time to time up to an additional $875 million, in aggregate. The Second Amended and Restated Revolving Credit Facility contains an option, which may be exercised up to two times, to extend the Second Amended and Restated Revolving Credit Facility for an additional one-year term.

The Second Amended and Restated Revolving Credit Facility provides that outstanding borrowings bear interest at the Eurodollar rate and/or an alternate base rate, at the Partnership’s election, plus an applicable margin. The applicable margin will be based on the Partnership’s designated credit ratings. The applicable margin shall equal, in the case of interest rates determined by reference to the Eurodollar rate, between 1.00% and 1.75% per annum.

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The Second Amended and Restated Revolving Credit Facility requires the Partnership to pay a quarterly fee on each lender’s unused commitment amount during such preceding quarter which shall equal between 0.10% and 0.30% per annum, depending on The Partnership’s designated credit rating. The Second Amended and Restated Revolving Credit Facility provides for issuance of letters of credit of up to $500 million dollars at any time outstanding. The Second and Amended Restated Revolving Credit Facility contains a financial covenant requiring the Partnership to maintain a ratio of consolidated funded debt to EBITDA as of the last day of each fiscal quarter of less than or equal to 5.00 to 1.00, although such ratio is increased to 5.50 to 1.00 for a certain period of time following an acquisition by the Partnership or certain of its subsidiaries with a purchase price that, when combined with the aggregate purchase price for all other such acquisitions in any rolling 12-month period, is equal to or greater than $25 million.

The Second Amended and Restated Revolving Credit Facility also contains covenants that restrict the Partnership and certain of its subsidiaries in respect of, among other things, mergers and consolidations, sales of all or substantially all assets, incurrence of subsidiary indebtedness, incurrence of liens, transactions with affiliates, designation of subsidiaries as excluded subsidiaries, restricted payments, changes in the nature of their respective businesses and entering into certain restrictive agreements. The Second Amended and Restated Revolving Credit Facility is subject to acceleration upon the occurrence of certain defaults, including, among others, payment defaults on such facility, breach of representations, warranties and covenants, acceleration of indebtedness (other than intercompany and non-recourse indebtedness) of $100 million or more in the aggregate, change of control, nonpayment of uninsured judgments in excess of $100 million, and the occurrence of certain ERISA and bankruptcy events, subject where applicable to specified cure periods.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with our unaudited condensed consolidated financial statements and the related notes included herein and our audited consolidated financial statements for the year ended December 31, 2017, included in our Annual Report. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Please read “Forward-Looking Statements.” In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

Overview

Enable Midstream Partners, LP is a Delaware limited partnership formed in May 2013 by CenterPoint Energy, OGE Energy and ArcLight to own, operate and develop midstream energy infrastructure assets strategically located to serve our customers. We completed our initial public offering in April 2014, and we are traded on the NYSE under the symbol “ENBL.” Our general partner is owned by CenterPoint Energy and OGE Energy. In this report, the terms “Partnership” and “Registrant” as well as the terms “our,” “we,” “us” and “its,” are sometimes used as abbreviated references to Enable Midstream Partners, LP together with its consolidated subsidiaries.

Our assets and operations are organized into two reportable segments: (i) gathering and processing and (ii) transportation and storage. Our gathering and processing segment primarily provides natural gas and crude oil gathering and natural gas processing services to our producer customers. Our transportation and storage segment provides interstate and intrastate natural gas pipeline transportation and storage services primarily to our producer, power plant, LDC and industrial end-user customers.

Our natural gas gathering and processing assets are primarily located in Oklahoma, Texas, Arkansas and Louisiana and serve natural gas production in the Anadarko, Arkoma and Ark-La-Tex Basins. Our crude oil gathering assets are located in North Dakota and serve crude oil production in the Bakken Shale formation of the Williston Basin. Our natural gas transportation and storage assets consist primarily of an interstate pipeline system extending from western Oklahoma and the Texas Panhandle to Louisiana, an interstate pipeline system extending from Louisiana to Illinois, an intrastate pipeline system in Oklahoma and our investment in SESH, an interstate pipeline extending from Louisiana to Alabama.

We expect our business to continue to be affected by the key trends included in our Annual Report, as well as the recent developments discussed herein. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results.

Our primary business objective is to increase the cash available for distribution to our unitholders over time while maintaining our financial flexibility. Our business strategies for achieving this objective include capitalizing on organic growth opportunities

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associated with our strategically located assets, growing through accretive acquisitions, maintaining strong customer relationships to attract new volumes and expand beyond our existing asset footprint and business lines, and continuing to minimize direct commodity price exposure through fee-based contracts. As part of these efforts, we continuously engage in discussions with new and existing customers regarding the development of potential projects to develop new midstream assets to support their needs as well as discussions with potential counterparties regarding opportunities to purchase or invest in complementary assets in new operating areas or midstream business lines. These growth, acquisition and development efforts often involve assets which, if acquired or constructed, could have a material effect on our financial condition and results of operations.

Recent Developments

Regulatory Update

Interstate Natural Gas Transportation Regulation

Effective December 22, 2017, the Tax Cuts and Jobs Act of 2017 changed several provisions of the federal tax code, including a reduction in the maximum corporate tax rate. On March 15, 2018, in a set of related issuances, FERC addressed treatment of federal income tax allowances in regulated entity rates. FERC issued a Revised Policy Statement on Treatment of Income Taxes stating that it will no longer permit pipelines organized as master limited partnerships to recover an income tax allowance in their cost-of-service rates. FERC issued the Revised Policy Statement in response to a remand from the U.S. Court of Appeals for the D.C. Circuit in United Airlines v. FERC, in which the court determined that FERC had not justified its conclusion that a pipeline organized as a master limited partnership would not “double recover” its taxes under the current policy by both including an income-tax allowance in its cost-of-service and earning a return on equity calculated using the discounted cash flow methodology. Requests for rehearing or clarification of the Revised Policy Statement are pending and FERC may change its decision in response to these requests. Accordingly, the impacts that such changes may have on the rates the Partnership can charge for transportation services are unknown at this time.

FERC also issued a Notice of Inquiry (NOI) requesting comments on the effect of the Tax Cuts and Jobs Act of 2017 on FERC-jurisdictional rates. The NOI states that of particular interest to FERC is whether, and if so how, FERC should address changes relating to accumulated deferred income taxes and bonus depreciation. Comments in response to the NOI are due on or before May 21, 2018. Actions FERC will take, if any, following receipt of responses to the NOI and any potential impacts from final rules or policy statements issued following the NOI on the rates the Partnership can charge for transportation services are unknown at this time, but could impact rates the Partnership is permitted to charge its customers.

Included in the March 15, 2018 issuances is a Notice of Proposed Rulemaking (NOPR) proposing rules for implementation of the Revised Policy Statement and the corporate income tax rate reduction with respect to natural gas pipeline rates. The NOPR proposes a new rule that will, if it becomes a final rule, require all FERC-regulated natural gas pipelines that have cost-based rates for service to make a one-time Form No. 501-G filing providing certain financial information. The NOPR suggests that this information will allow FERC and other stakeholders to evaluate the impacts of the Tax Cuts and Jobs Act of 2017 and the Revised Policy Statement on each individual pipeline’s rates. The NOPR proposes that each FERC-regulated natural gas pipeline will select one of four options: file a limited NGA Section 4 filing reducing its rates only as required in relation to the Tax Cuts and Jobs Act of 2017 and the Revised Policy Statement, commit to filing a general NGA Section 4 rate case in the near future, file a statement explaining why an adjustment to rates is not needed, or take no other action. Comments on the NOPR are due April 25, 2018, and once the comment period is complete, FERC may issue a final rule. At this time, we cannot predict the outcome of the NOPR, but adoption of the regulation in its proposed form could impact the rates the Partnership is permitted to charge its customers.

Even without action on the NOPR or NOI, the FERC or our shippers may challenge the cost‑of‑service rates we charge. FERC’s establishment of a just and reasonable rate is based on many components, and tax-related changes will affect tax-related accounts, such as the annual allowance for income taxes and the balance sheet amounts for accumulated deferred income taxes and related regulatory assets and liabilities, while other pipeline costs also will continue to affect FERC’s determination of just and reasonable cost-of-service rates. Although changes in these tax-related accounts may vary, other components in the cost-of-service rate calculation may also change and result in a newly calculated cost-of-service rate that is the same as or greater than the prior cost-of-service rate. Moreover, pipelines receive revenues from cost-of-service rates, negotiated rates, discounted rates, and market-based rates, or a combination thereof. As of December 31, 2017, approximately 62% and 0% of our aggregate contracted firm transportation capacity on EGT and MRT, respectively, was subscribed under negotiated rate contracts. As of December 31, 2017, approximately 100% and 0% of our aggregated contracted firm storage capacity on EGT and MRT, respectively, was subscribed under negotiated rate contracts. As of December 31, 2017, approximately 23% and 41% of our aggregate contracted firm transportation capacity on EGT and MRT, respectively, was subscribed under discounted rate contracts. We do not expect rates subject to negotiated rates that are not tied to the cost-of-service rates to be affected by the Revised Policy Statement or any

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final regulations that may result from the March 15, 2018 issuances. Nor will discounted rates which are below the level of any new maximum rate be affected. With respect to the cost-of-service rates, depending on a detailed review of all of the Partnership’s cost-of-service components and the outcomes of any challenges to our rates by the FERC or our shippers, the NOI, the NOPR, and the Revised Policy Statement, combined with the reduced corporate federal income tax rate established in the Tax Cuts and Jobs Act of 2017, the revenues associated with natural gas transportation services we provide pursuant to cost-of-service based rates may decrease in the future.

The FERC issued a Notice of Inquiry on April 19, 2018 (April 2018 NOI), thereby initiating a review of its policies on certification of natural gas pipelines, including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities, issued in 1999, that is used to determine whether to grant certificates for new pipeline projects. We are unable to predict what, if any, changes may be proposed as a result of the April 2018 NOI that will affect our natural gas pipeline business or when such proposals, if any, might become effective. We do not expect that any change in this policy would materially affect our plans and operations.

Interstate Crude Oil Transportation Regulation

FERC utilizes an indexing rate methodology which, as currently in effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index. The indexing methodology is applicable to existing rates, with the exclusion of market-based rates. FERC’s indexing methodology is subject to review every five years. During the five-year period commencing July 1, 2016 and ending June 30, 2021, common carriers charging indexed rates are permitted to adjust their indexed ceilings annually by PPI plus 1.23%. Many existing pipelines, including our Williston Basin crude oil gathering systems, utilize the FERC oil index to change transportation rates annually every July 1. With respect to oil and refined products pipelines subject to FERC jurisdiction, the Revised Policy Statement requires the pipeline to reflect the impacts to its cost of service from the Revised Policy Statement and the Tax Cuts and Jobs Act of 2017 on the Page 700 of FERC Form No. 6. This information will be used by FERC in its next five-year review of the oil pipeline index to generate the index level to be effective July 1, 2021, thereby including the effect of the Revised Policy Statement and the Tax Cuts and Jobs Act of 2017 in the determination of indexed rates prospectively, effective July 1, 2021. FERC’s establishment of a just and reasonable rate, including the determination of the appropriate oil pipeline index, is based on many components, and tax-related changes will affect two such components, the allowance for income taxes and the amount for accumulated deferred income taxes, while other pipeline costs also will continue to affect FERC’s determination of the appropriate pipeline index. Accordingly, depending on FERC’s application of its indexing rate methodology for the next five-year term of index rates, the Revised Policy Statement and tax effects related to the Tax Cuts and Jobs Act of 2017 may impact our revenues associated with any transportation services we may provide pursuant to cost-of-service based rates in the future, including indexed rates.

Imposition of Ad Valorem Tariffs

The construction of pipeline, gathering, treating, processing, compression or other facilities is subject to construction cost overruns due to costs and availability of equipment and materials such as steel. If third party providers of steel products essential to our capital improvements and additions are unable to obtain raw materials, including steel, at historical prices, they may raise the price we pay for such products. On March 8, 2018, the President issued two proclamations directing the imposition of ad valorem tariffs of 25 percent on certain imported steel products and 10 percent on certain imported aluminum products. Following these proclamations, domestic prices for steel have risen and are expected to continue to rise. While steel pipe costs relating to our previously announced projects are fixed for 2018, the price increases may result in increased costs associated with the continued build-out of our gathering systems as well as projects under development. If we are not able to pass these cost increases along to our customers, our Income from operations and cash flows may be adversely affected.

Commercial and Construction Update

Project Wildcat rich gas takeaway solution

The Partnership has entered into an agreement to deliver approximately 400 MMcf/d of rich natural gas from the Anadarko Basin to north Texas, providing a new market outlet for growing Anadarko Basin production. Project Wildcat is expected to provide access to the Texas intrastate natural gas markets, including the Tolar Hub, by contracting with an affiliate of Energy Transfer Partners, LP for 400 MMcf/d of firm processing capacity at the Godley Plant in Johnson County, Texas. The project is expected to be in service by the end of the second quarter of 2018. Even with the 400 MMcf/d of processing capacity provided by this project, the Partnership anticipates that there will be a need to resume construction of the previously announced Wildhorse Plant, though likely not before 2019.

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EGT and EOIT Expansion Projects

Newfield Exploration Company has entered into a 205,000 Dth/d firm natural gas transportation agreement with EGT related to the Cana and STACK Expansion (CaSE) project, a system expansion providing firm transportation service for growing Anadarko Basin production. The 10-year contract is expected to start at an initial capacity of 45,000 Dth/d in early 2018 and grow to the full contracted capacity by the fourth quarter of 2018. The Muskogee project, a 20-year, 228,000 Dth/d firm transportation service agreement with Oklahoma Gas and Electric on the EOIT system, is expected to commence service in late 2018.

CenterPoint Strategic Review

CenterPoint Energy has publicly disclosed that it is evaluating strategic alternatives for its investment in the Partnership. CenterPoint Energy has disclosed that the alternatives may include a sale of all or a portion of the interests that it owns in the Partnership and Enable GP, that if the sale option is not viable it intends to reduce its ownership in the Partnership over time through a sale in the public equity markets of Partnership common units that it holds, subject to market conditions, and that there can be no assurances that these evaluations will result in any specific action.

Liquidity Update

Second Amended and Restated Revolving Credit Facility

On April 6, 2018, the Partnership amended and restated the Revolving Credit Facility in its entirety. For more information, please see Note 16 of the Notes to Condensed Consolidated Financial Statements.

Results of Operations

The following tables summarize the key components of our results of operations for the three months ended March 31, 2018 and 2017.



Three Months Ended March 31, 2018	Gathering and Processing		Transportation and Storage		Eliminations			Enable Midstream Partners, LP
	(In millions)
Product sales	$	418	$	140	$	(115	)	$	443
Service revenue	173		139		(7		)	305
Total Revenues	591		279		(122		)	748
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	358		139		(122		)	375
Gross margin ⁽¹⁾	233		140		—			373
Operation and maintenance, General and administrative	76		46		(1		)	121
Depreciation and amortization	62		34		—			96
Taxes other than income tax	10		7		—			17
Operating income	$	85	$	53	$	1		$	139
Equity in earnings of equity method affiliate	$	—	$	6	$	—		$	6

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Three Months Ended March 31, 2017	Gathering and Processing		Transportation and Storage		Eliminations			Enable Midstream Partners, LP
	(In millions)
Product sales	$	351	$	153	$	(118	)	$	386
Service revenue	140		141		(1		)	280
Total Revenues	491		294		(119		)	666
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	286		140		(118		)	308
Gross margin ⁽¹⁾	205		154		(1		)	358
Operation and maintenance, General and administrative	70		45		(1		)	114
Depreciation and amortization	56		32		—			88
Taxes other than income tax	9		7		—			16
Operating income	$	70	$	70	$	—		$	140
Equity in earnings of equity method affiliate	$	—	$	7	$	—		$	7

_____________________


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



	Three Months Ended March 31,
	2018	2017
Operating Data:
Gathered volumes—TBtu	385	296
Gathered volumes—TBtu/d	4.28	3.29
Natural gas processed volumes—TBtu	200	168
Natural gas processed volumes—TBtu/d	2.22	1.87
NGLs produced—MBbl/d⁽¹⁾	110.29	79.76
NGLs sold—MBbl/d⁽¹⁾⁽²⁾	109.39	78.65
Condensate sold—MBbl/d	6.96	5.47
Crude Oil—Gathered volumes—MBbl/d	24.83	21.18
Transported volumes—TBtu	510	493
Transported volumes—TBtu/d	5.66	5.48
Interstate firm contracted capacity—Bcf/d	6.05	7.23
Intrastate average deliveries—TBtu/d	1.97	1.84

_____________________


(1)	Excludes condensate.


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

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	Three Months Ended March 31,
	2018	2017
Anadarko
Gathered volumes—TBtu/d	2.02	1.75
Natural gas processed volumes—TBtu/d	1.82	1.54
NGLs produced—MBbl/d⁽¹⁾	95.85	67.30
Arkoma
Gathered volumes—TBtu/d	0.54	0.57
Natural gas processed volumes—TBtu/d	0.10	0.10
NGLs produced—MBbl/d⁽¹⁾	4.98	4.85
Ark-La-Tex
Gathered volumes—TBtu/d	1.71	0.97
Natural gas processed volumes—TBtu/d	0.29	0.23
NGLs produced—MBbl/d⁽¹⁾	9.46	7.61

_____________________


(1)	Excludes condensate.

Gathering and Processing

Three Months Ended March 31, 2018 compared to three months ended March 31, 2017. Our gathering and processing segment reported operating income of $85 million for the three months ended March 31, 2018 compared to operating income of $70 million for the three months ended March 31, 2017. The difference of $15 million in operating income between periods was primarily due to a $28 million increase in gross margin. This was partially offset by a $6 million increase in operation and maintenance and general and administrative expenses, a $6 million increase in depreciation and amortization and a $1 million increase in taxes other than income tax during the three months ended March 31, 2018.

Our gathering and processing segment revenues increased $100 million. The increase was primarily due to the following:


•	revenues from NGL sales increased $89 million resulting from higher average NGL prices and higher processed volumes in the Anadarko and Ark-La-Tex Basins,


•	natural gas gathering revenues increased $14 million due to higher fees and gathered volumes in the Anadarko and Ark-La-Tex Basins,


•	processing service revenues increased $13 million resulting from higher processed volumes primarily under fixed processing arrangements,


•	revenues from natural gas sales increased $3 million due to higher gathered volumes in the Anadarko and Ark-La-Tex Basins as well as higher average natural gas prices, and


•	crude oil and water gathering revenues increased $1 million due to an increase in gathered volumes.

These increases were partially offset by a $14 million decrease due to the adoption of ASC 606, which resulted in a corresponding increase in Cost of natural gas and natural gas liquids, see Note 3 for further information regarding the adoption of ASC 606. The increase was also offset by a $7 million decrease in revenues from changes in the fair value of natural gas, condensate and NGL derivatives.

Our gathering and processing segment gross margin increased $28 million. The increase was primarily due to the following:


•	processing margins increased $19 million from higher average NGL prices and higher processed volumes in the Anadarko and Ark-La-Tex Basin,


•	natural gas gathering margin increased $15 million due to increased gathered volumes in the Anadarko and Ark-La-Tex Basins, and


•	crude oil and water gathering margins increased $1 million as a result of an increase in gathered volumes.

These increases were partially offset by a $7 million decrease in gross margin from changes in the fair value of natural gas, condensate and NGL derivatives.

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Our gathering and processing segment operation and maintenance and general and administrative expenses increased $6 million. The increase was primarily due to a $3 million increase in payroll-related costs, a $2 million increase in compressor rental expenses due to increased compression activity and a $2 million increase in materials and supplies expense. These were partially offset by a $2 million decrease due to an increase in capitalized overhead costs as a result of an increase in projects in the first quarter of 2018 and a $1 million change in the allowance for doubtful accounts due to the collection of accounts receivable in the three months ended March 31, 2018 that were previously included in the allowance for doubtful accounts.

Our gathering and processing segment depreciation and amortization increased $6 million due to additional assets placed in service primarily as a result of the Align Midstream, LLC acquisition in the fourth quarter of 2017.

Our gathering and processing segment taxes other than income tax increased $1 million due to higher accrued ad valorem taxes due to additional assets placed in service.

Transportation and Storage

Three Months Ended March 31, 2018 compared to three months ended March 31, 2017. Our transportation and storage segment reported operating income of $53 million for the three months ended March 31, 2018 compared to operating income of $70 million for the three months ended March 31, 2017. The difference of $17 million in operating income between periods was primarily due to a $14 million decrease in gross margin, a $2 million increase in depreciation and amortization and a $1 million increase in operation and maintenance and general and administrative expenses for the three months ended March 31, 2018.

Our transportation and storage segment revenues decreased $15 million. The decrease was primarily due to the following:


•	changes in the fair value of natural gas derivatives decreased $19 million and


•	firm transportation services between Carthage, Texas and Perryville, Louisiana decreased $12 million due to contract expirations in the second quarter of 2017.

These decreases were partially offset by:


•	volume-dependent transportation revenues increased $5 million primarily due to an increase in commodity fees from new contracts and an increase in off-system transportation due to increases in volumes at higher rates,


•	revenues from natural gas sales increased $3 million due to higher sales volumes and higher average sales prices,


•	other firm transportation services increased $4 million due to new intrastate transportation contracts,


•	realized gains on natural gas derivatives increased $4 million, and


•	revenues from NGL sales increased $1 million due to an increase in prices and volumes.

Our transportation and storage segment gross margin decreased $14 million. The decrease was primarily due to the following:


•	changes in the fair value of natural gas derivatives decreased $19 million,


•	firm transportation services of between Carthage, Texas and Perryville, Louisiana decreased $12 million due to contract expirations in the second quarter of 2017, and


•	storage decreased $6 million primarily due to storage field losses of $3 million and a lower of cost or net realizable value adjustment of $3 million in the first quarter of 2018.

These decreases were partially offset by:


•	system management activities increased $10 million,


•	volume-dependent transportation margins increased $5 million primarily due to an increase in commodity fees from new contracts and an increase in off-system transportation due to increases in volumes at higher rates,


•	other firm transportation services increased $4 million due to new intrastate contracts, and


•	realized gains on natural gas derivatives increased $4 million.

Our transportation and storage segment operation and maintenance and general and administrative expenses increased $1 million. The increase was primarily due to a $1 million increase in payroll-related costs and a $1 million increase in one-time reimbursements associated with an unplanned pipeline outage. These increases were partially offset by a $1 million decrease due to increased capitalized overhead costs.

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Our transportation and storage segment depreciation and amortization increased $2 million due to additional assets placed in service.

Condensed Consolidated Interim Information



	Three Months Ended March 31,
	2018			2017
	(In millions)
Operating Income	$	139		$	140
Other Income (Expense):
Interest expense	(33		)	(27		)
Equity in earnings of equity method affiliate	6			7
Other, net	2			1
Total Other Expense	(25		)	(19		)
Income Before Income Taxes	114			121
Income tax expense	—			1
Net Income	$	114		$	120
Less: Net income attributable to noncontrolling interest	—			—
Net Income Attributable to Limited Partners	$	114		$	120
Less: Series A Preferred Unit distributions	9			9
Net Income Attributable to Common and Subordinated Units	$	105		$	111

Three Months Ended March 31, 2018 compared to Three Months Ended March 31, 2017

Net Income attributable to limited partners. We reported net income attributable to limited partners of $114 million in the three months ended March 31, 2018 compared to net income attributable to limited partners of $120 million in the three months ended March 31, 2017. The decrease in net income attributable to limited partners of $6 million was primarily attributable to an increase in interest expense of $6 million in the three months ended March 31, 2018.

Interest Expense. Interest expense increased $6 million primarily due to an increase in the amount of debt outstanding as well as higher interest rates on the Partnership’s outstanding debt as a result of a long-term debt issuance in March 2017 that resulted in the repayment of amounts outstanding under the Partnership’s Revolving Credit Facility.

Reconciliations of Non-GAAP Financial Measures

The Partnership has included the non-GAAP financial measures Gross margin, Adjusted EBITDA, Adjusted interest expense, DCF and Distribution coverage ratio in this report based on information in its condensed consolidated financial statements. Gross margin, Adjusted EBITDA, Adjusted interest expense, DCF and Distribution coverage ratio are part of the performance measures that we use to manage the Partnership.

Provided below are reconciliations of Gross margin to total revenues, Adjusted EBITDA and DCF to net income attributable to limited partners, and Adjusted EBITDA to net cash provided by operating activities and Adjusted interest expense to interest expense, the most directly comparable GAAP financial measures, on a historical basis, as applicable, for each of the periods indicated. Gross margin, Adjusted EBITDA, Adjusted interest expense, DCF and Distribution coverage ratio should not be considered as alternatives to net income, operating income, total revenues, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. These non-GAAP financial measures have important limitations as analytical tools because they exclude some but not all items that affect the most directly comparable GAAP measures. Additionally, because Gross margin, Adjusted EBITDA, Adjusted interest expense, DCF and Distribution coverage ratio may be defined differently by other companies in the Partnership’s industry, these measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

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	Three Months Ended March 31,
	2018		2017
	(In millions)
Reconciliation of Gross margin to Total Revenues:
Consolidated
Product sales	$	443	$	386
Service revenue	305		280
Total Revenues	748		666
Cost of natural gas and natural gas liquids (excluding depreciation and amortization)	375		308
Gross margin	$	373	$	358

Reportable Segments
Gathering and Processing
Product sales	$	418	$	351
Service revenue	173		140
Total Revenues	591		491
Cost of natural gas and natural gas liquids (excluding depreciation and amortization)	358		286
Gross margin	$	233	$	205

Transportation and Storage
Product sales	$	140	$	153
Service revenue	139		141
Total Revenues	279		294
Cost of natural gas and natural gas liquids (excluding depreciation and amortization)	139		140
Gross margin	$	140	$	154

The following table shows the components of our gross margin for the three months ended March 31, 2018:



	Fee-Based ⁽¹⁾
	Demand		Volume- Dependent		Commodity- Based⁽¹⁾		Total
Three Months Ended March 31, 2018
Gathering and Processing Segment	22	%	52	%	26	%	100	%
Transportation and Storage Segment	85	%	14	%	1	%	100	%
Partnership Weighted Average	45	%	38	%	17	%	100	%

____________________


(1)	For purposes of this table, the Partnership includes the value of all natural gas and NGL commodities received as payment as commodity-based.

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	Three Months Ended March 31,
	2018			2017
	(In millions, except Distribution coverage ratio)
Reconciliation of Adjusted EBITDA and DCF to net income attributable to limited partners and calculation of Distribution coverage ratio:
Net income attributable to limited partners	$	114		$	120
Depreciation and amortization expense	96			88
Interest expense, net of interest income	33			27
Income tax expense	—			1
Distributions received from equity method affiliate in excess of equity earnings	7			4
Non-cash equity-based compensation	5			4
Change in fair value of derivatives	2			(24		)
Other non-cash losses ⁽¹⁾	—			1
Adjusted EBITDA	$	257		$	221
Series A Preferred Unit distributions ⁽²⁾	(9		)	(9		)
Distributions for phantom and performance units ⁽³⁾	(3		)	—
Adjusted interest expense ⁽⁴⁾	(35		)	(27		)
Maintenance capital expenditures	(14		)	(14		)
DCF	$	196		$	171

Distributions related to common and subordinated unitholders ⁽⁵⁾	$	138		$	137

Distribution coverage ratio	1.42			1.25

____________________


(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 three months ended March 31, 2018 and 2017. 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 2018 reflect estimated cash distributions for common units outstanding for the quarter ended March 31, 2018.

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	Three Months Ended March 31,
	2018			2017
	(In millions)
Reconciliation of Adjusted EBITDA to net cash provided by operating activities:
Net cash provided by operating activities	$	166		$	156
Interest expense, net of interest income	33			27
Other non-cash items ⁽¹⁾	(1		)	1
Changes in operating working capital which (provided) used cash:
Accounts receivable	(23		)	(10		)
Accounts payable	60			55
Other, including changes in noncurrent assets and liabilities	13			12
Return of investment in equity method affiliate	7			4
Change in fair value of derivatives	2			(24		)
Adjusted EBITDA	$	257		$	221

____________________


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



	Three Months Ended March 31,
	2018			2017
	(In millions)
Reconciliation of Adjusted interest expense to Interest expense:
Interest Expense	$	33		$	27
Amortization of premium on long-term debt	1			1
Capitalized interest on expansion capital	2			—
Amortization of debt expense and discount	(1		)	(1		)
Adjusted interest expense	$	35		$	27

Liquidity and Capital Resources

Working Capital

Working capital is the difference in our current assets and our current liabilities. Working capital is an indication of liquidity and potential need for short-term funding. The change in our working capital requirements are driven generally by changes in accounts receivable, accounts payable, commodity prices, credit extended to, and the timing of collections from, customers, and the level and timing of spending for maintenance and expansion activity. As of March 31, 2018, we had a working capital deficit of $991 million. The deficit is primarily due to the classification of $450 million of borrowings under the 2015 Term Loan Agreement as Current portion of long-term debt as of March 31, 2018 as well as $596 million of commercial paper outstanding as of March 31, 2018. We utilize our commercial paper program and Revolving Credit Facility to manage the timing of cash flows and fund short-term working capital deficits.

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Cash Flows

The following tables reflect cash flows for the applicable periods:



	Three Months Ended March 31,
	2018			2017
	(In millions)
Net cash provided by operating activities	$	166		$	156
Net cash used in investing activities	$	(176	)	$	(56	)
Net cash provided by (used in) financing activities	$	35		$	(92	)

Operating Activities

The increase of $10 million, or 6%, in net cash provided by operating activities for the three months ended March 31, 2018 as compared to the three months ended March 31, 2017 was primarily driven by an increase of $8 million in other non-cash items and an increase of $7 million in the timing of cash receipts and disbursements and changes in other working capital assets and liabilities, partially offset by a decrease in net income of $6 million.

Investing Activities

The increase of $120 million, or 214%, in net cash used in investing activities for the three months ended March 31, 2018 as compared to the three months ended March 31, 2017 was primarily due to higher capital expenditures of $129 million partially offset by an increase in proceeds from sale of asset of $6 million due to the sale of a cryogenic processing plant, previously included in assets held for sale, in the first quarter 2018 and an increase in return of investment in equity method affiliate of $3 million.

Financing Activities

Net cash provided by financing activities increased $127 million, or 138%, for the three months ended March 31, 2018 as compared to the three months ended March 31, 2017. Our primary financing activities consist of the following:



	Three Months Ended March 31,
	2018			2017
	(In millions)
Proceeds from 2027 Notes, net of issuance costs	$	—		$	691
Net (repayments) proceeds from Revolving Credit Facility	—			(636		)
Proceeds from commercial paper program	190			—
Distributions	(150		)	(147		)
Cash taxes paid for employee equity-based compensation	(5		)	—

Please see Note 8, “Debt” in the Notes to the Unaudited Condensed Consolidated Financial Statements in Part 1, Item 1. for a description of the Partnership’s debt agreements.

Sources of Liquidity

As of March 31, 2018, our sources of liquidity included:


•	cash on hand;


•	cash generated from operations;


•	proceeds from commercial paper issuances;


•	borrowings under our Revolving Credit Facility; and


•	capital raised through debt and equity markets.

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ATM Program

On May 12, 2017, the Partnership entered into an ATM Equity Offering Sales Agreement, pursuant to which the Partnership may issue and sell common units having an aggregate offering price of up to $200 million, by sales methods and at prices determined by market conditions and other factors at the time of our offerings. The Partnership has no obligation to sell any common units under the ATM Program and the Partnership may suspend sales under the ATM Program at any time. The Partnership did not sell any common units under the ATM Program during the three months ended March 31, 2018.

Distribution Reinvestment Plan

In June 2016, the Partnership implemented a Distribution Reinvestment Plan, which offers owners of our common units the ability to purchase additional common units by reinvesting all or a portion of the cash distributions paid to them on their common units. The Partnership will have the sole discretion to determine whether common units purchased under the DRIP will come from our newly issued common units or from common units purchased on the open market. The purchase price for newly issued common units will be the average of the high and low trading prices of the common units on the New York Stock Exchange-Composite Transactions for the five trading days immediately preceding the investment date. The purchase price for common units purchased on the open market will be the weighted average price of all common units purchased for the DRIP for the respective investment date. We can set a discount ranging from 0% to 5% for common units purchased pursuant to the DRIP. The discount is currently set at 0%. Participation in the DRIP is voluntary, and once enrolled, our unitholders may terminate participation at any time.

Capital Requirements

The midstream business is capital intensive and can require significant investment to maintain and upgrade existing operations, connect new wells to the system, organically grow into new areas and comply with environmental and safety regulations. Going forward, our capital requirements will consist of the following:


•	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.

Our future capital expenditures may vary significantly from period to period based on commodity prices and the investment opportunities available to us. We expect to fund future capital expenditures from cash flow generated from our operations, issuances of commercial paper, borrowings under our Revolving Credit Facility, new debt offerings or the issuance of additional partnership units. Issuances of equity or debt in the capital markets may not, however, be available to us on acceptable terms.

Distributions

On May 1, 2018, the board of directors of Enable GP declared a quarterly cash distribution of $0.318 per common unit on all of the Partnership’s outstanding common units for the period ended March 31, 2018. The distributions will be paid May 29, 2018 to unitholders of record as of the close of business on May 22, 2018. Additionally, the board of directors of Enable GP declared a quarterly cash distribution of $0.625 on the Partnership’s outstanding Series A Preferred Units. The distributions will be paid May 15, 2018 to unitholders of record as of the close of business on May 1, 2018.

Expiration of Subordination Period

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. The conversion of the subordinated units did not change the aggregate amount of outstanding units, and the conversion of the subordinated units did not impact the amount of cash available for distribution by the Partnership.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

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Credit Risk

We are exposed to certain credit risks relating to our ongoing business operations. Credit risk includes the risk that counterparties that owe us money or energy commodities will breach their obligations. If the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected, and we could incur losses. We examine the creditworthiness of third party customers to whom we extend credit and manage our exposure to credit risk through credit analysis, credit approval, credit limits and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees.

Critical Accounting Policies and Estimates

The Partnership’s critical accounting policies and estimates are described in Critical Accounting Policies and Estimates within Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 1 of the Notes to the Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” in our Annual Report. The accounting policies and estimates used in preparing our interim Condensed Consolidated Financial Statements for the three months ended March 31, 2018 are the same as those described in our Annual Report.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to various market risks, including volatility in commodity prices and interest rates.

Commodity Price Risk

While we generate a substantial portion of our gross margin pursuant to fee-based contracts that include minimum volume commitments and/or demand fees, we are also directly and indirectly exposed to changes in the prices of natural gas, condensate and NGLs. The Partnership utilizes derivatives and forward commodity sales to mitigate the effects of price changes. We do not enter into risk management contracts for speculative purposes. For further information regarding our derivatives, see Note 9 of the Notes to the Unaudited Condensed Consolidated Financial Statements.

Based on our forecasted volumes, prices and contractual arrangements, we estimate approximately 14% of our total gross margin for the twelve months ending December 31, 2018 is directly exposed to changes in commodity prices, excluding the impact of hedges and contractual floors related to commodity prices in certain agreements. Since March 31, 2018, we have entered into additional derivative contracts to further manage our exposure to commodity price risk for the nine months ending December 31, 2018.

Commodity price risk is estimated as the potential loss in value resulting from a hypothetical 10% decline in prices over the next nine months. Based on a sensitivity analysis, a 10% decrease in prices from forecasted levels would decrease net income by approximately $9 million for natural gas and ethane and $8 million for NGLs (other than ethane) and condensate, excluding the impact of hedges, for the remaining nine months ending December 31, 2018.

Interest Rate Risk

Our current interest rate risk exposure is related primarily to our debt portfolio. Our debt portfolio is substantially comprised of fixed rate debt, which mitigates the impact of fluctuations in interest rates. Future issuances of long-term debt could be impacted by increases in interest rates, which could result in higher interest costs. Borrowings under our Revolving Credit Facility, 2015 Term Loan Agreement and any issuances under our commercial paper program are at a variable interest rate and expose us to the risk of increasing interest rates. Based upon the $1,046 million outstanding borrowings under commercial paper and the 2015 Term Loan Agreement as of March 31, 2018, and holding all other variables constant, a 100 basis-point, or 1%, increase in interest rates would increase our annual interest expense by approximately $10 million.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our chief executive officer and chief financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) under the Securities Exchange

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Act of 1934, as amended (the “Exchange Act”)) as of March 31, 2018. Based on such evaluation, our management has concluded that, as of March 31, 2018, our disclosure controls and procedures are designed and effective to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms and that information is accumulated and communicated to our management, including its principal executive officer and principal financial officer, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure.

In designing and evaluating our disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the control system will be met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events and the application of judgment in evaluating the cost-benefit relationship of possible controls and procedures. Because of these and other inherent limitations of control systems, there is only reasonable assurance that our controls will succeed in achieving their goals under all potential future conditions.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal controls over financial reporting during the quarter ended March 31, 2018, that have materially affected, or that are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Information regarding legal proceedings is set forth in Note 13 - Commitments and Contingencies to the Partnership’s condensed consolidated financial statements included in Item 1 of Part I of this Quarterly Report on Form 10-Q and is incorporated herein by reference.

Item 1A. Risk Factors

We are subject to various risks and uncertainties in the course of our business. Except as set forth below, there have been no material changes in our risk factors from those previously disclosed under “Risk Factors” in our Annual Report.

Our operations are subject to extensive regulation by federal regulatory authorities. Changes or additional regulatory measures adopted by such authorities could adversely affect our financial position, results of operations and ability to make cash distributions to unitholders.

The rates charged by several of our pipeline systems, including for interstate gas transportation service provided by our intrastate pipelines, are regulated by FERC. FERC and state regulatory agencies also regulate other terms and conditions of the services we may offer. If one of these regulatory agencies, on its own initiative or due to challenges by third parties, were to lower our tariff rates or deny any rate increase or other material changes to the types, or terms and conditions, of service we might propose or offer, the profitability of our pipeline businesses could suffer. If we were permitted to raise our tariff rates for a particular pipeline, there might be significant delay between the time the tariff rate increase is approved and the time that the rate increase actually goes into effect, which could also limit our profitability. Furthermore, competition from other pipeline systems may prevent us from raising our tariff rates even if regulatory agencies permit us to do so. The regulatory agencies that regulate our systems periodically implement new rules, regulations and terms and conditions of services subject to their jurisdiction. New initiatives or orders may adversely affect the rates charged for our services or otherwise adversely affect our financial position, results of operations and ability to make cash distributions to our unitholders.

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Our natural gas interstate pipelines are regulated by FERC under the Natural Gas Act of 1938, or NGA, the Natural Gas Policy Act of 1978, or the NGPA, and the Energy Policy Act of 2005, or EPAct of 2005. Generally, FERC’s authority over interstate natural gas transportation extends to:


•	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.

Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under EPACT 2005, FERC has civil penalty authority under the NGA and the NGPA to impose penalties for current violations of up to $1 million per day for each violation and possible criminal penalties of up to approximately $1.2 million per violation.

FERC’s jurisdiction extends to the certification and construction of interstate transportation and storage facilities, including, but not limited to expansions, lateral and other facilities and abandonment of facilities and services. Prior to commencing construction of significant new interstate transportation and storage facilities, an interstate pipeline must obtain a certificate authorizing the construction, or an order amending its existing certificate, from FERC. Certain minor expansions are authorized by blanket certificates that FERC has issued by rule. Typically, a significant expansion project requires review by a number of governmental agencies, including state and local agencies, whose cooperation is important in completing the regulatory process on schedule. Any failure by an agency to issue sufficient authorizations or permits in a timely manner for one or more of these projects may mean that we will not be able to pursue these projects or that they will be constructed in a manner or with capital requirements that we did not anticipate. Our inability to obtain sufficient permits and authorizations in a timely manner could materially and negatively impact the additional revenues expected from these projects.

FERC conducts audits to verify compliance with FERC’s regulations and the terms of its orders, including whether the websites of interstate pipelines accurately provide information on the operations and availability of services. FERC’s regulations require uniform terms and conditions for service, as set forth in agreements for transportation and storage services executed between interstate pipelines and their customers. These service agreements are required to conform, in all material respects, with the standard form of service agreements set forth in the pipeline’s FERC-approved tariff. Non-conforming agreements must be filed with, and accepted by, the FERC. In the event that FERC finds that an agreement, in whole or part, is materially non-conforming, it could reject the agreement or require us to seek modification, or alternatively require us to modify our tariff so that the non-conforming provisions are generally available to all customers.

The rates, terms and conditions for transporting natural gas in interstate commerce on certain of our intrastate pipelines and for services offered at certain of our storage facilities are subject to the jurisdiction of FERC under Section 311 of the NGPA. Rates to provide such interstate transportation service must be “fair and equitable” under the NGPA and are subject to review, refund with interest if found not to be fair and equitable, and approval by FERC at least once every five years.

Our crude oil gathering pipelines are subject to common carrier regulation by FERC under the Interstate Commerce Act, or ICA. The ICA requires that we maintain tariffs on file with FERC setting forth the rates we charge for providing transportation services, as well as the rules and regulations governing such services. The ICA requires, among other things, that our rates must be “just and reasonable” and that we provide service in a manner that is nondiscriminatory. Shippers on our crude oil gathering pipelines may protest our tariff filings, file complaints against our existing rates, or FERC can investigate our rates on its own initiative. In the event that FERC finds that our existing or proposed rates are unjust and unreasonable, it could deny requested rate increases or could order us to reduce our rates and could require the payment of reparations to complaining shippers for up to two years prior to the complaint.

On December 22, 2017, the Tax Cuts and Jobs Act of 2017 was enacted, which reduced the highest marginal United States federal corporate income tax rate from 35% to 21% for tax years beginning after December 31, 2017. In a series of related issuances on March 15, 2018, the FERC revised its policy so that it will no longer permit pipelines organized as master limited partnerships

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to recover an income tax allowance in their cost-of-service rates, and proposed rules for implementing this revised policy and the corporate income tax rate reduction pursuant to the Tax Cuts and Jobs Act of 2017 with respect to natural gas pipeline rates. The proposed rules, if they become final, would require all FERC-regulated natural gas pipelines that have cost-based rates for service to make a one-time filing providing certain financial information that will allow the FERC and other stakeholders to evaluate the impacts of the revised policy and the corporate income tax rate reduction on each individual pipeline’s rates, and to select one of four options: file a limited NGA Section 4 filing reducing its rates only as required related to the revised policy and the Tax Cuts and Jobs Act of 2017, commit to filing a general NGA Section 4 rate case in the near future, file a statement explaining why an adjustment to rates is not needed, or take no other action. Please read “Item No. 2, Recent Developments—Interstate Natural Gas Transportation Regulation”.

The FERC’s Revised Policy Statement requires the reduced maximum corporate tax rate to be reflected in initial oil cost-of-service rates and cost-of-service rate changes going forward and in future filings of Page 700 of FERC Form No. 6. FERC will consider the information provided by pipelines in Page 700 of FERC Form No. 6 in its 2020 five-year review of the oil pipeline index level. Please read “Item No. 2, Recent Developments—Interstate Natural Gas Transportation Regulation”.

We cannot predict the outcome of the NOPR, but the cost of service rates we are permitted to charge our customers for transportation and storage services could be impacted when MRT, or if EGT, files a limited or general NGA Section 4 rate filing or if the FERC or customers challenge the cost-of-service rates that EGT is authorized to charge. We also cannot predict the outcome of the 2020 oil pipeline index five-year review, but the rates we are permitted to charge our customers for cost-of-service based crude oil transportation services could be impacted. If FERC requires us to establish new tariff rates for either our natural gas or crude oil pipelines that reflect a lower federal corporate income tax rate and the Revised Policy Statement, it is possible the rates would be reduced, which could adversely affect our financial position, results of operations and ability to make cash distributions to our unitholders.

Item 5. Other Information

We are including information in this Part II. Item 5. in order to: (i) file Exhibit 99.1 hereto to replace in its entirety the section under the heading “Material U.S. Federal Income Tax Considerations” that appears in (a) the prospectus supplement we filed with the SEC on May 12, 2017 (the “ATM Prospectus”) and (b) the Registration Statement on Form S-3 (Registration File No. 333-212192) we filed with the SEC on June 23, 2016 (the “DRIP Registration Statement”), to provide updated disclosure regarding the material tax considerations associated with our operations and the purchase, ownership and disposition of our common units and (ii) provide the legal opinion of Vinson & Elkins L.L.P. relating to certain tax matters in connection with the ATM Prospectus and the DRIP Registration Statement, a copy of which is filed as Exhibit 8.1 hereto.

Item 6. Exhibits

Exhibits not incorporated by reference to a prior filing are designated by a cross (+); all exhibits not so designated are incorporated by reference to a prior filing as indicated. Management contracts and compensatory plans and arrangements are designated by a star (*).

Agreements included as exhibits are included only to provide information to investors regarding their terms. Agreements listed below may contain representations, warranties and other provisions that were made, among other things, to provide the parties thereto with specified rights and obligations and to allocate risk among them, and no such agreement should be relied upon as constituting or providing any factual disclosures about Enable Midstream Partners, LP, any other persons, any state of affairs or other matters.

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Exhibit Number	Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
2.1	Master Formation Agreement dated as of March 14, 2013 by and among CenterPoint Energy, Inc., OGE Energy Corp., Bronco Midstream Holdings, LLC and Bronco Midstream Holdings II, LLC	Registrant’s registration statement on Form S-1, filed on November 26, 2013	File No. 333-192545	Exhibit 2.1
3.1	Certificate of Limited Partnership of CenterPoint Energy Field Services LP, as amended	Registrant’s registration statement on Form S-1, filed on November 26, 2013	File No. 333-192545	Exhibit 3.1
3.2	Fifth Amended and Restated Agreement of Limited Partnership of Enable Midstream Partners, LP	Registrant’s Form 8-K filed November 15, 2017	File No. 001-36413	Exhibit 3.1
4.1	Specimen Unit Certificate representing common units (included with Second Amended and Restated Agreement of Limited Partnership of Enable Midstream Partners, LP as Exhibit A thereto)	Registrant’s Form 8-K filed April 22, 2014	File No. 001-36413	Exhibit 3.1
4.2	Indenture, dated as of May 27, 2014, between Enable Midstream Partners, LP and U.S. Bank National Association, as trustee.	Registrant’s Form 8-K filed May 29, 2014	File No. 001-36413	Exhibit 4.1
4.3	First Supplemental Indenture, dated as of May 27, 2014, by and among Enable Midstream Partners, LP, CenterPoint Energy Resources Corp., as guarantor, and U.S. Bank National Association, as trustee.	Registrant’s Form 8-K filed May 29, 2014	File No. 001-36413	Exhibit 4.2
4.4	Registration Rights Agreement, dated as of May 27, 2014, by and among Enable Midstream Partners, LP, CenterPoint Energy Resources Corp., as guarantor, 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.	Registrant’s Form 8-K filed May 29, 2014	File No. 001-36413	Exhibit 4.3
4.5	Registration Rights Agreement, dated as of February 18, 2016, by and between Enable Midstream Partners, LP and CenterPoint Energy, Inc.	Registrant’s Form 8-K filed February 19, 2016	File No. 001-36413	Exhibit 4.1
4.6	Second Supplemental Indenture, dated as of March 9, 2017, by and among Enable Midstream Partners, LP and U.S. Bank National Association, as trustee.	Registrant’s Form 8-K filed March 9, 2017	File No. 001-36413	Exhibit 4.2
+8.1	Opinion of Vinson & Elkins L.L.P. relating to tax matters.
+31.1	Rule 13a-14(a)/15d-14(a) Certification of principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
+31.2	Rule 13a-14(a)/15d-14(a) Certification of principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
+32.1	Section 1350 Certification of principal executive officer
+32.2	Section 1350 Certification of principal financial officer
+99.1	Material U.S. Federal Income Tax Considerations
+101.INS	XBRL Instance Document.
+101.SCH	XBRL Taxonomy Schema Document.
+101.PRE	XBRL Taxonomy Presentation Linkbase Document.
+101.LAB	XBRL Taxonomy Label Linkbase Document.
+101.CAL	XBRL Taxonomy Calculation Linkbase Document.
+101.DEF	XBRL Definition Linkbase Document.

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



		ENABLE MIDSTREAM PARTNERS, LP
		(Registrant)

		By: ENABLE GP, LLC
		Its general partner

Date:	May 2, 2018	By:	/s/ Tom Levescy
			Tom Levescy
			Senior Vice President, Chief Accounting Officer and Controller
			(Principal Accounting Officer)

Exhibit

Exhibit 8.1

May 2, 2018

Enable Midstream Partners, LP

211 North Robinson Avenue, Suite 150

Oklahoma City, Oklahoma 73102

Re: Enable Midstream Partners, LP Form 10-Q

Ladies and Gentlemen:

We have acted as counsel for Enable Midstream Partners, LP (the “Partnership”), a Delaware limited partnership, with respect to certain legal matters related to (i) the prospectus supplement dated May 12, 2017 related to the registration statement on Form S-3, No. 333-215670 (the “ATM Prospectus”), (ii) the registration statement on Form S-3, No. 333-212192, dated June 23, 2016 (the “DRIP Registration Statement”) and (iii) the Exhibit 99.1 filed as an exhibit to the 10-Q filed on or about the date hereof (the “Updated Tax Disclosure” together with the ATM Prospectus and the DRIP Registration Statement, the “Applicable Filings”). In connection with the Applicable Filings, we are issuing this opinion.

This opinion is based on various facts and assumptions, and is conditioned upon certain representations made by the Partnership as to factual matters through a certificate of an officer of the Partnership (the “Officer’s Certificate”). In addition, this opinion is based upon the factual representations of the Partnership concerning its business, properties and governing documents as set forth in the Applicable Filings.

In our capacity as counsel to the Partnership, we have made such legal and factual examinations and inquiries, including an examination of originals or copies certified or otherwise identified to our satisfaction of such documents, corporate records and other instruments, as we have deemed necessary or appropriate for purposes of this opinion. In our examination, we have assumed the authenticity of all documents submitted to us as originals, the genuineness of all signatures thereon, the legal capacity of natural persons executing such documents and the conformity to authentic original documents of all documents submitted to us as copies. For the purpose of our opinion, we have not made an independent investigation or audit of the facts set forth in the above-referenced documents or in the Officer’s Certificate. In addition, in rendering this opinion we have assumed the truth and accuracy of all representations and statements made to us which are qualified as to knowledge or belief, without regard to such qualification.



Vinson & Elkins LLP Attorneys at Law Austin Beijing Dallas Dubai Hong Kong Houston London Moscow New York Palo Alto Richmond Riyadh San Francisco Taipei Tokyo Washington	1001 Fannin Street, Suite 2500 Houston, TX 77002-6760 Tel +1.713.758.2222 Fax +1.713.758.2346 www.velaw.com

Exhibit 8.1

We hereby confirm that all statements of legal conclusions contained in the discussion in the ATM Prospectus under the caption “Material U.S. Federal Income Tax Considerations” and the DRIP Registration Statement under the caption “Material U.S. Federal Income Tax Considerations,” both, as are replaced in their entirety by the Updated Tax Disclosure, (collectively, the “Covered Discussions”) constitute the opinion of Vinson & Elkins L.L.P. with respect to the matters set forth therein as of the date hereof, subject to the assumptions, qualifications, and limitations set forth therein. This opinion is based on various statutory provisions, regulations promulgated thereunder and interpretations thereof by the Internal Revenue Service and the courts having jurisdiction over such matters, all of which are subject to change either prospectively or retroactively. Also, any variation or difference in the facts from those set forth in the representations described above, including in the Applicable Filings and the Officer’s Certificate, may affect the conclusions stated herein.

No opinion is expressed as to any matter not discussed in the Covered Discussions. We are opining herein only as to the federal income tax matters described above, and we express no opinion with respect to the applicability to, or the effect on, any transaction or other federal laws, foreign laws, the laws of any state or any other jurisdiction or as to any matters of municipal law or the laws of any other local agencies within any state.

This opinion is rendered to you as of the date hereof, and we undertake no obligation to update this opinion subsequent to the date hereof. This opinion is furnished to you and may be relied on by you in connection with the transactions set forth in the ATM Prospectus and the DRIP Registration Statement. In addition, this opinion may be relied on by persons entitled to rely on it pursuant to applicable provisions of federal securities law, including persons purchasing common units pursuant to the ATM Prospectus and the DRIP Registration Statement. However, this opinion may not be relied upon for any other purpose or furnished to, assigned to, quoted to or relied upon by any other person, firm or other entity, for any purpose, without our prior written consent.

We hereby consent to the filing of this opinion of counsel as Exhibit 8.1 to the Form 10-Q, to the incorporation by reference of this opinion of counsel into the DRIP Registration Statement and to the reference to our firm in the Applicable Filings. In giving such consent, we do not admit that we are within the category of persons whose consent is required under Section 7 of the Securities Act of 1933, as amended.

Very truly yours,

/s/ VINSON & ELKINS L.L.P.

Vinson & Elkins L.L.P.

Exhibit

Exhibit 31.1

CERTIFICATIONS

I, Rodney J. Sailor, certify that:

1. I have reviewed this Annual Report on Form 10-Q of Enable Midstream Partners, LP;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


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

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):


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.

Date: May 2, 2018




	/s/ Rodney J. Sailor
	Rodney J. Sailor
	President and Chief Executive Officer, Enable GP, LLC, the General Partner of Enable Midstream Partners, LP
	(Principal Executive Officer)

Exhibit

Exhibit 31.2

CERTIFICATIONS

I, John P. Laws, certify that:

1. I have reviewed this Annual Report on Form 10-Q of Enable Midstream Partners, LP;


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.

Date: May 2, 2018




	/s/ John P. Laws
	John P. Laws
	Executive Vice President, Chief Financial Officer, and Treasurer, Enable GP, LLC, the General Partner of Enable Midstream Partners, LP
	(Principal Financial Officer)

Exhibit

Exhibit 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Enable Midstream Partners, LP (the Partnership) on Form 10-Q for the period ended March 31, 2018, as filed with the Securities and Exchange Commission (the Report), I, Rodney J. Sailor, President and Chief Executive Officer of Enable GP, LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: May 2, 2018




	/s/ Rodney J. Sailor
	Rodney J. Sailor
	President and Chief Executive Officer, Enable GP, LLC, the General Partner of Enable Midstream Partners, LP
	(Principal Executive Officer)

Exhibit

Exhibit 32.2

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Enable Midstream Partners, LP (the Partnership) on Form 10-Q for the period ended March 31, 2018, as filed with the Securities and Exchange Commission (the Report), I, John P. Laws, Executive Vice President, Chief Financial Officer, and Treasurer of Enable GP, LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: May 2, 2018




	/s/ John P. Laws
	John P. Laws
	Executive Vice President, Chief Financial Officer, and Treasurer, Enable GP, LLC, the General Partner of Enable Midstream Partners, LP
	(Principal Financial Officer)

Exhibit

Exhibit 99.1

MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS

This section summarizes certain U.S. federal income tax consequences that may be relevant to prospective unitholders and is based upon current provisions of the Internal Revenue Code of 1986, as amended (the “Code”), existing and proposed Treasury Regulations thereunder (the “Treasury Regulations”), and current administrative rulings and court decisions, all of which are subject to change. Changes in these authorities may cause the U.S. federal income tax consequences to a prospective unitholder to vary substantially from those described below, possibly on a retroactive basis. Unless the context otherwise requires, references in this section to “we,” “us” or “the Partnership” are references to Enable Midstream Partners, LP and its subsidiaries.

Legal conclusions contained in this section, unless otherwise noted, are the opinion of Vinson & Elkins L.L.P. and are based on the accuracy of representations made by us to them for this purpose. However, this section does not address all U.S. federal income tax matters that affect us or our unitholders, such as the application of the alternative minimum tax. This section also does not address local taxes, state taxes, non-U.S. taxes, or other taxes that may be applicable, except to the limited extent that such tax considerations are addressed below under “—State Local and Other Tax Considerations.” Furthermore, this section focuses on unitholders who are individual citizens or residents of the United States (for U.S. federal income tax purposes), who have the U.S. dollar as their functional currency, who use the calendar year as their taxable year, who purchase units, who do not materially participate in the conduct of our business activities and who hold such units as capital assets (generally, property that is held for investment). This section has limited applicability to corporations (including other entities treated as corporations for U.S. federal income tax purposes), partnerships (including other entities treated as partnerships for U.S. federal income tax purposes), estates, trusts, non-resident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, non-U.S. persons, persons subject to special tax accounting rules as a result of any item of gross income with respect to our common units being taken into account in an applicable financial statement, individual retirement accounts (“IRAs”), employee benefit plans, banks, insurance companies and other financial institutions, real estate investment trusts or mutual funds.

Accordingly, we encourage each prospective unitholder to consult the unitholder’s own tax advisor in analyzing the federal, state, local and non-U.S. tax consequences particular to that unitholder resulting from ownership or disposition of our units and potential changes in applicable tax laws, including the impact of recently enacted U.S. tax legislation.

We have requested and received a private letter ruling from the IRS to the effect that certain of our income constitutes qualifying income, as described further below. In addition, we are relying on opinions and advice of Vinson & Elkins L.L.P. with respect to the matters described herein. An opinion of counsel represents only that counsel’s best legal judgment and does not bind the Internal Revenue Service (the “IRS”) or a court. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any such contest of the matters described herein may materially and adversely impact the market for units and the prices at which our units trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders because the costs will reduce our cash available for distribution. Furthermore, the tax consequences of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions, which may be retroactively applied.

For the reasons described below, Vinson & Elkins L.L.P. has not rendered an opinion with respect to the following U.S. federal income tax issues:


•	the treatment of a unitholder whose units are the subject of a securities loan (e.g., a loan to a short seller to cover a short sale of units) (please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction—Treatment of Securities Loans”);


•	whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “—Disposition of Units—Allocations Between Transferors and Transferees”);

II-1

Exhibit 99.1


•	whether our method for taking into account Section 743 adjustments is sustainable in certain cases (please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction—Section 754 Election” and “—Uniformity of Units”); and


•	whether our use of simplifying conventions for making adjustments to “book” basis and relevant allocations is permitted by existing Treasury Regulations (please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction” and “—Uniformity of Units”).

Taxation of the Partnership

Partnership Status

We are treated as a partnership for U.S. federal income tax purposes and, therefore, subject to the discussion below under “—Administrative Matters—Information Returns and Audit Procedures,” generally will not be liable for entity-level U.S. federal income taxes. Instead, as described below, each of our unitholders will take into account its respective share of our items of income, gain, loss and deduction in computing its U.S. federal income tax liability as if the unitholder had earned such income directly, even if we make no cash distributions to the unitholder. Distributions we make to a unitholder will not give rise to income or gain taxable to such unitholder, unless the amount of cash distributed exceeds the unitholder’s adjusted tax basis in its units. Please read “—Tax Consequences of Unit Ownership—Treatment of Distributions” and “—Disposition of Units”).

Section 7704 of the Code generally provides that publicly-traded partnerships will be treated as corporations for U.S. federal income tax purposes. However, if 90% or more of a partnership’s gross income for every taxable year it is publicly-traded consists of “qualifying income,” the Partnership may continue to be treated as a partnership for U.S. federal income tax purposes (the “Qualifying Income Exception”). Qualifying income includes income and gains derived from the exploration, development, production, transportation, storage, processing and marketing of certain natural resources, including crude oil, natural gas and products thereof, as well as other types of income such as interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than 5% of our current gross income is not qualifying income; however, this estimate could change from time to time.

No ruling has been or will be requested from the IRS regarding our treatment as a partnership for U.S. federal income tax purposes. Instead, we are relying on opinions and advice of Vinson & Elkins L.L.P. with respect to matters described herein. Based upon factual representations made by us and our general partner, Vinson & Elkins L.L.P. is of the opinion that we will be treated as a partnership for U.S. federal income tax purposes and each of our partnership or limited liability company operating subsidiaries, other than those that have been identified as corporations to Vinson & Elkins L.L.P., will be treated as a partnership or will be disregarded as an entity separate from us for U.S. federal income tax purposes. The representations made by us and our general partner upon which Vinson & Elkins L.L.P. has relied in rendering its opinion include, without limitation:

(a) Neither we nor any of our partnership or limited liability company operating subsidiaries, other than those that have been identified as corporations to Vinson & Elkins L.L.P., has elected or will elect to be treated as a corporation for U.S. federal income tax purposes; and

(b) For each taxable year since and including the year of our initial public offering, more than 90% of our gross income has been and will be income of a character that Vinson & Elkins L.L.P. has opined is “qualifying income” within the meaning of Section 7704(d) of the Code.

(c) Each hedging transaction that we treat as resulting in qualifying income has been and will be appropriately identified as a hedging transaction pursuant to applicable Treasury Regulations, and has been and will be associated with oil, natural gas or products thereof that are held or to be held by us in activities that Vinson & Elkins L.L.P. has opined or will opine result in qualifying income.

We believe that these representations are true and will be true in the future.

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Exhibit 99.1

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as transferring all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation and then as distributing that stock to our unitholders in liquidation. This deemed contribution and liquidation should not result in the recognition of taxable income by our unitholders or us so long as our liabilities do not exceed the tax basis of our assets. Thereafter, we would be treated as an association taxable as a corporation for U.S. federal income tax purposes.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative or legislative action or judicial interpretation at any time. For example, from time to time, members of the U.S. Congress and the President propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships, including the elimination of the Qualifying Income Exception upon which we rely for our treatment as a partnership for U.S. federal income tax purposes.

In addition, on January 24, 2017, final regulations regarding which activities give rise to qualifying income (the “Final Regulations”) were published in the Federal Register. The Final Regulations were effective as of January 19, 2017, and apply to taxable years beginning on or after January 19, 2017. We do not believe the Final Regulations affect our ability to qualify as a publicly traded partnership.

At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, or other forms of taxation. Imposition of a similar tax on us in the jurisdictions in which we operate or in other jurisdictions to which we may expand could substantially reduce our cash available for distribution to our unitholders.

It is possible that a change in law could affect us and may be applied retroactively. Any such changes could negatively impact the value of an investment in our units. If for any reason we are taxable as a corporation in any taxable year, our items of income, gain, loss and deduction would be taken into account by us in determining the amount of our liability for U.S. federal income tax, rather than being passed through to our unitholders. Our taxation as a corporation would materially reduce the cash available for distribution to unitholders and thus would likely substantially reduce the value of our units. Any distribution made to a unitholder at a time we are treated as a corporation would be (i) a taxable dividend to the extent of our current or accumulated earnings and profits, then (ii) a nontaxable return of capital to the extent of the unitholder’s tax basis in its units, and thereafter (iii) taxable capital gain.

The remainder of this discussion is based on the opinion of Vinson & Elkins L.L.P. that we will be treated as a partnership for U.S. federal income tax purposes.

Tax Consequences of Unit Ownership

Limited Partner Status

Unitholders of the Partnership who are admitted as limited partners of the Partnership, and unitholders whose units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their units will be treated as partners of the Partnership for U.S. federal income tax purposes.

In addition, a beneficial owner of units whose units have been transferred to a short seller to complete a short sale would appear to lose status as a partner with respect to such units for U.S. federal income tax purposes. Please read “—Tax Consequences of Unit Ownership—Treatment of Securities Loans.”

Income, gain, deductions or losses would not appear to be reportable by a unitholder who is not a partner for U.S. federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for U.S. federal income tax purposes would therefore appear to be fully taxable as ordinary income. A unitholder who is not

II-3

Exhibit 99.1

treated as a partner in us as described above is urged to consult its own tax advisors with respect to the tax consequences applicable to such unitholder under its particular circumstances.

Flow-Through of Taxable Income

Subject to the discussion below under “—Entity-Level Collections of Unitholder Taxes” and “—Administrative Matters—Information Returns and Audit Procedures” with respect to payments we may be required to make on behalf of our unitholders, we will not pay any U.S. federal income tax. Rather, each unitholder will be required to report on its U.S. federal income tax return each year its share of our income, gains, losses and deductions for our taxable year or years ending with or within its taxable year. Except as described below under “—Treatment of Distributions,” participants in our distribution reinvestment plan (“DRIP”) will be allocated taxable income and loss in the same manner as all other unitholders even if they elect to reinvest their entire cash distribution. Consequently, we may allocate income to a unitholder even if that unitholder has not received a cash distribution. The income we allocate to unitholders will generally be taxable as ordinary income. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.

Basis of Units

A unitholder’s tax basis in its units initially will be the amount paid or treated as paid for those units increased by the unitholder’s initial allocable share of our nonrecourse liabilities. That basis generally will be (i) increased by the unitholder’s share of our income, any increases in such unitholder’s share of our nonrecourse liabilities and, on the disposition of a common unit, such unitholder’s share of certain items related to business interest not yet deductible by the unitholder due to applicable limitations (please read “—Limitations on Deduction of Interest”), and (ii) decreased, but not below zero, by the amount of all distributions to the unitholder, the unitholder’s share of our losses, the unitholder’s share of certain items related to the limitations on the deduction of business interest and any decreases in the unitholder’s share of our nonrecourse liabilities and its share of our expenditures that are neither deductible nor required to be capitalized. The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all of those interests.

Treatment of Distributions

Distributions made by us to a unitholder generally will not be taxable to the unitholder, unless such distributions are of cash or marketable securities that are treated as cash and exceed the unitholder’s tax basis in its units, in which case the unitholder generally will recognize gain taxable in the manner described below under “—Disposition of Units.”

If, and to the extent that, a unitholder participates in our DRIP, such unitholder will receive common units in lieu of all or a portion of any cash distributions it would otherwise receive from us. The tax consequences of such participation are generally expected to be the same to the DRIP participants as if they had received their cash distributions paid to the unitholders and then used these cash distributions to purchase additional common units either from us or on the open market, depending on how we instruct the DRIP administrator to reinvest the distributions subject to our DRIP. If a participant in our DRIP is deemed to have purchased additional common units at a discount, it may be necessary to allocate income to such participant in our DRIP in order to preserve the uniformity of our units. Accordingly, a participant in our DRIP may recognize income in the amount of the discount.

Any reduction in a unitholder’s share of our “nonrecourse liabilities” (liabilities for which no partner bears the economic risk of loss) will be treated as a distribution by us of cash to that unitholder. A decrease in a unitholder’s percentage interest in us because of our issuance of additional units may decrease such unitholder’s share of our nonrecourse liabilities. For purposes of the foregoing, a unitholder’s share of our nonrecourse liabilities generally will be based upon that unitholder’s share of the unrealized appreciation (or depreciation) in our assets, to the extent thereof, with any excess liabilities allocated based on the unitholder’s share of our profits. Please read “—Disposition of Units.”

II-4

Exhibit 99.1

A non-pro rata distribution of money or property (including a deemed distribution as a result of the reallocation of our liabilities described above) may cause a unitholder to recognize ordinary income, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture and substantially appreciated “inventory items,” both as defined in Section 751 of the Code (“Section 751 Assets”). To the extent of such reduction, the unitholder would be deemed to receive its proportionate share of the Section 751 Assets and exchange such assets with us in return for a portion of the non-pro rata distribution. This deemed exchange generally will result in the unitholder’s recognition of ordinary income in an amount equal to the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis (generally zero) in the Section 751 Assets deemed to be relinquished in the exchange.

Limitations on Deductibility of Losses

A unitholder may not be entitled to deduct the full amount of loss we allocate to it because its share of our losses will be limited to the lesser of (i) the unitholder’s adjusted tax basis in its units, and (ii) in the case of a unitholder that is an individual, estate, trust or certain types of closely-held corporations, the amount for which the unitholder is considered to be “at risk” with respect to our activities. A unitholder will be at risk to the extent of its adjusted tax basis in its units, reduced by (1) any portion of that basis attributable to the unitholder’s share of our nonrecourse liabilities, (2) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or similar arrangement, and (3) any amount of money the unitholder borrows to acquire or hold its units, if the lender of those borrowed funds owns an interest in us, is related to another unitholder or can look only to the units for repayment. A unitholder subject to the at risk limitation must recapture losses deducted in previous years to the extent that distributions (including distributions deemed to result from a reduction in a unitholder’s share of nonrecourse liabilities) cause the unitholder’s at risk amount to be less than zero at the end of any taxable year.

Losses disallowed to a unitholder or recaptured as a result of the basis or at risk limitations will carry forward and will be allowable as a deduction in a later year to the extent that the unitholder’s adjusted tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon a taxable disposition of units, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but not losses suspended by the basis limitation. Any loss previously suspended by the at risk limitation in excess of that gain can no longer be used, and will not be available to offset a unitholder’s salary or active business income.

In addition to the basis and at risk limitations, a passive activity loss limitation limits the deductibility of losses incurred by individuals, estates, trusts, some closely-held corporations and personal service corporations from “passive activities” (such as, trade or business activities in which the taxpayer does not materially participate). The passive loss limitations are applied separately with respect to each publicly-traded partnership. Consequently, any passive losses we generate will be available to offset only passive income generated by us. Passive losses that exceed a unitholder’s share of passive income we generate may be deducted in full when the unitholder disposes of all of its units in a fully taxable transaction with an unrelated party. The passive activity loss rules are applied after other applicable limitations on deductions, including the at risk and basis limitations.

A unitholder’s share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.

For taxpayers other than corporations in taxable years beginning after December 31, 2017, and before January 1, 2026, an “excess business loss” limitation further limits the deductibility of losses by such taxpayers. An excess business loss is the excess (if any) of a taxpayer’s aggregate deductions for the taxable year that are attributable to the trades or businesses of such taxpayer (determined without regard to the excess business loss limitation) over the aggregate gross income or gain of such taxpayer for the taxable year that is attributable to such trades or businesses plus a threshold amount. The threshold amount is equal to $250,000 or $500,000 for taxpayers filing a joint return. Disallowed excess business losses are treated as a net operating loss carryover to the following tax year. Any losses we generate that are allocated to a unitholder and not otherwise limited by the basis, at risk, or passive loss limitations will be included in the determination of such unitholder’s aggregate trade or business deductions. Consequently, any losses we generate that are not otherwise limited will only be available to offset a unitholder’s

II-5

Exhibit 99.1

other trade or business income plus an amount of non-trade or business income equal to the applicable threshold amount. Thus, except to the extent of the threshold amount, our losses that are not otherwise limited may not offset a unitholder’s non-trade or business income (such as salaries, fees, interest, dividends and capital gains). This excess business loss limitation will be applied after the passive activity loss limitation.

Limitations on Interest Deductions

In general, deductions for interest paid or accrued on indebtedness properly allocable to a trade or business that would otherwise be deductible in a taxable year beginning on or after January 1, 2018 are limited to the sum of business interest income and 30% of a business’s “adjusted taxable income” for such year. For the purposes of this limitation, adjusted taxable income is computed without regard to any business interest or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion. A portion of our trade or business interest deductions are not expected to be subject to these interest deduction limitations as a result of an exemption that applies to interest deductions for, among other things, regulated natural gas pipelines.

To the extent our deduction for business interest is not limited, we will allocate the full amount of our deduction for business interest among our unitholders in accordance with their percentage interests in us. To the extent our deduction for business interest is limited, the amount of any disallowed deduction for business interest will also be allocated to each unitholder in accordance with their percentage interest in us, but such amount of “excess business interest” will not be currently deductible. Subject to certain limitations and adjustments to a unitholder’s basis in its units, this excess business interest may be carried forward and deducted by a unitholder in a future taxable year.

In addition to this limitation of the deductibility of a partnership’s business interest, the deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:


•	interest on indebtedness allocable to property held for investment;


•	interest expense attributed to portfolio income; and


•	the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income. Net investment income generally does not include qualified dividend income (if applicable) or gains attributable to the disposition of property held for investment. A unitholder’s share of a publicly-traded partnership’s portfolio income and, according to the IRS, net passive income will be treated as investment income for purposes of the investment interest expense limitation.

Entity-Level Collections of Unitholder Taxes

If we are required or elect under applicable law to pay any federal, state, local or non-U.S. tax on behalf of any current or former unitholder or our general partner, our partnership agreement authorizes us to treat the payment as a distribution of cash to the relevant unitholder or general partner. Where the tax is payable on behalf of all unitholders or we cannot determine the specific unitholder on whose behalf the tax is payable, our partnership agreement authorizes us to treat the payment as a distribution to all current unitholders. Payments by us as described above could give rise to an overpayment of tax on behalf of a unitholder, in which event the unitholder may be entitled to claim a refund of the overpayment amount. Please read “—Administrative Matters—Information Returns and Audit Procedures.” Unitholders are urged to consult their tax advisors to determine the consequences to them of any tax payment we make on their behalf.

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Exhibit 99.1

Allocation of Income, Gain, Loss and Deduction

In general, if we have a net profit, our items of income, gain, loss and deduction generally will be allocated amongst our unitholders in accordance with their percentage interests in us. At any time that we make incentive distributions, gross income will be allocated to the recipients to the extent of these distributions.

Specified items of our income, gain, loss and deduction will be allocated under Section 704(c) of the Code (or the principles of Section 704(c) of the Code) to account for any difference between the tax basis and fair market value of our assets at the time such assets are contributed to us and at the time of any subsequent offering of our units (a “Book-Tax Disparity”). As a result, the U.S. federal income tax burden associated with any Book-Tax Disparity immediately prior to an offering generally will be borne by our partners holding interests in us prior to such offering. In addition, items of recapture income will be specially allocated to the extent possible to the unitholder who was allocated the deduction giving rise to that recapture income in order to minimize the recognition of ordinary income by other unitholders.

It may not be administratively feasible to make the relevant adjustments to “book” basis and the relevant Section 704(c) allocations separately each time we issue units, particularly in the case of small or frequent unit issuances. If that is the case, we may use simplifying conventions to make those adjustments and allocations, which may include the aggregation of certain issuances of units. Our counsel, Vinson & Elkins, L.L.P., is unable to opine as to the validity of such conventions.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Code to eliminate a Book-Tax Disparity, will generally be given effect for U.S. federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has “substantial economic effect.” In any other case, a partner’s share of an item will be determined on the basis of the partner’s interest in us, which will be determined by taking into account all the facts and circumstances, including (i) the partner’s relative contributions to us, (ii) the interests of all the partners in profits and losses, (iii) the interest of all the partners in cash flow and (iv) the rights of all the partners to distributions of capital upon liquidation. Vinson & Elkins L.L.P. is of the opinion that, with the exception of the issues described in “—Section 754 Election,” “—Disposition of Units—Allocations Between Transferors and Transferees,” and “—Uniformity of Units,” allocations of income, gain, loss or deduction under our partnership agreement will be given effect for U.S. federal income tax purposes.

Treatment of Securities Loans

A unitholder whose units are loaned (for example, a loan to “short seller” to cover a short sale of units) may be treated as having disposed of those units. If so, such unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period (i) any of our income, gain, loss or deduction allocated to those units would not be reportable by the lending unitholder, and (ii) any cash distributions received by the lending unitholder as to those units may be treated as ordinary taxable income.

Due to a lack of controlling authority, Vinson & Elkins L.L.P. has not rendered an opinion regarding the tax treatment of a unitholder that enters into a securities loan with respect to its units. Unitholders desiring to assure their status as partners and avoid the risk of income recognition from a loan of their units are urged to consult their own tax advisors and to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and lending their units. The IRS has announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please read “—Disposition of Units—Recognition of Gain or Loss.”

Tax Rates

Under current law, the highest marginal U.S. federal income tax rates for individuals applicable to ordinary income and long-term capital gains (generally, gains from the sale or exchange of certain investment assets held for more than one year) are 37% and 20%, respectively. These rates are subject to change by new legislation at any time.

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Exhibit 99.1

In addition, a 3.8% net investment income tax (“NIIT”) applies to certain net investment income earned by individuals, estates, and trusts. For these purposes, net investment income generally includes a unitholder’s allocable share of our income and gain realized by a unitholder from a sale of units. In the case of an individual, the tax will be imposed on the lesser of (i) the unitholder’s net investment income from all investments, or (ii) the amount by which the unitholder’s modified adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or a surviving spouse), $125,000 (if married filing separately) or $200,000 (if the unitholder is unmarried or in any other case). In the case of an estate or trust, the tax will be imposed on the lesser of (i) undistributed net investment income, or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

For taxable years beginning after December 31, 2017 and ending on or before December 31, 2025, an individual unitholder is entitled to a deduction equal to 20% of his or her allocable share of our “qualified business income.” For purposes of this deduction, our “qualified business income” is equal to the sum of:


•	the net amount of our U.S. items of income, gain, deduction, and loss to the extent such items are included or allowed in the determination of taxable income for the year, excluding, however, certain specified types of passive investment income (such as capital gains and dividends) and certain payments made to the unitholder for services rendered to the Partnership; and


•	any gain recognized upon a disposition of our units to the extent such gain is attributable to Section 751 Assets, such as depreciation recapture and our “inventory items,” and is thus treated as ordinary income under Section 751 of the Code.

Section 754 Election

We have made the election permitted by Section 754 of the Code that permits us to adjust the tax bases in our assets as to specific purchasers of our units under Section 743(b) of the Code to reflect the unit purchase price upon subsequent purchases of units. That election is irrevocable without the consent of the IRS. The Section 743(b) adjustment separately applies to each purchaser of units based upon the values and bases of our assets at the time of the relevant purchase, and the adjustment will reflect the purchase price paid. The Section 743(b) adjustment does not apply to a person who purchases units directly from us. For purposes of this discussion, a unitholder’s basis in our assets will be considered to have two components: (1) its share of the tax basis in our assets as to all unitholders and (2) its Section 743(b) adjustment to that tax basis (which may be positive or negative).

Under our partnership agreement, we are authorized to take a position to preserve the uniformity of units even if that position is not consistent with applicable Treasury Regulations. A literal application of Treasury Regulations governing a 743(b) adjustment attributable to properties depreciable under Section 167 of the Code may give rise to differences in the taxation of unitholders purchasing units from us and unitholders purchasing from other unitholders. If we have any such properties, we intend to adopt methods employed by other publicly traded partnerships to preserve the uniformity of units, even if inconsistent with existing Treasury Regulations, and Vinson & Elkins L.L.P. has not opined on the validity of this approach. Please read “—Uniformity of Units.”

The IRS may challenge our positions with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of units due to lack of controlling authority. Because a unitholder’s tax basis for its units is reduced by its share of our items of deduction or loss, any position we take that understates deductions will overstate a unitholder’s basis in its units, and may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “—Disposition of Units—Recognition of Gain or Loss.” If a challenge to such treatment were sustained, the gain from the sale of units may be increased without the benefit of additional deductions.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. The IRS could seek to reallocate some or all of any Section 743(b) adjustment we allocated to our assets subject to depreciation to goodwill or nondepreciable assets. Goodwill, as an intangible asset, is generally amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure any unitholder that the determinations we make will not be successfully

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Exhibit 99.1

challenged by the IRS or that the resulting deductions will not be reduced or disallowed altogether. Should the IRS require a different tax basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than it would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year

We use the year ending December 31 as our taxable year and the accrual method of accounting for U.S. federal income tax purposes. Each unitholder will be required to include in its tax return its share of our income, gain, loss and deduction for each taxable year ending within or with its taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of its units following the close of our taxable year but before the close of its taxable year must include its share of our income, gain, loss and deduction in income for its taxable year, with the result that it will be required to include in income for its taxable year its share of more than twelve months of our income, gain, loss and deduction. Please read “—Disposition of Units—Allocations Between Transferors and Transferees.”

Tax Basis, Depreciation and Amortization

The tax basis of each of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of those assets. If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation deductions previously taken, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of its interest in us. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction.”

Valuation and Tax Basis of Our Properties

The U.S. federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values and the tax bases of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates and tax basis determinations ourselves. These estimates and determinations of tax basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deduction previously reported by unitholders could change, and unitholders could be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Units

Recognition of Gain or Loss

A unitholder will be required to recognize gain or loss on a sale of units equal to the difference between the unitholder’s amount realized and tax basis in the units sold. A unitholder’s amount realized generally will equal the sum of the cash and the fair market value of other property it receives plus its share of our nonrecourse liabilities with respect to the units sold. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Prior distributions from us that in the aggregate were in excess of cumulative net taxable income for a common unit and, therefore, decreased a unitholder’s tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder’s tax basis in that common unit, even if the price received is less than his original cost.

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Exhibit 99.1

Except as noted below, gain or loss recognized by a unitholder on the sale or exchange of a unit held for more than one year generally will be taxable as long-term capital gain or loss. However, gain or loss recognized on the disposition of units will be separately computed and taxed as ordinary income or loss under Section 751 of the Code to the extent attributable to Section 751 Assets, such as depreciation recapture and our “inventory items,” regardless of whether such inventory item is substantially appreciated in value. Ordinary income attributable to Section 751 Assets may exceed net taxable gain realized on the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and capital gain or loss upon a sale of units. Net capital loss may offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. Both ordinary income and capital gain recognized may be subject to the NIIT in certain circumstances. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction—Tax Rates.”

For purposes of calculating gain or loss on the sale of units, the unitholder’s adjusted tax basis will be adjusted by its allocable share of our income or loss in respect of its units for the year of the sale. Furthermore, as described above, the IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all of those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in its entire interest in the Partnership as the value of the interest sold bears to the value of the partner’s entire interest in the Partnership.

Treasury Regulations under Section 1223 of the Code allow a selling unitholder who can identify units transferred with an ascertainable holding period to elect to use the actual holding period of the units transferred. Thus, according to the ruling discussed in the paragraph above, a unitholder will be unable to select high or low basis units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, it may designate specific units sold for purposes of determining the holding period of the units transferred. A unitholder electing to use the actual holding period of units transferred must consistently use that identification method for all subsequent sales or exchanges of our units. A unitholder considering the purchase of additional units or a sale of units purchased in separate transactions is urged to consult its tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

Specific provisions of the Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” financial position, including a partnership interest with respect to which gain would be recognized if it were sold, assigned or terminated at its fair market value, in the event the taxpayer or a related person enters into:


•	a short sale;


•	an offsetting notional principal contract; or


•	a futures or forward contract with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is authorized to issue Treasury Regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees

In general, our taxable income or loss will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month (the “Allocation Date”). Nevertheless, we allocate certain deductions for depreciation of capital additions based upon the date the underlying

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Exhibit 99.1

property is placed in service, and gain or loss realized on a sale or other disposition of our assets or, in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction will be allocated among the unitholders on the Allocation Date in the month in which such income, gain, loss or deduction is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although simplifying conventions are contemplated by the Code and most publicly traded partnerships use similar simplifying conventions, existing Treasury Regulations do not specifically authorize the use of the proration method we have adopted. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the validity of this method of allocating income and deductions between transferee and transferor unitholders. If the IRS determines that this method is not allowed under the Treasury Regulations our taxable income or losses could be reallocated among our unitholders. Under our partnership agreement, we are authorized to revise our method of allocation between transferee and transferor unitholders, as well as among unitholders whose interests vary during a taxable year, to conform to a method permitted under the Treasury Regulations.

A unitholder who disposes of units prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deduction attributable to the month of disposition but will not be entitled to receive a cash distribution for that period.

Notification Requirements

A unitholder who sells or purchases any of its units is generally required to notify us in writing of that transaction within 30 days after the transaction (or, if earlier, January 15 of the year following the transaction in the case of a seller). Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a transfer of units may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale through a broker who will satisfy such requirements.

Uniformity of Units

Because we cannot match transferors and transferees of units and other reasons, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of U.S. federal income tax requirements. Any non-uniformity could have a negative impact on the value of the units. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction—Section 754 Election.”

Our partnership agreement permits our general partner to take positions in filing our tax returns that preserve the uniformity of our units. These positions may include reducing the depreciation, amortization or loss deductions to which a unitholder would otherwise be entitled or reporting a slower amortization of Section 743(b) adjustments for some unitholders than that to which they would otherwise be entitled. Vinson & Elkins L.L.P. is unable to opine as to the validity of such filing positions.

A unitholder’s adjusted tax basis in units is reduced by its share of our deductions (whether or not such deductions were claimed on an individual income tax return) so that any position that we take that understates deductions will overstate the unitholder’s basis in its units, and may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “—Disposition of Units—Recognition of Gain or Loss” above and “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction—Section 754 Election” above. The IRS may challenge one or more of any positions we take to preserve the uniformity of units. If such a challenge were sustained, the uniformity of units might be affected, and, under some circumstances, the gain from the sale of units might be increased without the benefit of additional deductions.

In addition, as described above at “—Tax Consequences of Unit Ownership–Allocation of Income, Gain, Loss and Deduction,” if we aggregate multiple issuances of units for purposes of making adjustments to “book” basis and related tax allocations, we will treat each of our units as having the same capital account balance, regardless of the

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Exhibit 99.1

price actually paid by each purchaser of units in the aggregated offerings. Our counsel, Vinson & Elkins L.L.P., is unable to opine as to the validity of such an approach. We do not expect the number of affected units, or the differences between the purchase price of a unit and the initial capital account balance assigned to the unit, to be material, and we do not expect this convention to have a material effect upon the trading of our units.

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans and other tax-exempt organizations as well as by non-resident alien individuals, non-U.S. corporations and other non-U.S. persons (collectively, “Non-U.S. Unitholders”) raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them. Prospective unitholders that are tax-exempt entities or Non-U.S. Unitholders should consult their tax advisors before investing in our units.

Employee benefit plans and most other tax-exempt organizations, including IRAs and other retirement plans, are subject to U.S. federal income tax on unrelated business taxable income. Virtually all of our income will be unrelated business taxable income and will be taxable to a tax-exempt unitholder. Tax-exempt unitholders with more than one unrelated trade or business (including by attribution from investment in the Partnership to the extent it is engaged in one or more unrelated trades or businesses) are required to separately compute their unrelated business taxable income with respect to each trade or business (including for purposes of determining any net operating loss deduction). As a result, it may not be possible for tax-exempt unitholders to utilize losses from an investment in the Partnership to offset unrelated business taxable income from another unrelated trade or business and vice versa.

Non-U.S. Unitholders are taxed by the United States on income effectively connected with the conduct of a U.S. trade or business (“effectively connected income”) and on certain types of U.S.-source non-effectively connected income (such as dividends), unless exempted or further limited by an income tax treaty will be considered to be engaged in business in the United States because of their ownership of our units. Furthermore, it is probable that they will be deemed to conduct such activities through permanent establishments in the United States within the meaning of applicable tax treaties. Consequently, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay U.S. federal income tax on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, distributions to Non-U.S. Unitholders are subject to withholding at the highest applicable effective tax rate. Each Non-U.S. Unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN, W-8BEN-E, or applicable substitute form in order to obtain credit for these withholding taxes.

In addition, because a Non-U.S. Unitholder classified as a corporation will be treated as engaged in a United States trade or business, that corporation may be subject to the U.S. branch profits tax at a rate of 30%, in addition to regular U.S. federal income tax, on its share of our income and gain as adjusted for changes in the foreign corporation’s “U.S. net equity” to the extent reflected in the corporation’s effectively connected earnings and profits. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Code.

A Non-U.S. Unitholder who sells or otherwise disposes of a unit will be subject to U.S. federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the Non-U.S. Unitholder. Gain realized by a Non-U.S. Unitholder from the sale of its interest in a partnership that is engaged in a trade or business in the United States will be considered to be “effectively connected” with a U.S. trade or business to the extent that gain that would be recognized upon a sale by the partnership of all its assets would be “effectively connected” with a U.S. trade or business. Thus, all of a Non-U.S. Unitholder’s gain from the sale or other disposition of our units would be treated as effectively connected with a unitholder’s indirect U.S. trade or business constituted by its investment in us and would be subject to U.S. federal income tax. As a result of the effectively connected income rules described above, the exclusion from U.S. taxation under the Foreign Investment in Real Property Tax Act for gain from the sale of partnership units regularly traded on an established securities market will not prevent a Non-U.S. Unitholder from being subject to U.S. federal income tax on gain from the sale or disposition of its units to the extent such gain is effectively connected with a U.S. trade

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Exhibit 99.1

or business. We expect all of the gain from the sale or disposition of our units to be treated as effectively connected with a U.S. trade or business.

Moreover, the transferee of an interest in a partnership that is engaged in a U.S. trade or business is generally required to withhold 10% of the amount realized by the transferor unless the transferor certifies that it is not a foreign person, and we are required to deduct and withhold from the transferee amounts that should have been withheld by the transferees but were not withheld. Because the “amount realized” includes a partner’s share of the partnership’s liabilities, 10% of the amount realized could exceed the total cash purchase price for the units. For this and other reasons, the IRS has suspended the application of this withholding rule to open market transfers of interest in publicly traded partnerships, pending promulgation of regulations that address the amount to be withheld, the reporting necessary to determine such amount and the appropriate party to withhold such amounts, but it is not clear if or when such regulations will be issued.

Administrative Matters

Information Returns and Audit Procedures

We intend to furnish to each unitholder, within 90 days after the close of each taxable year, specific tax information, including a Schedule K-1, which describes its share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure our unitholders that those positions will yield a result that conforms to all of the requirements of the Code, Treasury Regulations or administrative interpretations of the IRS.

The IRS may audit our U.S. federal income tax information returns. Neither we nor Vinson & Elkins L.L.P. can assure prospective unitholders that the IRS will not successfully challenge the positions we adopt, and such a challenge could adversely affect the value of the units. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability and may result in an audit of the unitholder’s own return. Any audit of a unitholder’s return could result in adjustments unrelated to our returns.

Publicly traded partnerships generally are treated as entities separate from their owners for purposes of U.S. federal income tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings of the partners.

Pursuant to the Bipartisan Budget Act of 2015, as amended by the Protecting Americans from Tax Hikes Act of 2015, for taxable years beginning after December 31, 2017, if the IRS makes an audit adjustment to any of our income tax returns, it may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, unless we elect to have our general partner, unitholders and former unitholders take any audit adjustment into account in accordance with their interests in us during the taxable year under audit. Similarly, for such taxable years, if the IRS makes an audit adjustment to an income tax return filed by an entity in which we are a member or partner, it may assess and collect any taxes (including penalties and interest) resulting from such audit adjustment directly from such entity. Generally, we expect to elect to have our general partner, unitholders and former unitholders take any material audit adjustment into account in accordance with their interests in us during the taxable year under audit, but there can be no assurance that such election, if made, will be effective in all circumstances. With respect to an audit adjustment as to an entity in which we are a member or partner, it is not clear that in all circumstances, we will be able to have our general partner and our unitholders take such audit adjustment into account in accordance with their interests in us during the taxable year under audit, and if we are unable to do so, our then current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own our units during the taxable year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties, and interest, we may require our unitholders and former unitholders to reimburse us for such taxes (including any applicable penalties or interest) or, if we are required to bear such payment our cash available for distribution to our unitholders might be substantially reduced.

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Exhibit 99.1

For taxable years beginning after December 31, 2017, we will be required to designate a partner, or other person, with a substantial presence in the United States as our partnership representative (“Partnership Representative”). The Partnership Representative will have the sole authority to act on our behalf for purposes of, among other things, U.S. federal income tax audits and judicial review of administrative adjustments by the IRS. If we do not make such a designation, the IRS can select any person as the Partnership Representative. We currently anticipate that we will designate our general partner (or one of its affiliates) as the Partnership Representative. Further, any actions taken by us or by the Partnership Representative on our behalf with respect to, among other things, U.S. federal income tax audits and judicial review of administrative adjustments by the IRS, will be binding on us and all of the unitholders.

These rules are not applicable for taxable years beginning on or prior to December 31, 2017. The U.S. Department of the Treasury has issued proposed regulations interpreting these rules, and accordingly, the manner in which these rules may apply to us in the future is uncertain.

Additional Withholding Requirements

Withholding taxes may apply to certain types of payments made to “foreign financial institutions” (as specially defined in the Code) and certain other non-U.S. entities. Specifically, a 30% withholding tax may be imposed on interest, dividends and other fixed or determinable annual or periodical gains, profits and income from sources within the United States (“FDAP Income”), or gross proceeds from the sale or other disposition of any property of a type which can produce interest or dividends from sources within the United States (“Gross Proceeds”) paid to a foreign financial institution or to a “non-financial foreign entity” (as specially defined in the Code), unless (i) the foreign financial institution undertakes certain diligence and reporting, (ii) the non-financial foreign entity either certifies it does not have any substantial U.S. owners or furnishes identifying information regarding each substantial U.S. owner or (iii) the foreign financial institution or non-financial foreign entity otherwise qualifies for an exemption from these rules. If the payee is a foreign financial institution and is subject to the diligence and reporting requirements in clause (i) above, it must enter into an agreement with the U.S. Department of the Treasury requiring, among other things, that it undertake to identify accounts held by certain U.S. persons or U.S.-owned foreign entities, annually report certain information about such accounts, and withhold 30% on payments to noncompliant foreign financial institutions and certain other account holders. Foreign financial institutions located in jurisdictions that have an intergovernmental agreement with the United States governing these requirements may be subject to different rules.

These rules generally apply to payments of FDAP Income currently and generally will apply to payments of relevant Gross Proceeds made on or after January 1, 2019. Thus, to the extent we have FDAP Income or we have Gross Proceeds on or after January 1, 2019 that are not treated as effectively connected with a U.S. trade or business (please read “—Tax-Exempt Organizations and Other Investors”), a unitholder who is foreign financial institution or certain other non-U.S. entity, or a person that hold its units through such foreign entities, may be subject to withholding on distributions they receive from us, or its distributive share of our income, pursuant to the rules described above. Each prospective unitholder should consult its own tax advisors regarding the potential application of these withholding provisions to its investment in our units.

Nominee Reporting

Persons who hold an interest in us as a nominee for another person are required to furnish to us:

(1) the name, address and taxpayer identification number of the beneficial owner and the nominee;

(2) a statement regarding whether the beneficial owner is:

(a) a non-U.S. person;

(b) a non-U.S. government, an international organization or any wholly-owned agency or instrumentality of either of the foregoing; or

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Exhibit 99.1

(3) the amount and description of units held, acquired or transferred for the beneficial owner; and

(4) specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Each broker and financial institution is required to furnish additional information, including whether such broker or financial institution is a U.S. person, and specific information on units they acquire, hold or transfer for their own account. A penalty per failure, with a significant maximum penalty per calendar year, is imposed by the Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Accuracy-Related Penalties

Certain penalties may be imposed as a result of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for the underpayment of that portion and that the taxpayer acted in good faith regarding the underpayment of that portion. We do not anticipate that any accuracy-related penalties will be assessed against us.

State, Local and Other Tax Considerations

In addition to U.S. federal income taxes, unitholders may be subject to other taxes, including state and local income taxes, unincorporated business taxes, and estate, inheritance or intangibles taxes that may be imposed by the various jurisdictions in which we conduct business or own property now or in the future or in which the unitholder is a resident. We currently conduct business or own property in several states, most of which impose a personal income tax on individuals. Most of these states also impose an income tax on corporations and other entities. In addition, we may also own property or do business in other states in the future that impose income or similar taxes on nonresident individuals, corporations and other entities. As we make acquisitions or expand our business, we may own property or conduct business in additional states that impose a personal income tax. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact of such taxes on its investment in us.

Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “—Tax Consequences of Unit Ownership—Entity-Level Collections of Unitholder Taxes.” Based on current law and our estimate of our future operations, our general partner anticipates that any amounts required to be withheld will not be material. Our counsel has not rendered an opinion on the foreign, state or local tax consequences of an investment in our common units.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of its investment in us. We strongly recommend that each prospective unitholder consult, and depend upon, its own tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and non-U.S., as well as U.S. federal tax returns that may be required of it. Vinson & Elkins L.L.P. has not rendered an opinion on the state, local, alternative minimum tax or non-U.S. tax consequences of an investment in us.

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