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 September 30, 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 150
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
As of October 16, 2015, there were 214,534,491 common units and 207,855,430 subordinated units outstanding.
 
 
 
 
 

Table of Contents


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

 



 




i
Table of Contents

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.
Bbl/d.
Barrels per day.
Bcf/d.
Billion cubic feet per day.
Btu.
British thermal unit. When used in terms of volume, Btu refers to the amount of natural gas required to raise the temperature of one pound of water by one degree Fahrenheit at one atmospheric pressure.
CenterPoint Energy.
CenterPoint Energy, Inc., a Texas corporation, and its subsidiaries, 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 5,946-mile interstate pipeline that provides natural gas transportation and storage services to customers principally in the Anadarko, Arkoma and Ark-La-Tex basins in Oklahoma, Texas, Arkansas, Louisiana and Kansas.
Enable GP.
Enable GP, LLC, a Delaware limited liability company and the general partner of Enable Midstream Partners, LP.
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 2,151-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.
General partner.
Enable GP, LLC, a Delaware limited liability company, the general partner of Enable Midstream Partners, LP.
Gross margin.
Total revenues minus cost of natural gas and natural gas liquids, excluding depreciation and amortization.
LIBOR.
London Interbank Offered Rate.
MBbl/d.
Thousand barrels per day.
MFA.
Master Formation Agreement dated March 14, 2013.
MMcf.
Million cubic feet of natural gas.
MMcf/d.
Million cubic feet per day.
MRT.
Enable Mississippi River Transmission, LLC, a wholly owned subsidiary of the Partnership that operates a 1,665-mile interstate pipeline that provides natural gas transportation and storage services principally in Texas, Arkansas, Louisiana, Missouri and Illinois.

1
Table of Contents

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.
Partnership.
Enable Midstream Partners, LP, and its subsidiaries.
Revolving Credit Facility.
$1.75 billion senior unsecured revolving credit facility.
SCOOP.
South Central Oklahoma Oil Province.
SEC.
Securities and Exchange Commission.
Securities Act.
Securities Act of 1933, as amended.
SESH.
Southeast Supply Header, LLC, in which the Partnership owns a 50% interest as of September 30, 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.
Term Loan Facility.
$450 million unsecured term loan facility.
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.


 
 
 
 
 
 
 
 
 
 
 
 




2
Table of Contents

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.


3
Table of Contents


PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ENABLE MIDSTREAM PARTNERS, LP
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
 
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2015
 
2014
 
2015
 
2014
 
(In millions, except per unit data)
Revenues (including revenues from affiliates (Note 12)):
 
 
 
 
 
 
 
Product sales
$
357

 
$
539

 
$
1,043

 
$
1,839

Service revenue
289

 
264

 
809

 
793

Total Revenues
646

 
803

 
1,852

 
2,632

Cost and Expenses (including expenses from affiliates (Note 12)):
 
 
 
 
 
 
 
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)
287

 
439

 
856

 
1,550

Operation and maintenance
130

 
128

 
391

 
383

Depreciation and amortization
84

 
69

 
233

 
205

Impairments (Note 6)
1,105

 
1

 
1,105

 
1

Taxes other than income taxes
15

 
14

 
45

 
41

Total Cost and Expenses
1,621

 
651

 
2,630

 
2,180

Operating (Loss) Income
(975
)
 
152

 
(778
)
 
452

Other Income (Expense):
 
 
 
 
 
 
 
Interest expense (including expenses from affiliates (Note 12))
(23
)
 
(20
)
 
(66
)
 
(50
)
Equity in earnings of equity method affiliates
7

 
5

 
21

 
12

Other, net
—

 
3

 
2

 
(2
)
Total Other Income (Expense)
(16
)
 
(12
)
 
(43
)
 
(40
)
(Loss) Income Before Income Taxes
(991
)
 
140

 
(821
)
 
412

Income tax expense
—

 
1

 
2

 
2

Net (Loss) Income
$
(991
)
 
$
139

 
$
(823
)
 
$
410

Less: Net (loss) income attributable to noncontrolling interest
(6
)
 
—

 
(6
)
 
2

Net (Loss) Income attributable to Enable Midstream
Partners, LP
$
(985
)
 
$
139

 
$
(817
)
 
$
408

Limited partners' interest in net (loss) income attributable to Enable Midstream Partners, LP (Note 3)
$
(985
)
 
139

 
$
(817
)
 
$
408

Basic and diluted (loss) earnings per limited partner
unit (Note 3)
 
 
 
 
 
 
 
Common units
$
(2.33
)
 
$
0.33

 
$
(1.93
)
 
$
1.00

Subordinated units
$
(2.34
)
 
$
0.33

 
$
(1.94
)
 
$
0.98

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

 
214

 
214

 
281

Subordinated units
208

 
208

 
208

 
128


 

See Notes to the Unaudited Condensed Consolidated Financial Statements
4
Table of Contents

ENABLE MIDSTREAM PARTNERS, LP
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
 
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2015
 
2014
 
2015
 
2014
 
(In millions)
Net (loss) income
$
(991
)
 
$
139

 
$
(823
)
 
$
410

Comprehensive (loss) income
(991
)
 
139

 
(823
)
 
410

Less: Comprehensive (loss) income attributable to noncontrolling interest
(6
)
 
—

 
(6
)
 
2

Comprehensive (loss) income attributable to Enable Midstream Partners, LP
$
(985
)
 
$
139

 
$
(817
)
 
$
408





See Notes to the Unaudited Condensed Consolidated Financial Statements
5
Table of Contents

ENABLE MIDSTREAM PARTNERS, LP
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited) 
 
September 30,
2015
 
December 31,
2014
 
(In millions)
Current Assets:
 
Cash and cash equivalents
$
5

 
$
12

Accounts receivable
291

 
254

Accounts receivable—affiliated companies
25

 
27

Inventory
52

 
63

Gas imbalances
16

 
45

Other current assets
38

 
37

Total current assets
427

 
438

Property, Plant and Equipment:
 
 
 
Property, plant and equipment
11,127

 
10,464

Less accumulated depreciation and amortization
1,089

 
882

Property, plant and equipment, net
10,038

 
9,582

Other Assets:
 
 
 
Intangible assets, net
346

 
357

Goodwill
—

 
1,068

Investment in equity method affiliates
341

 
348

Other
49

 
44

Total other assets
736

 
1,817

Total Assets
$
11,201

 
$
11,837

Current Liabilities:
 
 
 
Accounts payable
$
206

 
$
275

Accounts payable—affiliated companies
12

 
38

Short-term debt
432

 
253

Taxes accrued
54

 
23

Gas imbalances
17

 
13

Other
83

 
69

Total current liabilities
804

 
671

Other Liabilities:
 
 
 
Accumulated deferred income taxes, net
10

 
9

Notes payable—affiliated companies
363

 
363

Regulatory liabilities
18

 
16

Other
21

 
27

Total other liabilities
412

 
415

Long-Term Debt
2,374

 
1,928

Commitments and Contingencies (Note 13)

 

Partners’ Capital:
 
 
 
Common units (214,534,491 issued and outstanding at September 30, 2015 and 214,417,908 issued and outstanding at December 31, 2014, respectively)
3,747

 
4,353

Subordinated units (207,855,430 issued and outstanding at September 30, 2015 and 207,855,430 issued and outstanding at December 31, 2014, respectively)
3,839

 
4,439

Total partners' capital attributable to Enable Midstream Partners, LP Partners’ Capital
7,586

 
8,792

Noncontrolling interest
25

 
31

Total Partners’ Capital
7,611

 
8,823

Total Liabilities and Partners’ Capital
$
11,201

 
$
11,837


See Notes to the Unaudited Condensed Consolidated Financial Statements
6
Table of Contents

ENABLE MIDSTREAM PARTNERS, LP
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 
 
Nine Months Ended 
 September 30,
 
2015
 
2014
 
(In millions)
Cash Flows from Operating Activities:
 
Net (loss) income
$
(823
)
 
$
410

Adjustments to reconcile net (loss) income to net cash provided by operating activities:
 
 
 
Depreciation and amortization
233

 
205

Deferred income taxes
1

 
(1
)
Impairments
1,105

 
1

Loss on sale/retirement of assets
2

 
4

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

 
—

Equity based compensation
7

 
9

Amortization of debt costs and discount (premium)
(2
)
 
(1
)
Changes in other assets and liabilities:
 
 
 
Accounts receivable, net
(37
)
 
(11
)
Accounts receivable—affiliated companies
2

 
—

Inventory
11

 
6

Gas imbalance assets
29

 
(25
)
Other current assets
(1
)
 
(2
)
Other assets
(5
)
 
10

Accounts payable
(56
)
 
(91
)
Accounts payable—affiliated companies
(26
)
 
(5
)
Gas imbalance liabilities
4

 
(1
)
Other current liabilities
45

 
50

Other liabilities
(3
)
 
3

Net cash provided by operating activities
491

 
561

Cash Flows from Investing Activities:
 
 
 
Capital expenditures
(654
)
 
(586
)
Acquisitions, net of cash acquired
(80
)
 
—

Proceeds from sale of assets
1

 
—

Return of investment in equity method affiliates
11

 
198

Investment in equity method affiliates
(8
)
 
(187
)
Other, net
—

 
2

Net cash used in investing activities
(730
)
 
(573
)
Cash Flows from Financing Activities:
 
 
 
Repayment of long term debt
—

 
(1,500
)
Proceeds from long term debt, net of issuance costs
450

 
1,635

Proceeds from revolving credit facility
275

 
115

Repayment of revolving credit facility
(275
)
 
(487
)
Increase in short term debt
179

 
95

Capital contributions from partners
—

 
464

Distributions to partners
(397
)
 
(400
)
Net cash provided by (used in) financing activities
232

 
(78
)
Net Decrease in Cash and Cash Equivalents
(7
)
 
(90
)
Cash and Cash Equivalents at Beginning of Period
12

 
108

Cash and Cash Equivalents at End of Period
$
5

 
$
18



See Notes to the Unaudited Condensed Consolidated Financial Statements
7
Table of Contents

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
—

 
290

 
—

 
118

 
408

 
2

 
410

Issuance of IPO common units
25

 
464

 
—

 
—

 
464

 
—

 
464

Conversion to subordinated units
(208
)
 
(4,372
)
 
208

 
4,372

 
—

 
—

 
$
—

Issuance of common units upon interest acquisition of SESH
6

 
161

 
—

 
—

 
161

 
—

 
$
161

Distributions to partners
—

 
(345
)
 
—

 
(52
)
 
(397
)
 
(3
)
 
$
(400
)
Equity based compensation
1

 
10

 
—

 
—

 
10

 
—

 
$
10

Balance as of September 30, 2014
214

 
$
4,356

 
208

 
$
4,438

 
$
8,794

 
$
32

 
$
8,826

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance as of December 31, 2014
214

 
$
4,353

 
208

 
$
4,439

 
$
8,792

 
$
31

 
$
8,823

Net (loss) income
—

 
(412
)
 
—

 
(405
)
 
(817
)
 
(6
)
 
(823
)
Issuance of common units upon interest acquisition of SESH
—

 
1

 
—

 
—

 
1

 
—

 
1

Distributions to partners
—

 
(202
)
 
—

 
(195
)
 
(397
)
 
—

 
(397
)
Equity based compensation
—

 
7

 
—

 
—

 
7

 
$
—

 
7

Balance as of September 30, 2015
214

 
$
3,747

 
208

 
$
3,839

 
$
7,586

 
$
25

 
$
7,611


See Notes to the Unaudited Condensed Consolidated Financial Statements
8
Table of Contents

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 services 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 Ark-La-Tex 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 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. As of September 30, 2015, CenterPoint Energy held approximately 55.4% of the limited partner interests in the Partnership, or 94,151,707 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 June 29, 2015, the financial statements reflect a 49.90% interest in SESH. On June 12, 2015, CenterPoint Energy exercised its put right with respect to a 0.1% interest in SESH. Pursuant to the put right, on June 30, 2015, CenterPoint Energy contributed its remaining 0.1% interest in SESH to the Partnership in exchange for 25,341 common units representing limited partner interests in the Partnership. As of September 30, 2015, the Partnership owned a 50% interest in SESH. See Note 7 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, 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.  

 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.
 

9
Table of Contents

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

Revenue Recognition

The Partnership generates the majority of its revenues from midstream energy services, including natural gas gathering, processing, transportation and storage and crude oil gathering. The Partnership performs these services under various contractual arrangements, which include fee-based contract arrangements and arrangements pursuant to which it purchases and resells commodities in connection with providing the related service and earns a net margin for its fee. While the Partnership's transactions vary in form, the essential element of each transaction is the use of its assets to transport a product or provide a processed product to a customer. The Partnership reflects revenue as Product sales and Service revenue on the Condensed Consolidated Statements of Income as follows:

Product sales: Product sales represent the sale of natural gas, NGLs, crude oil and condensate where the product is purchased and used in connection with providing the Partnership's midstream services.

Service revenue: Service revenue represents all other revenue generated as a result of performing the Partnership's midstream services.

Revenues for gathering, processing, and transportation and storage services for the Partnership are recorded each month based on the current month’s estimated volumes, contracted prices (considering current commodity prices), historical seasonal fluctuations and any known adjustments. The estimates are reversed in the following month, and customers are billed on actual volumes and contracted prices. Gas sales are calculated on current-month nominations and contracted prices. Revenues associated with the production of NGLs are estimated based on current-month estimated production and contracted prices. These amounts are also reversed in the following month, and the customers are billed on actual production and contracted prices. Estimated revenues are reflected in Accounts Receivable or Accounts Receivable-affiliated companies, as appropriate, on the Consolidated Balance Sheets and in Total Revenues on the Combined and Consolidated Statements of Income.

The Partnership recognizes revenue from natural gas gathering, processing, transportation and storage and crude oil gathering services to third parties as services are provided. Revenue associated with NGLs is recognized when the production is sold. The Partnership records deferred revenue when it receives consideration from a third party before achieving certain criteria that must be met for revenue to be recognized in accordance with GAAP.

Cost of natural gas and natural gas liquids represents cost of our natural gas and natural gas liquids purchased exclusive of depreciation and Operation and maintenance expenses and consists primarily of product and fuel costs. Operation and maintenance expense represents the cost of our service related revenues and consists primarily of labor expenses, lease costs, utility costs, insurance premiums and repairs and maintenance expenses. Any Operation and maintenance expenses associated with product sales are immaterial.

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 not 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.

Fair Value - Monarch Acquisition

On April 22, 2015, Enable entered into an agreement with Monarch Natural Gas, LLC, pursuant to which Enable agreed to acquire approximately 106 miles of gathering pipeline, approximately 5,000 horsepower of associated compression, right-of-ways and certain other midstream assets that provide natural gas gathering services in the Greater Granite Wash area of Texas. The

10
Table of Contents

transaction closed on May 1, 2015. The aggregate purchase price for this transaction was approximately $80 million, which was funded from cash generated from operations and borrowings under our Revolving Credit Facility.

The acquisition was accounted for as a business combination. During the third quarter of 2015, the Partnership, with the assistance of a third-party valuation expert, finalized the purchase price allocation as of May 1, 2015.

Purchase price allocation (in millions):
 
Property, plant and equipment
$
51

Intangibles
10

Goodwill
19

Total
$
80


The Partnership recognized intangible assets related to customer relationships. The acquired intangible assets will be amortized on a straight-line basis over the estimated customer contract life of approximately 15 years. Goodwill recognized from the acquisition primarily relates to the value created from additional growth opportunities and greater operating leverage in the Anadarko Basin. See Note 6 for further information related to the Partnership's goodwill impairment. The Partnership incurred less than $1 million of acquisition costs associated with this transaction, which are included in Operation and maintenance expense in the Condensed Consolidated Statement of Income.

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.


(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.

In August 2015, FASB issued ASU No. 2015-14, "Revenue from Contracts with Customers (Topic 606)—Deferral of the Effective Date," which deferred 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 and related disclosures.

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, 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.


11
Table of Contents

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. As of September 30, 2015 and December 31, 2014, the Partnership had unamortized debt expense of $18 million and $17 million, respectively, a portion of which would have been classified as a reduction of long-term debt in our condensed consolidated balance sheets had we adopted this standard in the third quarter of 2015. The Partnership does not expect a material impact on its results of operations upon adoption of ASU 2015-03.

In August 2015, the FASB issued ASU No. 2015-15, "Interest—Imputation of Interest: Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements—Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting." This ASU adds SEC paragraphs pursuant to the SEC Staff Announcement at the June 18, 2015, Emerging Issues Task Force meeting about the presentation and subsequent measurement of debt issuance costs associated with line-of-credit arrangements to this topic. Given the absence of authoritative guidance within ASU 2015-03 for debt issuance costs related to line-of-credit arrangements, the SEC staff would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The Partnership does not expect a material impact on its results of operations upon adoption of ASU 2015-15.

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 and related disclosures.

Simplifying the Measurement of Inventory

In July 2015, the FASB issued ASU No. 2015-11, "Simplifying the Measurement of Inventory." Under this ASU, inventory will be measured at the “lower of cost and net realizable value,” and options that currently exist for “market value” will be eliminated. The ASU defines net realizable value as the “estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation.” No other changes were made to the current guidance on inventory measurement. ASU 2015-11 is effective for interim and annual periods beginning after December 15, 2016. Early application is permitted and should be applied prospectively. The Partnership is evaluating the provisions of this statement, including in which period to adopt this statement, and has not determined what impact the adoption of ASU 2015-11 will have on the Partnership's Consolidated Financial Statements and related disclosures.

Simplifying the Accounting for Measurement-Period Adjustments

In September 2015, the FASB issued ASU No. 2015-16, "Business Combinations—Simplifying the Accounting for Measurement-Period Adjustments." Under this ASU, acquirers are required to record, in the same period's financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. Acquirers are required to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. ASU 2015-16 is effective for interim and annual periods beginning after December 15, 2016. The amendments in this update should be applied prospectively to adjustments to provisional amounts that occur after the effective date with earlier application permitted for financial statements that have not been issued. The Partnership is currently evaluating the impact, if any, the adoption of this standard will have on our Consolidated Financial Statements and related disclosures.




12
Table of Contents

(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 
 September 30,
 
Nine Months Ended 
 September 30,
 
2015
 
2014
 
2015
 
2014
 
(In millions, except per unit data)
Net (loss) income attributable to Enable Midstream Partners, LP
$
(985
)
 
$
139

 
$
(817
)
 
$
408

Less general partner interest in net (loss) income
—

 
—

 
—

 
—

Limited partner interest in net (loss) income attributable to Enable Midstream Partners, LP
$
(985
)
 
$
139

 
$
(817
)
 
$
408

Net (loss) income allocable to common units
$
(499
)
 
$
71

 
$
(414
)
 
$
282

Net (loss) income allocable to subordinated units
(486
)
 
68

 
(403
)
 
126

Limited partner interest in net (loss) income attributable to Enable Midstream Partners, LP
$
(985
)
 
$
139

 
$
(817
)
 
$
408

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

 
214

 
214

 
281

Subordinated units (1)
208

 
208

 
208

 
128

Total
422

 
422

 
422

 
409

Basic and diluted (loss) earnings per limited partner unit
 
 
 
 
 
 
 
Common units
$
(2.33
)
 
$
0.33

 
$
(1.93
)
 
$
1.00

Subordinated units (1)
$
(2.34
)
 
$
0.33

 
$
(1.94
)
 
$
0.98

____________________
(1)
Basic and diluted earnings per subordinated unit reflect net (loss) 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 or nine months ended September 30, 2015 and 2014.


(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.


13
Table of Contents

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
September 30, 2015 (1)
 
November 3, 2015
 
November 13, 2015
 
$
0.318

 
$
134

June 30, 2015
 
August 3, 2015
 
August 13, 2015
 
$
0.316

 
$
134

March 31, 2015
 
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 $0.318 per common unit cash distribution on October 22, 2015, to be paid on November 13, 2015, to unitholders of record at the close of business on November 3, 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 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 $411 million in intangible assets associated with customer relationships due to the acquisition of Enogex and assets acquired from Monarch Natural Gas, LLC. The Partnership determined that intangible assets related to customer

14
Table of Contents

relationships have a weighted average useful life of 15 years. 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:
 
September 30,
2015
 
December 31, 2014
 
(In millions)
Customer relationships:
 
 
 
Total intangible assets
$
411

 
$
401

Accumulated amortization
65

 
45

Net intangible assets
$
346

 
$
356


The Partnership recorded amortization expense of $7 million during each of the three months ended September 30, 2015 and 2014, respectively, and $20 million during each of the nine months ended September 30, 2015 and 2014, respectively. As discussed in Note 1, the Partnership acquired a gas gathering system from Monarch Natural Gas, LLC on May 1, 2015 and has allocated $10 million to intangible assets based upon the purchase price allocation.

 
(6) Assessing Impairment of Long-lived Assets (including Intangible Assets) and Goodwill

Impairment of Long-lived Assets (including Intangible Assets)

The Partnership periodically evaluates long-lived assets, including property, plant and equipment, and specifically identifiable intangibles other than goodwill, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted cash flows attributable to the assets, as compared to the carrying value of the assets. During each of the three and nine months ended September 30, 2015, the Partnership recorded a $12 million impairment on jurisdictional pipelines in our transportation and storage segment, and a $6 million impairment to our Service Star business line, a component of our gathering and processing segment, which is included in Impairments on the Condensed Consolidated Statements of Income. The Partnership recorded no other material impairments to long-lived assets in the three and nine months ended September 30, 2015 or 2014. Based upon review of forecasted undiscounted cash flows, none of the asset groups were at risk of failing step one of the impairment test. Further price declines, throughput declines, cost increases, regulatory or political environment changes, and other changes in market conditions could reduce forecast undiscounted cash flows.

Impairment of Goodwill

The goodwill associated with the gathering and processing reportable segment is primarily related to the acquisitions of Enable Oklahoma, Waskom and Monarch. The Partnership recognized $438 million of goodwill as a result of the acquisition of Enable Oklahoma, which occurred at the time of the formation of the Partnership in 2013. The $579 million of goodwill associated with the transportation and storage reportable segment is related to the original acquisitions of EGT and MRT in 1997 by predecessors of the Partnership. The Partnership tests its goodwill for impairment annually on October 1st, or more frequently if events or changes in circumstances indicate that the carrying value of goodwill may not be recoverable. Goodwill is assessed for impairment by comparing the fair value of the reporting unit with its book value, including goodwill. Subsequent to the completion of the October 1, 2014 annual test and previous interim assessment as of December 31, 2014, the crude oil and natural gas industry was impacted by further commodity price declines, which consequently resulted in decreased producer activity in certain regions in which the Partnership operates. Due to the continuing commodity price declines, the resulting decreases in forward commodity prices and forecasted producer activities, and an increase in the weighted average cost of capital, we determined that the impact on our forecasted discounted cash flows for our gathering and processing and transportation and storage reportable segments would be significantly reduced. As a result, when we performed the first step of our annual goodwill impairment analysis as of October 1, 2015, we determined that the carrying value of the gathering and processing and transportation and storage reportable segments exceeded fair value. We completed the second step of the goodwill impairment analysis by comparing the implied fair value of the reporting unit to the carrying amount of that goodwill and determined that goodwill was completely impaired in the amount of $1,087 million, which is included in Impairments on the Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2015.


15
Table of Contents

The change in carrying amount of goodwill in each of our reportable segments is as follows:
 
Gathering and Processing
 
Transportation and Storage
 
Total
 
(In millions)
Balance as of December 31, 2014
$
489

 
$
579

 
$
1,068

Acquisition of Monarch
19

 
—

 
19

Goodwill Impairment
(508
)
 
(579
)
 
(1,087
)
Balance as of September 30, 2015
$
—

 
$
—

 
$
—



(7) 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. For the period from May 30, 2014 through June 29, 2015, the Partnership held a 49.90% interest in SESH. On June 12, 2015, CenterPoint Energy exercised its put right with respect to its remaining 0.1% interest in SESH. Pursuant to the put right, on June 30, 2015, CenterPoint Energy contributed a 0.1% interest in SESH to the Partnership in exchange for 25,341 common units representing limited partner interests in the Partnership, which had a fair value of $1 million based upon the closing market price of the Partnership's common units. 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, or does not have the ability to exercise certain control rights, affiliates of Spectra Energy Corp could have the right to purchase our interest in SESH at fair market value. As of September 30, 2015, the Partnership owned a 50% 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, 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:
 
Nine Months Ended 
 September 30,
 
2015
 
2014
 
(In millions)
Balance as of December 31
$
348

 
$
198

Interest acquisition of SESH
1

 
161

Return of investment from SESH refinancing
—

 
(198
)
Additional investment in SESH
—

 
187

Equity in earnings of equity method affiliate
21

 
12

Contributions to equity method affiliate
8

 
2

Distributions from equity method affiliate
(37
)
 
(13
)
Balance as of September 30
$
341

 
$
349


16
Table of Contents


Equity in Earnings of Equity Method Affiliates:
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2015
 
2014
 
2015

2014
 
(In millions)
SESH
$
7

 
$
5

 
$
21

 
$
12


Distributions from Equity Method Affiliates:
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2015

2014
 
2015
 
2014
 
(In millions)
SESH
$
10

 
$
7

 
$
37

 
$
13


Summarized financial information of SESH is presented below:
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2015
 
2014
 
2015
 
2014
 
(In millions)
Income Statements:
 
 
 
 
 
 
 
Revenues
$
29

 
$
27

 
$
86

 
$
80

Operating income
18

 
17

 
54

 
50

Net income
14

 
12

 
42

 
34


 
(8) Debt
 
The following table presents the Partnership's outstanding debt as of September 30, 2015 and December 31, 2014.

 
September 30,
2015
 
December 31,
2014
 
(In millions)
Commercial Paper
$
432

 
$
253

Term Loan Facility
450

 
—

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
24

 
28

Total debt
3,169

 
2,544

Less amount classified as short-term debt(1)
432

 
253

Less Notes payable—affiliated companies
363

 
363

Total long-term debt
$
2,374

 
$
1,928

___________________
(1)
Short-term debt includes $432 million and $253 million of commercial paper as of September 30, 2015 and December 31, 2014, respectively.


17
Table of Contents

Revolving Credit Facility

On June 18, 2015, the Partnership amended and restated its Revolving Credit Facility to, among other things, increase the borrowing capacity thereunder to $1.75 billion and extend its maturity date to June 18, 2020. As of September 30, 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.

The Revolving Credit Facility provides that outstanding borrowings bear interest at the LIBOR and/or an alternate base rate, at the Partnership’s election, plus an applicable margin. The applicable margin is based on the Partnership’s applicable credit ratings. As of September 30, 2015, the applicable margin for LIBOR-based borrowings under the Revolving Credit Facility was 1.50% based on the Partnership’s credit ratings. In addition, the Revolving Credit Facility requires the Partnership to pay a fee on unused commitments. The commitment fee is based on the Partnership’s applicable credit rating from the rating agencies. As of September 30, 2015, the commitment fee under the Revolving Credit Facility was 0.20% per annum based on the Partnership’s credit ratings. The commitment fee is recorded as interest expense in the Partnership's Condensed Consolidated Statements of Income.

Commercial Paper

The Partnership has a commercial paper program, pursuant to which the Partnership is authorized to issue up to $1.4 billion of commercial paper. The commercial paper program is supported by our Revolving Credit Facility, and outstanding commercial paper effectively reduces our borrowing capacity thereunder. There was $432 million and $253 million outstanding under our commercial paper program as of September 30, 2015 and December 31, 2014, respectively. Any reduction in our credit ratings could prevent us from accessing the commercial paper markets.

Term Loan Agreement

On July 31, 2015, the Partnership entered into a Term Loan Agreement dated as of July 31, 2015, providing for an unsecured three-year $450 million term loan facility (Term Loan Facility). The entire $450 million principal amount of the Term Loan Facility was borrowed by Enable on July 31, 2015. The Term Loan Facility contains an option, which may be exercised up to two times, to extend the term of the Term Loan Facility, in each case, for an additional one-year term. The Term Loan Facility provides an option to prepay, without penalty or premium, the amount outstanding, or any portion thereof, in a minimum amount of $1 million, or any multiple of $0.5 million in excess thereof. As of September 30, 2015, there was $450 million outstanding under the Term Loan Facility.

The Term Loan Facility provides that outstanding borrowings bear interest at the LIBOR and/or an alternate base rate, at the Partnership’s election, plus an applicable margin. The applicable margin is based on our applicable credit ratings. As of September 30, 2015, the applicable margin for LIBOR-based borrowings under the term loan facility was 1.375% based on our credit ratings.

Senior Notes

In connection with the issuance of the 2019 Notes, 2024 Notes and 2044 Notes, the Partnership, CenterPoint Energy Resources Corp., as guarantor, and RBS Securities Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Credit Suisse Securities (USA) LLC, and RBC Capital Markets, LLC, as representatives of the initial purchasers, entered into a registration rights agreement whereby the Partnership and the guarantor agreed to file with the SEC a registration statement relating to a registered offer to exchange the 2019 Notes, 2024 Notes and 2044 Notes for new series of the Partnership's notes in the same aggregate principal amount as, and with terms substantially identical in all respects to, the 2019 Notes, 2024 Notes and 2044 Notes. The agreement provided for the accrual of additional interest if the Partnership did not complete an exchange offer by October 9, 2015. Because an exchange offer was not consummated by October 9, 2015, additional interest began accruing on the 2019 Notes, 2024 Notes and 2044 Notes on October 10, 2015, at a rate of 0.25% per year until the first 90-day period after such date. The amount of additional interest will increase by an additional 0.25% per year for each subsequent 90-day period during which the exchange offer registration statement is not declared effective or the exchange offer is not completed, up to a maximum of 1.00% per year.

Financing Costs

Unamortized debt expense of $18 million and $17 million as of September 30, 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 $24 million and $28 million at September 30, 2015 and December 31, 2014,

18
Table of Contents

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 September 30, 2015, the Partnership and Enable Oklahoma were in compliance with all of their debt agreements, including financial covenants.

 
(9) Fair Value Measurements
 
Certain assets and liabilities are recorded at fair value in the Condensed Consolidated Balance Sheets and are categorized based upon the level of judgment associated with the inputs used to measure their value. Hierarchical levels, as defined below and directly related to the amount of subjectivity associated with the inputs to fair valuations of these assets and liabilities are as follows:
 
Level 1: Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. Instruments classified as Level 1 include natural gas futures, swaps and options transactions for contracts traded on the NYMEX and settled through a NYMEX clearing broker.
 
Level 2: Inputs, other than quoted prices included in Level 1, are observable for the asset or liability, either directly or indirectly. Level 2 inputs include quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities that are generally included in this category are derivatives with fair values based on inputs from actively quoted markets. Instruments classified as Level 2 include over-the-counter NYMEX natural gas swaps, natural gas basis swaps and natural gas purchase and sales transactions in markets such that the pricing is closely related to the NYMEX pricing, and over-the-counter WTI crude 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 September 30, 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

19

reported as an asset or a liability in the Condensed Consolidated Balance Sheets. The Partnership has presented the fair values of its derivative contracts under master netting agreements using a net fair value presentation.
 
The following tables summarize the Partnership’s assets and liabilities that are measured at fair value on a recurring basis as of September 30, 2015 and December 31, 2014:
 
September 30, 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)
$
17

 
$
3

 
$
—

 
$
—

Significant other observable inputs (Level 2)
1

 
—

 
10

 
$
12

Unobservable inputs (Level 3)
11

 
1

 
—

 
$
—

Total fair value
29

 
4

 
10

 
$
12

Netting adjustments
(4
)
 
(4
)
 
—

 
$
—

Total
$
25

 
$
—

 
$
10

 
$
12


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 September 30, 2015 and December 31, 2014.
(2)
Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $6 million and $4 million at September 30, 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 $5 million and $1 million at September 30, 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, 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 September 30, 2015 and December 31, 2014.
 


20

 
September 30, 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

 
$
361

 
$
363

 
$
362

Revolving Credit Facility (Level 2)(1)
—

 
—

 
—

 
—

Term Loan Facility (Level 2)
450

 
450

 
—

 
—

Enable Oklahoma Senior Notes (Level 2)
275

 
275

 
279

 
282

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

 
1,442

 
1,649

 
1,592

___________________
(1)
Borrowing capacity is reduced by our borrowings outstanding under the commercial paper program. $432 million and $253 million of commercial paper was outstanding as of September 30, 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 September 30, 2015 and December 31, 2014, no material fair value adjustments or fair value measurements were required for these non-financial assets or liabilities.


(10) 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.

21
Table of Contents

 
As of September 30, 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.
 
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 September 30, 2015 and December 31, 2014, the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes:

 
September 30, 2015
 
December 31, 2014
  
Gross Notional Volume
 
Purchases
 
Sales
 
Purchases
 
Sales
Natural gas— TBtu(1)
 
 
 
 
 
 
 
Physical purchases/sales
2

 
64

 
4

 
32

Financial fixed futures/swaps
2

 
32

 
5

 
35

Financial basis futures/swaps
3

 
41

 
7

 
54

Condensate— MBbl(2)

 

 
 
 
 
Financial Futures/swaps
—

 
1

 
—

 
12

Natural gas liquids— MBbl(3)

 

 
 
 
 
Financial Futures/swaps
—

 
1

 
—

 
—

____________________
(1)
As of September 30, 2015, 90.6% of the natural gas contracts had durations of one year or less, 9.2% had durations of more than one year and less than two years and 0.2% 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 September 30, 2015, 88.9% of the condensate contracts had durations of one year or less and 11.1% 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 September 30, 2015, 89.3% of the natural gas liquids contracts had durations of one year or less and 10.7% had durations of more than one year and less than two years.


22
Table of Contents

Balance Sheet Presentation Related to Derivative Instruments
 
The fair value of the derivative instruments that are presented in the Partnership’s Condensed Consolidated Balance Sheets as of September 30, 2015 and December 31, 2014 that were not designated as hedging instruments for accounting purposes are as follows:
 
 
 
 
September 30, 2015
 
December 31, 2014
 
 
 
Fair Value
Instrument
Balance Sheet Location
 
Assets
 
Liabilities
 
Assets
 
Liabilities
 
 
 
(In millions)
Natural gas
 
 
 
 
 
 
 
Financial futures/swaps
Other Current
 
$
17

 
$
3

 
$
34

 
$
4

Physical purchases/sales
Other Current
 
1

 
—

 
1

 
—

Condensate
 
 
 
 
 
 
 
 
 
Financial futures/swaps
Other Current
 
2

 
—

 
5

 
—

Natural gas liquids
 
 
 
 
 
 
 
 
 
Financial Futures/swaps
Other Current
 
9

 
1

 
—

 
—

Total gross derivatives (1)
 
 
$
29

 
$
4

 
$
40

 
$
4

_____________________
(1)
See Note 9 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Condensed Consolidated Balance Sheet as of September 30, 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 Statements of Income for the three and nine months ended September 30, 2015.
 
  
Amounts Recognized in Income
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2015
 
2014
 
2015
 
2014
 
(In millions)
Natural gas financial futures/swaps gains (losses)
$
10

 
$
3

 
$
13

 
$
4

Natural gas physical purchases/sales gains (losses)
(1
)
 
(1
)
 
(5
)
 
(1
)
Condensate financial futures/swaps gains (losses)
11

 
3

 
8

 
2

Natural gas liquids financial futures/swaps gains (losses)
1

 
—

 
7

 
—

Total
$
21

 
$
5

 
$
23

 
$
5

 
For derivatives not designated as hedges in the tables above, amounts recognized in income for the periods ended September 30, 2015 and 2014, if any, are reported in Product Sales.
 
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 September 30, 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 September 30, 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.




23
Table of Contents

(11) Supplemental Disclosure of Cash Flow Information

The following table provides information regarding supplemental cash flow information:

 
Nine Months Ended 
 September 30,
 
2015
 
2014
 
(In millions)
Supplemental Disclosure of Cash Flow Information:
 
 
 
Cash Payments:
 
 
 
Interest, net of capitalized interest
$
61

 
$
53

Income taxes, net of refunds
2

 
1

Non-cash transactions:


 


Accounts payable related to capital expenditures
66

 
4

Issuance of common units upon interest acquisition of SESH (Note 7)
1

 
161



(12) Related Party Transactions
 
The material related party transactions with CenterPoint Energy, OGE Energy and their respective subsidiaries are summarized below. There were no material related party transactions with other affiliates.
 
The Partnership’s revenues from affiliated companies accounted for 6% and 5% of revenues during the three months ended September 30, 2015 and 2014, respectively, and 7% and 5% of revenues during the nine months ended September 30, 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 
 September 30,
 
Nine Months Ended 
 September 30,
 
2015
 
2014
 
2015
 
2014
 
(In millions)
Gas transportation and storage service revenue - CenterPoint Energy
$
23

 
$
22

 
$
79

 
$
82

Natural gas product sales - CenterPoint Energy
—

 
1

 
7

 
17

Gas transportation and storage service revenue - OGE Energy (1)
10

 
9

 
28

 
31

Natural gas product sales - OGE Energy (1)
3

 
5

 
7

 
10

Total revenues - affiliated companies
$
36

 
$
37

 
$
121

 
$
140

____________________
(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 Statements 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 
 September 30,
 
Nine Months Ended 
 September 30,
 
2015
 
2014
 
2015
 
2014
 
(In millions)
Cost of natural gas purchases - CenterPoint Energy
$
1

 
$
—

 
$
2

 
$
2

Cost of natural gas purchases - OGE Energy
5

 
8

 
12

 
14

Total cost of natural gas purchases - affiliated companies
$
6

 
$
8

 
$
14

 
$
16


24
Table of Contents


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 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 $15 million and $11 million, respectively.

Amounts charged to the Partnership by affiliates for seconded employees and corporate services, included primarily in Operation and maintenance expenses in Partnership’s Condensed Consolidated Statements of Income are as follows:
 
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2015
 
2014
 
2015
 
2014
 
(In millions)
Seconded Employee Costs - CenterPoint Energy
$
—

 
$
32

 
$
—

 
$
101

Corporate Services - CenterPoint Energy
5

 
6

 
12

 
23

Seconded Employee Costs - OGE Energy
12

 
25

 
30

 
78

Corporate Services - OGE Energy
2

 
3

 
8

 
13

Total corporate services and seconded employees expense
$
19


$
66

 
$
50

 
$
215


The Partnership has outstanding long-term notes payable—affiliated companies to CenterPoint Energy at both September 30, 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 September 30, 2015 and 2014, respectively, and $6 million during each of the nine months ended September 30, 2015 and 2014, respectively.


(13) Commitments and Contingencies
 
The Partnership is involved in legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. Some of these proceedings involve substantial amounts. The Partnership regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. The Partnership does not expect the disposition of these matters to have a material adverse effect on its financial condition, results of operations or cash flows.




25
Table of Contents

(14) Equity Based Compensation

The following table summarizes the Partnership’s compensation expense for the three and nine months ended September 30, 2015 and 2014 related to performance units, restricted units, and phantom units for the Partnership's employees.

 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2015
 
2014
 
2015
 
2014
 
(In millions)
Performance units
$
1

 
$
1

 
$
3

 
$
1

Restricted units
2

 
3

 
5

 
8

Phantom units
—

 
1

 
1

 
1

Total compensation expense
$
3

 
$
5

 
$
9

 
$
10


Units Outstanding

The Partnership periodically grants performance units, restricted units, and phantom units to certain employees. Under the Enable Midstream Partners, LP Long Term Incentive Plan, the Partnership granted performance units and restricted units to certain employees in the second quarter of 2015. A summary of the activity for the Partnership's performance units, restricted units, and phantom units applicable to the Partnership’s employees at September 30, 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)
501,474

 
 
 
279,677

 
 
 
—

 
 
Vested
(1,254
)
 
 
 
(375,504
)
 
 
 
(90,000
)
 
 
Forfeited
(222,389
)
 
 
 
(126,278
)
 
 
 
(2,000
)
 
 
Units Outstanding at September 30, 2015
830,412

 
$
10

 
615,963

 
$
8

 
6,718

 
$
—

Units Fully Vested at September 30, 2015
2,799

 


 
 
 
 
 
90,500

 


_____________________
(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.
 
September 30, 2015
 
Unrecognized Compensation Cost
(In millions)
 
Weighted Average to be Recognized
(In years)
Performance Units
$
11

 
2.3
Restricted Units
10

 
1.9
Phantom Units
—

 
0.1
Total
$
21

 
 

As of September 30, 2015, there were 11,056,759 units available for issuance under the long term incentive plan.



26
Table of Contents


(15) Reportable Segments
 
The Partnership’s determination of reportable segments considers the strategic operating units under which it manages sales, allocates resources and assesses performance of various products and services to 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 are as follows:

Three Months Ended September 30, 2015
Gathering  and
Processing
 
Transportation
and Storage(1)
 
Eliminations
 
Total
 
(In millions)
Total revenues
$
456

 
$
299

 
$
(109
)
 
$
646

Cost of natural gas and natural gas liquids
235

 
161

 
(109
)
 
287

Operation and maintenance
75

 
55

 
—

 
130

Depreciation and amortization
53

 
31

 
—

 
84

Impairments
514

 
591

 
—

 
1,105

Taxes other than income tax
8

 
7

 
—

 
15

Operating loss
$
(429
)
 
$
(546
)
 
$
—

 
$
(975
)
Total assets
$
7,441

 
$
4,857

 
$
(1,097
)
 
$
11,201

Capital expenditures
$
167

 
$
31

 
$
—

 
$
198

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended September 30, 2014
Gathering and
Processing
 

Transportation
and Storage(1)
 
Eliminations
 
Total
 
(In millions)
Total revenues
$
604

 
$
341

 
$
(142
)
 
$
803

Cost of natural gas and natural gas liquids
382

 
198

 
(141
)
 
439

Operation and maintenance
76

 
53

 
(1
)
 
128

Depreciation and amortization
41

 
28

 
—

 
69

Impairments
1

 
—

 
—

 
1

Taxes other than income tax
8

 
6

 
—

 
14

Operating income
$
96

 
$
56

 
$
—

 
$
152

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

 
$
5,493

 
$
(2,012
)
 
$
11,837

Capital expenditures
$
227

 
$
25

 
$
(4
)
 
$
248

_____________________
(1)
Transportation and Storage recorded equity income of $7 million and $5 million for the three months ended September 30, 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 $341 million and $348 million as of September 30, 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. On June 30, 2015, CenterPoint Energy contributed its remaining 0.1% interest in SESH to the Partnership. As of September 30, 2015, the Partnership owns 50% interest in SESH. See Note 7 for further discussion regarding SESH.

27
Table of Contents




 
Nine Months Ended September 30, 2015
Gathering  and
Processing
 
Transportation
and Storage(1)
 
Eliminations
 
Total
 
(In millions)
Total revenues
$
1,279


$
875


$
(302
)
 
$
1,852

Cost of natural gas and natural gas liquids
698

 
459

 
(301
)
 
856

Operation and maintenance
229

 
163

 
(1
)
 
391

Depreciation and amortization
141

 
92

 
—

 
233

Impairments
514

 
591

 
—

 
1,105

Taxes other than income tax
23

 
22

 
—

 
45

Operating loss
$
(326
)
 
$
(452
)
 
$
—

 
$
(778
)
Total assets
$
7,441

 
$
4,857

 
$
(1,097
)
 
$
11,201

Capital expenditures(2)
$
657

 
$
77

 
$
—

 
$
734

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2014
Gathering and
Processing
 

Transportation
and Storage(1)
 
Eliminations
 
Total
 
(In millions)
Total revenues
$
1,882

 
$
1,219

 
$
(469
)
 
$
2,632

Cost of natural gas and natural gas liquids
1,250

 
768

 
(468
)
 
1,550

Operation and maintenance
219

 
165

 
(1
)
 
383

Depreciation and amortization
118

 
87

 
—

 
205

Impairments
1

 
—

 
—

 
1

Taxes other than income tax
18

 
23

 
—

 
41

Operating income
$
276

 
$
176

 
$
—

 
$
452

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

 
$
5,493

 
$
(2,012
)
 
$
11,837

Capital expenditures
$
522

 
$
69

 
$
(5
)
 
$
586

_____________________
(1)
Transportation and Storage recorded equity income of $21 million and $12 million for the nine months ended September 30, 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 $341 million and $348 million as of September 30, 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. On June 30, 2015, CenterPoint Energy contributed its remaining 0.1% interest in SESH to the Partnership. As of September 30, 2015, the Partnership owns 50% interest in SESH. See Note 7 for further discussion regarding SESH.
(2)
As discussed in Note 1, the Partnership acquired a gas gathering system for $80 million from Monarch Natural Gas, LLC on May 1, 2015.




28
Table of Contents

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

The following discussion and analysis should be read in conjunction with our unaudited condensed consolidated financial statements and the related notes included herein and our audited 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 Ark-La-Tex 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 March 2015, the Partnership commenced full operation of the Bradley Plant, a 200 MMcf/d cryogenic processing facility located in the Anadarko basin, and the 19,500 Bbl/d crude oil and produced water gathering system located in the Williston basin.

During August 2015, the Partnership announced the planned construction of the Wildhorse Plant, a 200 MMcf/d natural gas processing facility in Garvin County, Oklahoma, which supports the continued volume growth from producers in the SCOOP and other plays in the Anadarko 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 has received sufficient commitments to proceed with the project with an anticipated in-service date of April 1, 2017. The proposed Oklahoma expansion capacity will provide enhanced transportation options from receipt points in the Oklahoma supply area.

Monarch Acquisition

On April 22, 2015, Enable entered into an agreement with Monarch Natural Gas, LLC, pursuant to which Enable agreed to acquire approximately 106 miles of gathering pipeline, approximately 5,000 horsepower of associated compression, right-of-ways and certain other midstream assets that provide natural gas gathering services in the Greater Granite Wash area of Texas. The transaction closed on May 1, 2015. The aggregate purchase price for this transaction was approximately $80 million.


29
Table of Contents

Impairment of Long-lived Assets (including Intangible Assets) and Goodwill

The Partnership periodically evaluates long-lived assets, including property, plant and equipment, and specifically identifiable intangibles other than goodwill, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted cash flows attributable to the assets, as compared to the carrying value of the assets. During each of the three and nine months ended September 30, 2015, the Partnership recorded a $12 million impairment on jurisdictional pipelines in our transportation and storage segment, and a $6 million impairment to our Service Star business line, a component of our gathering and processing segment, which is included in Impairments on the Condensed Consolidated Statement of Income.

The Partnership tests its goodwill for impairment annually on October 1st, or more frequently if events or changes in circumstances indicate that the carrying value of goodwill may not be recoverable. Goodwill is assessed for impairment by comparing the fair value of the reporting unit with its book value, including goodwill. Subsequent to the completion of the October 1, 2014 annual test and previous interim assessment as of December 31, 2014, the crude oil and natural gas industry was impacted by further commodity price declines, which consequently resulted in decreased producer activity in certain regions in which the Partnership operates. As discussed in Note 6, the Partnership determined during its preparation of financial statements for the third quarter of 2015 that the carrying value of our gathering and processing and transportation and storage reportable segments exceeded fair value. The Partnership determined that goodwill was completely impaired in the amount of $1,087 million, which is included in Impairments on the Condensed Consolidated Statement of Income.


Results of Operations
 
The following tables summarize the key components of our results of operations for the three and nine months ended September 30, 2015 and 2014.
 
Three Months Ended September 30, 2015
Gathering and
Processing
 
Transportation
and Storage
 
Eliminations
 
Enable
Midstream
Partners, LP
 
(In millions)
Total revenues
$
456

 
$
299

 
$
(109
)
 
$
646

Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)
235

 
161

 
(109
)
 
287

Gross margin
221

 
138

 
—

 
359

Operation and maintenance
75

 
55

 
—

 
130

Depreciation and amortization
53

 
31

 
—

 
84

Impairments
514

 
591

 
—

 
1,105

Taxes other than income tax
8

 
7

 
—

 
15

Operating loss
$
(429
)
 
$
(546
)
 
$
—

 
$
(975
)
Equity in earnings of equity method affiliates
$
—

 
$
7

 
$
—

 
$
7



30
Table of Contents

Three Months Ended September 30, 2014
Gathering and
Processing
 
Transportation
and Storage
 
Eliminations
 
Enable
Midstream
Partners, LP
 
(In millions)
Total revenues
$
604

 
$
341

 
$
(142
)
 
$
803

Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)
382

 
198

 
(141
)
 
439

Gross margin
222

 
143

 
(1
)
 
364

Operation and maintenance
76

 
53

 
(1
)
 
128

Depreciation and amortization
41

 
28

 
—

 
69

Impairments
1

 
—

 
—

 
1

Taxes other than income tax
8

 
6

 
—

 
14

Operating income
$
96

 
$
56

 
$
—

 
$
152

Equity in earnings of equity method affiliates
$
—

 
$
5

 
$
—

 
$
5


Nine Months Ended September 30, 2015
Gathering and
Processing
 
Transportation
and Storage
 
Eliminations
 
Enable
Midstream
Partners, LP
 
(In millions)
Total revenues
$
1,279

 
$
875

 
$
(302
)
 
$
1,852

Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)
698

 
459

 
(301
)
 
856

Gross margin
581

 
416

 
(1
)
 
996

Operation and maintenance
229

 
163

 
(1
)
 
391

Depreciation and amortization
141

 
92

 
—

 
233

Impairments
514

 
591

 
—

 
1,105

Taxes other than income tax
23

 
22

 
—

 
45

Operating loss
$
(326
)
 
$
(452
)
 
$
—

 
$
(778
)
Equity in earnings of equity method affiliates
$
—

 
$
21

 
$
—

 
$
21

Nine Months Ended September 30, 2014
Gathering and
Processing
 
Transportation
and Storage
 
Eliminations
 
Enable
Midstream
Partners, LP
 
(In millions)
Total revenues
$
1,882

 
$
1,219

 
$
(469
)
 
$
2,632

Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)
1,250

 
768

 
(468
)
 
1,550

Gross margin
632

 
451

 
(1
)
 
1,082

Operation and maintenance
219

 
165

 
(1
)
 
383

Depreciation and amortization
118

 
87

 
—

 
205

Impairments
1

 
—

 
—

 
1

Taxes other than income tax
18

 
23

 
—

 
41

Operating income
$
276

 
$
176

 
$
—

 
$
452

Equity in earnings of equity method affiliates
$
—

 
$
12

 
$
—

 
$
12



31
Table of Contents

 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2015
 
2014
 
2015
 
2014
Operating Data:
 
 
 
 
 
Gathered volumes—TBtu
291

 
306

 
866

 
913

Gathered volumes—TBtu/d
3.17

 
3.32

 
3.17

 
3.34

Natural gas processed volumes—TBtu
172

 
147

 
488

 
418

Natural gas processed volumes—TBtu/d
1.87

 
1.60

 
1.79

 
1.53

NGLs produced—MBbl/d(1)
83.80

 
68.11

 
73.81

 
67.63

NGLs sold—MBbl/d(1)(2)
81.63

 
68.87

 
74.45

 
69.60

Condensate sold—MBbl/d
4.63

 
3.52

 
5.34

 
4.31

Crude Oil - Gathered volumes—MBbl/d
16.46

 
4.51

 
10.76

 
2.37

Transported volumes—TBtu
425

 
418

 
1,395

 
1,373

Transportation volumes—TBtu/d
4.62

 
4.54

 
5.10

 
5.02

Interstate firm contracted capacity—Bcf/d
6.71

 
7.50

 
7.25

 
8.69

Intrastate average deliveries—TBtu/d
1.88

 
1.66

 
1.85

 
1.62

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

Gathering and Processing

Three months ended September 30, 2015 compared to three months ended September 30, 2014. Our gathering and processing segment reported operating loss of $429 million in the three months ended September 30, 2015 compared to operating income of $96 million in the three months ended September 30, 2014. Operating income decreased $525 million primarily from an increase in impairment charges of $513 million related to the impairment of goodwill and long-lived assets, decreased gross margin of $1 million, and an increase in depreciation and amortization of $12 million, partially offset by a decrease in operation and maintenance expenses of $1 million, during the three months ended September 30, 2015.

Our gathering and processing segment gross margin decreased $1 million primarily due to a decrease in processing margin of $17 million resulting from the impact of lower NGL prices offset by increased processed volumes in the Anadarko basin and lower revenues on third party measurement and communication services of $2 million. These decreases were partially offset by increased gathering margins of $6 million primarily due to increased gathered volumes in the Anadarko basin and higher minimum volume payments in the Ark-La-Tex basin, and higher crude oil gathering of $12 million due to higher volumes in the Williston basin, while unrealized gains on condensate and NGL derivatives remained flat for the three months ended September 30, 2015.   

Our gathering and processing segment operation and maintenance expenses decreased $1 million. Decreases in integration related costs of $2 million, lower loss on sale of assets of $4 million, and lower write down of materials and supplies inventory of $2 million were offset by an increase in payroll related costs of $5 million for severance charges related to workforce reductions and an increase in operation and maintenance expenses of $2 million to support and operate new assets.

Our gathering and processing segment depreciation and amortization increased $12 million due to additional assets placed in service.

Our gathering and processing segment impairments increased $513 million. We recognized impairments of $514 million and $1 million in the three months ended September 30, 2015 and 2014, respectively. Due to the continuing commodity price declines, the resulting decreases in forward commodity prices and forecasted producer activities, and an increase in the weighted average cost of capital, in its preparation of financial statements for the third quarter of 2015, the Partnership determined that the carrying value of goodwill associated with the gathering and processing reportable segment was completely impaired and as a result recognized impairment expense of $508 million. Also in the third quarter of 2015, we recognized impairment expense of $6 million on the Service Star business line. In the third quarter of 2014, impairment of assets held for sale of $1 million was recognized.

Nine months ended September 30, 2015 compared to nine months ended September 30, 2014. Our gathering and processing segment reported operating loss of $326 million in the nine months ended September 30, 2015 compared to operating income of $276 million in the nine months ended September 30, 2014. Operating income decreased $602 million primarily from increased

32
Table of Contents

impairment charges of $513 million related to the impairment of goodwill and long-lived assets, decreased gross margin of $51 million, an increase in operation and maintenance expenses of $10 million, an increase in depreciation and amortization of $23 million, and an increase in taxes other than income tax of $5 million during the nine months ended September 30, 2015.

Our gathering and processing segment gross margin decreased $51 million primarily due to a decrease in processing margins of $47 million resulting from the impact of lower average natural gas liquids prices and lower processed volumes in the Ark-La-Tex basin offset by higher processed volumes in the Anadarko and Arkoma basins. Also, gathering margins decreased $19 million due to reduced sales on efficiency gas due to lower gathered volumes and lower average natural gas prices, decreased gathering fees of $6 million due to lower gathered volumes in the Arkoma and Ark-La-Tex basins, net of minimum volume payments, and lower revenues on third party measurement and communication services of $3 million. These decreases were partially offset by higher crude oil gathering of $20 million due to higher volumes in the Williston basin, and a $4 million increase in unrealized gains on condensate and NGL derivatives during the nine months ended September 30, 2015.

Our gathering and processing segment operation and maintenance expenses increased $10 million primarily due to an increase in operation and maintenance expenses of $7 million to support and operate new assets, an increase in payroll related costs of $8 million for severance charges related to workforce reductions, partially offset by lower write down of materials and supplies inventory of $3 million and lower losses on sale of assets of $2 million.

Our gathering and processing segment depreciation and amortization increased $23 million due to additional assets placed in service.

Our gathering and processing segment recognized impairments of $514 million and $1 million in the nine months ended September 30, 2015 and 2014, respectively. Due to the continuing commodity price declines, the resulting decreases in forward commodity prices and forecasted producer activities, and an increase in the weighted average cost of capital, in its preparation of financial statements for the third quarter of 2015, the Partnership determined that the carrying value of goodwill associated with the gathering and processing reportable segment was completely impaired and as a result recognized impairment expense of $508 million. Also in the third quarter of 2015, we recognized impairment expense of $6 million on the Service Star business line. In the third quarter of 2014, an impairment of assets held for sale of $1 million was recognized.

Our gathering and processing segment taxes other than income tax increased $5 million due to additional assets placed in service of $2 million and the effect of a favorable settlement of a state and local tax dispute in 2014 for $3 million less than the previously recognized reserve.

Transportation and Storage

Three months ended September 30, 2015 compared to three months ended September 30, 2014. Our transportation and storage segment reported operating loss of $546 million in the three months ended September 30, 2015 compared to operating income of $56 million in the three months ended September 30, 2014. Operating income decreased $602 million primarily resulting from an increase of $591 million in impairment charges primarily related to the impairment of goodwill, a decrease in gross margin of $5 million, an increase of $2 million in operation and maintenance expenses, an increase of $3 million in depreciation and amortization expenses, and an increase in taxes other than income tax of $1 million for the three months ended September 30, 2015.

Our transportation and storage segment gross margin decreased $5 million primarily due to lower firm transportation revenues of $5 million, lower margins on unrealized natural gas derivatives of $4 million, and a decrease in liquid sales related to NGLs collected under contractual arrangements due to lower NGL prices of $3 million. These decreases were partially offset by higher margins of $7 million related to realized gains on system optimization activities for the three months ended September 30, 2015.

Our transportation and storage segment operation and maintenance expenses increased $2 million due to a decrease in insurance proceeds of $2 million and an increase in payroll related costs of $1 million for severance charges related to workforce reductions, partially offset by lower write down of materials and supplies inventory of $1 million.

Our transportation and storage segment depreciation and amortization increased $3 million primarily due to additional assets placed in service.

Our transportation and storage segment impairments increased $591 million. Due to the continuing commodity price declines, the resulting decreases in forward commodity prices and forecasted producer activities, and an increase in the weighted average cost of capital, in its preparation of financial statements for the third quarter of 2015, the Partnership determined that the carrying value of goodwill associated with the transportation and storage reportable segment was completely impaired and as a result

33
Table of Contents

recognized impairment expense of $579 million. Additionally, we recognized an impairment on jurisdictional pipeline assets of $12 million.

Our transportation and storage segment taxes other than income tax increased $1 million due to a change in estimate related to ad valorem taxes.

Our transportation and storage segment recorded equity in earnings of equity method affiliates of $7 million and $5 million for the three months ended September 30, 2015 and 2014, respectively, from our interest in SESH. The $2 million increase in equity in earnings of equity method affiliates is attributable to our increased interest in SESH for the three months ended September 30, 2015 compared to the three months ended September 30, 2014.
 
Nine months ended September 30, 2015 compared to nine months ended September 30, 2014. Our transportation and storage segment reported operating loss of $452 million in the nine months ended September 30, 2015 compared to operating income of $176 million in the nine months ended September 30, 2014. Operating income decreased $628 million primarily resulting from an increase in impairment charges of $591 million primarily related to the impairment of goodwill, a decrease in gross margin of $35 million, and a $5 million increase in depreciation and amortization expenses, partially offset by a decrease of $2 million in operation and maintenance expenses and a decrease in taxes other than income tax of $1 million for the nine months ended September 30, 2015.

Our transportation and storage segment gross margin decreased $35 million primarily due to lower firm transportation revenues of $8 million, a decrease in liquid sales related to NGLs collected under contractual arrangements of $16 million resulting from lower NGL prices, a decrease in storage demand fees of $5 million, lower margin on unrealized natural gas derivatives of $20 million, as well as lower rates on transportation services for local distribution companies of $3 million. These decreases were partially offset by higher margins of $11 million related to realized gains on system optimization activities and increased margins from off-system transportation revenues of $6 million for the nine months ended September 30, 2015.

Our transportation and storage segment operation and maintenance expenses decreased $2 million due to a decrease in integration related costs of $5 million and lower write down of materials and supplies inventory of $1 million, offset by an increase in payroll related costs of $2 million for severance charges related to workforce reductions and a decrease in insurance proceeds of $2 million.

Our transportation and storage segment depreciation and amortization increased $5 million primarily due to additional assets placed in service.

Our transportation and storage segment impairment increased $591 million. Due to the continuing commodity price declines, the resulting decreases in forward commodity prices and forecasted producer activities, and an increase in the weighted average cost of capital, in its preparation of financial statements for the third quarter of 2015, the Partnership determined that the carrying value of goodwill associated with the transportation and storage reportable segment was completely impaired and as a result recognized impairment expense of $579 million. Additionally, we recognized an impairment on jurisdictional pipeline assets of $12 million.
 
Our transportation and storage segment taxes other than income tax decreased $1 million due to reduced ad valorem taxes.

Our transportation and storage segment recorded equity in earnings of equity method affiliates of $21 million and $12 million for the nine months ended September 30, 2015 and 2014, respectively, from our interest in SESH. The $9 million increase in equity in earnings of equity method affiliates is attributable to our increased interest in SESH for the nine months ended September 30, 2015 compared to the nine months ended September 30, 2014.



34
Table of Contents

Condensed Consolidated Interim Information
 
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2015
 
2014
 
2015
 
2014
 
(In millions)
Operating (Loss) Income
$
(975
)
 
$
152

 
$
(778
)
 
$
452

Other Income (Expense):
 
 
 
 
 
 
 
Interest expense
(23
)
 
(20
)
 
(66
)
 
(50
)
Equity in earnings of equity method affiliates
7

 
5

 
21

 
12

Other, net
—

 
3

 
2

 
(2
)
Total Other Income (Expense)
(16
)
 
(12
)
 
(43
)
 
(40
)
(Loss) Income Before Income Taxes
(991
)
 
140

 
(821
)
 
412

Income tax expense
—

 
1

 
2

 
2

Net (Loss) Income
$
(991
)
 
$
139

 
$
(823
)
 
$
410

Less: Net (loss) income attributable to noncontrolling interest
(6
)
 
—

 
(6
)
 
2

Net (Loss) Income attributable to Enable Midstream Partners, LP
$
(985
)
 
$
139

 
$
(817
)
 
$
408


 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2015
 
2014
 
2015
 
2014
 
(In millions)
Other Financial Data:
 
 
 
 
 
 
 
Gross Margin (1)
$
359

 
$
364

 
$
996

 
$
1,082

Adjusted EBITDA (1)
221

 
231

 
622

 
670

Distributable cash flow (1)
153

 
161

 
431

 
503

 _____________________
(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 September 30, 2015 compared to Three Months Ended September 30, 2014

Net Income attributable to the Partnership. We reported net loss attributable to the Partnership of $985 million in the three months ended September 30, 2015 compared to net income attributable to the Partnership of $139 million in the three months ended September 30, 2014. The decrease in net income attributable to the Partnership of $1,124 million was primarily attributable to a decrease in operating income of $1,127 million (inclusive of impairments discussed by segment above), an increase in interest expense of $3 million, and a decrease in other income and expense of $3 million, partially offset by an increase in equity earnings in equity method affiliates of $2 million (discussed by segment above) in the three months ended September 30, 2015.

Interest Expense. Interest expense increased $3 million due to an increase in the amount of the Partnership's outstanding debt.

Nine Months Ended September 30, 2015 compared to Nine Months Ended September 30, 2014

Net Income attributable to the Partnership. We reported net loss attributable to the Partnership of $817 million in the nine months ended September 30, 2015 compared to net income attributable to the Partnership of $408 million in the nine months ended September 30, 2014. The decrease in net income attributable to the Partnership of $1,225 million was primarily attributable to a decrease in operating income of $1,230 million (inclusive of impairments discussed by segment above) and an increase in interest expense of $16 million, partially offset by an increase in equity earnings in equity method affiliates of $9 million (discussed by segment above) and an increase in other income and expense of $4 million in the nine months ended September 30, 2015.

Interest Expense. Interest expense increased $16 million due to higher interest rates on the Partnership's outstanding debt and an increase in the amount of outstanding debt.


35
Table of Contents


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
•
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 total 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.


36
Table of Contents


Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,

2015

2014
 
2015
 
2014

(In millions)
Reconciliation of Gross Margin to Total Revenues:



 
 
 
 
Total revenues
$
646


$
803

 
$
1,852

 
$
2,632

Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)
287


439

 
856

 
1,550

Gross margin
$
359


$
364

 
$
996

 
$
1,082

 
 
 
 
 
 
 
 
Reconciliation of Adjusted EBITDA and distributable cash flow to net (loss) income attributable to controlling interest:
 
 
 
 
 
 
 
Net (loss) income attributable to Enable Midstream Partners, LP
$
(985
)

$
139

 
$
(817
)
 
$
408

Add:
 
 
 
 

 

Depreciation and amortization expense
84


69

 
233

 
205

Interest expense, net of interest income
23


20

 
66

 
50

Income tax expense
—


1

 
2

 
2

EBITDA
$
(878
)

$
229

 
$
(516
)
 
$
665

Add:
 
 
 
 
 
 
 
Loss on extinguishment of debt
—

 
—

 
—

 
4

Distributions from equity method affiliates
10

 
7

 
37

 
13

Other non-cash losses
4

 
8

 
30

 
8

Impairments
1,105

 
1

 
1,105

 
1

Less:
 
 
 
 
 
 
 
Other non-cash gains
(13
)
 
(9
)
 
(13
)
 
(9
)
Equity in earnings of equity method affiliates
(7
)
 
(5
)
 
(21
)
 
(12
)
Adjusted EBITDA
$
221


$
231

 
$
622

 
$
670

Less:
 
 
 
 
 
 
 
Adjusted interest expense, net (1)
(27
)

(23
)
 
(77
)
 
(60
)
Maintenance capital expenditures
(41
)

(47
)
 
(113
)
 
(107
)
Current income taxes
—

 
—

 
(1
)
 
—

Distributable cash flow
$
153


$
161

 
$
431

 
$
503


37
Table of Contents

 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2015
 
2014
 
2015
 
2014
 
 
 
 
 
(In millions)
Reconciliation of Adjusted EBITDA to net cash provided by operating activities:
 
 
 
 
 
 
 
Net cash provided by operating activities
$
207

 
$
269

 
$
491

 
$
561

Interest expense, net of interest income
23

 
20

 
66

 
50

Net loss (income) attributable to noncontrolling interest
6

 
—

 
6

 
(2
)
Income tax expense
—

 
1

 
2

 
2

Deferred income tax (expense) benefit
—

 
—

 
(1
)
 
1

Equity in earnings of equity method affiliates, net of distributions
(3
)
 
(2
)
 
(16
)
 
(1
)
Impairments
(1,105
)
 
(1
)
 
(1,105
)
 
(1
)
Other non-cash items
3

 
(5
)
 
4

 
(11
)
Changes in operating working capital which (provided) used cash:

 
 
 
 
 
 
Accounts receivable
37

 
(20
)
 
35

 
11

Accounts payable
12

 
(5
)
 
82

 
96

Other, including changes in noncurrent assets and liabilities
(58
)
 
(28
)
 
(80
)
 
(41
)
EBITDA
$
(878
)
 
$
229

 
$
(516
)
 
$
665

Add:
 
 
 
 
 
 
 
Loss on extinguishment of debt
—

 
—

 
—

 
4

Distributions from equity method affiliates
10

 
7

 
37

 
13

Impairments
1,105

 
1

 
1,105

 
1

Other non-cash losses
4

 
8

 
30

 
8

Less:

 

 
 
 
 
Other non-cash gains
(13
)
 
(9
)
 
(13
)
 
(9
)
Equity in earnings of equity method affiliates
(7
)
 
(5
)
 
(21
)
 
(12
)
Adjusted EBITDA
$
221

 
$
231

 
$
622

 
$
670

____________________
(1) Adjusted interest expense, net excludes the effect of the amortization of the premium on Enable Oklahoma’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 capital activity. As of September 30, 2015, we had a working capital deficit of $377 million due primarily to borrowings under our commercial paper program to manage the timing of cash flows for maintenance and expansion capital activity. We utilize our commercial paper program to manage the timing of cash flows and fund short-term working capital deficits.
 

38
Table of Contents

Cash Flows
 
The following tables reflect cash flows for the applicable periods:
 
Nine Months Ended 
 September 30,
 
2015
 
2014
 
(In millions)
Net cash provided by operating activities
$
491

 
$
561

Net cash used in investing activities
(730
)
 
(573
)
Net cash provided by (used in) financing activities
232

 
(78
)
 
Operating Activities
 
The decrease of $70 million, or 12%, in net cash provided by operating activities for the nine months ended September 30, 2015 as compared to the nine months ended September 30, 2014 was primarily due to lower gross margin, which was partially offset by the impact of timing of payments to suppliers, receipts from customers, and changes in other working capital assets and liabilities.

Investing Activities
 
The increase of $157 million, or 27%, in net cash used in investing activities for the nine months ended September 30, 2015 as compared to the nine months ended September 30, 2014 was primarily due to higher capital expenditures of $148 million including the $80 million associated with the acquisition of the Monarch gas gathering system.

Financing Activities

Net cash provided by financing activities increased $310 million for the nine months ended September 30, 2015 as compared to the nine months ended September 30, 2014. Our primary financing activities consist of the following:

 
Nine Months Ended 
 September 30,
 
2015
 
2014
 
(In millions)
Repayment of Term Loan Facility
—

 
(1,050
)
Proceeds from Term Loan Facility
450

 
—

Repayment of Enable Oklahoma Term Loan
—

 
(250
)
Repayment of Enable Oklahoma Senior Note
—

 
(200
)
Proceeds from Enable Midstream Partners, LP 2019, 2024 and 2044 Notes, net of issuance costs
—

 
1,635

Net repayments of Revolving Credit Facility
—

 
(372
)
Proceeds from commercial paper program
179

 
95

Capital contributions from partners
—

 
464

Distributions to partners
(397
)
 
(400
)

Term Loan Agreement

On July 31, 2015, the Partnership entered into a Term Loan Agreement dated as of July 31, 2015, providing for an unsecured three-year $450 million term loan facility (Term Loan Facility). The entire $450 million principal amount of the Term Loan Facility was borrowed by Enable on July 31, 2015. The Term Loan Facility contains an option, which may be exercised up to two times, to extend the term of the Term Loan Facility, in each case, for an additional one-year term. The Term Loan Facility provides an option to prepay, without penalty or premium, the amount outstanding, or any portion thereof, in a minimum amount of $1 million, or any multiple of $0.5 million in excess thereof. As of September 30, 2015 there was $450 million outstanding under the Term Loan Facility.

The Term Loan Facility provides that outstanding borrowings bear interest at the LIBOR and/or an alternate base rate, at the Partnership’s election, plus an applicable margin. The applicable margin is based on our applicable credit ratings. As of

39
Table of Contents

September 30, 2015, the applicable margin for LIBOR-based borrowings under the term loan facility was 1.375% based on our credit ratings.

Revolving Credit Facility

On June 18, 2015, the Partnership amended and restated its Revolving Credit Facility to, among other things, increase the borrowing capacity thereunder to $1.75 billion and extend its maturity date to June 18, 2020. The Revolving Credit Facility is discussed in Note 8 of the condensed consolidated financial statements and related notes. As of September 30, 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 September 30, 2015, we had $432 million outstanding under our commercial paper program.

The Revolving Credit Facility provides that outstanding borrowings bear interest at the LIBOR and/or an alternate base rate, at the Partnership’s election, plus an applicable margin. The applicable margin is based on the Partnership’s applicable credit ratings. As of September 30, 2015, the applicable margin for LIBOR-based borrowings under the Revolving Credit Facility was 1.50% based on the Partnership’s credit ratings. In addition, the Revolving Credit Facility requires the Partnership to pay a fee on unused commitments. The commitment fee is based on the Partnership’s applicable credit rating from the rating agencies. As of September 30, 2015, the commitment fee under the Revolving Credit Facility was 0.20% per annum based on the Partnership’s credit ratings. The commitment fee is recorded as interest expense in the Partnership's Combined and Consolidated Statements of Income.

Sources of Liquidity

As of September 30, 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.

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 October 22, 2015, the board of directors of Enable GP declared a quarterly cash distribution of $0.318 per common unit on all of the Partnership's outstanding common and subordinated units for the period ended September 30, 2015. The distribution represents an increase of approximately 0.6% over the prior quarter distribution and will be paid November 13, 2015 to unitholders of record as of the close of business August 3, 2015.
 
Off-Balance Sheet Arrangements
 
We do not have any off-balance sheet arrangements.
 

40
Table of Contents

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
 
Revenue Recognition

The Partnership generates the majority of its revenues from midstream energy services, including natural gas gathering, processing, transportation and storage and crude oil gathering. The Partnership performs these services under various contractual arrangements, which include fee-based contract arrangements and arrangements pursuant to which it purchases and resells commodities in connection with providing the related service and earns a net margin for its fee. While the Partnership's transactions vary in form, the essential element of each transaction is the use of its assets to transport a product or provide a processed product to a customer. The Partnership reflects revenue as Product sales and Service revenue on the Condensed Consolidated Statements of Income as follows:

Product sales: Product sales represent the sale of natural gas, NGLs, crude oil and condensate where the product is purchased and used in connection with providing the Partnership's midstream services.

Service revenue: Service revenue represents all other revenue generated as a result of performing the Partnership's midstream services.

Revenues for gathering, processing, and transportation and storage services for the Partnership are recorded each month based on the current month’s estimated volumes, contracted prices (considering current commodity prices), historical seasonal fluctuations and any known adjustments. The estimates are reversed in the following month, and customers are billed on actual volumes and contracted prices. Gas sales are calculated on current-month nominations and contracted prices. Revenues associated with the production of NGLs are estimated based on current-month estimated production and contracted prices. These amounts are also reversed in the following month, and the customers are billed on actual production and contracted prices. Estimated revenues are reflected in Accounts Receivable or Accounts Receivable-affiliated companies, as appropriate, on the Consolidated Balance Sheets and in Total Revenues on the Combined and Consolidated Statements of Income.

The Partnership recognizes revenue from natural gas gathering, processing, transportation and storage and crude oil gathering services to third parties as services are provided. Revenue associated with NGLs is recognized when the production is sold. The Partnership records deferred revenue when it receives consideration from a third party before achieving certain criteria that must be met for revenue to be recognized in accordance with GAAP.

Cost of natural gas and natural gas liquids represents cost of our natural gas and natural gas liquids purchased exclusive of depreciation and Operation and maintenance expenses and consists primarily of product and fuel costs. Operation and maintenance expense represents the cost of our service related revenues and consists primarily of labor expenses, lease costs, utility costs, insurance premiums and repairs and maintenance expenses. Any Operation and maintenance expenses associated with product sales are immaterial.

Assessing Impairment of Long-lived Assets (including Intangible Assets) and Goodwill

The Partnership periodically evaluates long-lived assets, including property, plant and equipment, and specifically identifiable intangibles other than goodwill, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted cash flows attributable to the assets, as compared to the carrying value of the assets. During each of the three and nine months ended September 30, 2015, the Partnership recorded a $12 million impairment on jurisdictional pipelines in our transportation and storage segment, and a $6 million impairment to our Service Star business line, a component of our gathering and processing segment.


41
Table of Contents

The Partnership tests its goodwill for impairment annually on October 1st, or more frequently if events or changes in circumstances indicate that the carrying value of goodwill may not be recoverable. Goodwill is assessed for impairment by comparing the fair value of the reporting unit with its book value, including goodwill.

As discussed in Note 6, the Partnership determined during its preparation of financial statements for the third quarter of 2015 that the carrying value of the gathering and processing and transportation and storage reportable segments exceeded fair value. The Partnership determined that goodwill was completely impaired in the amount of $1,087 million, which is included in Impairments on the Condensed Consolidated Statement of Income for the three and nine months ended September 30, 2015.


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 substantially comprised of fixed rate debt, which mitigates the impact of fluctuations in interest rates. Future issuances of long-term debt could be impacted by increases in interest rates, which could result in higher interest costs. 


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 September 30, 2015. Based on such evaluation, our management has concluded that, as of September 30, 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. During the quarter ended September 30, 2015, 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.

42
Table of Contents


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 assessment of effectiveness of our internal control over financial reporting in our Annual Report on Form 10-K for the year ending December 31, 2015. We are required to comply with the auditor attestation requirement of Section 404 of the Sarbanes-Oxley Act in our Annual Report on Form 10-K for the year ending December 31, 2015.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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


Item 1A. Risk Factors

We are subject to various risks and uncertainties in the course of our business. Risk factors relating to the Partnership are set forth under "Risk Factors" in our Annual Report. No material changes to such risk factors have occurred during the three and nine months ended September 30, 2015.

 
Item 6. Exhibits

The following exhibits are filed herewith:

Exhibits not incorporated by reference to a prior filing are designated by a cross (+); all exhibits not so designated are incorporated by reference to a prior filing as indicated.

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


43
Table of Contents

Exhibit Number

Description
Report or Registration Statement
SEC File or Registration Number
Exhibit Reference
2.1


Master Formation Agreement dated as of March 14, 2013 by and among CenterPoint Energy, Inc., OGE Energy Corp., Bronco Midstream Holdings, LLC and Bronco Midstream Holdings II, LLC
Registrant’s registration statement on Form S-1, filed on November 26, 2013
File No. 333-192545
Exhibit 2.1
3.1


Certificate of Limited Partnership of CenterPoint Energy Field Services LP, as amended
Registrant’s registration statement on Form S-1, filed on November 26, 2013
File No. 333-192545
Exhibit 3.1
3.2


Second Amended and Restated Agreement of Limited Partnership of Enable Midstream Partners, LP
Registrant's Form 8-K filed April 22,2014
File No. 001-36413
Exhibit 3.1
4.1


Specimen Unit Certificate representing common units (included with Second Amended and Restated Agreement of Limited Partnership of Enable Midstream Partners, LP as Exhibit A thereto)
Registrant's Form 8-K filed April 22,2014
File No. 001-36413
Exhibit 3.1
4.2


Indenture, dated as of May 27, 2014, between Enable Midstream Partners, LP and U.S. Bank National Association, as trustee.
Registrant’s Form 8-K filed May 29, 2014
File No. 001-36413
Exhibit 4.1
4.3


First Supplemental Indenture, dated as of May 27, 2014, by and among Enable Midstream Partners, LP, CenterPoint Energy Resources Corp., as guarantor, and U.S. Bank National Association, as trustee.
Registrant’s Form 8-K filed May 29, 2014

File No. 001-36413

Exhibit 4.2

4.4


Registration Rights Agreement, dated as of May 27, 2014, by and among Enable Midstream Partners, LP, CenterPoint Energy Resources Corp., as guarantor, and RBS Securities Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Credit Suisse Securities (USA) LLC, and RBC Capital Markets, LLC, as representatives of the initial purchasers.
Registrant’s Form 8-K filed May 29, 2014
File No. 001-36413

Exhibit 4.3
+10.1

 
Term Loan Agreement dated July 31, 2015 by and among Enable Midstream Partners, LP and Bank of America, N.A., as administrative agent, Merrill Lynch, Pierce, Fenner & Smith Incorporated, as sole lead arranger and sole bookrunner, Mizuho Bank, Ltd., as syndication agent and as documentation agent, and the several lenders from time to time party thereto relating to a 3-year $450 million unsecured term loan facility.
 
 
 
+31.1


Rule 13a-14(a)/15d-14(a) Certification of principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.



+31.2


Rule 13a-14(a)/15d-14(a) Certification of principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.



+32.1


Section 1350 Certification of principal executive officer



+32.2


Section 1350 Certification of principal financial officer



+101.INS

 
XBRL Instance Document.
 
 
 
+101.SCH

 
XBRL Taxonomy Schema Document.
 
 
 
+101.PRE

 
XBRL Taxonomy Presentation Linkbase Document.
 
 
 
+101.LAB

 
XBRL Taxonomy Label Linkbase Document.
 
 
 
+101.CAL

 
XBRL Taxonomy Calculation Linkbase Document.
 
 
 
+101.DEF

 
XBRL Definition Linkbase Document.
 
 
 



44
Table of Contents

SIGNATURE
 
Pursuant to the requirements of the Securities Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
 
 
ENABLE MIDSTREAM PARTNERS, LP
 
 
(Registrant)
 
 
 
 
 
By: ENABLE GP, LLC
 
 
Its general partner
 
 
 
 
Date:
November 4, 2015
By:
 
/s/ Tom Levescy
 
 
 
 
Tom Levescy
 
 
 
 
Senior Vice President, Chief Accounting Officer and Controller
 
 
 
 
(Principal Accounting Officer)