Document
Table of Contents

 
 
 
 
 
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
or
¨ 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.
 
 
 
 
 


Table of Contents


ENABLE MIDSTREAM PARTNERS, LP
FORM 10-Q
TABLE OF CONTENTS
 
 
Page
 
 
 
 
 
 
 
 
 

 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.


23


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.
 

24


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
$



25


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