10-Q
Table of Contents

 
 
 
 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
 _______________________________________
FORM 10-Q
 _______________________________________
þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES AND EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2016
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
 
þ
 
Accelerated filer
 
¨
 
 
 
 
 
 
 
Non-accelerated filer
 
¨ (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 April 15, 2016, there were 214,467,409 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.
A non-GAAP measure calculated as 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.
Annual Report.
Annual Report on Form 10-K for the year ended December 31, 2015.
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 for periods prior to formation of the Partnership on May 1, 2013.
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 5,900-mile interstate pipeline that provides natural gas transportation and storage services to customers principally in the Anadarko, Arkoma and Ark-La-Tex basins in Oklahoma, Texas, Arkansas, Louisiana and Kansas.
Enable GP.
Enable GP, LLC, a Delaware limited liability company and the general partner of Enable Midstream Partners, LP.
Enable Midstream Services.
Enable Midstream Services, LLC, a wholly owned subsidiary of Enable Midstream Partners, LP.
Enogex.
Enogex LLC, a Delaware limited liability company.
EOIT.
Enable Oklahoma Intrastate Transmission, LLC, formerly Enogex LLC, a wholly owned subsidiary of the Partnership that operates a 2,200-mile intrastate pipeline that provides natural gas transportation and storage services to customers in Oklahoma.
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.
A non-GAAP measure calculated as 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 as of March 14, 2013.
MMcf.
Million cubic feet of natural gas.
MMcf/d.
Million cubic feet per day.
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.
Partnership.
Enable Midstream Partners, LP, and its subsidiaries.

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Partnership Agreement
Third Amended and Restated Agreement of Limited Partnership of Enable Midstream Partners, LP dated as of February 18, 2016.
Purchase Agreement.
Purchase Agreement, dated January 28, 2016, by and between the Partnership and CenterPoint Energy, Inc. for the sale by the Partnership and purchase by CenterPoint Energy, Inc. of Series A Preferred Units.
Revolving Credit Facility.
$1.75 billion senior unsecured revolving credit facility.
SEC.
Securities and Exchange Commission.
Securities Act.
Securities Act of 1933, as amended.
Series A Preferred Units.
10% Series A Fixed-to-Floating Non-Cumulative Redeemable Perpetual Preferred Units representing limited partner interests in the Partnership.
SESH.
Southeast Supply Header, LLC, in which the Partnership owns a 50% interest, that operates an approximately 290-mile interstate natural gas pipeline from Perryville, Louisiana to southwestern Alabama near the Gulf Coast.
TBtu.
Trillion British thermal units.
TBtu/d.
Trillion British thermal units per day.
WTI.
West Texas Intermediate.
2015 Term Loan Agreement.
$450 million unsecured term loan agreement.
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

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FORWARD-LOOKING STATEMENTS
 
Some of the information in this report may contain forward-looking statements. Forward-looking statements give our current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as “could,” “will,” “should,” “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this report include our expectations of plans, strategies, objectives, growth and anticipated financial and operational performance, including revenue projections, capital expenditures and tax position. Forward-looking statements can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed.
 
A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, when considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this report and in our Annual Report on Form 10-K for the year ended December 31, 2015 (Annual Report). Those risk factors and other factors noted throughout this report and in our Annual Report could cause our actual results to differ materially from those disclosed in any forward-looking statement. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:
changes in general economic conditions;
competitive conditions in our industry;
actions taken by our customers and competitors;
the supply and demand for natural gas, NGLs, crude oil and midstream services;
our ability to successfully implement our business plan;
our ability to complete internal growth projects on time and on budget;
the price and availability of debt and equity financing;
operating hazards and other risks incidental to transporting, storing and gathering natural gas, NGLs, crude oil and midstream products;
natural disasters, weather-related delays, casualty losses and other matters beyond our control;
interest rates;
labor relations;
large customer defaults;
changes in the availability and cost of capital;
changes in tax status;
the effects of existing and future laws and governmental regulations;
changes in insurance markets impacting costs and the level and types of coverage available;
the timing and extent of changes in commodity prices;
the suspension, reduction or termination of our customers’ obligations under our commercial agreements;
disruptions due to equipment interruption or failure at our facilities, or third-party facilities on which our business is dependent;
the effects of future litigation; and
other factors set forth in this report and our other filings with the SEC, including our Annual Report.
Forward-looking statements speak only as of the date on which they are made. We expressly disclaim any obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by law.


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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ENABLE MIDSTREAM PARTNERS, LP
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
 
 
Three Months Ended 
 March 31,
 
2016

2015
 
(In millions, except per unit data)
Revenues (including revenues from affiliates (Note 11)):





Product sales
$
245


$
351

Service revenue
264


265

Total Revenues
509


616

Cost and Expenses (including expenses from affiliates (Note 11)):





Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)
195


292

Operation and maintenance
95


104

General and Administrative
20


26

Depreciation and amortization
81


73

Taxes other than income taxes
15


17

Total Cost and Expenses
406


512

Operating Income
103


104

Other Income (Expense):



Interest expense (including expenses from affiliates (Note 11))
(23
)

(20
)
Equity in earnings of equity method affiliates
7


7

Other, net


1

Total Other Income (Expense)
(16
)

(12
)
Income Before Income Taxes
87


92

Income tax expense
1


1

Net Income
$
86


$
91

Less: Net income attributable to noncontrolling interest



Less: Series A Preferred Unit distributions (Note 4)



Net Income attributable to common and subordinated units (Note 3)
$
86


$
91





Basic earnings per unit (Note 3)





Common units
$
0.21


$
0.22

Subordinated units
$
0.20


$
0.21

Diluted earnings per unit (Note 3)
 
 
 
Common units
$
0.19

 
$
0.22

Subordinated units
$
0.20

 
$
0.21

Basic weighted average number of outstanding (Note 3)





Common units
214


214

Subordinated units
208


208

Diluted weighted average number of outstanding (Note 3)
 
 
 
Common units
235

 
214

Subordinated units
208

 
208

 

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

ENABLE MIDSTREAM PARTNERS, LP
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
 
 
Three Months Ended 
 March 31,
 
2016
 
2015
 
(In millions)
Net income
$
86

 
$
91

Comprehensive income
86

 
91

Less: Comprehensive income attributable to noncontrolling interest

 

Comprehensive income attributable to Enable Midstream Partners, LP
$
86

 
$
91





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

ENABLE MIDSTREAM PARTNERS, LP
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited) 
 
March 31,
2016
 
December 31,
2015
 
(In millions)
Current Assets:
 
Cash and cash equivalents
$
38

 
$
4

Accounts receivable
226

 
245

Accounts receivable—affiliated companies
16

 
21

Inventory
45

 
53

Gas imbalances
20

 
23

Other current assets
35

 
35

Total current assets
380

 
381

Property, Plant and Equipment:
 
 
 
Property, plant and equipment
11,395

 
11,293

Less accumulated depreciation and amortization
1,219

 
1,162

Property, plant and equipment, net
10,176

 
10,131

Other Assets:
 
 
 
Intangible assets, net
327

 
333

Investment in equity method affiliates
331

 
344

Other
35

 
37

Total other assets
693

 
714

Total Assets
$
11,249

 
$
11,226

Current Liabilities:
 
 
 
Accounts payable
$
153

 
$
248

Accounts payable—affiliated companies
6

 
9

Short-term debt

 
236

Taxes accrued
29

 
30

Gas imbalances
7

 
25

Other
85

 
67

Total current liabilities
280

 
615

Other Liabilities:
 
 
 
Accumulated deferred income taxes, net
8

 
8

Notes payable—affiliated companies

 
363

Regulatory liabilities
18

 
18

Other
22

 
20

Total other liabilities
48

 
409

Long-Term Debt
3,074

 
2,671

Commitments and Contingencies (Note 12)

 

Partners’ Equity:
 
 
 
Series A Preferred Units (14,520,000 issued and outstanding at March 31, 2016 and 0 issued and outstanding at December 31, 2015)
362

 

Common units (214,467,409 issued and outstanding at March 31, 2016 and 214,541,422 issued and outstanding at December 31, 2015, respectively)
3,692

 
3,714

Subordinated units (207,855,430 issued and outstanding at March 31, 2016 and December 31, 2015, respectively)
3,781

 
3,805

Noncontrolling interest
12

 
12

Total Partners’ Equity
7,847

 
7,531

Total Liabilities and Partners’ Equity
$
11,249

 
$
11,226


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

ENABLE MIDSTREAM PARTNERS, LP
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 
 
Three Months Ended 
 March 31,
 
2016
 
2015
 
(In millions)
Cash Flows from Operating Activities:
 
Net income
$
86

 
$
91

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization
81

 
73

Loss on sale/retirement of assets
1

 

Equity in earnings of equity method affiliates, net of distributions

 
5

Equity based compensation
2

 
3

Amortization of debt costs and discount (premium)
(1
)
 
(1
)
Changes in other assets and liabilities:
 
 
 
Accounts receivable, net
19

 
2

Accounts receivable—affiliated companies
5

 
(2
)
Inventory
8

 
13

Gas imbalance assets
3

 
8

Other current assets

 
6

Other assets
1

 
(2
)
Accounts payable
(84
)
 
18

Accounts payable—affiliated companies
(3
)
 
(21
)
Gas imbalance liabilities
(18
)
 
(5
)
Other current liabilities
15

 
2

Other liabilities
2

 
(2
)
Net cash provided by operating activities
117

 
188

Cash Flows from Investing Activities:
 
 
 
Capital expenditures
(130
)
 
(239
)
Investment in equity method affiliates

 
(6
)
Return of investment in equity method affiliates
13

 

Net cash used in investing activities
(117
)
 
(245
)
Cash Flows from Financing Activities:
 
 
 
Proceeds from revolving credit facility
495

 

Repayment of revolving credit facility
(90
)
 

Increase (decrease) in short-term debt
(236
)
 
183

Repayment of notes payable—affiliated companies
(363
)
 

Proceeds from issuance of Series A Preferred Units, net of issuance costs
362

 

Distributions
(134
)
 
(130
)
Net cash provided by financing activities
34

 
53

Net Increase (Decrease) in Cash and Cash Equivalents
34

 
(4
)
Cash and Cash Equivalents at Beginning of Period
4

 
12

Cash and Cash Equivalents at End of Period
$
38

 
$
8



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

ENABLE MIDSTREAM PARTNERS, LP
CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY
(Unaudited)
 
 
Series A
Preferred
Units
 
Common
Units
 
Subordinated
 Units
 
Noncontrolling
Interest
 
Total Partners’
Equity
 
Units
 
Value
 
Units
 
Value
 
Units
 
Value
 
Value
 
Value
 
(In millions)
Balance as of December 31, 2014

 
$

 
214

 
$
4,353

 
208

 
$
4,439

 
$
31

 
$
8,823

Net income

 

 

 
48

 

 
43

 

 
91

Distributions

 

 

 
(66
)
 

 
(64
)
 

 
$
(130
)
Equity based compensation

 

 

 
3

 

 

 

 
$
3

Balance as of March 31, 2015

 
$

 
214

 
$
4,338

 
208

 
$
4,418

 
$
31

 
$
8,787

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance as of December 31, 2015

 
$

 
214

 
$
3,714

 
208

 
$
3,805

 
$
12

 
$
7,531

Net income

 

 

 
44

 

 
42

 

 
86

Issuance of Series A Preferred Units
15

 
362

 

 

 

 

 

 
362

Distributions

 

 

 
(68
)
 

 
(66
)
 

 
(134
)
Equity based compensation

 

 

 
2

 

 

 
$

 
2

Balance as of March 31, 2016
15

 
$
362

 
214

 
$
3,692

 
208

 
$
3,781

 
$
12

 
$
7,847


See Notes to the Unaudited Condensed Consolidated Financial Statements
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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), a Delaware limited 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 March 31, 2016, CenterPoint Energy held approximately 55.4% of the common and subordinated units in the Partnership, or 94,151,707 common units and 139,704,916 subordinated units, and OGE Energy held approximately 26.3% of the common and subordinated units in the Partnership, or 42,832,291 common units and 68,150,514 subordinated units. Additionally, CenterPoint Energy holds 14,520,000 Series A Preferred Units. See Note 4 for further information related to the Series A Preferred Units.
 
For the period from December 31, 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 March 31, 2016, the Partnership owned a 50% interest in SESH. See Note 6 for further discussion of SESH.

Basis of Presentation

The accompanying condensed consolidated financial statements and related notes of the Partnership have been prepared pursuant to the rules and regulations of the SEC and GAAP. Pursuant to such rules and regulations, certain disclosures normally included in financial statements prepared in accordance with GAAP have been omitted. The accompanying condensed consolidated financial statements and related notes should be read in conjunction with the 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.
 
For a description of the Partnership’s reportable segments, see Note 14.

Use of Estimates

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

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Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable are recorded at the invoiced amount and do not bear interest. It is the policy of management to review the outstanding accounts receivable at least quarterly, as well as the bad debt write-offs experienced in the past. Based on this review, a $3 million allowance for doubtful accounts was recognized as of March 31, 2016. There was no allowance for doubtful accounts as of December 31, 2015.

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

On February 18, 2016, in connection with the closing of the private placement of 14,520,000 Series A Preferred Units and pursuant to the Purchase Agreement, the General partner adopted the Third Amended and Restated Agreement of Limited Partnership (the Partnership Agreement) which, among other things, authorized and established the terms of the Series A Preferred Units and the other series of preferred units that are issuable upon conversion of the Series A Preferred Units. For further information related to the issuance of the Series A Preferred Units, see Note 4.


(2) New Accounting Pronouncements

Revenue from Contracts with Customers

In May 2014, the 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, the 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 Condensed Consolidated Financial Statements and related disclosures.

In March 2016, the FASB issued ASU No. 2016-08, “Revenue from Contracts with Customers (Topic 606)-Principal versus Agent Considerations (Reporting Revenue Gross versus Net)”. ASU No. 2016-08 requires an entity to determine whether the nature of its promise is to provide the specified good or service itself (i.e., the entity is a principal) or to arrange for that good or service to be provided by the other party (i.e., the entity is an agent) when another party is involved in providing goods or services to a customer. Additionally, the amendments in this ASU require an entity that is a principal to recognize revenue in the gross amount of consideration to which it expects to be entitled in exchange for the specified good or service transferred to the customer, and require an entity that is an agent to recognize revenue in the amount of any fee or commission to which it expects to be entitled in exchange for arranging for the specified good or service to be provided by the other party. ASU 2016-08 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. The Partnership is currently evaluating the impact, if any, the adoption of this standard will have on our Condensed Consolidated Financial Statements and related disclosures.

In April 2016, the FASB issued ASU No. 2016-10, “Revenue from Contracts with Customers (Topic 606)-Identifying Performance Obligations and Licensing”. The amendments in ASU No. 2016-10 impact entities with transactions that include contracts with customers to transfer goods or services (that are an output of the entity’s ordinary activities) in exchange for consideration, and they require entities to recognize revenue by following certain steps, including (1) identifying the contract(s) with a customer; (2) identifying the performance obligations in a contract; (3) determining the transaction price; (4) allocating the transaction price to the performance obligations in the contract; and (5) recognizing revenue when, or as, the entity satisfies a performance obligation. Notably, ASU No. 2016-10 does not impact the core revenue recognition principles set forth in Topic 606, but rather clarifies the identification of performance obligations and the licensing implementation guidance, while retaining the related principles for those areas. ASU 2016-10 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. The Partnership is currently evaluating the impact, if any, the adoption of this standard will have on our Condensed Consolidated Financial Statements and related disclosures.


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Consolidation

In February 2015, the 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. The Partnership adopted the amendment in the first quarter of 2016, which resulted in no impact to our Condensed Consolidated Financial Statements and related disclosures.

Presentation of Debt Issuance Costs

In April 2015, the 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. The Partnership adopted the amendment in the first quarter of 2016 on a retrospective basis in order to conform the presentation of debt issuance costs on the Condensed Consolidated Balance Sheets. At each of March 31, 2016 and December 31, 2015, the Partnership had unamortized debt expense of $12 million classified as a reduction of Long-Term Debt in the Condensed Consolidated Balance Sheets. Unamortized debt expense related to the Revolving Credit Facility of $5 million and $6 million as of March 31, 2016 and December 31, 2015, respectively, is classified as Other Assets in the Condensed Consolidated Balance Sheets.

Balance Sheet Classification of Deferred Taxes

In November 2015, the FASB issued ASU No. 2015-17, “Income Taxes—Balance Sheet Classification of Deferred Taxes.” This ASU eliminates the requirement to present deferred tax liabilities and assets as current and non-current in a classified balance sheet. Instead, all deferred tax assets and liabilities will be classified as non-current. ASU 2015-17 is effective for all interim and annual periods beginning after December 16, 2016 and early application is permitted. The amendments in this update may be applied either prospectively to all deferred tax liabilities and assets or retrospectively to all periods presented. The Partnership adopted the amendment in the first quarter of 2016, which resulted in no impact to our Condensed Consolidated Financial Statements and related disclosures.

Leases

In February 2016, the FASB issued ASU 2016-02, “Leases”. The amendments in this update require, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The Partnership expects to adopt the amendments in the first quarter of 2019 and is currently evaluating the impacts of the amendments to our Condensed Consolidated Financial Statements and accounting practices for leases.

Share-Based Compensation

In March 2016, the FASB issued ASU No. 2016-09, “Compensation—Stock Compensation (Topic 718).” This standard makes several modifications to Topic 718 related to the accounting for forfeitures, employer tax withholding on share-based compensation and the financial statement presentation of excess tax benefits or deficiencies. ASU 2016-09 also clarifies the statement of cash flows presentation for certain components of share-based awards. The standard is effective for interim and annual reporting periods beginning after December 15, 2016, although early adoption is permitted. The Partnership is currently assessing how the adoption of this standard will impact our Condensed Consolidated Financial Statements and related disclosures.



11

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(3) Earnings Per Limited Partner Unit

The following table illustrates the Partnership’s calculation of earnings per unit for common and subordinated units:
 
Three Months Ended 
 March 31,
 
2016
 
2015
 
(In millions, except per unit data)
Net income
$
86

 
$
91

Net income attributable to noncontrolling interest

 

Series A Preferred Unit distribution

 

General partner interest in net income

 

Net income available to common and subordinated unitholders
$
86

 
$
91

 
 
 
 
Net income allocable to common units
$
44

 
$
48

Net income allocable to subordinated units
42

 
43

Net income available to common and subordinated unitholders
$
86

 
$
91

 
 
 
 
Net income allocable to common units
$
44

 
$
48

Series A Preferred Unit Distribution

 

Diluted net income allocable to common units
44

 
48

Diluted net income allocable to subordinated units
42

 
43

Total
$
86

 
$
91

 
 
 
 
Basic weighted average number of outstanding
 
 
 
Common units
214

 
214

Subordinated units 
208

 
208

Total
422

 
422

 
 
 
 
Basic earnings per unit
 
 
 
Common units
$
0.21

 
$
0.22

Subordinated units
$
0.20

 
$
0.21

 
 
 
 
Basic weighted average number of outstanding common units
214

 
214

Dilutive effect of Series A Preferred Units
21

 

Diluted weighted average number of outstanding common units
235

 
214

Diluted weighted average number of outstanding subordinated units
208

 
208

Total
443

 
422

 
 
 
 
Diluted earnings per unit
 
 
 
Common units
$
0.19

 
$
0.22

Subordinated units
$
0.20

 
$
0.21


There was no dilutive effect of equity based compensation during the three months ended March 31, 2016 and 2015.


(4) Partners’ Equity

The Partnership Agreement requires that, within 45 days subsequent to the end of each quarter, the Partnership distribute all of its available cash (as defined in the Partnership Agreement) to unitholders of record on the applicable record date.


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The Partnership paid or has authorized payment of the following cash distributions to common and subordinated unitholders during 2015 and 2016 (in millions, except for per unit amounts):
Quarter Ended
 
Record Date
 
Payment Date
 
Per Unit Distribution
 
Total Cash Distribution
March 31, 2016 (1)
 
May 6, 2016
 
May 13, 2016
 
$
0.318

 
$
134

December 31, 2015
 
February 2, 2016
 
February 12, 2016
 
$
0.318

 
$
134

September 30, 2015
 
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

_____________________
(1)
The board of directors of Enable GP declared this $0.318 per common unit cash distribution on April 26, 2016, to be paid on May 13, 2016, to common and subordinated unitholders of record at the close of business on May 6, 2016.

The board of directors of Enable GP declared a $0.2917 per Series A Preferred Unit prorated cash distribution on April 26, 2016, to be paid on May 13, 2016, to Series A Preferred unitholders of record at the close of business on May 6, 2016. The prorated quarterly distribution for the Series A Preferred Units is for a partial period beginning on February 18, 2016, and ending on March 31, 2016, which equates to $0.625 per unit on a full-quarter basis or $2.50 per unit on an annualized basis.

General Partner Interest and Incentive Distribution Rights

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

Subordinated Units

Subordinated Unit Ownership

All subordinated units are held by CenterPoint Energy and OGE Energy. These units are considered subordinated because during the subordination period (as defined in the 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 which (1) distributions of available cash from operating surplus (as defined in the Partnership Agreement) on each of the outstanding common units and subordinated units equal or exceed $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 and (2) the adjusted operating surplus for each of the three consecutive, non-overlapping four-quarter periods immediately preceding such date equaled or exceeded the sum of the minimum quarterly distribution on all common units and subordinated units that were outstanding during such periods on a fully diluted weighted average basis. 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.

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Series A Preferred Units

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

Pursuant to the Partnership Agreement, the Series A Preferred Units:
rank senior to the Partnership’s common units with respect to the payment of distributions and distribution of assets upon liquidation, dissolution and winding up;
have no stated maturity;
are not subject to any sinking fund; and
will remain outstanding indefinitely unless repurchased or redeemed by the Partnership or converted into its common units in connection with a change of control.

Holders of the Series A Preferred Units receive, on a non-cumulative basis and if and when declared by the General Partner, a quarterly cash distribution, subject to certain adjustments, equal to an annual rate of 10% on the stated liquidation preference from the date of original issue to, but not including, the five year anniversary of the original issue date and an annual rate of LIBOR plus a spread of 8.5% on the stated liquidation preference thereafter.

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

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

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

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


(5) Assessing 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. The Partnership recorded no material impairments to long-lived assets in the three months ended March 31, 2016 or 2015. 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.

14

Table of Contents



(6) Investments in Equity Method Affiliates
 
The Partnership uses the equity method of accounting for investments in entities in which it has an ownership interest between 20% and 50% and exercises significant influence.
 
For the period from December 31, 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. Spectra Energy Partners, LP owns 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 interest in the Partnership and its economic interest in Enable GP, or does not have the ability to exercise certain control rights, Spectra Energy Partners, LP may, under certain circumstances, have the right to purchase our interest in SESH at fair market value. As of March 31, 2016, the Partnership owned a 50% interest in SESH.

The Partnership shares operations of SESH with Spectra Energy Partners, LP under service agreements. The Partnership is responsible for the field operations of SESH. SESH reimburses each party for actual costs incurred, which are billed based upon a combination of direct charges and allocations. During the three months ended March 31, 2016 and 2015, the Partnership billed SESH $4 million and $2 million, respectively, associated with these service agreements.

  
Investment in Equity Method Affiliates:
 
Three Months Ended 
 March 31,
 
2016
 
2015
 
(In millions)
Balance as of December 31
$
344

 
$
348

Equity in earnings of equity method affiliate
7

 
7

Contributions to equity method affiliate

 
6

Distributions from equity method affiliate(1)
(20
)
 
(12
)
Balance as of March 31
$
331

 
$
349

____________________
(1)
Distributions from equity method affiliates includes a $7 million and $12 million return on investment and a $13 million and zero return of investment for the three months ended March 31, 2016 and 2015, respectively.

Equity in Earnings of Equity Method Affiliates:
 
Three Months Ended 
 March 31,
 
2016
 
2015
 
(In millions)
SESH
$
7

 
$
7


Distributions from Equity Method Affiliates:
 
Three Months Ended 
 March 31,
 
2016

2015
 
(In millions)
SESH
$
20

 
$
12



15

Table of Contents

Summarized financial information of SESH is presented below:
 
Three Months Ended 
 March 31,
 
2016
 
2015
 
(In millions)
Income Statements:
 
 
 
Revenues
$
29

 
$
29

Operating income
19

 
18

Net income
14

 
14


 
(7) Debt
 
The following table presents the Partnership’s outstanding debt as of March 31, 2016 and December 31, 2015.

 
March 31,
2016
 
December 31,
2015
 
(In millions)
Commercial Paper
$

 
$
236

2015 Term Loan Agreement
450

 
450

Revolving Credit Facility
715

 
310

Notes payable — affiliated companies (Note 11)

 
363

2019 Notes
500

 
500

2024 Notes
600

 
600

2044 Notes
550

 
550

EOIT Senior Notes
250

 
250

Premium (Discount) on long-term debt
21

 
23

Total debt
3,086

 
3,282

Less: Short-term debt(1)

 
236

Less: Unamortized debt expense
12

 
12

Less: Notes payable—affiliated companies

 
363

Total long-term debt
$
3,074

 
$
2,671

___________________
(1)
Short-term debt includes $236 million of commercial paper as of December 31, 2015. There were no commercial paper borrowings outstanding as of March 31, 2016.

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 March 31, 2016, there was $715 million of principal advances and $3 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 weighted average interest rate of the Revolving Credit Facility was 1.97% as of March 31, 2016.

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 March 31, 2016, 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 March 31, 2016, 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.


16

Table of Contents

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 $236 million outstanding under our commercial paper program as of December 31, 2015. On February 2, 2016, Standard & Poor’s Ratings Services lowered its credit rating on the Partnership from an investment grade rating to a non-investment grade rating. The short-term rating on the Partnership was also reduced from an investment grade rating to a non-investment grade rating. As a result of the downgrade, the Partnership repaid its outstanding borrowings under the commercial program upon maturity and did not issue any additional commercial paper. There was no outstanding commercial paper as of March 31, 2016.

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 agreement (2015 Term Loan Agreement). The entire $450 million principal amount of the 2015 Term Loan Agreement was borrowed by Enable on July 31, 2015. The 2015 Term Loan Agreement contains an option, which may be exercised up to two times, to extend the term of the 2015 Term Loan Agreement, in each case, for an additional one-year term. The 2015 Term Loan Agreement provides an option to prepay, without penalty or premium, the amount outstanding, or any portion thereof, in a minimum amount of $1 million, or any multiple of $0.5 million in excess thereof. As of March 31, 2016, there was $450 million outstanding under the 2015 Term Loan Agreement. As of March 31, 2016, the weighted average interest rate of the 2015 Term Loan Agreement was 1.80%.

The 2015 Term Loan Agreement 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 March 31, 2016, the applicable margin for LIBOR-based borrowings under the term loan agreement 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 of the 2019 Notes and the 2024 Notes, 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. On December 29, 2015, the Partnership completed the exchange offer.

A wholly owned subsidiary of CenterPoint Energy guaranteed collection of the Partnership’s obligations under the 2019 Notes and the 2024 Notes, which expired on May 1, 2016.

As of March 31, 2016, the Partnership’s debt included EOIT’s $250 million 6.25% senior notes due March 2020 (the EOIT Senior Notes). The EOIT Senior Notes have a $22 million unamortized premium at March 31, 2016, resulting in an effective interest rate of 5.7%, during the three months ended March 31, 2016. These senior notes do not contain any financial covenants other than a limitation on liens. This limitation on liens is subject to certain exceptions and qualifications.

Financing Costs

Unamortized debt expense of $17 million and $18 million as of March 31, 2016 and December 31, 2015, respectively, is classified as either a reduction to Long-Term Debt or 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 $21 million and $23 million at March 31, 2016 and December 31, 2015, respectively, is classified as either Long-Term Debt or Short-Term Debt, consistent with the underlying debt instrument, in the Condensed Consolidated Balance Sheets and is being amortized over the life of the respective debt.

 As of March 31, 2016, the Partnership and EOIT were in compliance with all of their debt agreements, including financial covenants.

 

17


(8) Fair Value Measurements
 
Certain assets and liabilities are recorded at fair value in the Condensed Consolidated Balance Sheets and are categorized based upon the level of judgment associated with the inputs used to measure their value. Hierarchical levels, as defined below and directly related to the amount of subjectivity associated with the inputs to fair valuations of these assets and liabilities are as follows:
 
Level 1: Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. Instruments classified as Level 1 include natural gas futures, swaps and options transactions for contracts traded on the NYMEX and settled through a NYMEX clearing broker.
 
Level 2: Inputs, other than quoted prices included in Level 1, are observable for the asset or liability, either directly or indirectly. Level 2 inputs include quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities that are generally included in this category are derivatives with fair values based on inputs from actively quoted markets. Instruments classified as Level 2 include over-the-counter NYMEX natural gas swaps, natural gas basis swaps and natural gas purchase and sales transactions in markets such that the pricing is closely related to the NYMEX pricing, and over-the-counter WTI crude swaps for condensate sales.
 
Level 3: Inputs are unobservable for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. Unobservable inputs reflect the Partnership’s judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. The Partnership develops these inputs based on the best information available, including the Partnership’s own data.
 
The Partnership utilizes the market approach in determining the fair value of its derivative positions by using either NYMEX or WTI published market prices, independent broker pricing data or broker/dealer valuations. The valuations of derivatives with pricing based on NYMEX published market prices may be considered Level 1 if they are settled through a NYMEX clearing broker account with daily margining. Over-the-counter derivatives with NYMEX or WTI based prices are considered Level 2 due to the impact of counterparty credit risk. Valuations based on independent broker pricing or broker/dealer valuations may be classified as Level 2 only to the extent they may be validated by an additional source of independent market data for an identical or closely related active market. In certain less liquid markets or for longer-term contracts, forward prices are not as readily available. In these circumstances, contracts are valued using internally developed methodologies that consider historical relationships among various quoted prices in active markets that result in management’s best estimate of fair value. These contracts are classified as Level 3.
 
The Partnership determines the appropriate level for each financial asset and liability on a quarterly basis and recognizes transfers between levels at the end of the reporting period. For the period ended March 31, 2016, there were no transfers between Level 1, 2, and 3 investments.
 
The impact to the fair value of derivatives due to credit risk is calculated using the probability of default based on Standard & Poor’s Ratings Services and/or internally generated ratings. The fair value of derivative assets is adjusted for credit risk. The fair value of derivative liabilities is adjusted for credit risk only if the impact is deemed material.

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

18


The following tables summarize the Partnership’s assets and liabilities that are measured at fair value on a recurring basis as of March 31, 2016 and December 31, 2015:
 
March 31, 2016
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)
7

 

 
11

 
$
7

Unobservable inputs (Level 3)
2

 
3

 

 
$

Total fair value
26

 
6

 
11

 
$
7

Netting adjustments
(5
)
 
(5
)
 

 
$

Total
$
21

 
$
1

 
$
11

 
$
7


December 31, 2015
Commodity Contracts
 
Gas Imbalances (1)
 
Assets
 
Liabilities
 
Assets (2)
 
Liabilities (3)
 
(In millions)
Quoted market prices in active market for identical assets (Level 1)
$
17

 
$
3

 
$

 
$

Significant other observable inputs (Level 2)
10

 

 
17

 
20

Unobservable inputs (Level 3)
4

 

 

 

Total fair value
31

 
3

 
17

 
20

Netting adjustments
(3
)
 
(3
)
 

 

Total
$
28

 
$

 
$
17

 
$
20

______________________
(1)
The Partnership uses the market approach to fair value its gas imbalance assets and liabilities at individual, or where appropriate an average of, current market indices applicable to the Partnership’s operations, not to exceed net realizable value. Gas imbalances held by EOIT are valued using an average of the Inside FERC Gas Market Report for Panhandle Eastern Pipe Line Co. (Texas, Oklahoma Mainline), ONEOK (Oklahoma) and ANR Pipeline (Oklahoma) indices. There were no netting adjustments as of March 31, 2016 and December 31, 2015.
(2)
Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $10 million and $6 million at March 31, 2016 and December 31, 2015, 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 $0 million and $5 million at March 31, 2016 and December 31, 2015, 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.

Changes in Level 3 Fair Value Measurements

The following tables provides a reconciliation of changes in the fair value of our Level 3 commodity contracts between the periods presented.
 
Commodity Contracts
 
Natural gas liquids
 financial futures/swaps
 
(In millions)
Balance as of December 31, 2015
$
4

Losses included in earnings
(4
)
Settlements
(1
)
Balance as of March 31, 2016
$
(1
)


19


Quantitative Information on Level 3 Fair Value Measurements

The Partnership utilizes the market approach to measure the fair value of our commodity contracts. The significant unobservable inputs used in this approach to fair value are longer dated price quotes. Our sensitivity to these longer dated forward curve prices are presented in the table below. Significant changes in any of those inputs in isolation would result in significantly different fair value measurements, depending on our short or long position in contracts.

 
March 31, 2016
Product Group
Fair Value
 
Forward Curve Range
 
(In millions)
 
(Per gallon)
Natural gas liquids
$
(1
)
 
$0.441 - $0.495

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 March 31, 2016 and December 31, 2015.
 
 
March 31, 2016
 
December 31, 2015
 
Carrying Amount
 
Fair Value
 
Carrying Amount
 
Fair Value
 
(In millions)
Long-Term Debt
 
 
 
 
 
 
 
Long-term notes payableaffiliated companies (Level 2)
$

 
$

 
$
363

 
$
350

Revolving Credit Facility (Level 2)(1)
715

 
715

 
310

 
310

2015 Term Loan Agreement (Level 2)
450

 
450

 
450

 
450

EOIT Senior Notes (Level 2)
272

 
218

 
273

 
280

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

 
1,302

 
1,650

 
1,255

___________________
(1)
Borrowing capacity is reduced by our borrowings outstanding under the commercial paper program. There was zero and $236 million of commercial paper outstanding as of March 31, 2016 and December 31, 2015, respectively.

The fair value of the Partnership’s Long-term notes payable—affiliated companies, Revolving Credit Facility, and 2015 Term Loan Agreement, along with the EOIT Senior Notes and Enable Midstream Partners, LP 2019, 2024 and 2044 Notes, is based on quoted market prices and estimates of current rates available for similar issues with similar maturities and is classified as Level 2 in the fair value hierarchy.
 
Non-Financial Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
 
Certain assets and liabilities are measured at fair value on a nonrecurring basis; that is, the assets and liabilities are not measured at fair value on an ongoing basis, but are subject to fair value adjustments in certain circumstances (e.g., when there is evidence of impairment).

As of March 31, 2016, no material fair value adjustments or fair value measurements were required for these non-financial assets or liabilities.


(9) Derivative Instruments and Hedging Activities
 
The Partnership is exposed to certain risks relating to its ongoing business operations. The primary risk managed using derivative instruments is commodity price risk. The Partnership is also exposed to credit risk in its business operations.
 

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Commodity Price Risk
 
The Partnership has used forward physical contracts, commodity price swap contracts and commodity price option features to manage the Partnership’s commodity price risk exposures in the past. Commodity derivative instruments used by the Partnership are as follows:
NGL put options, NGL futures and swaps, and WTI crude futures and swaps for condensate sales are used to manage the Partnership’s NGL and condensate exposure associated with its processing agreements;
natural gas futures and swaps are used to manage the Partnership’s keep-whole natural gas exposure associated with its processing operations and the Partnership’s natural gas exposure associated with operating its gathering, transportation and storage assets; and
natural gas futures and swaps, natural gas options and natural gas commodity purchases and sales are used to manage the Partnership’s natural gas exposure associated with its storage and transportation contracts and asset management activities.

Normal purchases and normal sales contracts are not recorded in Other Assets or Liabilities in the Condensed Consolidated Balance Sheets and earnings are recognized and recorded in the period in which physical delivery of the commodity occurs. Management applies normal purchases and normal sales treatment to: (i) commodity contracts for the purchase and sale of natural gas used in or produced by the Partnership’s operations and (ii) commodity contracts for the purchase and sale of NGLs produced by the Partnership’s gathering and processing business.
 
The Partnership recognizes its non-exchange traded derivative instruments as Other Assets or Liabilities in the Condensed Consolidated Balance Sheets at fair value with such amounts classified as current or long-term based on their anticipated settlement. Exchange traded transactions are settled on a net basis daily through margin accounts with a clearing broker and, therefore, are recorded at fair value on a net basis in Other Current Assets in the Condensed Consolidated Balance Sheets.
 
As of March 31, 2016 and December 31, 2015, 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.


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As of March 31, 2016 and December 31, 2015, the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes:

 
March 31, 2016
 
December 31, 2015
  
Gross Notional Volume
 
Purchases
 
Sales
 
Purchases
 
Sales
Natural gas— TBtu(1)
 
 
 
 
 
 
 
Physical purchases/sales

 
48

 
2

 
51

Financial fixed futures/swaps
3

 
44

 
1

 
37

Financial basis futures/swaps
5

 
47

 
4

 
38

Crude oil (for condensate)— MBbl(2)
 
 
 
 
 
 
 
Financial Futures/swaps

 
460

 

 
506

Natural gas liquids— MBbl(3)
 
 
 
 
 
 
 
Financial Futures/swaps

 
1,551

 
75

 
1,011

____________________
(1)
As of March 31, 2016, 86.1% of the natural gas contracts had durations of one year or less and 13.9% had durations of more than one year and less than two years. As of December 31, 2015, 97.7% of the natural gas contracts had durations of one year or less and 2.3% had durations of more than one year and less than two years.
(2)
As of March 31, 2016, 93.5% of the condensate contracts had durations of one year or less and 6.5% had durations of more than one year and less than two years. As of December 31, 2015, 100% of the crude oil (for condensate) contracts had durations of one year or less.
(3)
As of March 31, 2016, 85.5% of the natural gas liquids contracts had durations of one year or less and 14.5% had durations of more than one year and less than two years. As of December 31, 2015, 100% of the natural gas liquid contracts had durations of one year or less.

Balance Sheet Presentation Related to Derivative Instruments
 
The fair value of the derivative instruments that are presented in the Partnership’s Condensed Consolidated Balance Sheets as of March 31, 2016 and December 31, 2015 that were not designated as hedging instruments for accounting purposes are as follows:
 
 
 
 
March 31, 2016
 
December 31, 2015
 
 
 
Fair Value
Instrument
Balance Sheet Location
 
Assets
 
Liabilities
 
Assets
 
Liabilities
 
 
 
(In millions)
Natural gas
 
 
 
 
 
 
 
Financial futures/swaps
Other Current
 
$
18

 
$
3

 
$
17

 
$
3

Physical purchases/sales
Other Current
 

 

 
1

 

Crude Oil (for condensate)
 
 
 
 
 
 
 
 
 
Financial futures/swaps
Other Current
 
6

 

 
9

 

Natural gas liquids
 
 
 
 
 
 
 
 
 
Financial Futures/swaps
Other Current
 
2

 
3

 
4

 

Total gross derivatives (1)
 
 
$
26

 
$
6

 
$
31

 
$
3

_____________________
(1)
See Note 8 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Condensed Consolidated Balance Sheets as of March 31, 2016 and December 31, 2015.


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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 months ended March 31, 2016 and 2015.
 
  
Amounts Recognized in Income
 
Three Months Ended 
 March 31,
 
2016
 
2015
 
(In millions)
Natural gas financial futures/swaps gains (losses)
$
10

 
$
7

Natural gas physical purchases/sales gains (losses)
(4
)
 
(4
)
Crude Oil (for condensate) financial futures/swaps gains (losses)
1

 
4

Natural gas liquids financial futures/swaps gains (losses)
(4
)
 

Total
$
3

 
$
7

 
For derivatives not designated as hedges in the tables above, amounts recognized in income for the periods ended March 31, 2016 and 2015, if any, are reported in Product Sales.
 
Credit-Risk Related Contingent Features in Derivative Instruments
 
Based upon the Partnership’s senior unsecured debt rating with Moody’s Investors Services or Standard & Poor’s Ratings Services, the Partnership could be required to provide credit assurances to third parties, which could include letters of credit or cash collateral to satisfy its obligation under its financial and physical contracts relating to derivative instruments that are in a net liability position. As of March 31, 2016, under these obligations, no cash collateral has been posted. However, based on positions as of March 31, 2016, approximately $1 million of additional collateral may be required to be posted by the Partnership.


(10) Supplemental Disclosure of Cash Flow Information

The following table provides information regarding supplemental cash flow information:

 
Three Months Ended 
 March 31,
 
2016
 
2015
 
(In millions)
Supplemental Disclosure of Cash Flow Information:
 
 
 
Cash Payments:
 
 
 
Interest, net of capitalized interest
$
15

 
$
9

Income taxes, net of refunds
1

 

Non-cash transactions:


 


Accounts payable related to capital expenditures
42

 
51



(11) Related Party Transactions
 
The material related party transactions with CenterPoint Energy, OGE Energy and their respective subsidiaries are summarized below. There were no material related party transactions with other affiliates.
 

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The Partnership’s revenues from affiliated companies accounted for 9% and 8% of revenues during the three months ended March 31, 2016 and 2015, respectively. Amounts of revenues from affiliated companies included in the Partnership’s Condensed Consolidated Statements of Income are summarized as follows:
 
 
Three Months Ended 
 March 31,
 
2016
 
2015
 
(In millions)
Gas transportation and storage service revenue — CenterPoint Energy
$
33

 
$
33

Natural gas product sales — CenterPoint Energy
1

 
6

Gas transportation and storage service revenue — OGE Energy
9

 
9

Natural gas product sales — OGE Energy 
1

 
3

Total revenues — affiliated companies
$
44

 
$
51


Amounts of natural gas purchased from affiliated companies included in the Partnership’s Condensed Consolidated Statements of Income are summarized as follows:
 
 
Three Months Ended 
 March 31,
 
2016
 
2015
 
(In millions)
Cost of natural gas purchases — CenterPoint Energy
$

 
$
1

Cost of natural gas purchases — OGE Energy
2

 
3

Total cost of natural gas purchases — affiliated companies
$
2

 
$
4


Prior to May 1, 2013, the Partnership had employees and reflected the associated benefit costs directly and not as corporate services. Under the terms of the MFA, effective May 1, 2013 the Partnership’s employees were seconded by CenterPoint Energy and OGE Energy, and the Partnership began reimbursing each of CenterPoint Energy and OGE Energy for all employee costs under the seconding agreements until the seconded employees transition from CenterPoint Energy and OGE Energy to the Partnership. The Partnership transitioned seconded employees from CenterPoint Energy and OGE Energy to the Partnership effective January 1, 2015, except for certain employees who are participants under OGE Energy’s defined benefit and retiree medical plans, who will remain seconded to the Partnership, subject to certain termination rights of the Partnership and OGE 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 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 2016 are $7 million and $3 million, respectively.


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Table of Contents

Amounts charged to the Partnership by affiliates for seconded employees and corporate services, included primarily in Operation and maintenance and General and administrative expenses in the Partnership’s Condensed Consolidated Statements of Income are as follows:
 
 
Three Months Ended 
 March 31,
 
2016
 
2015
 
(In millions)
Corporate Services — CenterPoint Energy
2

 
4

Seconded Employee Costs — OGE Energy
9

 
9

Corporate Services — OGE Energy
2

 
3

Total corporate services and seconded employees expense
$
13

 
$
16


The Partnership had outstanding long-term notes payable—affiliated companies to CenterPoint Energy at December 31, 2015 of $363 million, which were scheduled to mature in 2017. On February 18, 2016, in connection with the Private Placement of the Series A Preferred Units, the Partnership redeemed the $363 million of notes payable—affiliated companies payable to a subsidiary of CenterPoint Energy.

The Partnership recorded affiliated interest expense to CenterPoint Energy on notes payable—affiliated companies of $1 million and $2 million during the three months ended March 31, 2016 and 2015, respectively.

On February 18, 2016, the Partnership completed the private placement, with CenterPoint Energy, of 14,520,000 Series A Preferred Units representing limited partner interests in the Partnership for a cash purchase price of $25.00 per Series A Preferred Unit, resulting in proceeds of $362 million, net of issuance costs. See Note 4 for further discussion.


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


(13) Equity Based Compensation

The following table summarizes the Partnership’s compensation expense for the three months ended March 31, 2016 and 2015 related to performance units, restricted units, and phantom units for the Partnership’s employees and independent directors:

 
Three Months Ended 
 March 31,
 
2016
 
2015
 
(In millions)
Performance units
$
1

 
$
1

Restricted units
1

 
2

Phantom units

 

Total compensation expense
$
2

 
$
3


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Units Outstanding

The Partnership periodically grants performance units, restricted units, and phantom units to certain employees under the Enable Midstream Partners, LP Long Term Incentive Plan. A summary of the activity for the Partnership’s performance units, restricted units, and phantom units applicable to the Partnership’s employees at March 31, 2016 and changes during 2016 are shown in the following table.

 
Performance Units
 
Restricted Units
 
Phantom Units
  
Number
of Units
 
Weighted Average Grant-Date Fair Value, Per Unit
 
Number
of Units
 
Weighted Average Grant-Date Fair Value, Per Unit
 
Number
of Units
 
Weighted Average Grant-Date Fair Value, Per Unit
 
(In millions, except unit data)
Units Outstanding at December 31, 2015
814,510

 
$
20.67

 
581,772

 
$
21.04

 
9,817

 
$
12.70

Granted

 

 

 

 

 

Vested
(1,685
)
 
20.72

 
(78,375
)
 
22.58

 

 

Forfeited
(44,408
)
 
17.69

 
(49,834
)
 
19.26

 

 

Units Outstanding at March 31, 2016
768,417

 
$
20.84

 
453,563

 
$
20.97

 
9,817

 
$
12.70

 Aggregate Intrinsic Value of Units Outstanding at March 31, 2016
$
5

 
 
 
$
3

 
 
 
$

 
 

Unrecognized Compensation Cost

A summary of the Partnership’s unrecognized compensation cost for its non-vested performance units, restricted units, and phantom units, and the weighted-average periods over which the compensation cost is expected to be recognized are shown in the following table.
 
March 31, 2016
 
Unrecognized Compensation Cost
(In millions)
 
Weighted Average to be Recognized
(In years)
Performance Units
$
9

 
1.80
Restricted Units
8

 
1.78
Phantom Units

 
0.24
Total
$
17

 
 

As of March 31, 2016, there were 11,149,474 units available for issuance under the long term incentive plan.


(14) Reportable Segments
 
The Partnership’s determination of reportable segments considers the strategic operating units under which it manages sales, allocates resources and assesses performance of various products and services to 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 2015 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.
 

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Financial data for reportable segments are as follows:
 
Three Months Ended March 31, 2016
Gathering  and
Processing
 
Transportation
and Storage(1)
 
Eliminations
 
Total
 
(In millions)
Revenues
$
333

 
$
246

 
$
(70
)
 
$
509

Cost of natural gas and natural gas liquids
165

 
99

 
(69
)
 
195

Operation and maintenance, General and administrative
75

 
41

 
(1
)
 
115

Depreciation and amortization
49

 
32

 

 
81

Impairments

 

 

 

Taxes other than income tax
8

 
7

 

 
15

Operating income
$
36

 
$
67

 
$

 
$
103

Total assets
$
7,543

 
$
4,888

 
$
(1,182
)
 
$
11,249

Capital expenditures
$
121

 
$
9

 
$

 
$
130

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended March 31, 2015
Gathering and
Processing
 

Transportation
and Storage(1)
 
Eliminations
 
Total
 
(In millions)
Revenues
$
401

 
$
308

 
$
(93
)
 
$
616

Cost of natural gas and natural gas liquids
222

 
163

 
(93
)
 
292

Operation and maintenance, General and administrative
76

 
54

 

 
130

Depreciation and amortization
43

 
30

 

 
73

Impairments

 

 

 

Taxes other than income tax
8

 
9

 

 
17

Operating income
$
52

 
$
52

 
$

 
$
104

Total assets as of December 31, 2015
$
7,536

 
$
4,976

 
$
(1,286
)
 
$
11,226

Capital expenditures
$
215

 
$
24

 
$

 
$
239

_____________________
(1)
See Note 6 for discussion regarding ownership interests in SESH and related equity earnings included in the Transportation and Storage segment for the three months ended March 31, 2016 and 2015.



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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, 2015, 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 services primarily to natural gas producers, utilities and industrial customers.

Our natural gas gathering and processing assets are located in Oklahoma, Texas, Arkansas, Louisiana and Mississippi and serve natural gas production in the Anadarko, Arkoma and Ark-La-Tex basins. We also own a crude oil gathering business located in North Dakota to serve shale development in the Bakken Shale formation of the Williston Basin. 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

The Bradley II Plant, a 200 MMcf/d cryogenic processing facility located in the Anadarko basin, is under construction and estimated to be in service in the second quarter of 2016.

The Partnership has commenced construction on the Wildhorse Plant, a 200 MMcf/d cryogenic processing facility located in the Anadarko basin, which is estimated to be in service no sooner than the second half of 2017.

Series A Preferred Units

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


Results of Operations
 
The following tables summarize the key components of our results of operations for the three months ended March 31, 2016 and 2015.
 

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Table of Contents

Three Months Ended March 31, 2016
Gathering and
Processing
 
Transportation
and Storage
 
Eliminations
 
Enable
Midstream
Partners, LP
 
(In millions)
Revenues
$
333

 
$
246

 
$
(70
)
 
$
509

Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)
165

 
99

 
(69
)
 
195

Gross margin (1)
168

 
147

 
(1
)
 
314

Operation and maintenance, General and administrative
75

 
41

 
(1
)
 
115

Depreciation and amortization
49

 
32

 

 
81

Taxes other than income tax
8

 
7

 

 
15

Operating income
$
36

 
$
67

 
$

 
$
103

Equity in earnings of equity method affiliates
$

 
$
7

 
$

 
$
7

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

 
$
308

 
$
(93
)
 
$
616

Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)
222

 
163

 
(93
)
 
292

Gross margin (1)
179

 
145

 

 
324

Operation and maintenance, General and administrative
76

 
54

 

 
130

Depreciation and amortization
43

 
30

 

 
73

Taxes other than income tax
8

 
9

 

 
17

Operating income
$
52

 
$
52

 
$

 
$
104

Equity in earnings of equity method affiliates
$

 
$
7

 
$

 
$
7

 _____________________
(1)
Gross margin is defined and reconciled to its most directly comparable financial measures calculated and presented below under the caption Non-GAAP Financial Measures.


 
Three Months Ended 
 March 31,
 
2016

2015
Operating Data:

Gathered volumes—TBtu
278


286

Gathered volumes—TBtu/d
3.05


3.18

Natural gas processed volumes—TBtu
162


151

Natural gas processed volumes—TBtu/d
1.78


1.68

NGLs produced—MBbl/d(1)
73.47


65.00

NGLs sold—MBbl/d(1)(2)
76.31


67.62

Condensate sold—MBbl/d
6.45


5.96

Crude Oil - Gathered volumes—MBbl/d
28.85


6.72

Transported volumes—TBtu
465


514

Transportation volumes—TBtu/d
5.11


5.72

Interstate firm contracted capacity—Bcf/d
7.17


7.82

Intrastate average deliveries—TBtu/d
1.68


1.84

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


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Table of Contents

Gathering and Processing

Three months ended March 31, 2016 compared to three months ended March 31, 2015. Our gathering and processing segment reported operating income of $36 million in the three months ended March 31, 2016 compared to operating income of $52 million in the three months ended March 31, 2015. Operating income decreased $16 million primarily from decreased gross margin of $11 million, and an increase in depreciation and amortization of $6 million, partially offset by a decrease in operation and maintenance expenses of $1 million, during the three months ended March 31, 2016.

Our gathering and processing segment gross margin decreased $11 million primarily due to a decrease in processing margins of $9 million resulting from lower average natural gas liquids prices and lower processed volumes in the Ark-La-Tex basin offset by higher processed volumes in the Anadarko basin, combined with a decrease in unrealized gains on condensate and NGL derivatives of $8 million. Additionally, gathering margins decreased $6 million due to reduced sales on natural gas length due to lower average natural gas prices, and lower revenues on third party measurement and communication services of $1 million. These decreases were partially offset by an increase in the imbalance receivable of $9 million associated with our annual fuel rate determination and an increase in gathering fees of $3 million as a result of higher gathered volumes in the Anadarko basin. Also, crude oil gathering increased $4 million due to higher volumes in the Williston basin, offset by a decrease of $3 million from one-time project reimbursements during the three months ended March 31, 2016.

Our gathering and processing segment operation and maintenance and general and administrative expenses decreased $1 million primarily due to a decrease in payroll related costs of $3 million and lower severance charges related to 2015 workforce reductions of $2 million. These decreases were partially offset by an increase in allowance for doubtful accounts of $3 million and higher losses on sale of assets of $1 million.

Our gathering and processing segment depreciation and amortization increased $6 million due to additional assets placed in service.

Transportation and Storage

Three months ended March 31, 2016 compared to three months ended March 31, 2015. Our transportation and storage segment reported operating income of $67 million in the three months ended March 31, 2016 compared to operating income of $52 million in the three months ended March 31, 2015. Operating income increased $15 million primarily resulting from an increase in gross margin of $2 million, a decrease of $13 million in operation and maintenance and general and administrative expenses, and a decrease in taxes other than income tax of $2 million, partially offset by a $2 million increase in depreciation and amortization expenses for the three months ended March 31, 2016.

Our transportation and storage segment gross margin increased $2 million primarily due to higher margins of $8 million related to unrealized gains on natural gas derivatives and an increase of $1 million in gains on system optimization activities. These increases were partially offset by lower firm transportation revenues of $5 million and decreased margins from off-system transportation revenues of $2 million for the three months ended March 31, 2016.

Our transportation and storage segment operation and maintenance and general and administrative expenses decreased $13 million due to a decrease in payroll related costs of $7 million, lower integration costs of $4 million, and lower severance charges related to 2015 workforce reductions of $2 million.

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

Our transportation and storage segment taxes other than income tax decreased $2 million due to reduced ad valorem taxes.

Our transportation and storage segment recorded equity in earnings of equity method affiliates of $7 million for each of the three months ended March 31, 2016 and 2015 from our interest in SESH.


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Table of Contents

Condensed Consolidated Interim Information
 
 
Three Months Ended 
 March 31,
 
2016
 
2015
 
(In millions)
Operating Income
$
103

 
$
104

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

 
7

Other, net

 
1

Total Other Income (Expense)
(16
)
 
(12
)
Income Before Income Taxes
87

 
92

Income tax expense
1

 
1

Net Income
$
86

 
$
91

Less: Net income attributable to noncontrolling interest

 

Less: Series A Preferred Unit distributions

 

Net Income attributable to common and subordinated units
$
86

 
$
91


 
Three Months Ended 
 March 31,
 
2016
 
2015
 
(In millions)
Other Financial Data:
 
 
 
Gross Margin (1)
$
314

 
$
324

Adjusted EBITDA (1)
215

 
207

Distributable cash flow (1)
174

 
145

 _____________________
(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 Measures within this Part I, Item 2.

 
Three Months Ended March 31, 2016 compared to Three Months Ended March 31, 2015

Net Income attributable to the Partnership. We reported net income attributable to the Partnership of $86 million in the three months ended March 31, 2016 compared to net income attributable to the Partnership of $91 million in the three months ended March 31, 2015. The decrease in net income attributable to the Partnership of $5 million was primarily attributable to an increase in interest expense of $3 million, a decrease in operating income of $1 million and a decrease in other income and expense of $1 million in the three months ended March 31, 2016.

Interest Expense. Interest expense increased $3 million due to higher interest rates on the Partnership’s outstanding debt and an increase in the amount of outstanding debt.


Non-GAAP Financial Measures

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

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


Three Months Ended 
 March 31,

2016

2015