SEC Info - Enable Midstream Partners, LP

Enable Midstream Partners, LP – ‘10-Q’ for 9/30/19

Enable Midstream Partners, LP – ‘10-Q’ for 9/30/19

On: Wednesday, 11/6/19, at 6:38am ET · For: 9/30/19 · Accession #: 1591763-19-55 · File #: 1-36413

Previous ‘10-Q’: ‘10-Q’ on 8/6/19 for 6/30/19 · Next: ‘10-Q’ on 5/6/20 for 3/31/20 · Latest: ‘10-Q’ on 11/1/21 for 9/30/21

Quarterly Report — Form 10-Q — Sect. 13 / 15(d) – SEA’34
Filing Table of Contents

‘10-Q’ — Quarterly Report
Document Table of Contents

This is an HTML Document rendered as filed. [ Alternative Formats ]

Dates Referenced Herein and Documents Incorporated by Reference

On: Wednesday, 11/6/19, at 6:38am ET · For: 9/30/19 · Accession #: 1591763-19-55 · File #: 1-36413

Previous ‘10-Q’: ‘10-Q’ on 8/6/19 for 6/30/19 · Next: ‘10-Q’ on 5/6/20 for 3/31/20 · Latest: ‘10-Q’ on 11/1/21 for 9/30/21

Quarterly Report — Form 10-Q — Sect. 13 / 15(d) – SEA’34Filing Table of Contents

‘10-Q’ — Quarterly ReportDocument Table of Contents

This is an HTML Document rendered as filed. [ Alternative Formats ]

Dates Referenced Herein and Documents Incorporated by Reference

Quarterly Report — Form 10-Q — Sect. 13 / 15(d) – SEA’34
Filing Table of Contents

‘10-Q’ — Quarterly Report
Document Table of Contents

Page	(sequential)		(alphabetic)	↑Top
		Alternative Formats (Word, et al.) Condensed Consolidated Balance Sheets Condensed Consolidated Statements of Cash Flows Condensed Consolidated Statements of Comprehensive Income Condensed Consolidated Statements of Income Condensed Consolidated Statements of Partners' Equity Controls and Procedures Exhibits Financial Information Financial Statements (Unaudited) Forward-Looking Statements Glossary of Terms Legal Proceedings Management's Discussion and Analysis of Financial Condition and Results of Operations Notes to Condensed Consolidated Financial Statements Other Information Part I -- FINANCIAL INFORMATION Part II -- OTHER INFORMATION Quantitative and Qualitative Disclosures About Market Risk Risk Factors Signature Table of Contents
1	1st Page – Filing Submission
"	Table of Contents
"	Glossary of Terms
"	Forward-Looking Statements
"	Part I -- FINANCIAL INFORMATION
"	Item 1. Financial Statements (Unaudited)
"	Condensed Consolidated Statements of Income
"	Condensed Consolidated Statements of Comprehensive Income
"	Condensed Consolidated Balance Sheets
"	Condensed Consolidated Statements of Cash Flows
"	Condensed Consolidated Statements of Partners' Equity
"	Notes to Condensed Consolidated Financial Statements
"	Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
"	Item 3. Quantitative and Qualitative Disclosures About Market Risk
"	Item 4. Controls and Procedures
"	Part II -- OTHER INFORMATION
"	Item 1. Legal Proceedings
"	Item 1A. Risk Factors
"	Item 6. Exhibits
"	Signature

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WASHINGTON, D.C. 20549



i ☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended	i September 30, 2019



i ☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

i ENABLE MIDSTREAM PARTNERS, LP



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

i 499 West Sheridan Avenue,	i Suite 1500	i Oklahoma City,	i Oklahoma	i 73102
(Address of Principal Executive Offices)				(Zip 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. i Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files). i 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.



i Large accelerated filer	☒	Accelerated filer	☐

Non-accelerated filer	☐	Smaller reporting company	i ☐

		Emerging growth company	i ☐

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 i ☐ No ☒

As of October 14, 2019, there were i 435,152,510 common units outstanding.

ENABLE MIDSTREAM PARTNERS, LP

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.



2019 Notes.	$500 million aggregate principal amount of the Partnership’s 2.400% senior notes due 2019.
2019 Term Loan Agreement.	Unsecured term loan agreement dated January 29, 2019, by and among Enable Midstream Partners, LP and Bank of America, N.A., as administrative agent, and the several lenders from time to time party thereto.
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.
2028 Notes.	$800 million aggregate principal amount of the Partnership’s 4.950% senior notes due 2028.
2029 Notes.	$550 million aggregate principal amount of the Partnership’s 4.150% senior notes due 2029.
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, change in fair value of derivatives not designated as hedging instruments, 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 interest income, 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, 2018.
ASC.	Accounting Standards Codification.
ASU.	Accounting Standards Update.
Atoka.	Atoka Midstream LLC, in which the Partnership owns a 50% interest, which provides gathering and processing services to customers in the Arkoma Basin in Oklahoma.
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.
Board of Directors.	The board of directors of Enable GP, LLC.
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.	Distributable Cash Flow, 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 unitholders.
EGR	Enable Gulf Run Transmission, LLC, a Delaware limited liability company, a wholly owned subsidiary of the Partnership.
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.



EOCS.	Enable Oklahoma Crude Services, LLC, formerly Velocity Holdings, LLC, a wholly owned subsidiary of the Partnership that provides crude oil and condensate gathering services in the SCOOP and STACK plays of the Anadarko Basin in Oklahoma.
EOIT.	Enable Oklahoma Intrastate Transmission, LLC, formerly Enogex LLC, a wholly owned subsidiary of the Partnership that operates an approximately 2,300-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.
ESCP.	Enable South Central Pipeline, LLC, formerly Velocity Pipeline Partners, LLC, a Delaware limited liability company, in which the Partnership, through EOCS, owns a 60% joint venture interest in a 26-mile pipeline system with a third party which owns and operates a refinery connected to the EOCS system.
Exchange Act.	Securities Exchange Act of 1934, as amended.
FASB.	Financial Accounting Standards Board.
FERC.	Federal Energy Regulatory Commission.
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.
ICE.	Intercontinental Exchange.
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.
MMcf.	Million cubic feet of natural gas.
MMcf/d.	Million cubic feet per day.
Moody’s.	Moody’s Investor Services.
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.
PHMSA.	Pipeline and Hazardous Materials Safety Administration.
Revolving Credit Facility.	$1.75 billion senior unsecured revolving credit facility.
S&P.	Standard & Poor’s Rating Services.
SCOOP.	South Central Oklahoma Oil Province.
SEC.	Securities and Exchange Commission.
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.
STACK.	Sooner Trend (oil field), Anadarko (basin), Canadian and Kingfisher (counties).
TBtu.	Trillion British thermal units.
TBtu/d.	Trillion British thermal units per day.
WTI.	West Texas Intermediate.

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 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;

the timing and extent of changes in labor and material prices;

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 current or 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.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ENABLE MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

Three Months Ended September 30,

Nine Months Ended September 30,

2019

2018

2019

2018

(In millions, except per unit data)

Revenues (including revenues from affiliates (Note 13)):

Product sales

i 320

i 553

i 1,156

i 1,497

Service revenues

i 379

i 375

i 1,073

i 984

Total Revenues

i 699

i 928

i 2,229

i 2,481

Cost and Expenses (including expenses from affiliates (Note 13)):

Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)

i 263

i 516

i 958

i 1,335

Operation and maintenance

i 105

i 98

i 307

i 289

General and administrative

i 31

i 28

i 82

i 81

Depreciation and amortization

i 108

i 100

i 323

i 292

Taxes other than income tax

i 17

i 15

i 52

i 48

Total Cost and Expenses

i 524

i 757

i 1,722

i 2,045

Operating Income

i 175

i 171

i 507

i 436

Other Income (Expense):

Interest expense

( i 48

)

( i 40

)

( i 142

)

( i 109

)

Equity in earnings of equity method affiliate

i 5

i 7

i 12

i 20

Other, net

i 1

i 2

i 1

Total Other Expense

( i 42

)

( i 32

)

( i 128

)

( i 88

)

Income Before Income Tax

i 133

i 139

i 379

i 348

Income tax benefit

i —

( i 1

)

i —

Net Income

i 133

i 139

i 380

i 348

Less: Net income attributable to noncontrolling interest

i 1

i 2

i 1

Net Income Attributable to Limited Partners

i 132

i 138

i 378

i 347

Less: Series A Preferred Unit distributions (Note 7)

i 9

i 27

Net Income Attributable to Common Units (Note 6)

i 123

i 129

i 351

i 320

Basic earnings per unit (Note 6)

Common units

i 0.28

i 0.30

i 0.81

i 0.74

Diluted earnings per unit (Note 6)

Common units

i 0.28

i 0.30

i 0.81

i 0.73

See Notes to the Unaudited Condensed Consolidated Financial Statements

ENABLE MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Three Months Ended September 30,

Nine Months Ended September 30,

2019

2018

2019

2018

(In millions)

Net income

i 133

i 139

i 380

i 348

Other comprehensive loss:

Unrealized losses on derivative instruments

( i 1

)

i —

( i 4

)

i —

Reclassification of derivative losses to net income

i —

Other comprehensive loss

( i 1

)

i —

( i 4

)

i —

Comprehensive income

i 132

i 139

i 376

i 348

Less: Comprehensive income attributable to noncontrolling interest

i 1

i 2

i 1

Comprehensive income attributable to Limited Partners

i 131

i 138

i 374

i 347

ENABLE MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS



	September 30, 2019			December 31, 2018

	(In millions)
Current Assets:
Cash and cash equivalents	$	i 12		$	i 8
Restricted cash	i 1			i 14
Accounts receivable, net of allowance for doubtful accounts (Note 1)	i 268			i 290
Accounts receivable—affiliated companies	i 22			i 19
Inventory	i 47			i 50
Gas imbalances	i 23			i 29
Other current assets	i 44			i 39
Total current assets	i 417			i 449
Property, Plant and Equipment:
Property, plant and equipment	i 13,171			i 12,899
Less accumulated depreciation and amortization	i 2,263			i 2,028
Property, plant and equipment, net	i 10,908			i 10,871
Other Assets:
Intangible assets, net	i 616			i 663
Goodwill	i 98			i 98
Investment in equity method affiliate	i 309			i 317
Other	i 87			i 46
Total other assets	i 1,110			i 1,124
Total Assets	$	i 12,435		$	i 12,444
Current Liabilities:
Accounts payable	$	i 147		$	i 288
Accounts payable—affiliated companies	i 2			i 4
Current portion of long-term debt	i 253			i 500
Short-term debt	i 182			i 649
Taxes accrued	i 58			i 31
Gas imbalances	i 17			i 22
Other	i 160			i 121
Total current liabilities	i 819			i 1,615
Other Liabilities:
Accumulated deferred income taxes, net	i 5			i 5
Regulatory liabilities	i 24			i 23
Other	i 79			i 54
Total other liabilities	i 108			i 82
Long-Term Debt	i 3,968			i 3,129
Commitments and Contingencies (Note 14)	i			i
Partners’ Equity:
Series A Preferred Units (14,520,000 issued and outstanding at September 30, 2019 and December 31, 2018)	i 362			i 362
Common units (435,150,159 issued and outstanding at September 30, 2019 and 433,232,411 issued and outstanding at December 31, 2018, respectively)	i 7,145			i 7,218
Accumulated other comprehensive loss	( i 4		)	i —
Noncontrolling interest	i 37			i 38
Total Partners’ Equity	i 7,540			i 7,618
Total Liabilities and Partners’ Equity	$	i 12,435		$	i 12,444

ENABLE MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Nine Months Ended September 30,
	2019			2018

	(In millions)
Cash Flows from Operating Activities:
Net income	$	i 380		$	i 348
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	i 323			i 292
Deferred income taxes	( i 1		)	i —
Loss on sale/retirement of assets	i 5			i 1
Equity in earnings of equity method affiliate	( i 12		)	( i 20		)
Return on investment in equity method affiliate	i 12			i 20
Equity-based compensation	i 13			i 12
Amortization of debt costs and discount (premium)	( i 1		)	( i 1		)
Changes in other assets and liabilities:
Accounts receivable, net	i 19			( i 56		)
Accounts receivable—affiliated companies	( i 3		)	( i 2		)
Inventory	i 3			( i 5		)
Gas imbalance assets	i 6			i 12
Other current assets	( i 2		)	( i 19		)
Other assets	i 8			( i 6		)
Accounts payable	( i 108		)	( i 19		)
Accounts payable—affiliated companies	( i 2		)	i —
Gas imbalance liabilities	( i 5		)	i 8
Other current liabilities	i 64			i 55
Other liabilities	( i 8		)	i 18
Net cash provided by operating activities	i 691			i 638
Cash Flows from Investing Activities:
Capital expenditures	( i 353		)	( i 551		)
Proceeds from sale of assets	i 1			i 8
Proceeds from insurance	i —			i 1
Return of investment in equity method affiliate	i 8			i 11
Other, net	( i 9		)	i —
Net cash used in investing activities	( i 353		)	( i 531		)
Cash Flows from Financing Activities:
(Decrease) increase in short-term debt	( i 467		)	i 8
Proceeds from long-term debt, net of issuance costs	i 1,544			i 787
Repayment of long-term debt	( i 700		)	( i 450		)
Repayment of Revolving Credit Facility	( i 250		)	i —
Proceeds from issuance of common units, net of issuance costs	i —			i 2
Distributions to common unitholders	( i 420		)	( i 413		)
Distributions to Series A Preferred Units	( i 27		)	( i 27		)
Distributions to non-controlling interests	( i 3		)	( i 2		)
Cash paid for employee equity-based compensation	( i 24		)	( i 9		)
Net cash used in financing activities	( i 347		)	( i 104		)
Net (Decrease) Increase in Cash, Cash Equivalents and Restricted Cash	( i 9		)	i 3
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	i 22			i 19
Cash, Cash Equivalents and Restricted Cash at End of Period	$	i 13		$	i 22

See Notes to the Unaudited Condensed Consolidated Financial Statements

ENABLE MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY

Nine Months Ended September 30, 2019

Series A

Preferred

Units

Common

Units

Accumulated Other Comprehensive Loss

Noncontrolling

Interest

Total Partners’

Equity

Units

Value

Units

Value

(In millions)

Balance as of December 31, 2018

i 15

i 362

i 433

i 7,218

i —

i 38

i 7,618

Net income

—

i 9

—

i 113

—

i 1

i 123

Distributions

—

( i 9

)

—

( i 138

)

—

( i 1

)

( i 148

)

Equity-based compensation, net of units for employee taxes

—

i 2

( i 10

)

—

( i 10

)

Balance as of March 31, 2019

i 15

i 362

i 435

i 7,183

i —

i 38

i 7,583

Net income

—

i 9

—

i 115

—

i 124

Other comprehensive loss

—

( i 3

)

—

( i 3

)

Distributions

—

( i 9

)

—

( i 138

)

—

( i 1

)

( i 148

)

Equity-based compensation, net of units for employee taxes

—

i 3

—

i 3

Balance as of June 30, 2019

i 15

i 362

i 435

i 7,163

( i 3

)

i 37

i 7,559

Net income

—

i 9

—

i 123

—

i 1

i 133

Other comprehensive loss

—

( i 1

)

—

( i 1

)

Distributions

—

( i 9

)

—

( i 144

)

—

( i 1

)

( i 154

)

Equity-based compensation, net of units for employee taxes

—

i 3

—

i 3

Balance as of September 30, 2019

i 15

i 362

i 435

i 7,145

( i 4

)

i 37

i 7,540

Nine Months Ended September 30, 2018

Series A

Preferred

Units

Common

Units

Accumulated Other Comprehensive Loss

Noncontrolling

Interest

Total Partners’

Equity

Units

Value

Units

Value

(In millions)

Balance as of December 31, 2017

i 15

i 362

i 433

i 7,280

i —

i 12

i 7,654

Net income

—

i 9

—

i 105

—

i 114

Distributions

—

( i 9

)

—

( i 139

)

—

( i 1

)

( i 149

)

Balance as of March 31, 2018

i 15

i 362

i 433

i 7,246

i —

i 11

i 7,619

Net income

—

i 9

—

i 86

—

i 95

Distributions

—

( i 9

)

—

( i 137

)

—

( i 146

)

Equity-based compensation, net of units for employee taxes

—

i 3

—

i 3

Balance as of June 30, 2018

i 15

i 362

i 433

i 7,198

i —

i 11

i 7,571

Net income

—

i 9

—

i 129

—

i 1

i 139

Issuance of common units

—

i 2

—

i 2

Distributions

—

( i 9

)

—

( i 137

)

—

( i 1

)

( i 147

)

Equity-based compensation, net of units for employee taxes

—

i 3

—

i 3

Balance as of September 30, 2018

i 15

i 362

i 433

i 7,195

i —

i 11

i 7,568

See Notes to the Unaudited Condensed Consolidated Financial Statements

ENABLE MIDSTREAM PARTNERS, LP

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(1) i Summary of Significant Accounting Policies

Enable Midstream Partners, LP is a Delaware limited partnership whose assets and operations are organized into i 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 Oklahoma and serve crude oil production in the SCOOP and STACK plays of the Anadarko Basin and 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, a pipeline extending from Louisiana to Alabama.

CenterPoint Energy and OGE Energy each have i 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 i two representatives designated by each of CenterPoint Energy and OGE Energy, along with the Partnership’s Chief Executive Officer and i three independent board members CenterPoint Energy and OGE Energy mutually agreed to appoint. CenterPoint Energy and OGE Energy also own a i 40% and i 60% interest, respectively, in the incentive distribution rights held by Enable GP.

As of September 30, 2019, CenterPoint Energy held approximately i 53.7% or i 233,856,623 of the Partnership’s common units, and OGE Energy held approximately i 25.5% or i 110,982,805 of the Partnership’s common units. Additionally, CenterPoint Energy holds i 14,520,000 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 i 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 September 30, 2019, the Partnership owned a i 50% interest in SESH. See Note 8 for further discussion of SESH. For the nine months ended September 30, 2019, the Partnership held a i 50% ownership in Atoka and consolidated Atoka in its Condensed Consolidated Financial Statements as EOIT acted as the managing member of Atoka and had control over the operations of Atoka. In addition, beginning November 1, 2018 through September 30, 2019, the Partnership owned a i 60% interest in ESCP, which is consolidated in its Condensed Consolidated Financial Statements as EOCS acted as the managing member of ESCP and had control over the operations of ESCP.

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 16.

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.

Depreciation Expense

The Partnership completed a depreciation study for the Gathering and Processing and Transportation and Storage segments. Effective January 1, 2019, the new depreciation rates have been applied prospectively as a change in accounting estimate. The new depreciation rates did not result in a material change in depreciation expense or results of operations.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable are recorded at the invoiced amount and do not typically bear interest. The determination of the allowance for doubtful accounts requires management to make estimates and judgments regarding our customers’ ability to pay. The allowance for doubtful accounts is determined based upon specific identification and estimates of future uncollectable amounts. On an ongoing basis, we evaluate our customers’ financial strength based on aging of accounts receivable, payment history, and review of other relevant information, including ratings agency credit ratings and alerts, publicly available reports and news releases, and bank and trade references. It is the policy of management to review the outstanding accounts receivable at least quarterly, giving consideration to credit losses, the aging of receivables, specific customer circumstances that may impact their ability to pay the amounts due and current and forecasted economic conditions over the assets contractual lives. Based on this review, management determined that a $ i 3 million and $ i 2 million allowance for doubtful accounts was required at September 30, 2019 and December 31, 2018, respectively.

Natural gas inventory is held, through the transportation and storage segment, to provide operational support for 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 i no write-downs to net realizable value related to natural gas and natural gas liquids inventory during the three months ended September 30, 2019 and 2018, respectively, and $ i 6 million and $ i 3 million during the nine months ended September 30, 2019 and 2018, respectively.

(2) i i New Accounting Pronouncements /

Accounting Standards to be Adopted in Future Periods

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 manner. 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 expects to adopt this standard in the first quarter of 2020 and does not expect the adoption of this standard to have a material impact on our Condensed Consolidated Financial Statements and related disclosures.

Intangibles—Goodwill and Other

In January 2017, the FASB issued ASU No. 2017-04, “Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment.” This standard requires entities to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. The standard is effective for interim and annual reporting periods beginning after December 15, 2019. The Partnership does not expect the adoption of this standard to have a material impact on our Condensed Consolidated Financial Statements and related disclosures.

Fair Value Measurement—Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement

In August 2018, the FASB issued ASU No. 2018-13, “Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement” which focuses on improving the effectiveness of disclosures in the notes to the financial statements by facilitating clear communication of the information required by U.S. GAAP that is most important to users of each entity’s financial statements. The standard is effective for interim and annual reporting periods beginning after December 15, 2019, although early adoption is permitted. The Partnership expects to adopt this standard in the first quarter of 2020 and continues to evaluate the other impacts of the new standards on our Condensed Consolidated Financial Statements and related disclosures.

Intangibles—Goodwill and Other—Internal-Use Software

In August 2018, the FASB issued ASU No. 2018-15, “Intangibles—Goodwill and Other—Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract,” which aims to reduce complexity in the accounting for costs of implementing a cloud computing service arrangement. ASU No. 2018-15 aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The standard is effective for interim and annual periods beginning after December 15, 2019. The Partnership does not expect the adoption of this standard to have a material impact on our Condensed Consolidated Financial Statements and related disclosures.

Collaborative Arrangements

In November 2018, the FASB issued ASU No. 2018-18, “Collaborative Arrangements (Topic 808): Clarifying the Interaction between Topic 808 and Topic 606.” This standard resolves the diversity in practice concerning the manner in which entities account for transactions on the basis of their view of the economics of the collaborative arrangement. The amendments (1) clarify that certain transactions between collaborative participants should be accounted for as revenue under topic 606 when the collaborative participant is a customer in the context of the unit of account; (2) add unit-of-account guidance in Topic 808 to align with the guidance in Topic 606; and (3) clarify that in a transaction that is not directly related to sales to third parties, presenting the transaction as revenue would be precluded if the collaborative participant counterparty was not a customer. The standard is effective for interim and annual periods beginning after December 15, 2019. The Partnership does not expect the adoption of this standard to have a material impact on our Condensed Consolidated Financial Statements and related disclosures.

Codification Improvements

In April 2019, the FASB issued ASU No. 2019-04, “Codification Improvements to Topic 326, Financial Instruments-Credit Losses, Topic 815, Derivatives and Hedging, and Topic 825, Financial Instruments,” which clarifies and improves areas of guidance related to recently issued standards on credit losses, hedging and recognition and measurement. The standard is effective for interim and annual periods beginning after December 15, 2019. The Partnership does not expect the adoption of this standard to have a material impact on our Condensed Consolidated Financial Statements and related disclosures.

The following tables disaggregate total revenues by major source from contracts with customers and the gain (loss) on derivative activity for the three and nine months ended September 30, 2019 and 2018.

Three Months Ended September 30, 2019

Gathering and
Processing

Transportation
and Storage

Eliminations

Total

(In millions)

Revenues:

Product sales:

Natural gas

i 69

i 95

( i 69

)

i 95

Natural gas liquids

i 191

i 5

( i 5

)

i 191

Condensate

i 26

i —

i 26

Total revenues from natural gas, natural gas liquids, and condensate

i 286

i 100

( i 74

)

i 312

Gain (loss) on derivative activity

i 8

i —

i 8

Total Product sales

i 294

i 100

( i 74

)

i 320

Service revenues:

Demand revenues

i 97

i 119

i —

i 216

Volume-dependent revenues

i 151

i 15

( i 3

)

i 163

Total Service revenues

i 248

i 134

( i 3

)

i 379

Total Revenues

i 542

i 234

( i 77

)

i 699

Three Months Ended September 30, 2018

Gathering and
Processing

Transportation
and Storage

Eliminations

Total

(In millions)

Revenues:

Product sales:

Natural gas

i 87

i 146

( i 120

)

i 113

Natural gas liquids

i 439

i 7

( i 7

)

i 439

Condensate

i 25

i —

i 25

Total revenues from natural gas, natural gas liquids, and condensate

i 551

i 153

( i 127

)

i 577

Loss on derivative activity

( i 23

)

i —

( i 1

)

( i 24

)

Total Product sales

i 528

i 153

( i 128

)

i 553

Service revenues:

Demand revenues

i 92

i 114

i —

i 206

Volume-dependent revenues

i 158

i 14

( i 3

)

i 169

Total Service revenues

i 250

i 128

( i 3

)

i 375

Total Revenues

i 778

i 281

( i 131

)

i 928

Nine Months Ended September 30, 2019

Gathering and
Processing

Transportation
and Storage

Eliminations

Total

(In millions)

Revenues:

Product sales:

Natural gas

i 291

i 365

( i 305

)

i 351

Natural gas liquids

i 698

i 16

( i 16

)

i 698

Condensate

i 93

i —

i 93

Total revenues from natural gas, natural gas liquids, and condensate

i 1,082

i 381

( i 321

)

i 1,142

Gain (loss) on derivative activity

i 14

i —

i 14

Total Product sales

i 1,096

i 381

( i 321

)

i 1,156

Service revenues:

Demand revenues

i 225

i 373

i —

i 598

Volume-dependent revenues

i 438

i 48

( i 11

)

i 475

Total Service revenues

i 663

i 421

( i 11

)

i 1,073

Total Revenues

i 1,759

i 802

( i 332

)

i 2,229

Nine Months Ended September 30, 2018

Gathering and
Processing

Transportation
and Storage

Eliminations

Total

(In millions)

Revenues:

Product sales:

Natural gas

i 299

i 420

( i 336

)

i 383

Natural gas liquids

i 1,054

i 20

( i 20

)

i 1,054

Condensate

i 98

i —

i 98

Total revenues from natural gas, natural gas liquids, and condensate

i 1,451

i 440

( i 356

)

i 1,535

Gain (loss) on derivative activity

( i 40

)

i 2

i —

( i 38

)

Total Product sales

i 1,411

i 442

( i 356

)

i 1,497

Service revenues:

Demand revenues

i 194

i 347

i —

i 541

Volume-dependent revenues

i 405

i 48

( i 10

)

i 443

Total Service revenues

i 599

i 395

( i 10

)

i 984

Total Revenues

i 2,010

i 837

( i 366

)

i 2,481

The table below summarizes the change in accounts receivable for the nine months ended September 30, 2019.



	September 30, 2019		December 31, 2018

	(In millions)
Accounts Receivable:
Customers	$	i 281	$	i 297
Contract assets ⁽¹⁾	i 4		i 6
Non-customers	i 5		i 6
Total Accounts Receivable ⁽²⁾	$	i 290	$	i 309

____________________

Contract assets reflected in Total Accounts Receivable include accrued minimum volume commitments. Contract assets are primarily attributable to revenues associated with estimated shortfall volumes on certain annual minimum volume commitment arrangements. Total Accounts Receivable does not include $ i 5 million of contracts assets related to firm service transportation contracts with tiered rates, which are reflected in Other Assets.

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

Contract Liabilities

Our contract liabilities primarily consist of prepayments received from customers for which the good or service has not yet been provided in connection with the prepayment. i The table below summarizes the change in the contract liabilities for the nine months ended September 30, 2019:



	September 30, 2019		December 31, 2018		Amounts recognized in revenues

	(In millions)
Deferred revenues	$	i 46	$	i 48	$	i 23

The table below summarizes the timing of recognition of these contract liabilities as of September 30, 2019:



	2019		2020		2021		2022		2023 and After
	(In millions)
Deferred revenues	$	i 19	$	i 6	$	i 5	$	i 5	$	i 11

Remaining Performance Obligations

Our remaining performance obligations consist primarily of firm arrangements and minimum volume commitment 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. i The table below summarizes the timing of recognition of the remaining performance obligations as of September 30, 2019:



	2019		2020		2021		2022		2023 and After
	(In millions)
Transportation and Storage	$	i 119	$	i 419	$	i 229	$	i 172	$	i 822
Gathering and Processing	i 47		i 163		i 136		i 138		i 460
Total remaining performance obligations	$	i 166	$	i 582	$	i 365	$	i 310	$	i 1,282

On January 1, 2019, the Partnership adopted 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. The Partnership has applied the standard to only contracts that were not expired as of January 1, 2019.

The Partnership elected the 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 elected the optional transition practical expedient to not reassess whether any expired or existing contracts are or contain leases, the lease classification for any expired or existing leases and initial direct costs for any existing leases. Upon adoption, we increased our asset and liability balances on the Condensed Consolidated Balance Sheets by approximately $ i 35 million due to the required recognition of right-of-use assets and corresponding lease liabilities for all lease obligations that were classified as operating leases. The Partnership did not recognize a material cumulative adjustment to the Condensed Consolidated Statement of Partners’ Equity and we did not have any material changes in the timing of expense recognition or our accounting policies.

Our lease obligations are primarily comprised of rentals of field equipment and buildings, which are recorded as Operation and maintenance and General and administrative expenses in the Partnership’s Condensed Consolidated Statements of Income. Other than the contractual terms for each lease obligation, the key inputs for our calculations of the initial right-of-use assets and corresponding lease liabilities are the expected remaining life and applicable discount rate. Field equipment has an expected lease term of three to i five years, with contractual base terms of one to i three years followed by month-to-month renewals. Field equipment rental arrangements do not generally contain any significant variable lease payments. While certain arrangements may include lower standby rates, field equipment is generally anticipated to be in use for all of its expected lease term. Buildings have an expected lease term of seven to i ten years, which is currently the same as the contractual base term. Building rental arrangements contain market-based renewal options of up to i 15 years. Variable lease payments for buildings are generally comprised of costs for utilities, maintenance and building management services. There were no variable lease payments due under building rental arrangements until July 1, 2019, after which amounts are due monthly. The Partnership is generally not aware of the implicit rate for either field equipment or building rental arrangements, so discount rates are based upon the expected term of each arrangement and the Partnership’s uncollateralized borrowing rate associated with the expected term at the time of lease inception. As of September 30, 2019, the weighted average remaining lease term is i 6.6 years and the weighted average discount rate is i 5.52%.

As of September 30, 2019, we have right-of-use assets of $ i 36 million recorded as Other Assets, $ i 11 million of corresponding obligations recorded as Other Current Liabilities and $ i 28 million of corresponding obligations recorded as Other Liabilities on the Partnership’s Condensed Consolidated Balance Sheet. All lease obligations outstanding during the three and nine months ended September 30, 2019 were classified as operating leases, therefore all cash flows are reflected in Cash Flows from Operating Activities. Rental costs associated with field equipment and buildings were $ i 6 million and $ i 1 million during the three months ended September 30, 2019, respectively, and $ i 18 million and $ i 5 million during the nine months ended September 30, 2019, respectively.

The table below summarizes lease expense for the three and nine months ended September 30, 2019:



	Three Months Ended September 30, 2019
	Gathering and Processing		Transportation and Storage		Total

	(In millions)
Lease Expense:
Lease Cost:
Operating lease cost	$	i 2	$	i —	$	i 2
Short-term lease cost	i 3		i 1		i 4
Variable lease cost	i 1		i —		i 1
Total Lease Cost	$	i 6	$	i 1	$	i 7



	Nine Months Ended September 30, 2019
	Gathering and Processing		Transportation and Storage		Total

	(In millions)
Lease Expense:
Lease Cost:
Operating lease cost	$	i 7	$	i —	$	i 7
Short-term lease cost	i 14		i 1		i 15
Variable lease cost	i 1		i —		i 1
Total Lease Cost	$	i 22	$	i 1	$	i 23

Under ASC 842, as of September 30, 2019, the Partnership has operating lease obligations expiring at various dates. The $ i 17 million difference between undiscounted cash flows for operating leases and our $ i 39 million of lease obligations is due to the impact of the applicable discount rate. i Undiscounted cash flows for operating lease liabilities are as follows:



	Year Ended December 31,
	2019		2020		2021		2022		2023		2024 and After		Total

	(In millions)
Noncancellable operating leases	$	i 11	$	i 11	$	i 7	$	i 6	$	i 6	$	i 15	$	i 56

Under ASC 840, as of December 31, 2018, the Partnership had the following operating lease obligations as well as the estimate of the period in which the obligation will be settled:



	Year Ended December 31,
	2019		2020-2021		2022-2023		After 2023		Total

	(In millions)
Noncancellable operating leases	$	i 14	$	i 6	$	i 6	$	i 14	$	i 40

Velocity Holdings, LLC Acquisition

On November 1, 2018, the Partnership acquired all of the equity interests in Velocity Holdings, LLC, now EOCS, which owns and operates a crude oil and condensate gathering system in the SCOOP and STACK plays of the Anadarko Basin, for approximately $ i 444 million in cash, subject to certain customary working capital adjustments. The acquisition was accounted for as a business combination and was funded with borrowings under the commercial paper program. During the fourth quarter of 2018, the Partnership finalized the purchase price allocation as of November 1, 2018.

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



Purchase price allocation:
Assets acquired:
Cash	$	i 1
Current Assets	i 3
Property, plant and equipment	i 124
Intangibles	i 259
Goodwill	i 86
Liabilities assumed:
Current liabilities	i 1
Less: Non-Controlling Interest at fair value	i 28
Total identifiable net assets	$	i 444

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 i 15 years. Goodwill recognized from the acquisition primarily relates to greater operating leverage in the Anadarko Basin and is allocated to the gathering and processing segment. Included within the acquisition was i 60% of a i 26-mile pipeline system joint venture with a third party which owns and operates a refinery connected to the EOCS system. This joint venture’s financials have been consolidated within the Partnership’s financial statements resulting in $ i 28 million in non-controlling interest. The Partnership incurred approximately $ i 6 million of acquisition costs associated with this transaction, which were included in General and administrative expense in the Consolidated Statements of Income for the twelve months ended December 31, 2018. The Partnership determined not to include pro forma consolidated financial statements for the periods presented as the impact would not be material.

(6) i Earnings Per Limited Partner Unit

The following table illustrates the Partnership’s calculation of earnings per unit for common units:

Three Months Ended September 30,

Nine Months Ended September 30,

2019

2018

2019

2018

(In millions, except per unit data)

Net income

i 133

i 139

i 380

i 348

Net income attributable to noncontrolling interest

i 1

i 2

i 1

Series A Preferred Unit distributions

i 9

i 27

General partner interest in net income

i —

Net income available to common unitholders

i 123

i 129

i 351

i 320

Net income allocable to common units

i 123

i 129

i 351

i 320

Dilutive effect of Series A Preferred Unit distributions

i —

Diluted net income allocable to common units

i 123

i 129

i 351

i 320

Basic earnings per unit

Common units

i 0.28

i 0.30

i 0.81

i 0.74

Basic weighted average number of common units outstanding ⁽¹⁾

i 437

i 435

i 436

i 434

Dilutive effect of Series A Preferred Units

i —

Dilutive effect of performance units

i —

i 1

i —

i 2

Diluted weighted average number of common units outstanding

i 437

i 436

Diluted earnings per unit

Common units

i 0.28

i 0.30

i 0.81

i 0.73

____________________

Basic weighted average number of outstanding common units includes approximately i two million time-based phantom units for each of the three months ended September 30, 2019 and 2018, respectively, and i one million time-based phantom units for each of the nine months ended September 30, 2019 and 2018, respectively.

(7) i Partners’ Equity

The Partnership Agreement requires that, within i 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 unitholders, as applicable, during 2018 and 2019 (in millions, except for per unit amounts):

Three Months Ended

Record Date

Payment Date

Per Unit Distribution

Total Cash Distribution

September 30, 2019⁽¹⁾

i November 19, 2019

i November 26, 2019

i 0.3305

i 144

June 30, 2019

i August 20, 2019

i August 27, 2019

i 0.3305

i 144

March 31, 2019

i May 21, 2019

i May 29, 2019

i 0.318

i 138

December 31, 2018

i February 19, 2019

i February 26, 2019

i 0.318

i 138

September 30, 2018

i November 16, 2018

i November 29, 2018

i 0.318

i 138

June 30, 2018

i August 21, 2018

i August 28, 2018

i 0.318

i 138

March 31, 2018

i May 22, 2018

i May 29, 2018

i 0.318

i 138

_____________________

The Board of Directors declared this $ i 0.3305 per common unit cash distribution on November 5, 2019, to be paid on i November 26, 2019 to common unitholders of record at the close of business on i November 19, 2019.

The Partnership paid or has authorized payment of the following cash distributions to holders of the Series A Preferred Units during 2018 and 2019 (in millions, except for per unit amounts):

Three Months Ended

Record Date

Payment Date

Per Unit Distribution

Total Cash Distribution

September 30, 2019 ⁽¹⁾

i November 5, 2019

i November 14, 2019

i 0.625

i 9

June 30, 2019

i August 2, 2019

i August 14, 2019

i 0.625

i 9

March 31, 2019

i April 29, 2019

i May 15, 2019

i 0.625

i 9

December 31, 2018

i February 8, 2019

i February 14, 2019

i 0.625

i 9

September 30, 2018

i November 6, 2018

i November 14, 2018

i 0.625

i 9

June 30, 2018

i August 1, 2018

i August 14, 2018

i 0.625

i 9

March 31, 2018

i May 1, 2018

i May 15, 2018

i 0.625

i 9

_____________________

The Board of Directors declared a $ i 0.625 per Series A Preferred Unit cash distribution on November 5, 2019, to be paid on i November 14, 2019, to Series A Preferred unitholders of record at the close of business on i November 5, 2019.

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 $ i 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 nine months ended September 30, 2019 and 2018, the Partnership did not issue common units under the ATM Program. As of September 30, 2019, $ i 197 million of common units remained available for issuance through the ATM Program.

(8) i 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 i 50% by Enbridge, Inc. and i 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 i 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, Enbridge, Inc. 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 Enbridge, Inc. 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 $ i 2 million and $ i 6 million during the three months ended September

30, 2019 and 2018, respectively, and $ i 12 million and $ i 14 million during the nine months ended September 30, 2019 and 2018, respectively, associated with these service agreements.

The Partnership includes equity in earnings of equity method affiliate under the Other Income (Expense) caption in the Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2019 and 2018.



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018

	(In millions)
Equity in Earnings of Equity Method Affiliate	$	i 5	$	i 7	$	i 12	$	i 20
Distributions from Equity Method Affiliate ⁽¹⁾	$	i 4	$	i 10	$	i 20	$	i 31

Distributions from equity method affiliate includes a $ i 12 million and $ i 20 million return on investment and a $ i 8 million and $ i 11 million return of investment for the nine months ended September 30, 2019 and 2018, respectively.

Summarized financial information of SESH:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018

	(In millions)
Income Statements:
Revenues	$	i 27	$	i 29	$	i 81	$	i 85
Operating income	$	i 15	$	i 18	$	i 37	$	i 51
Net income	$	i 10	$	i 13	$	i 24	$	i 38

The following table presents the Partnership’s outstanding debt as of September 30, 2019 and December 31, 2018.

September 30, 2019

December 31, 2018

Outstanding Principal

Premium (Discount)

Total Debt

Outstanding Principal

Premium (Discount)

Total Debt

(In millions)

Commercial Paper

i 182

i —

i 182

i 649

i —

i 649

Revolving Credit Facility

i —

i 250

i —

i 250

2019 Term Loan Agreement

i 800

i —

i 800

i —

2019 Notes

i —

i 500

i —

i 500

2024 Notes

i 600

i —

i 600

i —

i 600

2027 Notes

i 700

( i 2

)

i 698

i 700

( i 2

)

i 698

2028 Notes

i 800

( i 6

)

i 794

i 800

( i 6

)

i 794

2029 Notes

i 550

( i 1

)

i 549

i —

2044 Notes

i 550

i —

i 550

i —

i 550

EOIT Senior Notes

i 250

i 3

i 253

i 250

i 7

i 257

Total debt

i 4,432

( i 6

)

i 4,426

i 4,299

( i 1

)

i 4,298

Less: Short-term debt ⁽¹⁾

i 182

i 649

Less: Current portion of long-term debt ⁽²⁾

i 253

i 500

Less: Unamortized debt expense⁽³⁾

i 23

i 20

Total long-term debt

i 3,968

i 3,129

____________________

Short-term debt includes $ i 182 million and $ i 649 million of outstanding commercial paper as of September 30, 2019 and December 31, 2018, respectively.

As of September 30, 2019, Current portion of long-term debt included $ i 253 million outstanding balance of the EOIT Senior Notes due March 15, 2020. As of December 31, 2018, Current portion of long-term debt included $ i 500 million outstanding balance of the 2019 Notes due May 15, 2019.

As of September 30, 2019 and December 31, 2018, there was an additional $ i 5 million and $ i 6 million, respectively, of unamortized debt expense related to the Revolving Credit Facility included in Other assets, not included above.

The Partnership has a commercial paper program, pursuant to which the Partnership is authorized to issue up to $ i 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 $ i 182 million and $ i 649 million outstanding under our commercial paper program at September 30, 2019 and December 31, 2018, respectively. The weighted average interest rate for the outstanding commercial paper was i 2.96% as of September 30, 2019.

Revolving Credit Facility

On April 6, 2018, the Partnership amended and restated its Revolving Credit Facility. As amended and restated, the Revolving Credit Facility is a $ i 1.75 billion, i 5-year senior unsecured revolving credit facility, which under certain circumstances may be increased from time to time up to an additional $ i 875 million. The Revolving Credit Facility is scheduled to mature on April 6, 2023, subject to an extension option, which could be exercised i two times to extend the term of the Revolving Credit Facility, in each case, for an additional one-year term. As of September 30, 2019, there were i no principal advances and $ i 3 million in letters of credit outstanding under the Revolving Credit Facility.

The Revolving Credit Facility provides that outstanding borrowings bear interest at the LIBOR and/or an alternate base rate, at the Partnership’s election, plus an applicable margin. The applicable margin is based on the Partnership’s designated credit ratings from S&P, Moody’s and Fitch Ratings. As of September 30, 2019, the applicable margin for LIBOR-based borrowings under the Revolving Credit Facility was i 1.50% based on the Partnership’s credit ratings. In addition, the Revolving Credit Facility requires the Partnership to pay a fee on unused commitments. The commitment fee is based on the Partnership’s credit ratings. As of September 30, 2019, the commitment fee under the restated Revolving Credit Facility was i 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.

2019 Term Loan Agreement

On January 29, 2019, the Partnership entered into an unsecured term loan agreement with Bank of America, N.A., as administrative agent, and the several lenders thereto. The 2019 Term Loan Agreement has a scheduled maturity date of January 29, 2022, but contains an option, which may be exercised up to two times, to extend the maturity date for an additional one-year term. The 2019 Term Loan Agreement 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 is based on the Partnership’s credit ratings. The applicable margin shall equal, (1) in the case of interest rates determined by reference to the eurodollar rate, between i 0.75% and i 1.50% per annum and (2) in the case of interest rates determined by reference to the alternate base rate, between i 0% and i 0.50% per annum. As of September 30, 2019, the applicable margin for LIBOR-based advances under the 2019 Term Loan Facility was i 1.25% based on the Partnership’s credit ratings. As of September 30, 2019, the weighted average interest rate of the 2019 Term Loan Agreement was i 3.33%.

Prior to the expiration of the availability period for advances on July 26, 2019, the Partnership drew $ i 1 billion in advances under the Term Loan Agreement, which were used for general partnership purposes. Advances under the 2019 Term Loan Agreement can be prepaid, in whole or in part, at any time without premium or penalty, other than usual and customary LIBOR breakage costs, if applicable. On September 16, 2019, the Partnership prepaid $ i 200 million of the advances under the Term Loan Agreement, the repayment of which was not subject to LIBOR breakage costs. As of September 30, 2019, there was $ i 800 million outstanding under the 2019 Term Loan Agreement.

The 2019 Term Loan Agreement contains a financial covenant requiring the Partnership to maintain a ratio of consolidated funded debt to consolidated EBITDA as of the last day of each fiscal quarter of less than or equal to i 5.00 to 1.00; provided that, for a certain period 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 $ i 25 million, the consolidated funded debt to consolidated EBITDA ratio as of the last day of each such fiscal quarter during such period would be permitted to be up to i 5.50 to 1.00.

The 2019 Term Loan Agreement 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 (as defined in the 2019 Term Loan Agreement), restricted payments, changes in the nature of their respective business and entering into certain restrictive agreements. The 2019 Term Loan Agreement 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 $ i 100 million or more in the aggregate, change of control, nonpayment of uninsured judgments in excess of $ i 100 million, and the occurrence of certain ERISA and bankruptcy events, subject, where applicable, to specified cure periods.

On September 13, 2019, the Partnership completed the public offering of $ i 550 million aggregate principal amount of its i 4.15% Senior Notes due 2029. The Partnership received net proceeds of approximately $ i 544 million, after deducting the underwriting discount and offering expenses. The net proceeds were used to repay $ i 200 million of borrowings outstanding under the 2019 Term Loan Agreement, to repay amounts outstanding under the commercial paper program, and for general partnership purposes. The Partnership intends to issue commercial paper to repay the full amount of the EOIT Senior Notes at maturity. The 2029 Notes had an unamortized discount of $ i 1 million and unamortized debt expense of $ i 5 million at September 30, 2019, resulting in an effective interest rate of i 4.31% from the issue date through September 30, 2019.

As of September 30, 2019, the Partnership’s debt also included the 2024 Notes, 2027 Notes, 2028 Notes and 2044 Notes, which had $ i 8 million of unamortized discount and $ i 18 million of unamortized debt expense at September 30, 2019, resulting in effective interest rates of i 4.01%, i 4.57%, i 5.20% and i 5.08%, respectively, during the nine months ended September 30, 2019. In May 2019, the Partnership’s 2019 Notes matured and were paid using proceeds from the 2019 Term Loan Agreement.

As of September 30, 2019, the Partnership’s debt included EOIT’s Senior Notes. The EOIT Senior Notes had $ i 3 million of unamortized premium at September 30, 2019, resulting in an effective interest rate of i 3.82% during the nine months ended September 30, 2019.

As of September 30, 2019, the Partnership and EOIT were in compliance with all of their debt agreements, including financial covenants.

(10) i Derivative Instruments and Hedging Activities

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

Commodity Price Risk

The Partnership uses forward physical contracts, commodity price swap contracts and commodity price option features to manage its commodity price risk exposures. Commodity derivative instruments used by the Partnership are as follows:

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

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

Normal purchases and normal sales contracts are not recorded in Other Assets or Liabilities in the Condensed Consolidated Balance Sheets and earnings are recognized and recorded in the period in which physical delivery of the commodity occurs. Management applies normal purchases and normal sales treatment to: (i) commodity contracts for the purchase and sale of natural gas used in or produced by the Partnership’s operations and (ii) commodity contracts for the purchase and sale of NGLs produced by its gathering and processing business.

The Partnership recognizes its non-exchange traded derivative instruments as Other Assets or Liabilities in the Condensed Consolidated Balance Sheets at fair value with such amounts classified as current or long-term based on their anticipated settlement. Exchange traded transactions are settled on a net basis daily through margin accounts with a clearing broker and are recorded as Other Assets or Liabilities in the Condensed Consolidated Balance Sheets at fair value on a net basis with such amounts classified as current or long-term based on their anticipated settlement.

As of September 30, 2019 and December 31, 2018, the Partnership had i no commodity derivative instruments that were designated as cash flow or fair value hedges for accounting purposes.

The Partnership uses interest rate swap contracts to manage its interest rate risk exposures. The Partnership recognizes its interest rate 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. The Partnership’s interest rate swap contracts are designated as cash flow hedging instruments for accounting purposes. For interest rate derivative instruments designated as cash flow hedging instruments, the gain or loss on the derivative is recognized currently in Accumulated other comprehensive loss and will be reclassified to Interest expense in the same period the hedged transaction affects earnings. As of September 30, 2019, the Partnership had no interest rate derivative instruments that were designated as fair value hedges for accounting purposes. As of December 31, 2018, the Partnership had no outstanding interest rate derivative instruments.

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 to manage its exposure to commodity price risk. 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 Not Designated as Hedging Instruments

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

As of September 30, 2019 and December 31, 2018, the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes:



	September 30, 2019		December 31, 2018
	Gross Notional Volume
	Purchases	Sales	Purchases	Sales
Natural gas—TBtu ⁽¹⁾
Financial fixed futures/swaps	i 13	i 22	i 16	i 28
Financial basis futures/swaps	i 16	i 40	i 18	i 29
Financial swaptions ⁽³⁾	i —	i 3	i —	i 1
Physical purchases/sales	i —	i 7	i —	i 11
Crude oil (for condensate)—MBbl ⁽²⁾
Financial futures/swaps	i —	i 915	i —	i 945
Financial swaptions ⁽³⁾	i —	i 90	i —	i 30
Natural gas liquids—MBbl ⁽⁴⁾
Financial futures/swaps	i 3,210	i 3,165	i 270	i 2,535

____________________



	2019
Number of units granted	i 610,170
Fair value of units granted	$	i 19.95
Expected distribution yield	i 8.38		%
Expected price volatility	i 34.2		%
Risk-free interest rate	i 2.54		%
Expected life of units (in years)	i 3



	2019
Phantom Units granted	i 603,571
Fair value of phantom units granted	$14.04 - $15.04



	September 30, 2019
	Unrecognized Compensation Cost (In millions)		Weighted Average Period for Recognition (In years)
Performance Units	$	i 15	i 1.54
Phantom Units	i 11		i 1.56
Total	$	i 26



	Three Months Ended September 30,		Nine Months Ended September 30,
	2019	2018	2019	2018

Operating Data:
Natural gas gathered volumes—TBtu	411	424	1,240	1,212
Natural gas gathered volumes—TBtu/d	4.47	4.61	4.54	4.44
Natural gas processed volumes—TBtu ⁽¹⁾	229	230	689	641
Natural gas processed volumes—TBtu/d ⁽¹⁾	2.49	2.50	2.52	2.35
NGLs produced—MBbl/d ⁽¹⁾⁽²⁾	117.78	142.00	128.62	127.92
NGLs sold—MBbl/d ⁽²⁾⁽³⁾	118.29	146.29	131.49	130.18
Condensate sold—MBbl/d	6.16	4.25	7.36	5.97
Crude oil and condensate gathered volumes—MBbl/d	132.99	31.87	120.17	29.11
Transported volumes—TBtu	549	497	1,703	1,502
Transported volumes—TBtu/d	5.97	5.40	6.22	5.49
Interstate firm contracted capacity—Bcf/d	6.02	5.76	6.31	5.84
Intrastate average deliveries—TBtu/d	2.10	2.02	2.16	2.04



	Three Months Ended September 30,		Nine Months Ended September 30,
	2019	2018	2019	2018
Anadarko
Gathered volumes—TBtu/d	2.27	2.31	2.32	2.16
Natural gas processed volumes—TBtu/d ⁽¹⁾	2.04	2.08	2.07	1.94
NGLs produced—MBbl/d ⁽¹⁾⁽²⁾	103.53	124.80	111.99	111.74
Crude oil and condensate gathered volumes—MBbl/d	91.58	—	82.75	—
Arkoma
Gathered volumes—TBtu/d	0.46	0.56	0.48	0.55
Natural gas processed volumes—TBtu/d ⁽¹⁾	0.10	0.10	0.10	0.10
NGLs produced—MBbl/d ⁽¹⁾⁽²⁾	4.42	7.04	5.89	6.54
Ark-La-Tex
Gathered volumes—TBtu/d	1.74	1.74	1.74	1.73
Natural gas processed volumes—TBtu/d	0.35	0.32	0.35	0.31
NGLs produced—MBbl/d ⁽¹⁾⁽²⁾	9.83	10.16	10.74	9.64
Williston
Crude oil gathered volumes—MBbl/d	41.41	31.87	37.42	29.11


(1)	As of September 30, 2019, i 85.6% of the natural gas contracts had durations of one year or less and i 14.4% had durations of more than one year and less than two years. As of December 31, 2018, i 74.0% of the natural gas contracts had durations of one year or less, i 24.2% had durations of more than one year and less than two years and i 1.8% had durations of more than two years.


(2)	As of September 30, 2019, i 83.6% of the crude oil (for condensate) contracts had durations of one year or less and i 16.4% had durations of more than one year and less than two years. As of December 31, 2018, i 76.9% of the crude oil (for condensate) contracts had durations of one year or less and i 23.1% had durations of more than one year and less than two years.


(3)	The notional contains a combined derivative instrument consisting of a fixed price swap and a sold option, which gives the counterparties the right, but not the obligation, to increase the notional quantity hedged under the fixed price swap until the option expiration date. The notional volume represents the volume prior to option exercise.


(4)	As of September 30, 2019, i 69.2% of the natural gas liquids contracts had durations of one year or less and i 30.8% had durations of more than one year and less than two years. As of December 31, 2018, i 86.1% of the natural gas liquid contracts had durations of one year or less and i 13.9% had durations of more than one year and less than two years.



	September 30, 2019		December 31, 2018
	Gross Notional Value
	(In millions)
Interest rate swaps	$	i 300	$	i —


(1)	See Note 11 for a reconciliation of the Partnership’s commodity derivatives fair value to the Partnership’s Condensed Consolidated Balance Sheets as of September 30, 2019 and December 31, 2018.


(1)	All interest rate derivative instruments that were designated as cash flow hedges are considered Level 2 as of September 30, 2019.



	Amounts Recognized in Income
	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018

	(In millions)
Natural gas
Financial futures/swaps gains (losses)	$	i 2		$	( i 1	)	$	i 10		$	( i 6	)
Physical purchases/sales gains	i 1			i —			i 1			i 5
Crude oil (for condensate)
Financial futures/swaps losses	( i 8		)	( i 4		)	( i 29		)	( i 14		)
Natural gas liquids
Financial futures/swaps gains (losses)	i 13			( i 19		)	i 32			( i 23		)
Interest Rates
Financial futures/swaps gains (losses)	—			—			—			—
Total	$	i 8		$	( i 24	)	$	i 14		$	( i 38	)


(1)	Borrowing capacity is effectively reduced by our borrowings outstanding under the commercial paper program. $ i 182 million and $ i 649 million of commercial paper was outstanding as of September 30, 2019 and December 31, 2018, respectively.


(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. There were no netting adjustments as of September 30, 2019 and December 31, 2018.


•	interest rates;


•	labor relations;


(2)	Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $ i 15 million and $ i 11 million at September 30, 2019 and December 31, 2018, 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 $ i 9 million and $ i 5 million at September 30, 2019 and December 31, 2018, 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.



	September 30,
	2019		2018

	(In millions)
Cash and cash equivalents	$	i 12	$	i 8
Restricted cash	i 1		i 14
Cash, cash equivalents and restricted cash shown in the Condensed Consolidated Statements of Cash Flows	$	i 13	$	i 22


(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 i 0% to i 200% of the target.


(1)	See Note 8 for discussion regarding ownership interests in SESH and related equity earnings included in the transportation and storage segment for the three and nine months ended September 30, 2019 and 2018.


(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.


(1)	Includes volumes under third-party processing arrangements.


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


•	revenues from NGL sales decreased $247 million primarily due to lower sales volumes from lower recoveries of ethane, a decrease in the average realized sales price from lower average market prices for all NGL products, and higher volumes subject to fee deductions for NGLs sold under certain third-party processing arrangements and


•	revenues from natural gas sales decreased $18 million due to lower average realized natural gas sales prices and lower sales volumes.

Title of each class

Trading symbol(s)

Name of each exchange on which registered

i Common Units Representing Limited Partner Interests

i New York Stock Exchange


•	realized gains on natural gas, condensate and NGL derivatives increased $17 million and


•	changes in the fair value of natural gas, condensate and NGL derivatives increased $14 million.


•	processing service revenues decreased $22 million due to lower consideration received from percent-of-proceeds, percent-of-liquids and keep-whole processing arrangements due to a decrease in the average realized price.


•	crude oil, condensate and produced water gathering revenues increased $12 million primarily due to an increase related to the November 2018 acquisition of EOCS and an increase in volumes in the Williston Basin, partially offset by lower average rates and


•	natural gas gathering revenues increased $8 million due to higher fees in the Anadarko Basin, partially offset by lower gathered volumes and lower shortfall payments associated with the expiration of minimum volume commitments in the Arkoma Basin.


•	natural gas gathering fees increased $8 million due to higher fees in the Anadarko Basin, partially offset by lower gathered volumes and lower shortfall payments associated with the expiration of minimum volume commitments in the Arkoma Basin, and


•	revenues from natural gas sales less the cost of natural gas increased approximately $3 million due to lower operational gas purchases, partially offset by lower average natural gas sales prices.


•	processing service fees decreased $22 million due to lower consideration received from percent-of-proceeds, percent-of-liquids and keep-whole processing arrangements due to a decrease in the average realized price and


•	revenues from NGL sales less the cost of NGLs decreased $13 million due to lower average realized sales prices and lower processed volumes.


•	revenues from NGL sales decreased $361 million primarily due to a decrease in the average realized sales price from lower average market prices for all NGL products and higher volumes subject to fee deductions for NGLs sold under certain third-party processing arrangements, partially offset by higher processed volumes and