2015 Q1 ENBL 10-Q
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 AND EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2015
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 jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
 
One Leadership Square
211 North Robinson Avenue
Suite 950
Oklahoma City, Oklahoma 73102
(Address of principal executive offices)
(Zip Code)

Registrant's telephone number, including area code: (405) 525-7788
 _______________________________________
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, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer
 
¨
 
Accelerated filer
 
¨
 
 
 
 
 
 
 
Non-accelerated filer
 
þ  (Do not check if a smaller reporting company)
 
Smaller reporting company
 
¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨ Yes þ No
At April 17, 2015, there were 214,423,917 common units and 207,855,430 subordinated units outstanding.
 
 
 
 
 


Table of Contents


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

 



 




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GLOSSARY
 
Adjusted EBITDA.
Net income from continuing operations before interest expense, income tax expense, depreciation and amortization expense and certain other items management believes affect the comparability of operating results.
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.
Annual Report.
Annual Report on Form 10-K for the year ended December 31, 2014.
ASU.
Accounting Standards Update.
Barrel.
42 U.S. gallons of petroleum products.
Bbl.
Barrel.
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, other than Enable Midstream Partners, LP.
Condensate.
A natural gas liquid with a low vapor pressure, mainly composed of propane, butane, pentane and heavier hydrocarbon fractions.
EGT.
Enable Gas Transmission, LLC, a wholly owned subsidiary of the Partnership that operates a 5,952-mile interstate pipeline that provides natural gas transportation and storage services to customers principally in the Anadarko, Arkoma and Tex-La 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.
Enable Midstream Services.
Enable Midstream Services, LLC, a wholly owned subsidiary of Enable Midstream Partners, LP.
Enable Oklahoma.
Enable Oklahoma Intrastate Transmission, LLC, formerly Enogex LLC, a wholly owned subsidiary of the Partnership that operates a 2,241-mile intrastate pipeline that provides natural gas transportation and storage services to customers in Oklahoma.
Enogex.
Enogex LLC, a Delaware limited liability company.
Exchange Act.
Securities Exchange Act of 1934, as amended.
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.
Total revenues minus cost of goods sold, excluding depreciation and amortization.
LIBOR.
London Interbank Offered Rate.
MBbl/d.
Thousand barrels per day.
MFA.
Master Formation Agreement dated March 14, 2013.
MRT.
Enable Mississippi River Transmission, LLC, a wholly owned subsidiary of the Partnership that operates a 1,663-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.
Offering.
Initial public offering of Enable Midstream Partners, LP.
OGE Energy.
OGE Energy Corp., an Oklahoma corporation, and its subsidiaries, other than Enable Midstream Partners, LP.

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Partnership.
Enable Midstream Partners, LP.
SEC.
Securities and Exchange Commission.
Securities Act.
Securities Act of 1933, as amended.
SESH.
Southeast Supply Header, LLC, in which the Partnership owns a 49.90% interest at March 31, 2015, that operates a 286-mile interstate natural gas pipeline from Perryville, Louisiana, to southeastern Alabama near the Gulf Coast.
TBtu.
Trillion British thermal units.
TBtu/d.
Trillion British thermal units per day.
WTI.
West Texas Intermediate.
2019 Notes.
$500 million 2.400% senior notes due 2019.
2024 Notes.
$600 million 3.900% senior notes due 2024.
2044 Notes.
$550 million 5.000% senior notes due 2044.


 
 
 
 
 
 
 
 
 
 
 
 




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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 on Form 10-K for the year ended December 31, 2014 (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;
operating hazards and other risks incidental to transporting, storing and gathering 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,
 
2015
 
2014
 
(In millions, except per unit data)
Revenues (including revenues from affiliates (Note 11))
$
616

 
$
1,002

Cost of Goods Sold, excluding depreciation and amortization (including expenses from affiliates (Note 11))
292

 
633

Operating Expenses:
 
 
 
Operation and maintenance (including expenses from affiliates (Note 11))
130

 
126

Depreciation and amortization
73

 
67

Taxes other than income taxes
17

 
14

Total Operating Expenses
220

 
207

Operating Income
104

 
162

Other Income (Expense):
 
 
 
Interest expense (including expenses from affiliates (Note 11))
(20
)
 
(14
)
Equity in earnings of equity method affiliates
7

 
3

Other, net
1

 

Total Other Income (Expense)
(12
)
 
(11
)
Income Before Income Taxes
92

 
151

Income tax expense (benefit)
1

 
1

Net Income
$
91

 
$
150

Less: Net income attributable to noncontrolling interest

 
1

Net Income attributable to Enable Midstream Partners, LP
$
91

 
$
149

Limited partners' interest in net income attributable to Enable Midstream Partners, LP (Note 3)
$
91

 
$
149

Basic and diluted earnings per limited partner unit (Note 3)
 
 
 
Common units
$
0.22

 
$
0.38

Subordinated units
$
0.21

 
$

Basic and diluted weighted average number of outstanding limited partner units
(Note 3)
 
 
 
Common units
214

 
390

Subordinated units
208

 


 

See Notes to the Unaudited Condensed Consolidated Financial Statements
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ENABLE MIDSTREAM PARTNERS, LP
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
 
 
Three Months Ended 
 March 31,
 
2015
 
2014
 
(In millions)
Net income
$
91

 
$
150

Comprehensive income
91

 
150

Less: Comprehensive income attributable to noncontrolling interest

 
1

Comprehensive income attributable to Enable Midstream Partners, LP
$
91

 
$
149





See Notes to the Unaudited Condensed Consolidated Financial Statements
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ENABLE MIDSTREAM PARTNERS, LP
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited) 
 
March 31,
2015
 
December 31,
2014
 
(In millions)
Current Assets:
 
Cash and cash equivalents
$
8

 
$
12

Accounts receivable
252

 
254

Accounts receivable—affiliated companies
29

 
27

Inventory
50

 
63

Gas imbalances
37

 
45

Other current assets
31

 
37

Total current assets
407

 
438

Property, Plant and Equipment:
 
 
 
Property, plant and equipment
10,695

 
10,464

Less accumulated depreciation and amortization
948

 
882

Property, plant and equipment, net
9,747

 
9,582

Other Assets:
 
 
 
Intangible assets, net
350

 
357

Goodwill
1,068

 
1,068

Investment in equity method affiliates
349

 
348

Other
47

 
44

Total other assets
1,814

 
1,817

Total Assets
$
11,968

 
$
11,837

Current Liabilities:
 
 
 
Accounts payable
$
287

 
$
275

Accounts payable—affiliated companies
17

 
38

Short-term debt
436

 
253

Taxes accrued
26

 
23

Gas imbalances
8

 
13

Other
67

 
69

Total current liabilities
841

 
671

Other Liabilities:
 
 
 
Accumulated deferred income taxes, net
10

 
9

Notes payable—affiliated companies
363

 
363

Regulatory liabilities
17

 
16

Other
24

 
27

Total other liabilities
414

 
415

Long-Term Debt
1,926

 
1,928

Commitments and Contingencies (Note 12)

 

Partners’ Capital:
 
 
 
Common units (214,424,816 issued and outstanding at March 31, 2015 and 214,417,908 issued and outstanding at December 31, 2014, respectively)
4,338

 
4,353

Subordinated units (207,855,430 issued and outstanding at March 31, 2015 and 207,855,430 issued and outstanding at December 31, 2014, respectively)
4,418

 
4,439

Total partners' capital attributable to Enable Midstream Partners, LP Partners’ Capital
8,756

 
8,792

Noncontrolling interest
31

 
31

Total Partners’ Capital
8,787

 
8,823

Total Liabilities and Partners’ Capital
$
11,968

 
$
11,837


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,
 
2015
 
2014
 
(In millions)
Cash Flows from Operating Activities:
 
Net income
$
91

 
$
150

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization
73

 
67

Equity in earnings of equity method affiliates, net of distributions
5

 

Equity based compensation
3

 

Amortization of debt costs and discount (premium)
(1
)
 
(3
)
Changes in other assets and liabilities:
 
 
 
Accounts receivable, net
2

 
(59
)
Accounts receivable—affiliated companies
(2
)
 
7

Inventory
13

 
19

Gas imbalance assets
8

 
(15
)
Other current assets
6

 
1

Other assets
(2
)
 
(9
)
Accounts payable
18

 
(61
)
Accounts payable—affiliated companies
(21
)
 

Gas imbalance liabilities
(5
)
 
9

Other current liabilities
2

 
(5
)
Other liabilities
(2
)
 
5

Net cash provided by operating activities
188

 
106

Cash Flows from Investing Activities:
 
 
 
Capital expenditures
(239
)
 
(149
)
Investment in equity method affiliates
(6
)
 

Net cash provided by (used in) investing activities
(245
)
 
(149
)
Cash Flows from Financing Activities:
 
 
 
Proceeds from revolving credit facility

 
115

Repayment of revolving credit facility

 
(487
)
Increase in short term debt
183

 
433

Distributions to partners
(130
)
 
(114
)
Net cash provided by (used in) financing activities
53

 
(53
)
Net Increase in Cash and Cash Equivalents
(4
)
 
(96
)
Cash and Cash Equivalents at Beginning of Period
12

 
108

Cash and Cash Equivalents at End of Period
$
8

 
$
12



See Notes to the Unaudited Condensed Consolidated Financial Statements
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ENABLE MIDSTREAM PARTNERS, LP
CONDENSED CONSOLIDATED STATEMENTS OF
ENABLE MIDSTREAM PARTNERS, LP PARTNERS’ CAPITAL
(Unaudited)
 
 
Partners' Capital
 
 
 
 
 
 
 
Common Units
 
Subordinated Units
 
Total Enable
Midstream
Partners, LP
Partners’
Capital
 
Noncontrolling
Interest
 
Total
Partners’
Capital
 
Units
 
Value
 
Units
 
Value
 
Value
 
Value
 
Value
 
(In millions)
Balance as of December 31, 2013
390

 
$
8,148

 

 
$

 
$
8,148

 
$
33

 
$
8,181

Net income

 
149

 

 

 
149

 
1

 
150

Distributions to partners

 
(114
)
 

 

 
(114
)
 

 
(114
)
Balance as of March 31, 2014
390

 
$
8,183

 

 
$

 
$
8,183

 
$
34

 
$
8,217

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance as of December 31, 2014
214

 
$
4,353

 
208

 
$
4,439

 
$
8,792

 
$
31

 
$
8,823

Net income

 
48

 


 
43

 
91

 

 
91

Distributions to partners

 
(66
)
 

 
(64
)
 
(130
)
 

 
(130
)
Equity based compensation

 
3

 

 

 
3

 
$

 
3

Balance as of March 31, 2015
214

 
$
4,338

 
208

 
$
4,418

 
$
8,756

 
$
31

 
$
8,787


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 (Partnership) is a Delaware limited partnership formed on May 1, 2013 by CenterPoint Energy, Inc. (CenterPoint Energy), OGE Energy Corp. (OGE Energy) and affiliates of ArcLight Capital Partners, LLC (ArcLight), pursuant to the terms of the MFA. The Partnership is a large-scale, growth-oriented limited partnership formed to own, operate and develop strategically located natural gas and crude oil infrastructure assets. The Partnership’s assets and operations are organized into two reportable segments: (i) Gathering and Processing, which primarily provides natural gas gathering, processing and fractionation services and crude oil gathering for our producer customers, and (ii) Transportation and Storage, which provides interstate and intrastate natural gas pipeline transportation and storage service primarily to natural gas producers, utilities and industrial customers. The natural gas gathering and processing assets are located in five states and serve natural gas production in the Anadarko, Arkoma and Tex-La basins. This segment also includes a crude oil gathering business in the Bakken Shale formation, principally located in the Williston basin. The natural gas transportation and storage assets extend from western Oklahoma and the Texas Panhandle to Alabama and from Louisiana to Illinois.
 
The Partnership is controlled equally by CenterPoint Energy and OGE Energy, who each have 50% of the management rights of Enable GP. Enable GP was established by CenterPoint Energy and OGE Energy to govern the Partnership and has no other operating activities. Enable GP is governed by a board made up of an equal number of representatives designated by each of CenterPoint Energy and OGE Energy, along with the Partnership's Chief Executive Officer and the independent board members CenterPoint Energy and OGE Energy mutually agreed to appoint. Based on the 50/50 management ownership, with neither company having control, CenterPoint Energy and OGE Energy do not consolidate their interests in the Partnership. CenterPoint Energy and OGE Energy also own a 40% and 60% interest, respectively, in the incentive distribution rights held by Enable GP. At March 31, 2015, CenterPoint Energy held approximately 55.4% of the limited partner interests in the Partnership, or 94,126,366 common units and 139,704,916 subordinated units, and OGE Energy held approximately 26.3% of the limited partner interests in the Partnership, or 42,832,291 common units and 68,150,514 subordinated units.
 
For the period from December 31, 2013 through May 29, 2014, the financial statements reflect a 24.95% interest in SESH. For the period of May 30, 2014 through March 31, 2015, the financial statements reflect a 49.90% interest in SESH. See Note 6 for further discussion of SESH.

On April 16, 2014, the Partnership completed the Offering of 25,000,000 common units, representing limited partner interests in the Partnership, at a price to the public of $20.00 per common unit. The Partnership received net proceeds of $464 million from the sale of the common units, after deducting underwriting discounts and commissions, the structuring fee and offering expenses. In connection with the Offering, underwriters exercised their option to purchase 3,750,000 additional common units, which were fulfilled with units held by ArcLight. As a result, the Partnership did not receive any proceeds from the sale of common units pursuant to the exercise of the underwriters' option to purchase additional common units. The exercise of the underwriters' option to purchase additional common units did not affect the total number of units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all outstanding units. The Partnership retained the net proceeds of the Offering for general partnership purposes, including the funding of expansion capital expenditures, and to pre-fund demand fees expected to be incurred over the next three years relating to certain expiring transportation and storage contracts. In connection with the Offering, 139,704,916 of CenterPoint Energy's common units and 68,150,514 of OGE Energy's common units were converted into subordinated units.

Basis of Presentation

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


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 These condensed consolidated financial statements and the related financial statement disclosures reflect all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position and results of operations for the respective periods. Amounts reported in the Partnership’s Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for a full-year period due to the effects of, among other things, (a) seasonal fluctuations in demand for energy and energy services, (b) changes in energy commodity prices, (c) timing of maintenance and other expenditures and (d) acquisitions and dispositions of businesses, assets and other interests.
 
For a description of the Partnership’s reportable business segments, see Note 14.

Use of Estimates

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

Income Taxes

As a limited partnership, the Partnership’s earnings are no longer subject to income tax (other than Texas state margin taxes and taxes associated with the Partnership's corporate subsidiary) and are taxable at the individual partner level, with the exception of Enable Midstream Services, LLC, a wholly owned subsidiary (Enable Midstream Services). The Partnership and its subsidiaries are pass-through entities for federal income tax purposes. For these entities, all income, expenses, gains, losses and tax credits generated flow through to their owners and, accordingly, do not result in a provision for income taxes in the consolidated financial statements.

Reverse Unit Split

On March 25, 2014, the Partnership effected a 1 for 1.279082616 reverse unit split. All unit and per unit amounts presented within the condensed consolidated financial statements reflect the effects of the reverse unit split.

Second Amended and Restated Agreement of Limited Partnership of Enable Midstream Partners, LP

On April 16, 2014, in connection with the closing of the Offering of the Partnership, the Partnership amended and restated its First Amended and Restated Agreement of Limited Partnership to remove certain provisions that expired upon completion of the Offering. Following the Offering, ArcLight no longer has protective approval rights over certain material activities of the Partnership, including material increases in capital expenditures and certain equity issuances, entering into transactions with related parties and acquiring, pledging or disposing of certain material assets.

 
(2) New Accounting Pronouncements

Revenue from Contracts with Customers

In May 2014, FASB issued ASU No. 2014-09, "Revenue from Contracts with Customers," which supersedes the revenue recognition requirements in "Revenue Recognition (Topic 605)," and requires entities to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services. ASU 2014-09 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, and is to be applied retrospectively, with early application not permitted.

On April 1, 2015, FASB proposed deferring the effective date of ASU 2014-09 by one year to December 15, 2017 for annual reporting periods beginning after that date. The FASB also proposed permitting early adoption of the standard, but not before the original effective date of December 15, 2016. The Partnership is currently evaluating the impact, if any, the adoption of this standard will have on our Consolidated Financial Statements.

Consolidation

In February 2015, FASB issued ASU No. 2015-02, “Consolidation,” to improve consolidation guidance for certain types of legal entities. The guidance modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities (VIEs) or voting interest entities, eliminates the presumption that a general partner should consolidate a limited partnership,

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affects the consolidation analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships, and provides a scope exception from consolidation guidance for certain money market funds. These provisions are effective for annual reporting periods beginning after December 15, 2015, and interim periods within those annual periods, with early adoption permitted. These provisions may also be adopted retrospectively in previously issued financial statements for one or more years with a cumulative-effect adjustment to partners’ capital as of the beginning of the first year restated. The Partnership is currently evaluating the effect that adopting this new accounting standard will have on our Consolidated Financial Statements and related disclosures.

Presentation of Debt Issuance Costs

In April 2015, FASB issued ASU No. 2015-03, "Simplifying the Presentation of Debt Issuance Costs." This standard amends existing guidance to require the presentation of debt issuance costs in the balance sheet as a deduction from the carrying amount of the related debt liability instead of a deferred charge. It is effective for annual reporting periods beginning after December 15, 2015, but early adoption is permitted. The Partnership is currently evaluating the impact the adoption of this standard will have on our Consolidated Financial Statements and related disclosures.

Customer's Accounting for Fees Paid in a Cloud Computing Arrangement

In April 2015, the FASB issued ASU No. 2015-05, "Customer's Accounting for Fees Paid in a Cloud Computing Arrangement." This standard provides guidance to customers about whether a cloud computing arrangement includes a software license. If a cloud computing arrangement includes a software license, the customer should account for the software license element of the arrangement consistent with the acquisition of other software licenses. If a cloud computing arrangement does not include a software license, the customer should account for the arrangement as a service contract. The new guidance does not change the accounting for a customer's accounting for service contracts. ASU No. 2015-05 is effective for interim and annual reporting periods beginning after December 15, 2015. The Partnership is currently evaluating the impact, if any, of the adoption of this standard will have on our Consolidated Financial Statements.


(3) Earnings Per Limited Partner Unit

The following table illustrates the Partnership’s calculation of earnings per unit for common and subordinated limited partner units:
 
Three Months Ended 
 March 31,
 
2015
 
2014
 
(In millions, except per unit data)
Net income attributable to Enable Midstream Partners, LP
$
91

 
$
149

Less general partner interest in net income

 

Limited partner interest in net income attributable to Enable Midstream Partners, LP
$
91

 
$
149

Net income allocable to common units
$
48

 
$
149

Net income allocable to subordinated units
43

 

Limited partner interest in net income attributable to Enable Midstream Partners, LP
$
91

 
$
149

Basic and diluted weighted average number of outstanding limited partner units
 
 
 
Common units
214

 
390

Subordinated units(1)
208

 

Total
422

 
390

Basic and diluted earnings per limited partner unit
 
 
 
Common units
$
0.22

 
$
0.38

Subordinated units(1)
$
0.21

 
$

____________________
(1)
Basic and diluted earnings per subordinated unit reflect net income attributable to the Partnership for periods subsequent to its Offering, as no subordinated units were outstanding prior to this date.

There was no dilutive effect of unit-based awards during the three months ended March 31, 2015.

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(4) Partners’ Capital

In accordance with the Partnership’s First Amended and Restated Agreement of Limited Partnership, on February 14, 2014, May 14, 2014 and August 14, 2014, the Partnership distributed $114 million, $155 million and $22 million to the unitholders of record as of January 1, 2014, April 1, 2014, and April 1, 2014, respectively.

The Partnership's Second Amended and Restated Agreement of Limited Partnership requires that, within 45 days subsequent to the end of each quarter, the Partnership distribute all of its available cash (as defined in the Second Amended and Restated Agreement of Limited Partnership) to unitholders of record on the applicable record date. The Partnership did not make distributions for the period that began on April 1, 2014 and ended on April 15, 2014, the day prior to the closing of the Offering, other than the required distributions to CenterPoint Energy, OGE Energy, and ArcLight under the First Amended and Restated Agreement of Limited Partnership.

The Partnership paid or has authorized payment of the following cash distributions under the Second Amended and Restated Agreement of Limited Partnership during 2014 and 2015 (in millions, except for per unit amounts):
Quarter Ended
 
Record Date
 
Payment Date
 
Per Unit Distribution
 
Total Cash Distribution
March 31, 2015(1)
 
May 5, 2015
 
May 15, 2015
 
$
0.3125

 
$
132

December 31, 2014
 
February 4, 2015
 
February 13, 2015
 
$
0.30875

 
$
130

September 30, 2014
 
November 4, 2014
 
November 14, 2014
 
$
0.3025

 
$
128

June 30, 2014 (2)
 
August 4, 2014
 
August 14, 2014
 
$
0.2464

 
$
104

_____________________
(1)
The board of directors of Enable GP declared this $0.3125 per common unit cash distribution on April 24, 2015, to be paid on May 15, 2015, to unitholders of record at the close of business on May 5, 2015.
(2)
The quarterly distribution for three months ended June 30, 2014 was prorated for the period beginning immediately after the closing of the Partnership's Offering, April 16, 2014 through June 30, 2014.

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 our partnership agreement) in excess of $0.330625 per unit per quarter. The maximum distribution of 50.0% does not include any distributions that Enable GP or its affiliates may receive on common units or subordinated units that they own.

Subordinated Units

All subordinated units are held by CenterPoint Energy and OGE Energy. These units are considered subordinated because during the subordination period (as defined in our partnership agreement), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.2875 per common unit, which amount is defined in the partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units.

Subordination Period

The subordination period began on the closing date of the Offering and will extend until the first business day following the distributions of available cash from operating surplus (as defined in the partnership agreement) on each of the outstanding

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common units and subordinated units equal to or exceeding $1.15 per unit (the annualized minimum quarterly distribution) for each of the three consecutive, non-overlapping four-quarter periods immediately preceding June 30, 2017. Also, if the Partnership has paid distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equal to or exceeding $1.725 per unit (150% of the annualized minimum quarterly distribution) and the related distribution on the incentive distribution rights, for any four-consecutive-quarter period ending on or after June 30, 2015, the subordination period will terminate.


(5) Intangible Assets, Net
 
The Partnership has $401 million in intangible assets associated with customer relationships due to the acquisition of Enogex. The Partnership determined that intangible assets related to customer relationships have a weighted average useful life of 15 years as of May 1, 2013. Intangible assets do not have any significant residual value or renewal options of existing terms. There are no intangible assets with indefinite useful lives.

Intangible assets consist of the following:

 
March 31,
2015
 
December 31, 2014
 
(In millions)
Customer relationships:
 
 
 
Total intangible assets
$
401

 
$
401

Accumulated amortization
51

 
45

Net intangible assets
$
350

 
$
356


The Partnership recorded amortization expense of $6 million and $7 million during each of the three months ended March 31, 2015 and 2014, respectively.

 
(6) Investments in Equity Method Affiliates
 
The Partnership uses the equity method of accounting for investments in entities in which it has an ownership interest between 20% and 50% and exercises significant influence.
 
For the period from May 1, 2013 through May 29, 2014, the Partnership held a 24.95% interest in SESH, which is accounted for as an investment in equity method affiliates, and CenterPoint Energy indirectly owned a 25.05% interest in SESH. Pursuant to the MFA, that interest could be contributed to the Partnership upon exercise of certain put or call rights, under which CenterPoint Energy would contribute to the Partnership CenterPoint Energy’s retained interest in SESH at a price equal to the fair market value of such interest at the time the put right or call right is exercised. On May 13, 2014, CenterPoint Energy exercised its put right with respect to a 24.95% interest in SESH. Pursuant to the put right, on May 30, 2014, CenterPoint Energy contributed a 24.95% interest in SESH to the Partnership in exchange for 6,322,457 common units representing limited partner interests in the Partnership, which had a fair value of $161 million based upon the closing market price of the Partnership's common units. If CenterPoint Energy were to exercise its remaining put right or the Partnership were to exercise its remaining call right (which may be no earlier than June 2015), CenterPoint Energy’s retained interest in SESH would be contributed to the Partnership in exchange for consideration consisting of 25,341 limited partner units for a 0.1% interest in SESH and, subject to certain restrictions, a cash payment, payable either from CenterPoint Energy to the Partnership or from the Partnership to CenterPoint Energy, in an amount such that the total consideration exchanged is equal in value to the fair market value of the contributed interest in SESH, subject to adjustment for accretion and dilution events. Affiliates of Spectra Energy Corp own the remaining 50% interest in SESH. Pursuant to the terms of the SESH LLC Agreement, if, at any time, CenterPoint Energy has a right to receive less than 50% of our distributions through its limited partner interest in the Partnership and its economic interest in Enable GP, affiliates of Spectra Energy Corp will have the right to purchase our interest in SESH at fair market value. As of March 31, 2015, the Partnership owned a 49.90% interest in SESH.

In connection with CenterPoint Energy's exercise of its put right with respect to its 24.95% interest in SESH, the parties agreed to allocate the distributions for the quarter ended June 30, 2014 on (i) the SESH interest acquired by Enable and (ii) the Enable units issued to CenterPoint Energy for the SESH interest pro rata based on the time each party held the relevant interest. On July 25, 2014, the Partnership received a $7 million distribution from SESH for the three month period ended June 30, 2014,

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representing the Partnership's 49.90% interest in SESH. Under the terms of the agreement, the Partnership made a payment of approximately $1 million to CenterPoint Energy related to the additional 24.95% interest during the quarter ending September 30, 2014.


Investment in Equity Method Affiliates:
 
Three Months Ended 
 March 31,
 
2015
 
2014
 
(In millions)
Balance as of December 31
$
348

 
$
198

Equity in earnings of equity method affiliate
7

 
3

Contributions to equity method affiliate
6

 

Distributions from equity method affiliate
(12
)
 
(3
)
Balance as of March 31
$
349

 
$
198


Equity in Earnings of Equity Method Affiliates:
 
Three Months Ended 
 March 31,
 
2015

2014
 
(In millions)
SESH
$
7

 
$
3


Distributions from Equity Method Affiliates:
 
Three Months Ended 
 March 31,
 
2015
 
2014
 
(In millions)
SESH
$
12

 
$
3


Summarized financial information of SESH is presented below:
 
Three Months Ended 
 March 31,
 
2015
 
2014
 
(In millions)
Income Statements:
 
 
 
Revenues
$
29

 
$
27

Operating income
18

 
17

Net income
14

 
12


 


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(7) Debt
 
The following table presents the Partnership's outstanding debt as of March 31, 2015 and December 31, 2014.

 
March 31,
2015
 
December 31,
2014
 
(In millions)
Commercial Paper
$
436

 
$
253

Notes payable — affiliated companies
363

 
363

2019 Notes
500

 
500

2024 Notes
600

 
600

2044 Notes
550

 
550

Enable Oklahoma Senior Notes
250

 
250

Premium (Discount) on long-term debt
26

 
28

Total debt
2,725

 
2,544

Less amount classified as short-term debt(1)
436

 
253

Less Notes payable—affiliated companies
363

 
363

Total long-term debt
$
1,926

 
$
1,928

___________________
(1)
Short-term debt includes $436 million and $253 million of commercial paper as of March 31, 2015 and December 31, 2014, respectively.

Revolving Credit Facility

The Partnership has a $1.4 billion senior unsecured revolving credit facility (Revolving Credit Facility) that is scheduled to expire on May 1, 2018. As of March 31, 2015 there were no principal advances and $2 million in letters of credit outstanding under the Revolving Credit Facility. However, as discussed below, commercial paper borrowings effectively reduce our borrowing capacity under this Revolving Credit Facility.

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. As of March 31, 2015, $436 million was outstanding under our commercial paper program. Any reduction in our credit ratings could prevent us from accessing the commercial paper markets.

Financing Costs

Unamortized debt expense of $16 million and $17 million as of March 31, 2015 and December 31, 2014, respectively, is classified in Other Assets in the Condensed Consolidated Balance Sheets and is being amortized over the life of the respective debt. Unamortized premium on long-term debt of $26 million and $28 million at March 31, 2015 and December 31, 2014, respectively, is classified as either Long-Term Debt or Current Portion of Long-Term Debt, consistent with the underlying debt instrument, in the Condensed Consolidated Balance Sheets and is being amortized over the life of the respective debt.

 As of March 31, 2015, the Partnership and Enable Oklahoma were in compliance with all of their debt agreements, including financial covenants.

 
(8) 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:
 

15


Level 1: Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. Instruments classified as Level 1 include natural gas futures, swaps and options transactions for contracts traded on the NYMEX and settled through a NYMEX clearing broker.
 
Level 2: Inputs, other than quoted prices included in Level 1, are observable for the asset or liability, either directly or indirectly. Level 2 inputs include quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities that are generally included in this category are derivatives with fair values based on inputs from actively quoted markets. Instruments classified as Level 2 include over-the-counter NYMEX natural gas swaps, natural gas basis swaps and natural gas purchase and sales transactions in markets such that the pricing is closely related to the NYMEX pricing, and over-the-counter WTI crude swaps for condensate sales.
 
Level 3: Inputs are unobservable for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. Unobservable inputs reflect the Partnership’s judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. The Partnership develops these inputs based on the best information available, including the Partnership’s own data.
 
The Partnership utilizes the market approach in determining the fair value of its derivative positions by using either NYMEX or WTI published market prices, independent broker pricing data or broker/dealer valuations. The valuations of derivatives with pricing based on NYMEX published market prices may be considered Level 1 if they are settled through a NYMEX clearing broker account with daily margining. Over-the-counter derivatives with NYMEX or WTI based prices are considered Level 2 due to the impact of counterparty credit risk. Valuations based on independent broker pricing or broker/dealer valuations may be classified as Level 2 only to the extent they may be validated by an additional source of independent market data for an identical or closely related active market. In certain less liquid markets or for longer-term contracts, forward prices are not as readily available. In these circumstances, contracts are valued using internally developed methodologies that consider historical relationships among various quoted prices in active markets that result in management’s best estimate of fair value. These contracts are classified as Level 3.
 
The Partnership determines the appropriate level for each financial asset and liability on a quarterly basis and recognizes transfers between levels at the end of the reporting period. For the period ended March 31, 2015, there were no transfers between Level 1, 2, and 3 investments.
 
The impact to the fair value of derivatives due to credit risk is calculated using the probability of default based on Standard & Poor’s Ratings Services and/or internally generated ratings. The fair value of derivative assets is adjusted for credit risk. The fair value of derivative liabilities is adjusted for credit risk only if the impact is deemed material.

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

16


The following tables summarize the Partnership’s assets and liabilities that are measured at fair value on a recurring basis as of March 31, 2015 and December 31, 2014:
 
March 31, 2015
Commodity Contracts
 
Gas Imbalances (1)
 
Assets
 
Liabilities
 
Assets (2)
 
Liabilities (3)
 
(In millions)
Quoted market prices in active market for identical assets (Level 1)
$
26

 
$
4

 
$

 
$

Significant other observable inputs (Level 2)
1

 

 
29

 
$
5

Unobservable inputs (Level 3)
7

 

 

 
$

Total fair value
34

 
4

 
29

 
$
5

Netting adjustments
(4
)
 
(4
)
 

 
$

Total
$
30

 
$

 
$
29

 
$
5


December 31, 2014
Commodity Contracts
 
Gas Imbalances (1)
 
Assets
 
Liabilities
 
Assets (2)
 
Liabilities (3)
 
(In millions)
Quoted market prices in active market for identical assets (Level 1)
$
33

 
$
4

 
$

 
$

Significant other observable inputs (Level 2)
2

 

 
40

 
12

Unobservable inputs (Level 3)
5

 

 

 

Total fair value
40

 
4

 
40

 
12

Netting adjustments
(4
)
 
(4
)
 

 

Total
$
36

 
$

 
$
40

 
$
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 Enable Oklahoma 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, 2015 and December 31, 2014.
(2)
Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $8 million and $4 million at March 31, 2015 and December 31, 2014, 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 $3 million and $1 million at March 31, 2015 and December 31, 2014, 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.

Estimated Fair Value of Financial Instruments

The fair values of all accounts receivable, notes receivable, accounts payable, notes payable-commercial paper, and other such financial instruments on the Condensed Consolidated Balance Sheets are estimated to be approximately equivalent to their carrying amounts and have been excluded from the table below. The following table summarizes the fair value and carrying amount of the Partnership’s financial instruments at March 31, 2015 and December 31, 2014.
 
 
March 31, 2015
 
December 31, 2014
 
Carrying Amount
 
Fair Value
 
Carrying Amount
 
Fair Value
 
(In millions)
Long-Term Debt
 
 
 
 
 
 
 
Long-term notes payable - affiliated companies (Level 2)
$
363

 
$
365

 
$
363

 
$
362

Revolving Credit Facility (Level 2)(1)

 

 

 

Enable Oklahoma Senior Notes (Level 2)(2)
277

 
282

 
279

 
282

Enable Midstream Partners, LP 2019, 2024 and 2044 Notes (Level 2)
1,649

 
1,568

 
1,649

 
1,592


17


___________________
(1)
Borrowing capacity is reduced by our borrowings outstanding under the commercial paper program. $436 million and $253 million of commercial paper was outstanding as of March 31, 2015 and December 31, 2014, respectively.
(2)
No amount was included in short term debt as of March 31, 2015 and December 31, 2014, respectively.

The fair value of the Partnership’s Long-term notes payable—affiliated companies, along with the Enable Oklahoma Senior Notes and Enable Midstream Partners, LP 2019, 2024 and 2044 Notes, is based on quoted market prices and estimates of current rates available for similar issues with similar maturities and is classified as Level 2 in the fair value hierarchy.
 
Non-Financial Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
 
Certain assets and liabilities are measured at fair value on a nonrecurring basis; that is, the assets and liabilities are not measured at fair value on an ongoing basis, but are subject to fair value adjustments in certain circumstances (e.g., when there is evidence of impairment).

As of March 31, 2015 and December 31, 2014, no material fair value adjustments or fair value measurements were required for these non-financial assets or liabilities.


(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 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 keep-whole natural gas exposure associated with its processing operations and the Partnership’s natural gas exposure associated with operating its gathering, transportation and storage assets; and
natural gas futures and swaps, natural gas options and natural gas commodity purchases and sales are used to manage the Partnership’s natural gas exposure associated with its storage and transportation contracts and asset management activities.

Normal purchases and normal sales contracts are not recorded in Other Assets or Liabilities in the Condensed Consolidated Balance Sheets and earnings are recognized and recorded in the period in which physical delivery of the commodity occurs. Management applies normal purchases and normal sales treatment to: (i) commodity contracts for the purchase and sale of natural gas used in or produced by the Partnership’s operations and (ii) commodity contracts for the purchase and sale of NGLs produced by the Partnership’s gathering and processing business.
 
The Partnership recognizes its non-exchange traded derivative instruments as Other Assets or Liabilities in the Condensed Consolidated Balance Sheets at fair value with such amounts classified as current or long-term based on their anticipated settlement. Exchange traded transactions are settled on a net basis daily through margin accounts with a clearing broker and, therefore, are recorded at fair value on a net basis in Other Current Assets in the Condensed Consolidated Balance Sheets.
 
As of March 31, 2015 and December 31, 2014, the Partnership had no derivative instruments that were designated as cash flow or fair value hedges for accounting purposes.

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

18

Table of Contents

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, 2015 and December 31, 2014, the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes:

 
March 31, 2015
 
December 31, 2014
  
Gross Notional  Volume
 
Purchases
 
Sales
 
Purchases
 
Sales
Natural gas— TBtu(1)
 
 
 
 
 
 
 
Physical purchases/sales
5

 
67

 
4

 
32

Financial fixed futures/swaps
5

 
34

 
5

 
35

Financial basis futures/swaps
4

 
40

 
7

 
54

Condensate— MBbl(2)

 

 
 
 
 
Financial Futures/swaps

 
970

 

 
12

Natural gas liquids— MBbl(3)

 

 
 
 
 
Financial Futures/swaps

 
714

 

 

____________________
(1)
As of March 31, 2015, 93.5% of the natural gas contracts had durations of one year or less, 5.1% had durations of more than one year and less than two years and 1.4% had durations of more than two years. As of December 31, 2014, 91.2% of the natural gas contracts had durations of one year or less, 6.5% had durations of more than one year and less than two years and 2.2% had durations of more than two years.
(2)
As of March 31, 2015, 75.5% of the condensate contracts had durations of one year or less and 24.5% had durations of more than one year and less than two years. As of December 31, 2014, 100.0% of the condensate contracts had durations of one year or less.
(3)
As of March 31, 2015, 100.0% of the natural gas liquids contracts had durations of one year or less.

Balance Sheet Presentation Related to Derivative Instruments
 
The fair value of the derivative instruments that are presented in the Partnership’s Condensed Consolidated Balance Sheet as of March 31, 2015 and December 31, 2014 that were not designated as hedging instruments for accounting purposes are as follows:
 

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March 31, 2015
 
December 31, 2014
 
 
 
Fair Value
Instrument
Balance Sheet Location
 
Assets
 
Liabilities
 
Assets
 
Liabilities
 
 
 
(In millions)
Natural gas
 
 
 
 
 
 
 
Financial futures/swaps
Other Current
 
$
27

 
$
4

 
$
34

 
$
4

Physical purchases/sales
Other Current
 
1

 

 
1

 

Condensate
 
 
 
 
 
 
 
 
 
Financial futures/swaps
Other Current
 
6

 

 
5

 

Natural gas liquids
 
 
 
 
 
 
 
 
 
Financial Futures/swaps
Other Current
 

 

 

 

Total gross derivatives (1)
 
 
$
34

 
$
4

 
$
40

 
$
4

_____________________
(1)
See Note 8 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Condensed Consolidated Balance Sheet as of March 31, 2015 and December 31, 2014.

Income Statement Presentation Related to Derivative Instruments
 
The following tables present the effect of derivative instruments on the Partnership’s Condensed Consolidated Statement of Income for the three months ended March 31, 2015.
 
  
Amounts Recognized in Income
 
Three Months Ended 
 March 31,
 
2015
 
2014
 
(In millions)
Natural gas financial futures/swaps gains (losses)
$
7

 
$
2

Natural gas physical purchases/sales gains (losses)
(4
)
 
2

Condensate financial futures/swaps gains (losses)
4

 

Natural gas liquids financial futures/swaps gains (losses)

 

Total
$
7

 
$
4

 
For derivatives not designated as hedges in the tables above, amounts recognized in income for the periods ended March 31, 2015 and 2014, if any, are reported in Revenues.
 
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, 2015, the Partnership would have been required to post no 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, 2015. 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) Supplemental Disclosure of Cash Flow Information

The following table provides information regarding supplemental cash flow information:


20

Table of Contents

 
Three Months Ended 
 March 31,
 
2015
 
2014
 
(In millions)
Supplemental Disclosure of Cash Flow Information:
 
 
 
Cash Payments:
 
 
 
Interest, net of capitalized interest
$
9

 
$
15

Non-cash transactions:


 


Accounts payable related to capital expenditures
51

 
17



(11) Related Party Transactions
 
The material related party transactions with CenterPoint Energy, OGE Energy and their respective subsidiaries are summarized below. There were no material related party transactions with other affiliates.
 
The Partnership’s revenues from affiliated companies accounted for 8% and 6% of revenues during the three months ended March 31, 2015 and 2014, 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,
 
2015
 
2014
 
(In millions)
Gas transportation and storage - CenterPoint Energy
$
33

 
$
33

Gas sales - CenterPoint Energy
6

 
15

Gas transportation and storage - OGE Energy (1)
9

 
12

Gas sales - OGE Energy (1)
3

 
5

Total revenues - affiliated companies
$
51

 
$
65

____________________
(1)
The Partnership's contracts with OGE Energy to transport and sell natural gas to OGE Energy’s natural gas-fired generation facilities and store natural gas are reflected in Partnership’s Condensed Consolidated Statement of Income beginning on May 1, 2013. On March 17, 2014, the Partnership and the electric utility subsidiary of OGE Energy signed a new transportation agreement effective May 1, 2014 with a primary term 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.

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,
 
2015
 
2014
 
(In millions)
Cost of goods sold - CenterPoint Energy
$
1

 
$
1

Cost of goods sold - OGE Energy
3

 
3

Total cost of goods sold - affiliated companies
$
4

 
$
4


Prior to May 1, 2013, the Partnership had employees and reflected the associated benefit costs directly and not as corporate services. Under the terms of the MFA, effective May 1, 2013 the Partnership’s employees were seconded by CenterPoint Energy and OGE Energy, and the Partnership began reimbursing each of CenterPoint Energy and OGE Energy for all employee costs under the seconding agreements until the seconded employees transition from CenterPoint Energy and OGE Energy to the Partnership. The Partnership transitioned seconded employees from CenterPoint Energy and OGE Energy to the Partnership effective January 1, 2015, except for certain employees who are participants under OGE Energy’s defined benefit and retiree medical plans, who will remain seconded to the Partnership, subject to certain termination rights of the Partnership and OGE

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Energy. The Partnership’s reimbursement of OGE Energy for employee costs arising out of OGE Energy’s defined benefit and retiree medical plans is fixed at $6 million in each of 2015 and 2016, $5 million in 2017, and at actual cost subject to a cap of $5 million in 2018 and thereafter, in the event of continued secondment.
 
Prior to May 1, 2013, the Partnership received certain services and support functions from CenterPoint Energy described below. Under the terms of the MFA, effective May 1, 2013, the Partnership receives services and support functions from each of CenterPoint Energy and OGE Energy under service agreements for an initial term ending on April 30, 2016. The service agreements automatically extend year-to-year at the end of the initial term, unless terminated by the Partnership with at least 90 days’ notice. Additionally, the Partnership may terminate these service agreements at any time with 180 days’ notice, if approved by the Board of Enable GP. The Partnership reimburses CenterPoint Energy and OGE Energy for these services up to annual caps, which for 2015 are $10 million and $11 million, respectively.

Effective April 1, 2014, the Partnership, CenterPoint Energy and OGE Energy agreed to reduce certain allocated costs charged to the Partnership because the Partnership has assumed responsibility for the related activities.

Amounts charged to the Partnership by affiliates for seconded employees and corporate services, included primarily in operating and maintenance expenses in Partnership’s Condensed Consolidated Statements of Income are as follows:
 
 
Three Months Ended 
 March 31,
 
2015
 
2014
 
(In millions)
Seconded Employee Costs - CenterPoint Energy
$

 
$
38

Corporate Services - CenterPoint Energy
4

 
11

Seconded Employee Costs - OGE Energy
9

 
31

Corporate Services - OGE Energy
3

 
6

Total corporate services and seconded employees expense
$
16

 
$
86


The Partnership has outstanding long-term notes payable—affiliated companies to CenterPoint Energy at both March 31, 2015 and December 31, 2014 of $363 million which mature in 2017. Notes having an aggregate principal amount of approximately $273 million bear a fixed interest rate of 2.10% and notes having an aggregate principal amount of approximately $90 million bear a fixed interest rate of 2.45%.

The Partnership recorded affiliated interest expense to CenterPoint Energy on note payable—affiliated companies of $2 million during each of the three months ended March 31, 2015 and 2014, respectively.


(12) 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.




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(13) Equity Based Compensation

The following table summarizes the Partnership’s compensation expense for the three months ended March 31, 2015 and 2014 related to performance units, restricted units, and phantom units for the Partnership's employees.

 
Three Months Ended 
 March 31,
 
2015
 
2014
 
(In millions)
Performance units
$
1

 
$

Restricted units
2

 

Phantom units

 

Total compensation expense
$
3

 
$


Units Outstanding

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, 2015 and changes during 2015 are shown in the following table.

 
Performance Units
 
Restricted Units
 
Phantom Units
  
Number
of Units
 
Aggregate
Intrinsic
Value
 
Number
of Units
 
Aggregate
Intrinsic
Value
 
Number
of Units
 
Aggregate
Intrinsic
Value
 
(In millions, except unit data)
Units Outstanding at December 31, 2014
552,581

 

 
838,068

 

 
98,718

 

Granted(1)

 

 
45,230

 

 

 

Vested
(712
)
 

 
(137,961
)
 

 

 


Forfeited
(42,130
)
 

 
(12,641
)
 

 
(2,000
)
 

Units Outstanding at March 31, 2015
509,739

 
$
7

 
732,696

 
$
14

 
96,718

 
$
2

Units Fully Vested at March 31, 2015
2,257

 


 
 
 
 
 
500

 


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

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, 2015
 
Unrecognized Compensation Cost
(In millions)
 
Weighted Average to be Recognized
(In years)
Performance Units
$
9

 
2.17
Restricted Units
12

 
2.06
Phantom Units

 
0.11
Total
$
21

 
 

As of March 31, 2015, there were 11,470,160 units available for issuance under the long term incentive plan.




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(14) Reportable Segments
 
The Partnership’s determination of reportable segments considers the strategic operating units under which it manages sales, allocates resources and assesses performance of various products and services to wholesale or retail customers in differing regulatory environments. The accounting policies of the reportable segments are the same as those described in the summary of significant accounting policies excerpt in the Partnership’s audited 2014 combined and consolidated financial statements included in the Annual Report. The Partnership uses operating income as the measure of profit or loss for its reportable segments.
 
The Partnership’s assets and operations are organized into two reportable segments: (i) Gathering and Processing, which primarily provides natural gas gathering, processing and fractionation services and crude oil gathering for our producer customers, and (ii) Transportation and Storage, which provides interstate and intrastate natural gas pipeline transportation and storage service primarily to natural gas producers, utilities and industrial customers.
 
Financial data for reportable segments and services are as follows:
 
Three Months Ended March 31, 2015
Gathering  and
Processing
 
Transportation
and Storage(1)
 
Eliminations
 
Total
 
(In millions)
Revenues
$
401

 
$
308

 
$
(93
)
 
$
616

Cost of goods sold, excluding depreciation and amortization
222

 
163

 
(93
)
 
292

Operation and maintenance
76

 
54

 

 
130

Depreciation and amortization
43

 
30

 

 
73

Taxes other than income tax
8

 
9

 

 
17

Operating income
$
52

 
$
52

 
$

 
$
104

Total assets
$
10,231

 
$
8,127

 
$
(6,390
)
 
$
11,968

Capital expenditures
$
215

 
$
24

 
$

 
$
239

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended March 31, 2014
Gathering and
Processing
 

Transportation
and Storage(1)
 
Eliminations
 
Total
 
(In millions)
Revenues
$
671

 
$
528

 
$
(197
)
 
$
1,002

Cost of goods sold, excluding depreciation and amortization
464

 
366

 
(197
)
 
633

Operation and maintenance
69

 
57

 

 
126

Depreciation and amortization
38

 
29

 

 
67

Taxes other than income tax
4

 
10

 

 
14

Operating income
$
96

 
$
66

 
$

 
$
162

Total assets as of December 31, 2014
$
8,356

 
$
5,493

 
$
(2,012
)
 
$
11,837

Capital expenditures
$
129

 
$
21

 
$
(1
)
 
$
149

_____________________
(1)
Transportation and Storage recorded equity income of $7 million and $3 million for the three months ended March 31, 2015 and 2014, respectively, from its interest in SESH, a jointly-owned pipeline. These amounts are included in Equity in earnings of equity method affiliates under the Other Income (Expense) caption. Transportation and Storage’s investment in SESH was $349 million and $348 million as of March 31, 2015 and December 31, 2014, respectively, and is included in Investments in equity method affiliates. The Partnership reflected a 24.95% interest in SESH for the period of December 31, 2013 until May 29, 2014. On May 30, 2014, CenterPoint Energy contributed its 24.95% interest in SESH to the Partnership. As of March 31, 2015, the Partnership owns 49.90% interest in SESH. See Note 6 for further discussion regarding SESH.




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Table of Contents

(15) Subsequent Events

On May 1, 2015, the Partnership completed an $80 million acquisition of certain natural gas gathering assets in the Texas Panhandle from Monarch Natural Gas, LLC.


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


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Table of Contents

The following discussion and analysis should be read in conjunction with our unaudited condensed consolidated financial statements and the related notes included herein and our audited combined and consolidated financial statements for the year ended December 31, 2014, included in our Annual Report. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Please read “Forward-Looking Statements.” In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.
Overview
 
We are a large-scale, growth-oriented publicly traded Delaware limited partnership formed to own, operate and develop strategically located natural gas and crude oil infrastructure assets. We serve current and emerging production areas in the United States, including several unconventional shale resource plays and local and regional end-user markets in the United States. Our assets and operations are organized into two reportable segments: (i) gathering and processing, which primarily provides natural gas gathering, processing and fractionation services and crude oil gathering for our producer customers, and (ii) transportation and storage, which provides interstate and intrastate natural gas pipeline transportation and storage service primarily to natural gas producers, utilities and industrial customers.

Our natural gas gathering and processing assets are located in five states and serve natural gas production from shale developments in the Anadarko, Arkoma and Tex-La basins. We also own a crude oil gathering business in the Bakken Shale formation of the Williston Basin that commenced initial operations in November 2013. Our natural gas transportation and storage assets extend from western Oklahoma and the Texas Panhandle to Alabama and from Louisiana to Illinois.
 
We expect our business to continue to be affected by the key trends included in our Annual Report. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results.


Recent Developments
 
Construction update

During the three months ended March 31, 2015, the Partnership commenced full operation of the 200 MMcf/d cryogenic processing facility (the Bradley Plant) located in the Anadarko basin and the 19,500 Bbl/d crude oil and produced water gathering system located in the Williston basin.

EGT Open Season

From February 20, 2015 through March 19, 2015, EGT held a non-binding open season for firm interstate natural gas transportation capacity, including capacity from an expansion of EGT’s Line AD in Oklahoma. EGT is currently in the process of evaluating the bids received. The proposed Oklahoma expansion capacity would provide enhanced transportation options from receipt points in the Oklahoma supply area.


Results of Operations
 
The following tables summarize the key components of our results of operations for the three months ended March 31, 2015 and 2014.
 

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Three Months Ended March 31, 2015
Gathering and
Processing
 
Transportation
and Storage
 
Eliminations
 
Enable
Midstream
Partners, LP
 
(In millions)
Revenues
$
401

 
$
308

 
$
(93
)
 
$
616

Cost of goods sold (excluding depreciation and amortization)
222

 
163

 
(93
)
 
292

Gross margin on revenues
179

 
145

 

 
324

Operation and maintenance
76

 
54

 

 
130

Depreciation and amortization
43

 
30

 

 
73

Impairment

 

 

 

Taxes other than income tax
8

 
9

 

 
17

Operating income
$
52

 
$
52

 
$

 
$
104

Equity in earnings of equity method affiliates
$

 
$
7

 
$

 
$
7


Three Months Ended March 31, 2014
Gathering and
Processing
 
Transportation
and Storage
 
Eliminations
 
Enable
Midstream
Partners, LP
 
(In millions)
Revenues
$
671

 
$
528

 
$
(197
)
 
$
1,002

Cost of goods sold (excluding depreciation and amortization)
464

 
366

 
(197
)
 
633

Gross margin on revenues
207

 
162

 

 
369

Operation and maintenance
69

 
57

 

 
126

Depreciation and amortization
38

 
29

 

 
67

Impairment

 

 

 

Taxes other than income tax
4

 
10

 

 
14

Operating income
$
96

 
$
66

 
$

 
$
162

Equity in earnings of equity method affiliates
$

 
$
3

 
$

 
$
3



 
Three Months Ended 
 March 31,
 
2015
 
2014
Operating Data:
 
 
 
Gathered volumes—TBtu
286

 
298

Gathered volumes—TBtu/d
3.18

 
3.31

Natural gas processed volumes—TBtu
151

 
130

Natural gas processed volumes—TBtu/d
1.68

 
1.44

NGLs produced—MBbl/d(1)
65.00

 
65.28

NGLs sold—MBbl/d(1)(2)
67.62

 
66.16

Condensate sold—MBbl/d
5.96

 
5.15

Crude Oil - Gathered volumes—MBbl/d
6.72

 
1.00

Transported volumes—TBtu
514

 
500

Transportation volumes—TBtu/d
5.72

 
5.55

Interstate firm contracted capacity—Bcf/d
7.82

 
7.93

Intrastate average deliveries—TBtu/d
1.84

 
1.57

 _____________________
(1)
Excludes condensate.
(2)
NGLs sold includes volumes of NGLs withdrawn from inventory or purchased for system balancing purposes.


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Table of Contents

Gathering and Processing
 
Three months ended March 31, 2015 compared to three months ended March 31, 2014. Our gathering and processing business segment reported operating income of $52 million in the three months ended March 31, 2015 compared to $96 million in the three months ended March 31, 2014. Operating income decreased $44 million primarily from decreased gross margin of $28 million, an increase in operation and maintenance expenses of $7 million, an increase in depreciation and amortization of $5 million and an increase in taxes other than income tax of $4 million, during the three months ended March 31, 2015.

Our gathering and processing business segment gross margin decreased $28 million primarily due to lower average natural gas prices of $10 million, lower processing margin of $19 million due to lower natural gas liquids prices partially offset by higher processed volumes in the Anadarko and Tex-La basins, increased unrealized gains on condensate derivatives of $1 million and decreased gathered volumes in the Arkoma and Tex-La basins of $5 million, net of minimum volume payments, partially offset by higher crude oil gathering margin of $5 million as our Bakken crude gathering continued to increase system volumes.

Our gathering and processing business segment operation and maintenance expenses increased $7 million primarily due to an increase in payroll related costs of $5 million related to workforce reductions as well as an increase in general operating expenses of $2 million to support and operate new assets.

Our gathering and processing business segment depreciation and amortization increased $5 million due to additional assets placed in service.

Our gathering and processing business segment taxes other than income tax increased $4 million due to additional assets placed in service of $1 million, and the effect of a favorable settlement of a state and local tax dispute for $3 million less than the previously recognized reserve during 2014.

Transportation and Storage
 
Three months ended March 31, 2015 compared to three months ended March 31, 2014. Our transportation and storage business segment reported operating income of $52 million in the three months ended March 31, 2015 compared to $66 million in the three months ended March 31, 2014. Operating income decreased $14 million primarily resulting from a decrease in gross margin of $17 million, a decrease of $3 million in operation and maintenance expenses and a $1 million increase in depreciation and amortization expenses, partially offset by lower taxes other than income tax of $1 million for the three months ended March 31, 2015.

Our transportation and storage business segment gross margin decreased $17 million primarily due to a decrease in unrealized gains on natural gas derivatives of $7 million, lower system optimization opportunities of $4 million, a decrease in liquid sales related to NGLs collected under contractual arrangement due to lower natural gas liquids prices of $7 million, as well as a decrease in storage demand fees of $3 million and balancing services of $1 million, partially offset by an increase to margins from off-system transportation revenues of $4 million, and higher other firm transportation revenues of $1 million.

Our transportation and storage business segment operation and maintenance expenses decreased $3 million due to a decrease in non-capital costs of $4 million, offset by $1 million of higher payroll related and general expenses.

Our transportation and storage business segment depreciation and amortization increased $1 million primarily due to additional assets placed in service.

Our transportation and storage business segment taxes other than income tax decreased $1 million due to reduced ad valorem taxes.

Our transportation and storage business segment recorded equity in earnings of equity method affiliates of $7 million and $3 million for the three months ended March 31, 2015 and 2014, respectively, from our interest in SESH. The $4 million increase in equity in earnings of equity method affiliates is attributable to a 24.95% increase to our interest in SESH.


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Table of Contents

Condensed Consolidated Interim Information
 
 
Three Months Ended 
 March 31,
 
2015
 
2014
 
(In millions)
Operating Income
$
104

 
$
162

Other Income (Expense):
 
 
 
Interest expense
(20
)
 
(14
)
Equity in earnings of equity method affiliates
7

 
3

Other, net
1

 

Total Other Income (Expense)
(12
)
 
(11
)
Income Before Income Taxes
92

 
151

Income tax expense (benefit)
1

 
1

Net Income
$
91

 
$
150

Less: Net income attributable to noncontrolling interest

 
1

Net Income attributable to Enable Midstream Partners, LP
$
91

 
$
149


 
Three Months Ended 
 March 31,
 
2015
 
2014
 
(In millions)
Other Financial Data:
 
 
 
Gross Margin (1)
$
324

 
$
369

Adjusted EBITDA (1)
204

 
228

Distributable cash flow (1)
143

 
183

 _____________________
(1)
Gross margin, Adjusted EBITDA and distributable cash flow are defined and reconciled to their most directly comparable financial measures calculated and presented below under the caption Non-GAAP Financial Measure within this Part I, Item 2.
 

Three Months Ended March 31, 2015 compared to Three Months Ended March 31, 2014

Net Income attributable to the Partnership. We reported net income attributable to the Partnership of $91 million and $149 million in the three months ended March 31, 2015 and 2014, respectively. The decrease in net income attributable to the Partnership of $58 million was primarily attributable to a decrease in operating income of $58 million and an increase in interest expense of $6 million, partially offset by an increase in equity earnings in equity method affiliates of $4 million (discussed by business segment above) and an increase in other income and expense of $1 million in the three months ended March 31, 2015.

Interest Expense. Interest expense increased $6 million due to higher interest rates on the Partnership's outstanding debt.


Non-GAAP Financial Measures

The Partnership has included the non-GAAP financial measures gross margin, Adjusted EBITDA and distributable cash flow in this report based on information in its condensed consolidated financial statements.
Gross margin, Adjusted EBITDA and distributable cash flow are supplemental financial measures that management and external users of the Partnership’s financial statements, such as industry analysts, investors, lenders and rating agencies may use, to assess:
The Partnership’s operating performance as compared to those of other publicly traded partnerships in the midstream energy industry, without regard to capital structure or historical cost basis;
The ability of the Partnership’s assets to generate sufficient cash flow to make distributions to its partners;
The Partnership’s ability to incur and service debt and fund capital expenditures; and

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Table of Contents

The viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.
This report includes a reconciliation of gross margin to revenues, Adjusted EBITDA and distributable cash flow to net income attributable to controlling interest, and Adjusted EBITDA to net cash provided by operating activities, the most directly comparable GAAP financial measures, on a historical basis, as applicable, for each of the periods indicated. The Partnership believes that the presentation of gross margin, Adjusted EBITDA and distributable cash flow provides information useful to investors in assessing its financial condition and results of operations. Gross margin, Adjusted EBITDA and distributable cash flow should not be considered as alternatives to net income, operating income, revenue, cash from operations or any other measure of financial performance or liquidity presented in accordance with GAAP. Gross margin, Adjusted EBITDA and distributable cash flow have important limitations as an analytical tool because they exclude some but not all items that affect the most directly comparable GAAP measures. Additionally, because gross margin, Adjusted EBITDA and distributable cash flow may be defined differently by other companies in the Partnership’s industry, its definitions of gross margin, Adjusted EBITDA and distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.


Three Months Ended 
 March 31,

2015
 
2014

(In millions)
Reconciliation of Gross Margin to Revenue:
 
 
 
Revenues
$
616

 
$
1,002

Cost of goods sold, excluding depreciation and amortization
292

 
633

Gross margin
$
324

 
$
369

 
 
 
 
Reconciliation of Adjusted EBITDA and distributable cash flow to net income attributable to controlling interest:
 
 
 
Net income attributable to Enable Midstream Partners, LP
$
91

 
$
149

Add:

 

Depreciation and amortization expense
73

 
67

Interest expense, net of interest income
20

 
14

Income tax expense
1

 
1

EBITDA
$
185

 
$
231

Add:
 
 
 
Distributions from equity method affiliates
12

 
3

Other non-cash losses
14

 

Less:
 
 
 
Other non-cash gains

 
(3
)
Equity in earnings of equity method affiliates
(7
)
 
(3
)
Adjusted EBITDA
$
204

 
$
228

Less:
 
 
 
Adjusted interest expense, net (1)
(22
)
 
(15
)
Maintenance capital expenditures
(39
)
 
(30
)
Distributable cash flow
$
143

 
$
183


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Three Months Ended 
 March 31,
 
2015
 
2014
 
(In millions)
Reconciliation of Adjusted EBITDA to net cash provided by operating activities:
 
 
 
Net cash provided by operating activities
$
188

 
$
106

Interest expense, net of interest income
20

 
14

Net income attributable to noncontrolling interest

 
(1
)
Income tax expense (benefit)
1

 
1

Equity in earnings of equity method affiliates, net of distributions
(5
)
 

Other non-cash items
(2
)
 
4

Changes in operating working capital which (provided) used cash:
 
 
 
Accounts receivable

 
51

Accounts payable
9

 
61

Other, including changes in noncurrent assets and liabilities
(26
)
 
(5
)
EBITDA
$
185

 
$
231

Add:
 
 
 
Distributions from equity method affiliates
12

 
3

Other non-cash losses
14

 

Less:
 
 
 
Other non-cash gains

 
(3
)
Equity in earnings of equity method affiliates
(7
)
 
(3
)
Adjusted EBITDA
$
204

 
$
228

____________________
(1) Adjusted interest expense, net excludes the effect of the amortization of the premium on Enogex’s fixed rate senior notes. This exclusion is the primary reason for the difference between “Interest expense, net” and “Adjusted interest expense, net.”


Liquidity and Capital Resources
 
Working Capital
 
Working capital is the difference in our current assets and our current liabilities. Working capital is an indication of liquidity and potential need for short-term funding. The change in our working capital requirements are driven generally by changes in accounts receivable, accounts payable, commodity prices, credit extended to, and the timing of collections from, customers, and the level and timing of spending for maintenance and expansion activity. As of March 31, 2015, we had a working capital deficit of $412 million due primarily to borrowings under our commercial paper program to manage the timing of cash flows for maintenance and expansion activity. We utilize our commercial paper program and the Revolving Credit Facility to manage the timing of cash flows and fund short-term working capital deficits.
 
Cash Flows
 
The following tables reflect cash flows for the applicable periods:
 
Three Months Ended 
 March 31,
 
2015
 
2014
 
(In millions)
Net cash provided by operating activities
$
188

 
$
106

Net cash (used in) provided by investing activities
(245
)
 
(149
)
Net cash provided by (used in) financing activities
53

 
(53
)
 

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Table of Contents

Operating Activities
 
The increase of $82 million, or 77%, in net cash provided by operating activities for the three months ended March 31, 2015 as compared to the three months ended March 31, 2014 was primarily due to the impact of timing of payments and receipts on changes in assets and liabilities partially offset by;
lower Gathering and Processing gross margin of $28 million;
lower Transportation and Storage gross margin of $17 million; and
higher payroll related expenses of $6 million, offset by lower non-capital costs of $2 million, all within operation and maintenance expenses.

Investing Activities
 
The increase of $96 million, or 64%, in net cash used in investing activities for the three months ended March 31, 2015 as compared to the three months ended March 31, 2014 was primarily due to:
higher Gathering and Processing capital expenditures of $86 million;
higher Transportation and Storage capital expenditures of $3 million; and
investments in equity affiliates of $6 million.

Financing Activities

The decrease of $106 million in net cash used in financing activities for the three months ended March 31, 2015 as compared to the three months ended March 31, 2014 was primarily due to:
decrease in gross borrowings under the Revolving Credit Facility of $115 million and decrease in gross repayments of $487 million;
a change of $250 million in commercial paper borrowings due to increases in short term debt of $183 million and $433 million for the three months ended March 31, 2015 and March 31, 2014, respectively; and
increase in distributions to partners of $16 million.

Revolving Credit Facility

The Partnership also has a $1.4 billion Revolving Credit Facility, discussed in Note 7 of the condensed consolidated financial statements and related notes. During the three months ended March 31, 2015, there were no gross borrowings under the Revolving Credit Facility. As of March 31, 2015, there were no principal advances and $2 million in letters of credit outstanding under the Revolving Credit Facility. Commercial paper borrowings effectively reduce our borrowing capacity under this Revolving Credit Facility. As of March 31, 2015, we had $436 million outstanding under our commercial paper program.

Sources of Liquidity

At March 31, 2015, our sources of liquidity included:
cash on hand;
cash generated from operations;
proceeds of commercial paper issuances and borrowings under our Revolving Credit facility; and
capital raised through debt and equity markets.

Capital Requirements
 
The midstream business is capital intensive and can require significant investment to maintain and upgrade existing operations, connect new wells to the system, organically grow into new areas and comply with environmental and safety regulations. Going forward, our capital requirements will consist of the following:
maintenance capital expenditures, which are cash expenditures (including expenditures for the construction or development of new capital assets or the replacement, improvement or expansion of existing capital assets) made to maintain, over the long-term, our operating capacity or operating income; and
expansion capital expenditures are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term.

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Our future expansion capital expenditures may vary significantly from period to period based on the investment opportunities available to us. We expect to fund future capital expenditures from cash flow generated from our operations, borrowings under our revolving credit facility, the issuance of commercial paper or new debt offerings or the issuance of additional partnership units. Issuances of equity or debt in the capital markets and the issuance of commercial paper may not, however, be available to us on acceptable terms.
 
Distributions
 
On April 24, 2015, the board of directors of Enable GP declared a quarterly cash distribution of $0.3125 per common unit on all of the Partnership's outstanding common and subordinated units for the period ended March 31, 2015. The distribution represents an increase of approximately 1.2% over the prior quarter distribution and will be paid May 15, 2015 to unitholders of record as of the close of business May 5, 2015.
 
Off-Balance Sheet Arrangements
 
We do not have any off-balance sheet arrangements.
 
Credit Risk
 
We are exposed to certain credit risks relating to our ongoing business operations. Credit risk includes the risk that counterparties that owe us money or energy will breach their obligations. If the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected, and we could incur losses. We examine the creditworthiness of third party customers to whom we extend credit and manage our exposure to credit risk through credit analysis, credit approval, credit limits and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees.


Critical Accounting Policies and Estimates
 
As of March 31, 2015, there have been no significant changes to our critical accounting policies and estimates as disclosed in our Annual Report.


Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to various market risks, including volatility in commodity prices and interest rates.
 
Commodity Price Risk
 
While we generate a substantial portion of our gross margin pursuant to long-term, fee-based contracts that include minimum volume commitments and/or demand fees, we are also exposed to changes in the prices of natural gas and NGLs. The Partnership utilizes derivatives and forward commodity sales to mitigate the effects of price changes. We do not enter into risk management contracts for speculative purposes.
 
Interest Rate Risk
 
Our current interest rate risk exposure is related primarily to our debt portfolio. Our debt portfolio is primarily comprised of fixed rate debt, which mitigates the impact of fluctuations in interest rates. Future issuances of long-term debt could be impacted by increases in interest rates, which could result in higher interest costs. 


Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our chief executive officer and chief financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act")) as of March 31, 2015. Based on such evaluation, our management has concluded

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that, as of March 31, 2015, our disclosure controls and procedures are designed and effective to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC's rules and forms and that information is accumulated and communicated to our management, including its principal executive officer and principal financial officer, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure.

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

Changes in Internal Controls

The Partnership maintains a system of internal controls over financial reporting that is designed to provide reasonable assurance that its books and records accurately reflect transactions and that established policies and procedures are followed. During the quarter ended March 31, 2015, the Partnership completed the initial implementation phase of SAP, a partnership-wide enterprise resource planning (ERP) system. The ERP system was implemented by the Partnership to improve standardization and automation, and not in response to a deficiency in internal control over financial reporting. Management believes the implementation of the ERP system and related changes to internal controls will enhance the Partnership's internal controls over financial reporting. Management believes the necessary steps have been taken to monitor and maintain appropriate internal control over financial reporting during this period of change and will continue to evaluate the operating effectiveness of related key controls during subsequent periods.

Internal Control Over Financial Reporting

The SEC, as required by Section 404 of the Sarbanes-Oxley Act, adopted rules that generally require every company that files reports with the SEC to include a management report on such company's internal control over financial reporting in its annual report. In addition, our independent registered public accounting firm must attest to our internal control over financial reporting. Our Annual Report on Form 10-K for the year ended December 31, 2014 did not include a report of management's assessment regarding internal control over financial reporting or an attestation report of our independent registered public accounting firm due to a transition period established by SEC rules applicable to new public companies. Management will be required to provide an assessme