Document
Table of Contents

 
 
 
 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
 ________________________________________________________________
FORM 10-K
 ________________________________________________________________
þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES AND EXCHANGE ACT OF 1934
For the fiscal year ended December 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
 ________________________________________________________________
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Name of each exchange on which registered
Common Units Representing Limited Partner Interests
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. þ  Yes  o  No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. o  Yes   þ  No
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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨
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
The aggregate market value of the Common Units held by non-affiliates of the registrant, based upon the closing price of $13.51 per common unit on June 30, 2016, was approximately $1,047 million.
As of February 1, 2017, there were 224,532,959 common units and 207,855,430 subordinated units outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
None
 
 
 
 
 


Table of Contents


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

 



 




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GLOSSARY
 
2011 Pipeline Safety Act.
Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011.
Adjusted EBITDA.
Please read “Measures We Use to Evaluate Results of Operations” under Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operation” for the definition.
Adjusted interest expense.
Please read “Measures We Use to Evaluate Results of Operations” under Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operation” for the definition.
APSA.
Accountable Pipeline Safety and Partnership Act of 1996.
ArcLight.
ArcLight Capital Partners, LLC, a Delaware limited liability company, its affiliated entities ArcLight Energy Partners Fund V, L.P., ArcLight Energy Partners Fund IV, L.P., Bronco Midstream Partners, L.P., Bronco Midstream Infrastructure LLC and Enogex Holdings LLC, and their respective general partners and subsidiaries.
ASU.
Accounting Standards Update.
Atoka.
Atoka Midstream LLC, in which the Partnership owns a 50% interest as of December 31, 2016, which provides gathering and processing services.
Barrel.
42 U.S. gallons of petroleum products.
Bbl.
Barrel.
Bbl/d.
Barrels per day.
Bcf.
Billion cubic feet.
Bcf/d.
Billion cubic feet per day.
Board of Directors.
The board of directors of Enable GP, LLC.
Btu.
British thermal unit. When used in terms of volume, Btu refers to the amount of natural gas required to raise the temperature of one pound of water by one degree Fahrenheit at one atmospheric pressure.
CAA.
Clean Air Act, as amended.
CenterPoint Energy.
CenterPoint Energy, Inc., a Texas corporation, and its subsidiaries.
CERCLA.
Comprehensive Environmental Response, Compensation and Liability Act of 1980.
CFTC.
Commodity Futures Trading Commission.
CO2e.
Carbon dioxide equivalent.
Code.
The Internal Revenue Code of 1986, as amended.
Condensate.
A natural gas liquid with a low vapor pressure, mainly composed of propane, butane, pentane and heavier hydrocarbon fractions.
DCF.
Please read “Measures We Use to Evaluate Results of Operations” under Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operation” for the definition.
Delaware Act.
Delaware Revised Uniform Limited Partnership Act.
DHS.
Department of Homeland Security.
Distribution coverage ratio.
Please read “Measures We Use to Evaluate Results of Operations” under Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operation” for the definition.
Dodd-Frank Act.
Dodd-Frank Wall Street Reform and Consumer Protection Act.
DOT.
Department of Transportation.
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, Missouri and Kansas.
EIA.
Energy Information Administration.
EIIT.
Enable Illinois Intrastate Transmission, LLC, a wholly owned subsidiary of the Partnership that operates a 20-mile intrastate pipeline that provides natural gas transportation and storage services to customers in Illinois.
Enable GP.
Enable GP, LLC, a Delaware limited liability company and the general partner of Enable Midstream Partners, LP.

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Enable Midstream Services.
Enable Midstream Services, LLC, a wholly owned subsidiary of Enable Midstream Partners, LP.
Enogex.
Enogex LLC, a Delaware limited liability company, and its subsidiaries.
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.
ESA.
Endangered Species Act.
EPA.
Environmental Protection Agency.
EPAct of 2005.
Energy Policy Act of 2005.
ERISA.
Employee Retirement Income Security Act of 1974.
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.
GHG.
Greenhouse gas.
Gross margin.
Please read “Measures We Use to Evaluate Results of Operations” under Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operation” for the definition.
HCA.
High-consequence area.
HLPSA.
Hazardous Liquid Pipeline Safety Act of 1979.
Hinshaw pipeline.
A pipeline that is exempt from FERC’s NGA regulation if its operations are within a single state, if any gas received from interstate sources is received within the state and if its service is regulated by the state commission.
ICA.
Interstate Commerce Act.
IPO.
Initial public offering of Enable Midstream Partners, LP.
IRS.
Internal Revenue Service.
LDC.
Local distribution company involved in the delivery of natural gas to consumers within a specific geographic area.
Lean gas.
Natural gas that is primarily methane without NGLs.
LIBOR.
London Interbank Offered Rate.
LNG.
Liquefied natural gas.
MAOP.
Maximum allowable operating pressure for gas pipelines.
MBbl.
Thousand barrels.
MBbl/d.
Thousand barrels per day.
MFA.
Master Formation Agreement dated as of March 14, 2013.
MMcf.
Million cubic feet of natural gas.
MMBtu.
Million British thermal units.
MMcf/d.
Million cubic feet per day.
MOP.
Maximum operating pressure for hazardous liquid pipelines.
MRT.
Enable Mississippi River Transmission, LLC, a wholly owned subsidiary of the Partnership that operates a 1,600-mile interstate pipeline that provides natural gas transportation and storage services principally in Texas, Arkansas, Louisiana, Missouri and Illinois.
NEPA.
National Environmental Policy Act.
NGA.
Natural Gas Act of 1938.
NGPA.
Natural Gas Policy Act of 1978.

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NGPSA.
Natural Gas Pipeline Safety Act of 1968.
NGLs.
Natural gas liquids, which are the hydrocarbon liquids contained within natural gas including condensate.
NYMEX.
New York Mercantile Exchange.
NYSE.
New York Stock Exchange.
OCC.
Oklahoma Corporation Commission.
OGE Energy.
OGE Energy Corp., an Oklahoma corporation, and its subsidiaries.
OPA.
Oil Pollution Act of 1990.
OSHA.
Occupational Safety and Health Act of 1970.
Partnership.
Enable Midstream Partners, LP, and its subsidiaries.
Partnership Agreement.
Fourth Amended and Restated Agreement of Limited Partnership of Enable Midstream Partners, LP dated as of June 22, 2016.
PDO.
Petition for a Declaratory Order. Petition filed with FERC to seek regulatory assurances for key terms of service offered during an open season.
PHMSA.
Pipeline and Hazardous Materials Safety Administration.
PIPES Act.
Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006.
PSA.
Pipeline Safety Act of 1992.
PSIA.
Pipeline Safety Improvement Act of 2002.
PVIR.
Preventable Vehicle Incident Rate.
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.
RCRA.
Resource Conservation and Recovery Act of 1976.
Revolving Credit Facility
$1.75 billion senior unsecured revolving credit facility
RICE MACT.
Reciprocating internal combustion engines maximum achievable control technology.
Rich gas.
Natural gas containing higher concentrations of NGLs.
SCOOP.
South Central Oklahoma Oil Province.
SDWA.
Safe Drinking Water Act.
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 as of December 31, 2016, that operates an approximately 290-mile interstate natural gas pipeline from Perryville, Louisiana to southwestern Alabama near the Gulf Coast.
Sponsors.
CenterPoint Energy and OGE Energy.
STACK
Sooner Trend Anadarko Basin Canadian and Kingfisher Counties.
Superfund.
Comprehensive Environmental Response, Compensation and Liability Act of 1980.
TBtu.
Trillion British thermal units.
TBtu/d.
Trillion British thermal units per day.
Tcf.
Trillion cubic feet of natural gas.
Term Loan Agreements.
$450 million unsecured term loan agreement dated July 31, 2015 (2015 Term Loan Agreement) and $1.05 billion unsecured term loan agreement dated May 1, 2013 (2013 Term Loan Agreement).
TRIR.
Total Recordable Incident Rate.
WTI.
West Texas Intermediate.
2019 Notes.
$500 million 2.400% senior notes due 2019.
2024 Notes.
$600 million 3.900% senior notes due 2024.
2044 Notes.
$550 million 5.000% senior notes due 2044.

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FORWARD-LOOKING STATEMENTS
 
Some of the information in this report may contain forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. 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. Those risk factors and other factors noted throughout this report could cause our actual results to differ materially from those disclosed in any forward-looking statement. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:
changes in general economic conditions;
competitive conditions in our industry;
actions taken by our customers and competitors;
the supply and demand for natural gas, NGLs, crude oil and midstream services;
our ability to successfully implement our business plan;
our ability to complete internal growth projects on time and on budget;
the price and availability of debt and equity financing;
strategic decisions by CenterPoint Energy and OGE Energy regarding their ownership of us and our General Partner;
operating hazards and other risks incidental to transporting, storing, gathering and processing natural gas, NGLs, crude oil and midstream products;
natural disasters, weather-related delays, casualty losses and other matters beyond our control;
interest rates;
labor relations;
large customer defaults;
changes in the availability and cost of capital;
changes in tax status;
the effects of existing and future laws and governmental regulations;
changes in insurance markets impacting costs and the level and types of coverage available;
the timing and extent of changes in commodity prices;
the suspension, reduction or termination of our customers’ obligations under our commercial agreements;
disruptions due to equipment interruption or failure at our facilities, or third-party facilities on which our business is dependent;
the effects of future litigation; and
other factors set forth in this report and our other filings with the SEC.
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

Item 1. Business

Overview

Enable Midstream Partners, LP is a Delaware limited partnership formed in May 2013 by CenterPoint Energy, OGE Energy and ArcLight to own, operate and develop midstream energy infrastructure assets strategically located to serve our customers. We completed our IPO in April 2014, and we are traded on the NYSE under the symbol “ENBL.” Our general partner is owned by CenterPoint Energy and OGE Energy. In this report, the terms “Partnership” and “Registrant” as well as the terms “our,” “we,” “us” and “its,” are sometimes used as abbreviated references to Enable Midstream Partners, LP together with its consolidated subsidiaries.
 
Our assets and operations are organized into two reportable segments: (i) gathering and processing and (ii) transportation and storage. Our gathering and processing segment primarily provides natural gas and crude oil gathering and natural gas processing services to our producer customers. Our transportation and storage segment provides interstate and intrastate natural gas pipeline transportation and storage services primarily to our producer, power plant, LDC and industrial end-user customers.
 
Our natural gas gathering and processing assets are primarily located in Oklahoma, Texas, Arkansas and Louisiana and serve natural gas production in the Anadarko, Arkoma and Ark-La-Tex Basins. Our crude oil gathering assets are located in North Dakota and serve crude oil production in the Bakken Shale formation of the Williston Basin. Our natural gas transportation and storage assets consist primarily of an interstate pipeline system extending from western Oklahoma and the Texas Panhandle to Louisiana, an interstate pipeline system extending from Louisiana to Illinois, an intrastate pipeline system in Oklahoma and our investment in SESH, a pipeline extending from Louisiana to Alabama.

As of December 31, 2016, our portfolio of midstream energy infrastructure assets included:
approximately 12,900 miles of gathering pipelines;
14 major processing plants with 2.5 Bcf/d of processing capacity;
approximately 7,800 miles of interstate pipelines (including SESH);
approximately 2,200 miles of intrastate pipelines; and
eight natural gas storage facilities with 85.0 Bcf of storage capacity.
 
Our website address is www.enablemidstream.com. Documents and information on our website are not incorporated by reference in this report. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed with or furnished to the SEC are available, free of charge, on our website as soon as reasonably practicable after we electronically file or furnish such materials.


Our Business Strategies
 
Our primary business objective is to increase the cash available for distribution to our unitholders over time while maintaining our financial flexibility. We strive to meet this objective through the following strategies:

Capitalize on Organic Growth Opportunities Associated with Our Strategically Located Assets: We own and operate assets servicing four of the largest basins in the United States, including some of the most productive shale plays in these basins. We intend to grow our business by developing new midstream energy infrastructure projects to support new and existing customers in these areas.
Maintain Strong Customer Relationships to Attract New Volumes and Expand Beyond Our Existing Asset Footprint and Business Lines: Management believes that we have built a strong and loyal customer base through exemplary customer service and reliable project execution. We have invested in organic growth projects in support of our existing and new customers. We work to maintain and build relationships with key producers and suppliers in an effort to attract new volumes and expansion opportunities.
Continue to Minimize Direct Commodity Price Exposure Through Fee-Based Contracts: We continually seek ways to minimize our exposure to commodity price risk. Management believes that focusing on fee-based revenues reduces our direct commodity price exposure. We intend to maintain our focus on increasing the percentage of long-term, fee-based contracts with our customers.

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Grow Through Accretive Acquisitions and Disciplined Development. We continually evaluate potential acquisitions of complementary assets with the potential for attractive returns in new operating areas or midstream business lines. We will continue to analyze acquisition opportunities using disciplined financial and operating practices, including evaluating and managing risks to cash distributions.


Our Sponsors
 
CenterPoint Energy and OGE Energy each own a significant interest in us. As of December 31, 2016, CenterPoint Energy owned 54.1% of our common and subordinated units and 100% of our Series A Preferred Units, and OGE Energy owned 25.7% of our common and subordinated units. In addition, our sponsors own Enable GP, our general partner. As of December 31, 2016, CenterPoint Energy owned a 50% management interest and a 40% economic interest in our general partner, and OGE Energy owned a 50% management interest and a 60% economic interest in our general partner. Enable GP owns the non-economic general partner interest in us and all of our incentive distribution rights.

On February 18, 2016, we completed a private placement with CenterPoint Energy of 14,520,000 Series A Preferred Units for a cash purchase price of $25.00 per Series A Preferred Unit, resulting in proceeds of $362 million, net of issuance costs. For a further discussion regarding the Series A Preferred Units, see Note 5 of the Notes to Consolidated Financial Statements in Part II, Item 8. “Financial Statements and Supplementary Data.”

CenterPoint Energy (NYSE: CNP) is a public utility holding company whose operating subsidiaries provide electric transmission and distribution services and natural gas distribution services to customers primarily in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas.

OGE Energy (NYSE: OGE) is the parent company of Oklahoma Gas & Electric Company (OG&E), a regulated electric utility serving customers in Oklahoma and western Arkansas.

Our sponsors are customers of our transportation and storage business. For the year ended December 31, 2016, approximately 3% of our gross margin was derived from transportation and storage contracts with OG&E. For the year ended December 31, 2016, approximately 9% of our total gross margin was derived from transportation and storage contracts servicing LDCs owned by CenterPoint Energy.

In addition, our sponsors have entered into a number of agreements affecting us. For a more detailed description of our relationship and agreements with CenterPoint Energy and OGE Energy, please read Item 13. “Certain Relationships and Related Party Transactions.” Although management believes our relationships with CenterPoint Energy and OGE Energy are positive attributes, there can be no assurance that we will benefit from these relationships or that these relationships will continue.


Our Assets and Operations 

Our assets and operations are organized into two reportable segments: (i) gathering and processing and (ii) transportation and storage.
 
Gathering and Processing

We own and operate substantial natural gas and crude oil gathering and natural gas processing assets in five states. Our gathering and processing operations consist primarily of natural gas gathering and processing assets serving the Anadarko, Arkoma and Ark-La-Tex Basins and crude oil gathering assets serving the Williston Basin. We provide a variety of services to the active producers in our operating areas, including gathering, compressing, treating, and processing natural gas, fractionating NGLs, and gathering crude oil and produced water. We serve shale and other unconventional plays in the basins in which we operate, including the following:

Anadarko Basin (Oklahoma, Texas Panhandle). We have natural gas gathering and processing operations in those portions of the Anadarko Basin located in Oklahoma and the Texas Panhandle where, as of December 31, 2016, we served over 200 producers. Our operations include gathering and processing natural gas produced from the Granite Wash, Cleveland, Marmaton, Tonkawa, Cana Woodford, SCOOP, STACK and Mississippi Lime plays. The current focus of our Anadarko Basin gathering and processing operations is on liquids-rich gas.
 

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Arkoma Basin (Oklahoma, Arkansas). In the Arkoma Basin, our operations primarily serve the Woodford Shale play located in Oklahoma and the Fayetteville Shale play located in Arkansas. Our Arkoma Basin gathering and processing operations serve both liquids-rich and lean gas production. As of December 31, 2016, we served more than 70 producers in the Arkoma Basin.

Ark-La-Tex Basin (Arkansas, Louisiana and Texas). We have gathering and processing operations in the Ark-La-Tex Basin located in Arkansas, Louisiana and Texas. Our Ark-La-Tex gathering and processing operations primarily serve the Haynesville, Cotton Valley and the lower Bossier plays. As of December 31, 2016, we served over 110 producers in the Ark-La-Tex Basin where our gathering and processing operations provide service for both liquids-rich and lean gas production.

Williston Basin (North Dakota). In the Williston Basin, we have operations in the Bakken Shale that are located in North Dakota. The focus of our operations in the Bakken Shale is the gathering of crude oil and produced water for XTO Energy Inc. (XTO), an affiliate of ExxonMobil Corporation, with pipeline gathering systems in Dunn, McKenzie, Williams and Mountrail Counties of North Dakota.
enablegppptno1264a01.jpg
 
Please see “Note 18. Reportable Business Segments” included in “Item 8. Financial Statements and Supplementary Data—Notes to Audited Consolidated Financial Statements” for gathering and processing segment information related to Total Revenues, Operating Income and Total Assets.

Capacity volumes for our facilities are measured based on physical volume and stated in cubic feet (“Bcf” or “MMcf”). Throughput volumes are measured based on energy content and stated in British thermal units (“MMBtu” or “TBtu” ). A volume capacity of 100 MMcf generally correlates to volume capacity of 100,000 MMBtu. Crude oil and condensate are measured based on physical volume and stated in barrels (“MBbl”).     

Natural Gas Gathering and Processing. The following table sets forth certain information regarding our natural gas gathering and processing assets as of or for the year ended December 31, 2016:


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Asset/Basin
Approximate Length
(miles)
 
Approximate Compression
(Horsepower)
 
Average
Gathered
Volume
(TBtu/d)
 
Number of
Processing
Plants
 
Processing
Capacity
(MMcf/d)
 
NGLs
Produced
(MBbl/d)
 
Gross Acreage
Dedications
(in millions)
Anadarko Basin
8,000

 
710,900

 
1.65

 
11

 
1,845

 
65.19

 
4.8

Arkoma Basin
2,900

 
134,500

 
0.62

 
1

 
60

 
4.86

 
1.4

Ark-La-Tex Basin(1)
1,700

 
146,700

 
0.86

 
2

 
545

 
8.65

 
0.7

Total
12,600

 
992,100

 
3.13

 
14

 
2,450

 
78.70

 
6.9

____________________
(1)
Ark-La-Tex Basin assets also include 14,500 Bbl/d of fractionation capacity and 6,300 Bbl/d of ethane pipeline capacity, which are not listed in the table.

Our gathering assets include more than 12,600 miles of natural gas gathering pipelines as of December 31, 2016. Our natural gas gathering systems consist of networks of pipelines that collect natural gas from points at or near our customers’ wells for delivery to plants for processing or pipelines for transportation. Natural gas is moved from the receipt points to the delivery points on our gathering systems by the use of compression.

Our natural gas processing assets included 14 natural gas processing plants with 2,450 MMcf/d of inlet capacity as of December 31, 2016. Natural gas is comprised primarily of methane, but at the wellhead natural gas may contain varying amounts of NGLs. Our processing plants recover NGLs from natural gas and primarily deliver NGLs and natural gas to pipelines for transportation. The following table sets forth information with respect to our natural gas processing plants as of or for the year ended December 31, 2016:
 
Processing Plant
Year
Installed
 
 
Type of Plant
 
Average
Daily Inlet
Volumes
(MMcf/d)
 
Inlet
Capacity
(MMcf/d)
 
NGL Production Capacity (Bbl/d)(1)
Anadarko
 
 
 
 
 
 
 
 
 
 
Bradley II
2016
 
 
Cryogenic
 
65

 
200

 
28,000

Bradley
2015
 
 
Cryogenic
 
191

 
200

 
28,000

McClure
2013
 
 
Cryogenic
 
182

 
200

 
22,000

Wheeler
2012
 
 
Cryogenic
 
179

 
200

 
22,000

South Canadian
2011
 
 
Cryogenic
 
188

 
200

 
26,000

Clinton
2009
 
 
Cryogenic
 
124

 
120

 
14,000

Roger Mills
2008
 
 
Refrigeration
 
25

 
100

 

Canute
1996
 
 
Cryogenic
 
32

 
60

 
4,300

Cox City
1994
 
 
Cryogenic
 
118

 
180

 
14,500

Thomas
1981
 
 
Cryogenic
 
59

 
135

 
9,900

Calumet
1969
 
 
Lean Oil
 
68

 
250

 
8,000

Arkoma
 
 
 
 
 
 
 
 
 
 
Wetumka
1983
 
 
Cryogenic
 
33

 
60

 
5,000

Ark-La-Tex
 
 
 
 
 
 
 
 
 
 
Sligo(2) 
2004
 
 
Refrigeration
 
31

 
225

 
1,400

Waskom
1995
(3) 
 
Cryogenic
 
182

 
320

 
14,500

Total
 
 
 
 
 
1,477

 
2,450

 
197,600

____________________
(1)
Excludes condensate capacity.
(2)
Average daily inlet volumes and inlet capacity includes 18 MMcf/d and 25 MMcf/d, respectively, related to a separate cryogenic unit.
(3)
A processing plant has been in operation on the Waskom plant site since 1940. The Waskom plant was upgraded to cryogenic in 1995.

The natural gas gathering and processing assets in the Anadarko Basin include 11 processing plants, nine of which are interconnected through our super-header system. The super-header system is configured to facilitate the flow of natural gas across our operating areas in western Oklahoma and the Texas Panhandle to the Bradley, Bradley II, Cox City, Thomas, McClure, Calumet,

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Clinton, South Canadian and Wheeler processing plants. The super-header system allows us to optimize the utilization of the connected processing plants.

Crude Oil Gathering. As of December 31, 2016, we had approximately 175 miles of crude oil gathering pipelines and approximately 160 miles of produced water gathering pipelines in the Bakken Shale of the Williston Basin. Our crude oil gathering systems have a combined design capacity of 49.5 MBbl/d, and as of December 31, 2016, we had 0.2 million gross acres dedicated under a crude oil gathering agreement. For the year ended December 31, 2016, we had an average daily throughput of 25.0 MBbl/d of crude oil and an average daily throughput of 6.0 MBbl/d of produced water on our Bakken Shale gathering system.

Our Bakken Shale crude oil gathering assets are located in Dunn, McKenzie, Williams and Mountrail Counties in North Dakota. These systems were designed and built to serve the crude oil production of XTO in the area that they serve. On our systems, crude oil is received on crude oil gathering pipelines near our customer’s wells for delivery to third party transportation pipelines, and produced water is received by produced water gathering pipelines for delivery to third party disposal wells. We do not take title to crude oil or produced water gathered and we do not own or operate produced water disposal wells.

Delivery Points. Natural gas that is gathered, and when applicable, processed, is typically redelivered to our customers at interconnections with transportation pipelines. Our gathering lines interconnect with both our interstate and intrastate pipelines, as well as other interstate and intrastate pipelines, including the Acadian, ANR, ETC Tiger, Gulf Crossing, Gulf South, NGPL, Northern Natural, Panhandle Eastern, Regency, Southern Natural Gas, Tennessee Gas and Texas Eastern Transmission pipelines. These connections provide producers with access to a variety of natural gas market hubs.

Crude oil gathered on our Bakken Shale gathering systems in Dunn and McKenzie Counties is redelivered to our customers on the BakkenLink Pipeline, which provides access to rail transportation. Crude oil gathered on our Bakken Shale gathering systems in Williams and Mountrail Counties is redelivered to our customers on the Enbridge North Dakota Pipeline, which provides interstate transportation from North Dakota to Minnesota. We anticipate constructing interconnections between our gathering systems and other pipelines that will provide access to the Dakota Access Pipeline during 2017.
 
We typically purchase the NGLs produced at our processing plants, and most of the NGLs are delivered into third-party pipelines and transported to Conway, Kansas, or Mont Belvieu, Texas, where the NGLs are sold under contract or on the spot market. At our Cox City, Calumet and Wetumka plants, we operate depropanizers that allow us to extract propane from the NGL stream and sell propane to local markets. Additionally, we operate a fractionator at our Waskom plant and sell ethane, propane, butane and natural gasoline to local markets.
 
Customers. We generate revenues from producers in the basins in which we operate. For the year ended December 31, 2016, our top natural gas gathering and processing customers by gathered volumes were Continental Resources, Inc. (Continental), Vine Oil and Gas (Vine), GeoSouthern Energy Corporation (GeoSouthern), XTO, Apache Corporation (Apache), Tapstone Energy LLC (Tapstone), affiliates of Chesapeake Energy Corporation (Chesapeake), BP America Production Company (BP), Covey Park Energy LLC (Covey Park) and Marathon Oil Company (Marathon). For the year ended December 31, 2016, our top ten natural gas producer customers accounted for approximately 66% of our gathered natural gas volumes.
 
Our Bakken Shale gathering systems serve XTO. The rates and terms of service on our Bakken Shale crude oil gathering systems are regulated by FERC under the Interstate Commerce Act, but our Bakken Shale produced water gathering systems are not FERC regulated. As of December 31, 2016, XTO was our only customer on these systems.

Contracts. Our contracts typically provide for natural gas and crude oil gathering services that are fee-based and for natural gas processing arrangements that are fee-based, or percent-of-liquids, percent-of-proceeds or keep-whole based. For the year ended December 31, 2016, 46%, 46% and 8% of our inlet volumes were under processing arrangements that were fee-based, percent-of-proceeds or percent-of-liquids, and keep-whole, respectively. For the year ended December 31, 2016, 78% of our gathering and processing gross margin was fee-based, and the remaining 22% of our gathering and processing gross margin was primarily from sales of commodities, including natural gas, natural gas liquids and condensate received under percent-of-proceeds, percent-of-liquids and keep-whole arrangements.

In lean gas areas, such as the lean gas areas of the eastern Arkoma Basin and the Haynesville Shale of the Ark-La-Tex Basin, some of our natural gas gathering contracts contain minimum volume commitments from our customers. In addition, a portion of the crude oil gathered by our crude oil gathering system is under a contract with a minimum volume commitment. Under a minimum volume commitment a customer agrees to either deliver a minimum volume of natural gas or crude oil to our system for service or pay the service fees for the minimum volume of natural gas or crude oil regardless of whether or not the minimum volume of natural gas or crude oil is delivered. We call any payment for the difference between the volume gathered and the minimum volume committed a shortfall payment. Some of our contracts provide our customers the option to elect to pay a higher gathering fee over

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the remaining term of the contract in lieu of making a shortfall payment. For the year ended December 31, 2016, 31% of our gathering and processing gross margin was attributable to natural gas gathering contracts with minimum volume commitments, which as of December 31, 2016 had volume commitment-weighted average remaining terms of 4.6 years. Of this gross margin, 62% was attributable to shortfall payments. For the year ended December 31, 2016, 3% of our gathering and processing gross margin was attributable to a crude oil gathering contract with a minimum volume commitment and a remaining term of 12.2 years; however, if the customer ships in excess of the minimum volume, this volume commitment could end before the expiration of the contract term. Of this gross margin, none was attributable to shortfall payments.
 
For our gathering and processing contracts that do not have minimum volume commitments, we strive to obtain acreage dedications. Under an acreage dedication, a customer agrees to deliver all of the natural gas or crude oil produced from a given area to our system for gathering, and, if applicable, processing. As of December 31, 2016, we had 6.9 million gross acres dedicated under natural gas gathering agreements with a volume-weighted average remaining term of 5.9 years, and 0.2 million gross acres dedicated under a crude oil gathering agreement with a remaining term of 14.2 years.

Construction. Our gathering and processing business involves the construction of natural gas and crude oil gathering and natural gas processing assets as needed to serve our existing and new customers. For example, during the year ended December 31, 2016, we constructed 200 miles of gathering pipelines, added 15,700 horsepower of compression and invested $268 million in the construction of gathering and processing assets. The Bradley II Plant, a cryogenic processing facility, was placed in service in the second quarter of 2016 and began full commercial operations in July 2016. In addition, in the second quarter of 2016, we elected to delay the completion of the Wildhorse Plant, a cryogenic processing facility that we plan to connect to our super-header system in Garvin County, Oklahoma. As of December 31, 2016, we anticipate that it would take at least 12 months to complete the construction of the Wildhorse plant following the restart of construction.
 
Competition. Competition to gather and process natural gas is primarily a function of gathering rate, processing value, system reliability, fuel rate, system run time, construction cycle time and prices at the wellhead. Our gathering and processing systems compete with gatherers and processors of all types and sizes, including those affiliated with various producers, other major pipeline companies and various independent midstream entities. In the process of selling NGLs, we compete against other natural gas processors extracting and selling NGLs. Our primary competitors are other midstream companies who are active in the regions where we operate.

Competition to gather crude oil and produced water is primarily a function of rates, terms of service, system reliability, construction cycle time and prices at the wellhead. The rates and terms of service of our crude oil gathering, but not our produced water gathering, are FERC regulated. Our Bakken gathering systems compete with other gatherers, including those affiliated with producers and other midstream companies.

Seasonality. While the results of our gathering and processing segment are not materially affected by seasonality, from time to time our operations and construction of assets can be impacted by inclement weather.


Transportation and Storage
 
We own and operate interstate and intrastate transportation and storage systems across nine states. Our transportation and storage systems consist primarily of our interstate systems, EGT and MRT, our intrastate system, EOIT, and our investment in SESH. Our transportation and storage assets transport natural gas from areas of production and interconnected pipelines to power plants, LDCs and industrial end users as well as interconnected pipelines for delivery to additional markets. Our transportation and storage assets also provide facilities where natural gas can be stored by customers.


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The following table sets forth certain information regarding our transportation and storage assets as of or for the year ended December 31, 2016:
Transportation and Storage
Asset
 
Length
(miles)
 
Compression (Horsepower)
 
Average
Throughput
(TBtu/d)
 
Transportation
Capacity
(Bcf/d) (1)
 
Transportation
Firm Contracted Capacity
(Bcf/d)
 
Storage Capacity (Bcf)
 
Storage Firm Contracted Capacity
(Bcf/d)
EGT
 
5,900

 
381,900

 
2.5

 
6.5

 
5.42

 
29.5

 
22.92

MRT
 
1,600

 
118,600

 
0.7

 
1.7

 
1.62

 
31.5

 
28.77

EOIT
 
2,200

 
216,200

 
1.7

(2) 

(2) 

 
24.0

 
12.25

Subtotal
 
9,700

 
716,700

 
4.9

 
8.2

 
7.04

 
85.0

 
63.94

SESH
 
290

 
107,800

 

 
1.1

(3) 

 

 

Total
 
9,990

 
824,500

 
4.9

 
9.3

 
7.04

 
85.0

 
63.94

__________________________
(1)
Actual volumes transported per day may be less than total firm contracted capacity based on demand.
(2)
Our EOIT pipeline system is a web-like configuration with multidirectional flow capabilities between numerous receipt and delivery points, which limits our ability to determine an overall system capacity. During the year ended December 31, 2016, the peak daily throughput was 2.3 TBtu/d or, on a volumetric basis, 2.3 Bcf/d.
(3)
SESH has 1.09 Bcf/d of transportation capacity from Perryville, Louisiana to its endpoint in Mobile County, Alabama.

 Our transportation and storage assets were designed and built to serve large natural gas and electric utilities in our areas of operation. In addition, our transportation and storage assets serve natural gas producers, industrial end users and natural gas marketers. For the year ended December 31, 2016, our top transportation and storage customers by revenue were affiliates of CenterPoint Energy, Spire Inc. (Spire), XTO, American Electric Power Co. (AEP), OGE Energy, Continental, Chesapeake, Midcontinent Express Pipeline LLC (MEP), EOG Resources, Inc. (EOG) and Entergy Corporation (Entergy).

Our transportation assets include approximately 10,000 miles of transportation pipelines in Texas, Oklahoma, Arkansas, Louisiana, Kansas and Missouri, providing access to natural gas supplies from the Anadarko, Arkoma and Ark-La-Tex Basins to natural gas consuming markets in the Southeastern, Northeastern and Midwestern United States. Our storage assets, as of December 31, 2016, provide a combined capacity of 85.0 Bcf with 2.0 Bcf/d of aggregate maximum withdrawal capacity from our seven storage facilities in Oklahoma, Louisiana and Illinois and from our undivided 1/12th interest in the Bistineau Storage Facility in Louisiana. Gulf South owns an undivided 9/12th interest in, and operates, the Bistineau Storage Facility. In addition, we have contracted for 3.3 Bcf of firm storage capacity in Cardinal’s Perryville and Arcadia salt cavern storage facilities.

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Our transportation and storage assets are comprised of three categories: (1) interstate transportation and storage, (2) intrastate transportation and storage and (3) our investment in SESH.

Please see “Note 18. Reportable Business Segments included in Item 8. Financial Statements and Supplementary Data—Notes to Audited Consolidated Financial Statements” for transportation and storage segment information related to Total Revenues, Operating Income and Total Assets.


Interstate Transportation and Storage

Our interstate transportation and storage business consists of EGT and MRT. As interstate pipelines, EGT and MRT are subject to regulation as natural gas companies by FERC under the NGA.

EGT

EGT provides natural gas transportation and storage services primarily to customers in Oklahoma, Texas, Arkansas, Louisiana, Missouri and Kansas. In addition to 5,900 miles of interstate pipelines with capacity of 6.5 Bcf/d, EGT has two underground natural gas storage facilities in Oklahoma and one underground natural gas storage facility in Louisiana, which, as of December 31, 2016, operate at a combined capacity of 29.5 Bcf with 739 MMcf/d of aggregate maximum withdrawal capacity.

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Interconnections and Delivery Points. In addition to delivering natural gas to utilities and industrial end users in Oklahoma, Louisiana, Texas and Arkansas, EGT receives natural gas from and delivers natural gas to a variety of intrastate and interstate pipelines through its numerous interconnections. Those interconnections include SESH, ANR, Columbia Gulf, EOIT, Gulf South, MEP, MRT, SONAT, Tennessee Gas, Texas Eastern, Texas Gas and Trunkline. Through EGT’s interconnection with SESH, our customers have access to the Southeast power generation market. Through our interconnections with other pipelines, our customers have access to the Midwest and Northeast markets. Many of EGT’s interconnections are at our Perryville Hub, which provides the ability to move natural gas between 11 major interstate pipelines. As a result, EGT provides our customers with access to not only natural gas consuming markets in Oklahoma, Louisiana, Texas and Arkansas, but also most of the major natural gas consuming markets east of the Mississippi River. In addition, EGT provides our customers supplying those markets with access to natural gas from producing basins and shale plays across the Mid-continent, including the Anadarko, Arkoma and Ark-La-Tex basins and the Barnett, Fayetteville, Granite Wash, Haynesville, SCOOP and STACK plays.
 
Customers. EGT primarily serves LDCs owned by CenterPoint Energy, producers in key plays in the Mid-continent, power plants, other LDCs and industrial end-users. EGT’s customer are primarily located in Arkansas, Louisiana, Oklahoma and Texas. For the year ended December 31, 2016, approximately 25% of EGT’s service revenue was attributable to contracts with LDCs owned by CenterPoint Energy with a volume-weighted average contract life of 4.1 years. In addition to the CenterPoint LDCs, EGT’s other major customers include XTO, Continental and AEP.

Contracts. Although EGT has established maximum rates for interstate transportation and storage services as required by FERC, EGT is authorized to enter into negotiated rate and discounted rate agreements with its customers. EGT’s services are typically provided under firm, fee-based transportation and storage agreements. For the year ended December 31, 2016, approximately 59% of our transportation and storage gross margin was derived from EGT’s firm contracts, 83% of EGT’s transportation capacity was under firm contracts with a volume-weighted average remaining contract life of 2.8 years, and 78% of EGT’s storage capacity was under firm contracts with a volume-weighted average remaining contract life of 4.2 years. The primary terms of EGT’s firm transportation and storage contracts with the CenterPoint Energy LDCs will begin to expire in 2018, with the majority of the contracts expiring in 2021.


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Seasonality. EGT provides gas transmission delivery services to LDCs owned by CenterPoint in Arkansas, Louisiana, Oklahoma and Texas. Customer demand for natural gas on EGT is usually greater during the winter, primarily due to LDC demand to serve residential and commercial natural gas requirements. In addition, EGT experiences seasonal impacts associated with storage spreads and basis spreads on interconnected pipelines, as well as power plant demand.

Competition. EGT competes with a variety of other interstate and intrastate pipelines across Texas, Oklahoma, Arkansas and Louisiana. Our management views the principal elements of competition among pipelines as rates and terms, flexibility and reliability of service. EGT provides both flexibility and reliability of service with access to multiple sources of supply in the Anadarko, Arkoma and Ark-La-Tex Basins and access to multiple markets in the Midwest, Northeast and Southeast through interconnections with other pipelines. EGT’s interconnections with other pipelines are primarily at our Perryville Hub.

MRT

MRT provides natural gas transportation and storage services principally in Texas, Arkansas, Louisiana, Missouri and Illinois. In addition to 1,600-miles of interstate pipelines with capacity of 1.7 Bcf/d, MRT has one underground natural gas storage facility in Louisiana and one underground natural gas storage facility in Illinois, which, as of December 31, 2016, operate at a combined capacity of 31.5 Bcf with 620 MMcf/d of aggregate maximum withdrawal capacity.
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Interconnections and Delivery Points. MRT receives natural gas from a variety of interstate and intrastate pipelines through its interconnections and delivers natural gas to the St. Louis market. Those interconnections include EGT, Gulf South, NGPL, Ozark Gas Transmission, Texas Eastern, Texas Gas and Trunkline. From MRT’s West Line, we provide our customers with access to supply from East Texas and North Louisiana, including the Haynesville Shale. From MRT’s mainline, we provide our customers with access to supply from the Anadarko, Arkoma and Ark-La-Tex basins through the Perryville Hub and from and the Fayetteville Shale though our interconnection with Ozark Gas Transmission. From MRT’s East Line, we provide our customers with access to supply from the Mid-continent and the Marcellus Shale through our interconnections with NGPL and Trunkline. As a result, MRT provides the St. Louis market with access to natural gas from a variety of major producing basins across the U.S.

 

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Customers. MRT primarily serves Laclede Gas Company, the St. Louis LDC owned by Spire. For the year ended December 31, 2016, 59% of MRT’s service revenue was attributable to Spire under contracts with a volume-weighted average contract life of 2.3 years. MRT’s other customers include utilities and industrial end users. MRT’s customers are primarily located in Arkansas, Missouri and Illinois.
 
Contracts. MRT’s services are typically provided under firm, fee-based transportation and storage agreements, with rates and terms of service regulated by FERC. For the year ended December 31, 2016, approximately 14% of our transportation and storage gross margin was derived from MRT’s firm contracts, 95% of MRT’s transportation capacity was under firm contracts with a volume-weighted average remaining contract life of 2.5 years and 91% of MRT’s storage capacity was under firm contracts with a volume-weighted average remaining contract life of 1.4 years. MRT’s firm transportation and storage contracts with Spire are scheduled to expire in 2018 and 2020.
 
Seasonality. Customer demand for natural gas on MRT is usually greater during the winter, primarily due to LDC demand to serve residential and commercial natural gas requirements. In addition, MRT experiences seasonal impacts associated with storage spreads and basis spreads on market-based pipelines.

Competition. MRT competes with various intrastate pipelines providing natural gas to the St. Louis market. In addition, MRT, from time-to-time, competes with potential projects to connect one or more third party interstate pipelines to the St. Louis market, such as the proposed Spire STL Pipeline for which a notice of application was filed on February 6, 2017 with FERC. Our management views the principal elements of competition among pipelines as rates, terms of service, flexibility and reliability of service. MRT, through its interconnections with a variety of interstate and intrastate pipelines and its access to supply from a variety of producing basins, provides our customers with access to a variety of natural gas supply sources.


Intrastate Transportation and Storage

Our intrastate transportation and storage assets consist primarily of EOIT. EOIT provides transportation and storage services in Oklahoma. Our EOIT system delivers natural gas from the Arkoma and Anadarko Basins, including growth areas in the Cana Woodford, Granite Wash, Cleveland, Tonkawa, SCOOP, STACK and Mississippi Lime Shale plays in western Oklahoma and the Texas Panhandle, to utilities and industrial end users connected to EOIT and to interstate and intrastate pipelines interconnected with EOIT. EOIT had 1.72 TBtu/d of average daily throughput for the year ended December 31, 2016. In addition to 2,200 miles of intrastate pipelines, EOIT has two underground natural gas storage facilities in Oklahoma, which, as of December 31, 2016 operate at a combined capacity of 24 Bcf with 605 MMcf/d of aggregate maximum withdrawal capacity. Our intrastate transportation also includes a 20-mile intrastate pipeline in Illinois.


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Interconnections and Delivery Points. EOIT has 67 interconnections and EOIT interconnects with EGT and 12 third-party interstate and intrastate natural gas pipelines, including ANR Pipeline, El Paso Natural Gas Pipeline, Gulf Crossing Pipeline Company LLC, MEP, Natural Gas Pipeline Company of America, Northern Natural Gas Company, ONEOK Gas Transmission, Ozark Gas Transmission, L.L.C., Panhandle Eastern Pipe Line, Postrock KPC Pipeline, LLC, Southern Star Central Gas Pipeline and Western Trails. In addition, EOIT connects to 41 end-user customers, including 16 natural gas-fired electric generation facilities in Oklahoma.
 
Customers. EOIT’s customers include Oklahoma’s two largest electric utilities, OG&E and Public Service Company of Oklahoma, an affiliate of AEP (PSO). For the year ended December 31, 2016, approximately 7% of our total transportation and storage gross margin was attributable to a firm contract with our affiliate OG&E, and approximately 3% of our transportation and storage gross margin was attributable to a firm contract with PSO. Our transportation agreement with OG&E extends through April 30, 2019, and will remain in effect year to year thereafter unless either party provides notice of termination to the other party at least 180 days prior to the commencement of the succeeding annual period. Our transportation agreement with PSO is on a one-year renewal term and has been extended through December 31, 2017. EOIT’s customers also include other electric generators, LDCs, Arkoma and Anadarko Basin producers and industrial end users.

Contracts. EOIT provides fee-based firm and interruptible transportation and storage services on both an intrastate basis and, pursuant to Section 311 of the NGPA, on an interstate basis. For the year ended December 31, 2016, approximately 20% of our transportation and storage gross margin was derived from EOIT’s firm contracts, with a volume-weighted average remaining contract life of 4.9 years.
 
Seasonality. EOIT provides gas transmission delivery services to the majority of OG&E’s and all of PSO’s natural gas-fired electric generation facilities in Oklahoma. Customer demand for natural gas transportation and storage services on EOIT is usually greater during the summer, primarily due to demand by natural gas-fired power plants to serve residential and commercial electricity requirements.
 

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Competition. EOIT competes with a variety of interstate and intrastate pipelines in providing transportation and storage services in Oklahoma, including competing against several pipelines with which EOIT interconnects. We view competition in the transportation and storage market as primarily a function of rates, terms of services, flexibility and reliability of service. EOIT’s integrated transportation and storage system allows us to provide load following service to natural gas-fired power plants to allow the power plants the ability to regulate generation and meet the instantaneous changes in customer demand for electricity.


Our Investment in SESH

SESH is an approximately 290-mile interstate pipeline that provides transportation services in Louisiana, Mississippi and Alabama. We own a 50% interest in SESH and provide field operations for the pipeline. Spectra Energy Partners, LP owns the remaining 50% interest in SESH and provides gas control and commercial operations for the pipeline. As of December 31, 2016, SESH had 1.09 Bcf/d of transportation capacity from Perryville, Louisiana to its endpoint in Mobile County, Alabama.
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Interconnections and Delivery Points. SESH runs from the Perryville Hub in northeastern Louisiana to southwestern Alabama near the Gulf Coast. SESH has 20 interconnects with third-party natural gas pipelines and provides access to major Southeast and Northeast markets. Natural gas transported by SESH is primarily transported by the interconnecting pipelines to companies generating electricity for the Florida power market. SESH also interconnects with three high-deliverability storage facilities, Mississippi Hub Storage, Petal Gas Storage and Southern Pines Energy Center.

Customers and Contracts. SESH’s customers are companies that generate electricity for the Florida power market. The rates charged by SESH for interstate transportation services are regulated by FERC. SESH’s transportation services are typically provided under firm, fee-based negotiated rate agreements. SESH’s transportation contracts have a volume-weighted average remaining contract life of 5.4 years.

Seasonality. SESH is generally not impacted by seasonality. SESH’s load factor generally remains constant throughout the year.


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Competition. SESH competes with other interstate and intrastate pipelines providing access to the Southeast power generation market. Our management views the principal elements of competition among pipelines as rates and terms, flexibility and reliability of service.


Rate and Other Regulation
 
Federal, state and local regulation of pipeline gathering and transportation services may affect certain aspects of our business and the market for our products and services.
 
Interstate Natural Gas Pipeline Regulation
 
EGT, MRT and SESH are subject to regulation by FERC and are considered “natural gas companies” under the Natural Gas Act (“NGA”). Natural gas companies may not charge rates that have been determined to be unjust or unreasonable by FERC. In addition, the NGA prohibits natural gas companies from granting any undue preference or advantage, or unduly discriminating against any person with respect to pipeline rates or terms and conditions of service, including unduly discriminatory or preferential access to information. FERC authority over natural gas companies that provide natural gas pipeline transportation services in interstate commerce includes:
rates, terms and conditions of service and service contracts;
certification and construction of new facilities or expansion of existing facilities;
abandonment of facilities;
maintenance of accounts and records;
acquisition and disposition of facilities;
initiation, extension or abandonment of services;
accounting, depreciation and amortization policies;
conduct and relationship with certain affiliates;
market manipulation in connection with the purchase or sale of natural gas or transportation in interstate commerce; and
various other matters.
Under the NGA, the rates for service on interstate facilities must be just and reasonable and not unduly discriminatory. Generally, the maximum recourse rates for interstate pipelines are based on the pipeline’s cost of service including recovery of and a return on the pipeline’s actual prudent investment cost. Key determinants in the ratemaking process are the total costs of providing service, allowed rate of return and throughput projections. Our interstate pipeline operations may be affected by changes in the demand for natural gas, the available supply and relative price of natural gas in the Mid-continent and Gulf Coast natural gas supply regions and general economic conditions.
 
Rate and tariff changes can only be implemented upon approval by FERC. Two primary methods are available for changing the rates, terms and conditions of service of an interstate natural gas pipeline. Under the first method, the pipeline voluntarily seeks a rate or tariff change by making a filing with FERC justifying the proposed change. FERC provides notice of the proposed change to the public through publication on its website and in the Federal Register. If FERC determines that a proposed change is just and reasonable, FERC grants approval of and allows the pipeline to implement the change. If FERC determines that a proposed change may not be just and reasonable, FERC may suspend the proposed change for up to five months. Subsequent to any suspension period ordered by FERC, the proposed change may be placed into effect by the company, pending final FERC approval. In most cases, a proposed rate change is placed into effect before a final FERC determination on such rate change, and the pipeline is permitted to collect the proposed rate subject to refund (plus interest). Under the second method, FERC may, on its own motion or based on a complaint filed by a third party, initiate a proceeding seeking to compel the company to change its rates, terms and/or conditions of service. If FERC determines that the existing rates, terms and/or conditions of service are unjust, unreasonable, unduly discriminatory or preferential, then any rate reduction or change that it orders generally will be effective prospectively from the date of the FERC order requiring this change.
 
Market Behavior Rules; Posting and Reporting Requirements
 
On August 8, 2005, Congress enacted the EPAct of 2005. Among other matters, the EPAct of 2005 amended the NGA to add an anti-manipulation provision that makes it unlawful for any entity to engage in prohibited behavior in contravention of rules and regulation to be prescribed by FERC and, furthermore, provides FERC with additional civil penalty authority. On January 19,

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2006, FERC issued Order No. 670, a rule implementing the anti-manipulation provisions of the EPAct of 2005. The rules make it unlawful for any entity, directly or indirectly in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC or the purchase or sale of transportation services subject to the jurisdiction of FERC, to (1) use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. The anti-manipulation rules apply to interstate gas pipelines and storage companies and intrastate gas pipelines and storage companies that provide interstate services, such as Section 311 service, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction. The anti-manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering to the extent such transactions do not have a “nexus” to jurisdictional transactions. The EPAct of 2005 also amends the NGA and the NGPA to give FERC authority to impose civil penalties for violations of these statutes and FERC’s regulations, rules and orders, up to $1 million per day per violation for violations occurring after August 8, 2005. The maximum penalty was increased to approximately $1.2 million on July 6, 2016. In connection with this enhanced civil penalty authority, FERC issued a revised policy statement on enforcement to provide guidance regarding the enforcement of the statutes, orders, rules and regulations it administers, including factors to be considered in determining the appropriate enforcement action to be taken. If we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. In addition, the CFTC is directed under the Commodities Exchange Act, or CEA, to prevent price manipulations for the commodity and futures markets, including the energy futures markets. Pursuant to the Dodd-Frank Act and other authority, the CFTC has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets. The CFTC also has statutory authority to seek civil penalties of up to the greater of $1.1 million or triple the monetary gain to the violator for violations of the anti-market manipulation sections of the CEA.
 
The EPAct of 2005 also added Section 23 to the NGA, authorizing FERC to facilitate price transparency in markets for the sale or transportation of physical natural gas in interstate commerce. In 2007, FERC took steps to enhance its market oversight and monitoring of the natural gas industry by issuing several rulemaking orders designed to promote gas price transparency and to prevent market manipulation. In December 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent order on rehearing, or Order No. 704. Order No. 704 requires buyers and sellers of annual quantities of natural gas of 2,200,000 MMBtu or more, including entities not otherwise subject to FERC’s jurisdiction, to provide by May 1 of each year an annual report to FERC describing their aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to or may contribute to the formation of price indices. Order No. 704 also requires market participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with FERC’s policy statement on price reporting. In June 2010, FERC issued the last of its three orders on rehearing and clarification further clarifying its requirements.
 
Intrastate Natural Gas Pipeline and Storage Regulation
 
Our intrastate natural gas pipeline and Hinshaw pipelines are subject to state regulation of rates and terms of service, but the scope of such regulation varies state to state. In Oklahoma, our intrastate pipeline system (EOIT) is subject to limited regulation by the Oklahoma Corporation Commission, or the OCC. Oklahoma has a non-discriminatory access requirement, which is subject to a complaint-based review. EOIT’s rates and terms of service are not subject to regulation by the OCC. In Illinois, our intrastate pipeline system is subject to regulation by the Illinois Commerce Commission.
 
Intrastate natural gas transportation is largely regulated by the state in which the transportation takes place. An intrastate natural gas pipeline system may transport natural gas in interstate commerce provided that the rates, terms and conditions of such transportation service comply with FERC’s regulations under Section 311 of the NGPA and Part 284 of the FERC’s regulations. The NGPA regulates, among other things, the provision of transportation and storage services by an intrastate natural gas pipeline on behalf of an interstate natural gas pipeline or a LDC served by an interstate natural gas pipeline. Under Section 311, rates charged for transportation must be fair and equitable, and amounts collected in excess of fair and equitable rates are subject to refund with interest. The rates under Section 311 are maximum rates and an intrastate pipeline may agree to discount contractual rates at or below such maximum rates. Rates for service pursuant to Section 311 of the NGPA are generally subject to review and approval by FERC at least once every five years. Should the FERC determine not to authorize rates equal to or greater than our currently approved Section 311 rates, our business may be adversely affected.
Failure to observe the service limitations applicable to transportation services provided under Section 311, failure to comply with the rates approved by FERC for Section 311 service, or failure to comply with the terms and conditions of service established in the pipeline’s FERC-approved Statement of Operating Conditions could result in the assertion of federal NGA jurisdiction by FERC and/or the imposition of administrative, civil and criminal penalties, as described in the “—Interstate Natural Gas Pipeline Regulation” section above.
 

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The transportation rates charged by EOIT for natural gas transportation in interstate commerce on intrastate pipelines are subject to the jurisdiction of FERC under Section 311 of the NGPA. EOIT currently has two zones under its Section 311 transportation rate structure—an East Zone and a West Zone. For Section 311 service, EOIT may charge up to its maximum established zonal East and West interruptible transportation rates for interruptible transportation in one zone or cumulative maximum rates for transportation in both zones. EOIT may charge up to its maximum established firm rate for firm Section 311 transportation in its East and West Zones. Finally, EOIT may charge the applicable fixed zonal fuel percentage(s) for the fuel used in transporting natural gas under Section 311 on our system. The fixed zonal fuel percentages are the same for firm and interruptible Section 311 services.
 
We also have a pipeline in Illinois that is subject to regulation by the Illinois Commerce Commission as a “Hinshaw pipeline.” Under Section 1(c) of the NGA, a Hinshaw pipeline is exempt from FERC’s NGA regulation if its operations are within a single state, if any gas received from interstate sources is received within the state and if its service is regulated by the state commission. A Hinshaw pipeline may, and our Illinois pipeline does, provide services in interstate commerce pursuant to limited jurisdiction certificate authority under Section 284.224(c) of FERC’s regulations, thereby subjecting itself to the same type of limited FERC jurisdiction imposed on intrastate pipelines engaged in Section 311 service.

Under FERC Order No. 735, intrastate pipelines providing transportation services under Section 311 of the NGPA and Hinshaw pipelines operating under Section 1(c) of the NGA are required to report on a quarterly basis via FERC Form 549D more detailed information and storage transaction information, including: rates charged by the pipeline under each contract; receipt and delivery points and zones or segments covered by each contract; the quantity of natural gas the shipper is entitled to transport, store, or deliver; the duration of the contract; and whether there is an affiliate relationship between the pipeline and the shipper. Order No. 735 further requires that such information must be supplied through an electronic reporting system and will be posted on FERC’s website, and that such quarterly reports may not contain information redacted as privileged. FERC promulgated this rule after determining that such transactional information would help shippers make more informed purchasing decisions and would improve the ability of both shippers and FERC to monitor actual transactions for evidence of market power or undue discrimination. Order No. 735 also extends FERC’s periodic review of the rates charged by the subject pipelines from three to five years. In Order No. 735-A, FERC generally reaffirmed Order No. 735 requiring Section 311 and “Hinshaw” pipelines to report on a quarterly basis storage and transportation transactions containing specific information for each transaction, aggregated by contract. Our intrastate storage assets at the Wetumka Storage Field offer both fee-based firm and interruptible storage services under Section 311 of the NGPA pursuant to terms and conditions specified in our statement of operating conditions for gas storage at market-based rates. Our intrastate Stuart Storage Field currently is used exclusively to provide intrastate storage service, even though FERC previously authorized the use of that storage facility for Section 311 interstate service.
 
Natural Gas Gathering and Processing Regulation
 
Section 1(b) of the NGA exempts natural gas gathering and processing facilities from the jurisdiction of the FERC. Although the FERC has not made formal determinations with respect to all of our facilities we consider to be gathering facilities, management believes that our natural gas pipelines meet the traditional tests that the FERC has used to determine that a pipeline is a gathering pipeline and is therefore not subject to FERC’s NGA jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and the FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our gathering facilities is subject to change based on future determinations by the FERC, the courts or Congress. If the FERC were to consider the status of an individual facility and determine that the facility and/or services provided by it are not exempt from FERC regulation under the NGA and that the facility provides interstate service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by the FERC under the NGA or the NGPA. Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our results of operations and cash flows. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the rate established by the FERC.
States may regulate gathering pipelines. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, requirements prohibiting undue discrimination, and in some instances complaint-based rate regulation. Our gathering operations may be subject to ratable take and common purchaser statutes in the states in which they operate. The ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas.
 

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Our gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services. Our gathering operations could also be subject to additional safety and operational regulations relating to the design, construction, testing, operation, replacement and maintenance of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on its operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.
 
Sales of Natural Gas
 
The price at which we buy and sell natural gas currently is not subject to federal regulation and, for the most part, is not subject to state regulation. However, as noted above, with regard to our physical purchases and sales of these energy commodities, and any related hedging activities that we undertake, we are required to observe anti-market manipulation laws and related regulations enforced by FERC and/or the CFTC. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, market participants, sellers, royalty owners and taxing authorities.
 
Our sales of natural gas are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies that remain subject to FERC jurisdiction. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry. We cannot predict the ultimate impact of these regulatory changes on our natural gas marketing operations.
 
Crude Oil Gathering Regulation
 
Crude oil gathering pipelines that provide interstate transportation service may be regulated as common carriers by FERC under the ICA, the Energy Policy Act of 1992 and the rules and regulations promulgated under those laws. Enable Bakken Crude Services, LLC (“Enable Bakken”) owns and operates two transportation systems that transport crude oil in interstate commerce and are located in the Bakken producing region of North Dakota. The ICA and FERC regulations require that rates for interstate service pipelines that transport crude oil and refined petroleum products (collectively referred to as “petroleum pipelines”) and certain other liquids, be just and reasonable and are to be non-discriminatory or not confer any undue preference upon any shipper. FERC regulations also require interstate common carrier petroleum pipelines to file with FERC and publicly post tariffs stating their interstate transportation rates and terms and conditions of service. Under the ICA, FERC or interested persons may challenge existing or changed rates or services. The FERC is authorized to investigate such charges and may suspend the effectiveness of a new rate for up to seven months. A successful rate challenge could result in a common carrier paying refunds together with interest for the period that the rate was in effect. FERC may also order a pipeline to change its rates, and may require a common carrier to pay shippers reparations for damages sustained for a period up to two years prior to the filing of a complaint.
 
If our rate levels were investigated by FERC, the inquiry could result in a comparison of our rates to those charged by others or to an investigation of our costs, including:
the overall cost of service, including operating costs and overhead;
the allocation of overhead and other administrative and general expenses to the regulated entity;
the appropriate capital structure to be utilized in calculating rates;
the appropriate rate of return on equity and interest rates on debt;
the rate base, including the proper starting rate base;
the throughput underlying the rate; and
the proper allowance for federal and state income taxes.
For some time now, FERC has been issuing regulatory assurances that necessarily balance the anti-discrimination and undue preference requirements of common carriage with the expectations of investors in new and expanding petroleum pipelines. There is an inherent tension between the requirements imposed upon a common carrier and the need for owners of petroleum pipelines to be able to enter into long-term, firm contracts with shippers willing to make the commitments which underpin such large capital investments. For example, FERC has found that shipper contract rates are not per se violations of the duty of non-discrimination, provided that such rates are available to all similarly-situated shippers. In the same vein, FERC has approved varying term commitments with tiered rate discounts on the basis that committed shippers were not similarly situated with uncommitted shippers and further that different types of committed shippers were not similarly situated with each other if their commitment level

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materially differed. FERC has also found that shippers making certain capacity commitments to the pipeline can take advantage of priority or firm service, which is service that is not subject to typical capacity allocation requirements, so long as any interested shipper has an equal opportunity to make such a commitment to the carrier. FERC’s solution has been to allow carriers to hold an “open season” prior to the in-service date of pipeline, during which time interested shippers can make commitments to the proposed pipeline project. Throughput commitments from interested shippers during an open season can be for firm service or for non-firm service. Typically, such an open season is for a 30-day period, must be publicly announced, and culminates in interested parties entering into transportation agreements with the carrier. Under FERC precedent, a carrier typically may reserve up to 90% of available capacity for the provision of firm or priority service to shippers making a commitment. At least 10% of capacity ordinarily is reserved for uncommitted shippers, i.e., “walk-up” shippers.
 
Under the ICA, FERC does not have authority over the siting of oil transportation assets nor over the abandonment of facilities or services. Accordingly, no approval from FERC is necessary prior to placing a new petroleum pipeline project in operation. However, FERC highly encourages carriers to file a Petition for Declaratory Order (PDO) to seek regulatory assurances for key terms of service offered during an open season. As long as the shippers on our Bakken crude oil gathering system move oil in interstate commerce, our crude oil gathering system will not be regulated by the North Dakota Public Service Commission.


Safety and Health Regulation
 
Certain of our facilities are subject to pipeline safety regulations. PHMSA regulates safety requirements in the design, construction, operation and maintenance of jurisdictional natural gas and hazardous liquid pipeline facilities. All natural gas transmission facilities, such as our interstate natural gas pipelines, are subject to PHMSA’s pipeline safety regulations, but natural gas gathering pipelines are subject to the pipeline safety regulations only to the extent they are classified as regulated gathering pipelines. In addition, several NGL pipeline facilities and crude oil pipeline facilities are regulated as hazardous liquids pipelines. Currently, each such NGL or crude oil facility is excepted from many of the requirements of PHMSA’s regulations applicable to hazardous liquids pipelines based on the facility’s location, product transported and/or the low stress level at which it operates.
 
Pursuant to the Natural Gas Pipeline Safety Act of 1968, or NGPSA, and the Hazardous Liquid Pipeline Safety Act of 1979, or HLPSA, as amended by the Pipeline Safety Act of 1992, or PSA, the Accountable Pipeline Safety and Partnership Act of 1996, or APSA, the Pipeline Safety Improvement Act of 2002, or PSIA, the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, or the PIPES Act, and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, or the 2011 Pipeline Safety Act, the DOT, through PHMSA, regulates pipeline safety and integrity. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of gas pipeline facilities, while the PSIA establishes mandatory inspections for all U.S. oil and natural gas transmission pipelines in high-consequence areas, or HCAs.
 
NGL and crude oil pipelines are subject to regulation by PHMSA under the HLPSA which requires PHMSA to develop, prescribe, and enforce minimum federal safety standards for the transportation of hazardous liquids by pipeline, and comparable state statutes with respect to design, installation, testing, construction, operation, replacement and management of pipeline facilities. HLPSA covers petroleum and petroleum products, including NGLs and condensate, and requires any entity that owns or operates pipeline facilities to comply with such regulations, to permit access to and copying of records and to file certain reports and provide information as required by the United States Secretary of Transportation. These regulations include potential fines and penalties for violations. Management believes that we are in compliance in all material respects with these HLPSA regulations. The PSA added the environment to the list of statutory factors that must be considered in establishing safety standards for hazardous liquid pipelines, established safety standards for certain “regulated gathering lines,” and mandated that regulations be issued to establish criteria for operators to use in identifying and inspecting pipelines located in HCAs, defined as those areas that are unusually sensitive to environmental damage, that cross a navigable waterway, or that have a high population density. In 1996, Congress enacted the APSA, which limited the operator identification requirement to operators of pipelines that cross a waterway where a substantial likelihood of commercial navigation exists, required that certain areas where a pipeline rupture would likely cause permanent or long-term environmental damage be considered in determining whether an area is unusually sensitive to environmental damage, and mandated that regulations be issued for the qualification and testing of certain pipeline personnel. In the PIPES Act, Congress required mandatory inspections for certain U.S. crude oil and natural gas transmission pipelines in HCAs and mandated that regulations be issued for low-stress hazardous liquid pipelines and pipeline control room management.
 

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PHMSA has developed regulations that require natural gas pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in HCAs. The regulations require operators, including us, to:
perform ongoing assessments of pipeline integrity;
identify and characterize applicable threats to pipeline segments that could impact an HCA;
improve data collection, integration and analysis;
repair and remediate pipelines as necessary; and
implement preventive and mitigating actions.

Although many of our pipeline facilities fall within a class that is currently not subject to these integrity management requirements, we may incur significant costs and liabilities associated with repair, remediation, and preventive or mitigating measures associated with our non-exempt pipelines. Furthermore, PHMSA has taken actions recently that may impact the exempt status of some of our pipeline facilities. On April 8, 2016, PHMSA published a notice of proposed rulemaking (NPRM) that would amend existing integrity management requirements, expand assessment and repair requirements to pipelines in areas with medium population densities, and extend regulatory requirements to onshore gas gathering lines that are currently exempt. PHMSA issued, but has yet to publish, a similar rule for hazardous liquids pipelines on January 13, 2017. That rule extends regulatory reporting requirements to all liquid gathering lines, requires additional event-driven and periodic inspections, requires use of leak detection systems on all hazardous liquid pipelines, modifies repair criteria, and requires certain pipelines to eventually accommodate inline inspection tools. It is unclear when or if this rule will go into effect as, on January 20, 2017, the Trump Administration requested that all regulations that had been sent to the Office of the Federal Register, but not yet published, be immediately withdrawn for further review. In 2016, we incurred $32 million of capital expenditures and operating costs for pipeline integrity management. We currently estimate that we will incur capital expenditures and operating costs of up to $290 million from 2017 to 2021 in connection with pipeline integrity management to complete the testing required by existing DOT regulations and their state counterparts. The estimated capital expenditures and operating costs include our estimates for the assessment, remediation and prevention or other mitigation that may be determined to be necessary. At this time, we cannot predict the ultimate costs of our integrity management program and compliance with these regulations because those costs will depend on the number and extent of any repairs found to be necessary and the degree to which newly proposed pipeline safety regulations may apply to our pipeline systems. We will continue to assess, remediate and maintain the integrity of our pipelines. The results of these activities could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operations of our pipelines. Additionally, should we fail to comply with DOT or comparable state regulations, we could be subject to penalties and fines. If future DOT pipeline integrity management regulations were to require that we expand our integrity managements program to currently unregulated pipelines, including gathering lines, our costs associated with compliance may have a material effect on our operations.

On December 20, 2016, the PHMSA issued a Notice of Proposed Violation (“NOPV”) and Proposed Compliance Order to EGT and MRT. The Notice was issued following inspection of our Operations and Maintenance and Integrity Management procedures and an inspection of our related records and facilities conducted on February 22, 2016 and November 17, 2016. The Notice included three proposed violations and a Proposed Compliance Order. No fines or penalties were proposed in the Notice. On January 26, 2017, we sent a response requesting clarification of one of the three proposed violations and of the Proposed Compliance Order addressing that violation, and are contesting another of the three proposed violations, asking that it be withdrawn or modified.
 
The 2011 Pipeline Safety Act reauthorizes funding for federal pipeline safety programs, increases penalties for safety violations, establishes additional safety requirements for newly constructed pipelines, and requires studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines. The 2011 Pipeline Safety Act, among other things, increases the maximum civil penalty for pipeline safety violations and directs the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation and testing to confirm the material strength of pipe operating above 30% of specified minimum yield strength in HCAs. PHMSA adopted new rules increasing the maximum administrative civil penalties for violations of the pipeline safety laws and regulations after January 3, 2012. Those potential penalties have recently been adjusted for inflation and can be up to approximately $0.2 million per violation per day, with a maximum of approximately $2 million for a related series of violations. In 2011, PHMSA issued a final rule applying safety regulations to certain rural low-stress hazardous liquid pipelines that were not covered previously by some of its safety regulations. PHMSA also published advance notice of proposed rulemakings to solicit comments on the need for changes to its natural gas and liquid pipeline safety regulations, including changes to those rules that would apply to gathering lines and removal of an exemption for natural gas pipelines installed before 1970. In May 2012, PHMSA published an advisory bulletin stating that operators of gas and hazardous liquid pipeline facilities should verify records relating to operating specifications for maximum allowable operating pressure, MAOP, for gas pipelines and

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maximum operating pressure, or MOP, for hazardous liquid pipelines. For natural gas transmission pipelines located within Class 3 and Class 4 locations or in Class 1 and Class 2 locations in HCAs, PHMSA modified its annual report form to require operators to report the number of verified miles of pipeline on their systems. This report was due and filed in June 2013, and subsequently updated in March 2014. No MOP reporting requirements were imposed on operators of hazardous liquid pipeline for the 2012 calendar year reports. Our current practice is to continually monitor and update our records with respect to MAOP of our gas pipelines.

On March 17, 2016, PHMSA proposed natural gas pipeline safety standards that, if implemented, are expected to lower methane emissions. Further, on January 13, 2017, PHMSA issued a final rule amending its pipeline safety regulations for the design, construction, testing, operation, and maintenance of pipelines transporting hazardous liquids. The rule imposes stricter standards that, among other things, determine how operators repair aging and high-risk infrastructure and increase the frequency of tests that assess the conditions of pipelines. In addition, the final rule extends certain safety-related condition reporting requirements to all hazardous liquid gathering lines and requires periodic assessments of certain hazardous liquid transmission lines in non-HCAs. The effective date of this rulemaking is currently uncertain due to a regulatory freeze implemented by the Trump administration on January 20, 2017. Future PHMSA rulemakings and/or industry commitments could have a material impact on our operations.

While we cannot predict the outcome of legislative or regulatory initiatives, such legislative and regulatory changes could have a material effect on our operations, particularly through more stringent and comprehensive safety regulations (such as integrity management requirements) to pipelines and gathering lines not previously subject to such requirements. While we expect any legislative or regulatory changes will provide sufficient time to come into compliance with the new requirements, the costs associated with compliance may have a material effect on our operations.
 
States are preempted by federal law from imposing pipeline safety standards below the minimum federal standards established by DOT, but they may establish more rigorous standards for intrastate gas and hazardous liquids pipelines. State agencies may also assume responsibility for enforcing intrastate pipeline regulations as a cooperating agency. In practice, states vary considerably in their authority and capacity to address pipeline safety. In the state of Oklahoma, the OCC’s Transportation Division, acting through the Pipeline Safety Department, administers the OCC’s intrastate regulatory program to assure the safe transportation of natural gas, petroleum and other hazardous materials by pipeline. The OCC develops regulations and other approaches to assure safety in design, construction, testing, operation, maintenance and emergency response to pipeline facilities. The OCC derives its authority over intrastate pipeline operations through state statutes and certification agreements with the DOT. A similar regime for safety regulation is in place in Texas and is administered by the Texas Railroad Commission. Our natural gas transmission and DOT regulated gathering pipelines have ongoing inspection and compliance programs designed to keep the facilities in compliance with pipeline safety and pollution control requirements.
 
We continue to incorporate new requirements into our procedures and budgets. We expect to incur increasing regulatory compliance costs, based on the intensification of the regulatory environment and forecasted changes to regulations as outlined above. In addition to regulatory changes, costs may be incurred when there is an accidental release of a commodity transported by our system, or a regulatory inspection identifies a deficiency in our required programs.
 
In addition to these pipeline safety requirements, we are subject to a number of federal and state laws and regulations, including the Occupational Safety and Health Act of 1970 (OSHA) and comparable state statutes, whose purpose is to protect the safety and health of workers, both generally and within the pipeline industry. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the Federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We are also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above the specified thresholds or any process which involves flammable liquid or gas, pressurized tanks, caverns and wells in excess of 10,000 pounds at various locations. We have an internal program of inspection designed to monitor and enforce compliance with worker safety and health requirements. Management believes that we are in material compliance with all applicable laws and regulations relating to worker safety and health.
 
The Department of Homeland Security Appropriation Act of 2007 requires the Department of Homeland Security, or DHS, to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present “high levels of security risk.” The DHS issued an interim final rule in April 2007 regarding risk-based performance standards to be attained pursuant to this act and, on November 20, 2007, further issued an Appendix A to the interim rules that establish chemicals of interest and their respective threshold quantities that will trigger compliance with these interim rules. Covered facilities that are determined by DHS to pose a high level of security risk will be

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required to prepare and submit Security Vulnerability Assessments and Site Security Plans as well as comply with other regulatory requirements, including those regarding inspections, audits, recordkeeping, and protection of chemical-terrorism vulnerability information.
 
While we are not currently subject to governmental standards for the protection of computer-based systems and technology from cyber threats and attacks, proposals to establish such standards are being considered by the U.S. Congress and by U.S. Executive Branch departments and agencies, including the Department of Homeland Security, and we may become subject to such standards in the future. We have systems in place to monitor and address the risk of cyber-security breaches in our business, operations and control environments. We routinely review and update those systems as the nature of that risk requires. We are not aware of any cyber-security breach affecting any of our business, operations or control environments. A significant cyber-attack could have a material effect on our operations and those of our customers.


Environmental Regulation
 
General
 
Our activities are subject to stringent and complex federal, state and local laws and regulations governing environmental protection including the discharge of materials into the environment. These laws and regulations can restrict or impact our business activities in many ways, such as restricting the way we can handle or dispose of our wastes, requiring remedial action to mitigate pollution conditions that may be caused by our operations or that are attributable to former operations, regulating future construction activities to mitigate harm to threatened or endangered species, wetlands and migratory birds, and requiring the installation and operation of pollution control equipment. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. Management believes that our operations are in material compliance with current federal, state and local environmental standards.
 
Environmental regulation can increase the cost of planning, design, initial installation, operation and maintenance of our facilities and has the potential to restrict or delay our operations and development projects, particularly pipeline projects. Historically, our total expenditures for environmental control measures and for remediation have not been significant in relation to our consolidated financial position or results of operations. Management believes, however, that it is reasonably likely that the trend in environmental legislation and regulations will continue towards more restrictive standards. Compliance with these standards is expected to increase the cost of conducting business.
 
Our routine environmental expenses for 2016 for technical support, fees, sampling, testing and other similar items were approximately $6 million. Reciprocating internal combustion engines maximum achievable control technology (RICE MACT) and greenhouse gases (GHG) expenses for 2016 were approximately $2 million. Routine expenses for 2017 to 2019 are expected to average $8 million per year, and RICE MACT and GHG costs are expected to average $2 million per year over the same timeframe. Costs for incidental environmental activities, such as permitting as part capital projects and waste disposal, are included in routine capital and operating expenses. Management continues to evaluate our compliance with existing and proposed environmental regulations and implements appropriate environmental programs in a competitive market.
 
Air
 
Our operations are subject to the federal Clean Air Act, as amended (CAA), and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including natural gas processing plants and compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions (including greenhouse gas emissions as discussed below), obtain and strictly comply with air permits containing various emissions and operational limitations or install emission control equipment. The EPA has also recently announced that it intends to develop methane emission standards for existing sources and has issued information collection requests to companies with production, gathering and boosting, gas processing, storage, and transmission facilities. We likely will be required to incur certain capital expenditures in the future for air pollution control equipment and technology in connection with obtaining and maintaining operating permits and approvals for air emissions. For more information, please read Item 1A, “Risk Factors–Costs of compliance with existing environmental laws and regulations are significant, and the cost of compliance with future environmental laws and regulations may adversely affect our financial position, results of operations and ability to make cash distributions to unitholders.”
 

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Climate Change
 
More stringent laws and regulations relating to climate change and GHGs (including methane) may be adopted in the future and could cause us to incur material expenses in complying with them. The United States Congress has, from time to time, considered adopting legislation to reduce emissions of GHGs, and there has been a wide-ranging policy debate, both nationally and internationally, regarding the impact of these gases and possible means for their regulation. Some of the proposals would require industrial sources to meet stringent new standards that would require substantial reductions in GHG emissions. Please read Item 1A, Risk Factors–Risks Related to Our Business–Our operations may incur substantial liabilities to comply with climate change legislation and regulatory initiatives.for more information. Following a finding by the U.S. Environmental Protection Agency (EPA) that certain GHGs represent an endangerment to human health, the EPA adopted two sets of rules regulating GHG emissions under the Clean Air Act. One requires a reduction in emissions of GHGs from motor vehicles beginning January 2, 2011. The other regulates emissions of GHGs from certain large stationary sources under the Clean Air Act’s Prevention of Significant Deterioration and Title V programs, commencing when the motor vehicle standards took effect on January 2, 2011. Also, the EPA adopted its “Mandatory Reporting of Greenhouse Gases Rule” that requires the annual calculation and reporting of GHG emissions from natural gas transmission, gathering, processing and distribution systems and electric distribution systems that emit 25,000 metric tons or more of carbon dioxide equivalent (CO2e) per year. These additional reporting requirements began in 2012 and we are currently in compliance. These permitting and reporting requirements could lead to further regulation of GHGs by the EPA.

Although the adoption of new legislation is uncertain, action by the EPA to impose new standards and reporting requirements regarding GHG emissions continues. For example, in May 2016, the EPA issued final new source performance standards imposing more stringent controls on methane and volatile organic compounds emissions at new and modified oil and natural gas production, processing, storage, and transmission facilities. The EPA has also announced that it intends to develop methane emission standards for existing sources and has issued information collection requests to companies with production, gathering and boosting, gas processing, storage, and transmission facilities. Similarly, in November 2016, the Bureau of Land Management finalized rules that require additional efforts by producers to reduce venting, flaring, and leaking of natural gas produced on federal and Native American lands. Furthermore, in October 2015, the EPA finalized proposed changes to its GHG reporting rule that requires additional reporting from natural gas transmission pipelines as well as gathering and boosting stations. This rule was effective January 1, 2016.

Several states have passed laws, adopted regulations or undertaken regulatory initiatives to reduce the emission of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Oklahoma, Arkansas, Louisiana, Kansas, Missouri, Illinois, Tennessee, Mississippi, Alabama, North Dakota and Texas are not among them. Finally, in April 2016, the United States signed the Paris Agreement, which requires member countries to review and “represent a progression” in their nationally determined contributions, which set GHG emission reduction goals, every five years. If legislation or regulations are passed at the federal or state levels in the future requiring mandatory reductions of carbon dioxide, methane and other GHGs on our facilities, this could result in significant additional compliance costs that would affect the our future financial position, results of operations and cash flows.
 
The adoption of state or federal legislation or regulatory programs to reduce emissions of GHGs, including methane, could require us to incur increased operating costs, such as costs to purchase and operate emissions monitoring and control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the natural gas we gather, treat and transport. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. For more information, please read Item 1A, “Risk Factors–Our operations may incur substantial liabilities to comply with climate change legislation and regulatory initiatives.”
 
National Environmental Policy Act (NEPA)
 
NEPA provides for regulatory review in connection with certain projects that involve federal lands or require certain actions by federal agencies, which implicates a number of other laws and regulations such as the Endangered Species Act (ESA), Migratory Bird Treaty Act, Rivers and Harbors Act, Clean Water Act, Bald and Golden Eagle Protection Act, Fish and Wildlife Coordination Act, Marine Mammal Protection Act and National Historic Preservation Act. The NEPA review process can be lengthy and subjective and can cause delays in projects. Some of our projects that require NEPA review are related to pipeline integrity. Ineffective implementation of this process could cause significant impacts to commercial and compliance projects.
 

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Protected Species
 
Certain federal laws, including the Bald and Golden Eagle Protection Act, the Migratory Bird Treaty Act and the Endangered Species Act, provide special protection to certain designated species. These laws and any state equivalents provide for significant civil and criminal penalties for unpermitted activities that result in harm to or harassment of certain protected animals and plants, including damage to their habitats. If such species are located in an area in which we conduct operations, or if additional species in those areas become subject to protection, our operations and development projects, particularly pipeline projects, could be restricted or delayed, or we could be required to implement expensive mitigation measures. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service is required to make a determination on listing of more than 250 species as endangered or threatened under the ESA by no later than completion of the agency’s 2017 fiscal year. The designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our customer’s exploration and production activities that could have an adverse impact on demand for our services. Portions of the basins we serve are designated as critical or suitable habitat for threatened and endangered species. If additional portions of the basins we serve were designated as critical or suitable habitat for threatened and endangered species, it could adversely impact the cost of operating our systems and of constructing new facilities. Management believes that we are in material compliance with all applicable laws providing special protection to designated species.
 
Hazardous Substances and Waste
 
Our operations are subject to federal and state environmental laws and regulations relating to the management and release of hazardous substances, solid and hazardous wastes, and petroleum hydrocarbons. For instance, our operations are subject to the Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA or Superfund) and comparable state cleanup laws that impose liability, without regard to the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. These persons include current and prior owners or operators of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover the costs they incur from the responsible classes of persons. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Because we utilize various products and generate wastes that are considered hazardous substances for purposes of CERCLA, we could be subject to liability for the costs of cleaning up and restoring sites where those substances have been released to the environment. At this time, it is not anticipated that any associated liability will cause a significant impact to us.
 
Our operations also generate solid and hazardous wastes that are subject to the federal Resource Conservation and Recovery Act of 1976 (RCRA) as well as comparable state laws. While RCRA regulates both solid and hazardous wastes, it imposes detailed requirements for the handling, storage, treatment and disposal of hazardous waste. RCRA currently exempts many natural gas gathering and field processing wastes from classification as hazardous waste. However, it is possible that these wastes, which could include wastes currently generated during our operations, will in the future be designated as “hazardous wastes” and therefore be subject to more rigorous and costly disposal requirements. Such changes to the law could have an impact on our capital expenditures and operating expenses. Further, these RCRA-exempt oil and gas exploration and production wastes may still be regulated under state law or RCRA’s less stringent solid waste requirements. The transportation of natural gas in pipelines may also generate some hazardous wastes that are subject to RCRA or a comparable state law regime.

Water

Our operations are subject to the federal Clean Water Act and analogous state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants into state and federal waters. The discharge of pollutants, including discharges resulting from a spill or leak, is prohibited unless authorized by a permit or other agency approval. In addition, the federal Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. These permits may require us to monitor and sample the storm water runoff from some of our facilities. The federal Clean Water Act and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarbon tank spill, rupture or leak. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with many of these requirements.

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The primary federal law related to oil spill liability is the Oil Pollution Act (the OPA) which amends and augments oil spill provisions of the Clean Water Act and imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening United States waters or adjoining shorelines. A liable “responsible party” includes the owner or operator of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge, or in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. OPA assigns joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist to the liability imposed by OPA, they are limited. In the event of an oil discharge or substantial threat of discharge, we may be liable for costs and damages.
 
Hydraulic Fracturing
 
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is regulated by state agencies, typically the state’s oil and gas commission. A number of federal agencies, including the EPA and the U.S. Department of Energy, are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. For instance, the EPA released the final results of its comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on drinking water resources in December 2016. The EPA concluded that hydraulic fracturing activities can impact drinking water resources under some circumstances, including large volume spills and inadequate mechanical integrity of wells. In addition, some states have adopted, and other states are considering adopting, regulations that could impose more stringent disclosure and/or well construction requirements on hydraulic fracturing operations.

State and federal regulatory agencies also recently focused on a possible connection between the operation of injection wells used for oil and gas wastewater disposal and seismic activity. Similar concerns have been raised that hydraulic fracturing may also contribute to seismic activity. When caused by human activity, such events are called induced seismicity. In March 2016, the United States Geological Survey identified six states with the most significant hazards from induced seismicity: Oklahoma, Kansas, Texas, Colorado, New Mexico, and Arkansas. In light of these concerns, some state regulatory agencies have modified their regulations or issued orders to address induced seismicity. Certain environmental and other groups have also suggested that additional federal, state and local laws and regulations may be needed to more closely regulate the hydraulic fracturing process.

If new laws or regulations that significantly restrict hydraulic fracturing or waste disposal wells are adopted, such laws could lead to greater opposition to, and litigation concerning, related oil and gas producing activities and to operational delays or increased operating costs for our customers, which in turn could reduce the demand for our services. For more information, please read Item 1A, “Risk Factors –Increased regulation of hydraulic fracturing could result in reductions or delays in natural gas production by our customers, which could adversely affect our financial position, results of operations and ability to make cash distributions to unitholders.” For a further discussion regarding contingencies relating to environmental laws and regulations, see Note 15 to Notes to Consolidated Financial Statements.
 

Our Employees
 
As of December 31, 2016, we employ approximately 1,600 employees with an additional 158 individuals providing services to us as seconded employees of OGE Energy. Personnel remain seconded to the Partnership, subject to certain termination rights of the Partnership and OGE Energy, in order to continue their participation in OGE Energy’s defined benefit and retiree medical plans. Please read Item 13, “Certain Relationships and Related Party Transactions—Employee Agreements” for a description of the agreements governing these relationships.


Item 1A. Risk Factors

You should carefully consider each of the following risks and all of the other information contained in this Annual Report on Form 10-K in evaluating us and our common units. Some of these risks relate principally to our business and the industry in which we operate, while others relate principally to tax matters, ownership of our common units, our preferred units and securities markets generally. If any of the following risks were actually to occur, our business, financial position or results of operations could be materially adversely affected. In that case, we might not be able to pay the minimum quarterly distribution on our common units, or the trading price of our common units could decline.



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Risks Related to Our Business
 
We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner and its affiliates, to enable us to pay the minimum quarterly distribution to holders of our common and subordinated units.
 
We may not have sufficient available cash each quarter to enable us to pay the minimum quarterly distribution. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
the fees and gross margins we realize with respect to the volume of natural gas, NGLs and crude oil that we handle;
the prices of, levels of production of, and demand for natural gas, NGLs and crude oil;
the volume of natural gas, NGLs and crude oil we gather, compress, treat, dehydrate, process, fractionate, transport and store;
the relationship among prices for natural gas, NGLs and crude oil;
cash calls and settlements of hedging positions;
margin requirements on open price risk management assets and liabilities;
the level of competition from other midstream energy companies;
adverse effects of governmental and environmental regulation;
the level of our operation and maintenance expenses and general and administrative costs; and
prevailing economic conditions.
In addition, the actual amount of cash we will have available for distribution will depend on other factors, including:
the level and timing of capital expenditures we make;
the cost of acquisitions;
our debt service requirements and other liabilities;
fluctuations in working capital needs;
our ability to borrow funds and access capital markets;
restrictions contained in our debt agreements;
the amount of cash reserves established by our general partner;
distributions paid on our Series A Preferred Units; and
other business risks affecting our cash levels.
 
Our contracts are subject to renewal risks.
 
As contracts with our existing suppliers and customers expire, we may have to negotiate extensions or renewals of those contracts or enter into new contracts with other suppliers and customers. We may be unable to extend or renew existing contracts or enter into new contracts on favorable commercial terms, if at all. Depending on prevailing market conditions at the time of an extension or renewal, gathering and processing customers with fee based contracts may desire to enter into contracts under different fee arrangements. Approximately 87% of our gross margin was generated from fee-based contracts during the year ended December 31, 2016. Likewise, our transportation and storage customers may choose not to extend or renew expiring contracts based on the economics of the related areas of production. To the extent we are unable to renew or replace our expiring contracts on terms that are favorable to us, if at all, or successfully manage our overall contract mix over time, our financial position, results of operations and ability to make cash distributions to unitholders could be adversely affected.
 
We depend on a small number of customers for a significant portion of our gathering and processing services revenues and our transportation and storage services revenues. The loss of, or reduction in volumes from, these customers could result in a decline in sales of our gathering and processing or transportation and storage services and adversely affect our financial position, results of operations and ability to make cash distributions to our unitholders.
 
For the year ended December 31, 2016, 49% of our gathered natural gas volumes were attributable to the affiliates of Continental, Vine, GeoSouthern, XTO and Apache and 51% of our transportation and storage service revenues were attributable to affiliates of CenterPoint Energy, Spire, XTO, AEP, and OGE Energy. The loss of all or even a portion of the gathering and processing or transportation and storage services for any of these customers, the failure to extend or replace these contracts or the

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extension or replacement of these contracts on less favorable terms, as a result of competition or otherwise, could adversely affect our financial position, results of operations and ability to make cash distributions to unitholders.
 
Our businesses are dependent, in part, on the drilling and production decisions of others.
 
Our businesses are dependent on the drilling and production of natural gas and crude oil. We have no control over the level of drilling activity in our areas of operation, or the amount of natural gas, NGL and crude oil reserves associated with wells connected to our systems. In addition, as the rate at which production from wells currently connected to our system naturally declines over time, our gross margin associated with those wells will also decline. To maintain or increase throughput levels on our gathering and transportation systems and the asset utilization rates at our natural gas processing plants, our customers must continually obtain new natural gas, NGL and crude oil supplies. The primary factors affecting our ability to obtain new supplies of natural gas, NGLs and crude oil and attract new customers to our assets are the level of successful drilling activity near our systems, our ability to compete for volumes from successful new wells and our ability to expand our capacity as needed. If we are not able to obtain new supplies of natural gas, NGLs and crude oil to replace the natural decline in volumes from existing wells, throughput on our gathering, processing, transportation and storage facilities would decline, which could adversely affect our financial position, results of operations and ability to make cash distributions to unitholders. We have no control over producers or their drilling and production decisions, which are affected by, among other things: 
the availability and cost of capital;
prevailing and projected commodity prices, including the prices of natural gas, NGLs and crude oil;
demand for natural gas, NGLs and crude oil;
levels of reserves;
geological considerations;
environmental or other governmental regulations, including the availability of drilling permits and the regulation of hydraulic fracturing; and
the availability of drilling rigs and other costs of production and equipment.
Fluctuations in energy prices can also greatly affect the development of new natural gas, NGL and crude oil reserves. Drilling and production activity generally decreases as commodity prices decrease. In general terms, the prices of natural gas, NGLs, crude oil and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. Because of these factors, even if new natural gas, NGL or crude oil reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. Declines in natural gas, NGL or crude oil prices can have a negative impact on exploration, development and production activity and, if sustained, could lead to decreases in such activity. In early 2016, natural gas and crude oil prices dropped to their lowest levels in over 10 years. Both natural gas and crude oil prices increased moderately in the second half of 2016. Sustained low natural gas, NGL or crude oil prices could also lead producers to shut in production from their existing wells. Sustained reductions in exploration or production activity in our areas of operation could lead to further reductions in the utilization of our systems, which could adversely affect our financial position, results of operations and ability to make cash distributions to unitholders.

In addition, it may be more difficult to maintain or increase the current volumes on our gathering systems and in our processing plants, as several of the formations in the unconventional resource plays in which we operate generally have higher initial production rates and steeper production decline curves than wells in more conventional basins. Should we determine that the economics of our gathering assets do not justify the capital expenditures needed to grow or maintain volumes associated therewith, we may reduce such capital expenditures, which could cause revenues associated with these assets to decline over time. In addition to capital expenditures to support growth, the steeper production decline curves associated with unconventional resource plays may require us to incur higher maintenance capital expenditures relative to throughput over time, which will reduce our distributable cash flow.
 
Because of these and other factors, even if new reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. Reductions in drilling activity would result in our inability to maintain the current levels of throughput on our systems and could adversely affect our financial position, results of operations and ability to make cash distributions to unitholders.
 
Our industry is highly competitive, and increased competitive pressure could adversely affect our financial position, results of operations and ability to make cash distributions to unitholders.
 
We compete with similar enterprises in our respective areas of operation. The principal elements of competition are rates, terms of service and flexibility and reliability of service. Our competitors include large energy companies that have greater financial

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resources and access to supplies of natural gas, NGLs and crude oil than us. Some of these competitors may expand or construct gathering, processing, transportation and storage systems that would create additional competition for the services we provide to our customers. Excess pipeline capacity in the regions served by our interstate pipelines could also increase competition and adversely impact our ability to renew or enter into new contracts with respect to our available capacity when existing contracts expire. In addition, our customers that are significant producers of natural gas or crude oil may develop their own gathering, processing, transportation and storage systems in lieu of using ours. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors and customers. Further, natural gas utilized as a fuel competes with other forms of energy available to end-users, including electricity, coal and liquid fuels. Increased demand for such forms of energy at the expense of natural gas could lead to a reduction in demand for natural gas gathering, processing, transportation and storage services. All of these competitive pressures could adversely affect our financial position, results of operations and ability to make cash distributions to unitholders.
 
We derive a substantial portion of our gross margin from subsidiaries through which we hold a substantial portion of our assets.
 
We derive a substantial portion of our gross margin from, and hold a substantial portion of our assets through, our subsidiaries. As a result, we depend on distributions from our subsidiaries in order to meet our payment obligations. In general, these subsidiaries are separate and distinct legal entities and have no obligation to provide us with funds for our payment obligations, whether by dividends, distributions, loans or otherwise. In addition, provisions of applicable law, such as those limiting the legal sources of dividends, limit our subsidiaries’ ability to make payments or other distributions to us, and our subsidiaries could agree to contractual restrictions on their ability to make distributions.
 
Our right to receive any assets of any subsidiary, and therefore the right of our creditors to participate in those assets, will be effectively subordinated to the claims of that subsidiary’s creditors, including trade creditors. In addition, even if we were a creditor of any subsidiary, our rights as a creditor would be subordinated to any security interest in the assets of that subsidiary and any indebtedness of the subsidiary senior to that held by us.

The amount of cash we have available for distribution to our limited partners depends primarily on our cash flow rather than on our profitability, which may prevent us from making distributions, even during periods in which we record net income.
 
The amount of cash we have available for distribution depends primarily upon our cash flow rather than on profitability. Profitability is affected by non-cash items but cash flow is not. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.
 
We may not be able to recover the costs of our substantial planned investment in capital improvements and additions, and the actual cost of such improvements and additions may be significantly higher than we anticipate.
 
Our business plan calls for investment in capital improvements and additions. For the year ending December 31, 2017, we estimate that expansion capital could range from approximately $455 million to $575 million and our maintenance capital could range from approximately $95 million to $125 million. For example, in the second quarter of 2016 we delayed the completion of the Wildhorse plant, a cryogenic processing facility that we plan to connect to our super-header system in Garvin County, Oklahoma. We also plan to construct natural gas gathering and compression infrastructure to support producer activity.
 
The construction of additions or modifications to our existing systems, and the construction of new midstream assets, involves numerous regulatory, environmental, political and legal uncertainties, many of which are beyond our control and may require the expenditure of significant amounts of capital, which may exceed our estimates. These projects may not be completed at the planned cost, on schedule or at all. The construction of new pipeline, gathering, treating, processing, compression or other facilities is subject to construction cost overruns due to labor costs, costs of equipment and materials such as steel, labor shortages or weather or other delays, inflation or other factors, which could be material. In addition, the construction of these facilities is typically subject to the receipt of approvals and permits from various regulatory agencies. Those agencies may not approve the projects in a timely manner, if at all, or may impose restrictions or conditions on the projects that could potentially prevent a project from proceeding, lengthen its expected completion schedule and/or increase its anticipated cost. Moreover, our revenues and cash flows may not increase immediately upon the expenditure of funds on a particular project. For instance, if we expand an existing pipeline or construct a new pipeline, the construction may occur over an extended period of time, and we may not receive any material increases in revenues or cash flows until the project is completed. In addition, we may construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. As a result, the new facilities may not be able to achieve our expected investment return, which could adversely affect our financial position, results of operations and ability to make cash distributions to unitholders.

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In connection with our capital investments, we may estimate, or engage a third party to estimate, potential reserves in areas to be developed prior to constructing facilities in those areas. To the extent we rely on estimates of future production in deciding to construct additions to our systems, those estimates may prove to be inaccurate due to numerous uncertainties inherent in estimating future production. As a result, new facilities may not be able to attract sufficient throughput to achieve expected investment return, which could adversely affect our financial position, results of operations and ability to make cash distributions to unitholders. In addition, the construction of additions to existing gathering and transportation assets may require new rights-of-way prior to construction. Those rights-of-way to connect new natural gas supplies to existing gathering lines may be unavailable and we may not be able to capitalize on attractive expansion opportunities. Additionally, it may become more expensive to obtain new rights-of-way or to renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, our financial position, results of operations and ability to make cash distributions to unitholders could be adversely affected.

Natural gas, NGL and crude oil prices are volatile, and changes in these prices could adversely affect our financial position, results of operations and our ability to make cash distributions to unitholders.
 
Our financial position, results of operations and ability to make cash distributions to unitholders could be negatively affected by adverse movements in the prices of natural gas, NGLs and crude oil depending on factors that are beyond our control. These factors include demand for these commodities, which fluctuates with changes in market and economic conditions and other factors, including the impact of seasonality and weather, general economic conditions, the level of domestic and offshore natural gas production and consumption, the availability of imported natural gas, LNG, NGLs and crude oil, actions taken by foreign natural gas and oil producing nations, the availability of local, intrastate and interstate transportation systems, the availability and marketing of competitive fuels, the impact of energy conservation efforts, technological advances affecting energy consumption and the extent of governmental regulation and taxation. In early 2016, natural gas and crude oil prices dropped to their lowest levels in over 10 years. Both natural gas and crude oil prices increased moderately in the second half of 2016.
 
Our natural gas processing arrangements expose us to commodity price fluctuations. In 2016, 8%, 46%, and 46% of our processing plant inlet volumes consisted of keep-whole arrangements, percent-of-proceeds or percent-of-liquids, and fee-based, respectively. Under a typical keep-whole arrangement, we process raw natural gas, extract the NGLs, replace the extracted NGLs with a Btu equivalent amount of natural gas, deliver the processed and replacement natural gas to the producer, retain the NGLs, and sell the NGLs for our own account. If we are unable to sell the NGLs extracted for more than the cost of the replacement natural gas, the margins on our sale of goods will be negatively affected.

Under a typical percent-of-proceeds processing arrangement, we purchase raw natural gas at a cost that is based on the amount of natural gas and NGLs contained in the raw natural gas. We then process the raw natural gas, extract the NGLs, and sell the processed natural gas and NGLs for our own account. If we are unable to sell the processed natural gas and NGLs for more than the cost of the raw natural gas, the margins on our sale of goods will be negatively affected.

Under a typical percent-of-liquids processing arrangement and a typical fee-based arrangement, we purchase a portion of the raw natural gas that is equivalent to the amount of NGLs it contains, process the raw natural gas, extract the NGLs, return the processed natural gas to the producer, and sell the NGLs for our own account. If we are unable to sell the processed natural gas and NGLs for more than the cost of raw natural gas, the margins on our sale of goods will be negatively affected.

At any given time, our overall portfolio of processing contracts may reflect a net short position in natural gas (meaning that we are a net buyer of natural gas) and a net long position in NGLs (meaning that we are a net seller of NGLs). As a result, our gross margin could be adversely impacted to the extent the price of NGLs decreases in relation to the price of natural gas.

We are exposed to credit risks of our customers, and any material nonpayment or nonperformance by our key customers could adversely affect our financial position, results of operations and ability to make cash distributions to unitholders.
 
Some of our customers may experience financial problems that could have a significant effect on their creditworthiness. Severe financial problems encountered by our customers could limit our ability to collect amounts owed to us, or to enforce performance of obligations under contractual arrangements. In addition, many of our customers finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. The combination of reduction of cash flow resulting from declines in commodity prices, a reduction in borrowing bases under reserve-based credit facility and the lack of availability of debt or equity financing may result in a significant reduction of our customers’ liquidity and limit their ability to make payment or perform on their obligations to us. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us. Financial problems experienced by our customers could result in the impairment of our assets, reduction of our operating cash flows and may also reduce or curtail their future use of our products and services, which could reduce our revenues.

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We provide certain transportation and storage services under fixed-price “negotiated rate” contracts that are not subject to adjustment, even if our cost to perform such services exceeds the revenues received from such contracts, and, as a result, our costs could exceed our revenues received under such contracts.
 
We have been authorized by the Federal Energy Regulatory Commission, or FERC, to provide transportation and storage services at our facilities at negotiated rates. Generally, negotiated rates are in excess of the maximum recourse rates allowed by FERC, but it is possible that costs to perform services under “negotiated rate” contracts will exceed the revenues obtained under these agreements. If this occurs, it could decrease the cash flow realized by our systems and, therefore, decrease the cash we have available for distribution to our unitholders.
 
As of December 31, 2016, approximately 54% of our contracted firm transportation capacity and 44% of our contracted firm storage capacity was subscribed under such “negotiated rate” contracts. These contracts generally do not include provisions allowing for adjustment for increased costs due to inflation, pipeline safety activities or other factors that are not tied to an applicable tracking mechanism authorized by FERC. Successful recovery of any shortfall of revenue, representing the difference between “recourse rates” (if higher) and negotiated rates, is not assured under current FERC policies.
 
If third-party pipelines and other facilities interconnected to our gathering, processing or transportation facilities become partially or fully unavailable to us for any reason, our financial position, results of operations and ability to make cash distributions to unitholders could be adversely affected.
 
We depend upon third-party pipelines to deliver natural gas to, and take natural gas from, our natural gas transportation systems and upon third party pipelines to take crude oil from our crude oil gathering systems. We also depend on third-party facilities to transport and fractionate NGLs that are delivered to the third party at the tailgates of our processing plants. Fractionation is the separation of the heterogeneous mixture of extracted NGLs into individual components for end-use sale. For example, an outage or disruption on certain pipelines or fractionators operated by a third party could result in the shutdown of certain of our processing plants and gathering systems, and a prolonged outage or disruption could ultimately result in a reduction in the volume of natural gas we gather and NGLs we are able to produce. Additionally, we depend on third parties to provide electricity for compression at many of our facilities. Since we do not own or operate any of these third-party pipelines or other facilities, their continuing operation is not within our control. If any of these third-party pipelines or other facilities become partially or fully unavailable to us for any reason, our financial position, results of operations and ability to make cash distributions to unitholders could be adversely affected.
 
We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations.
 
We do not own all of the land on which our pipelines and facilities have been constructed, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate. We may obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. A loss of these rights, through our inability to renew right-of-way contracts or otherwise, could cause us to cease operations temporarily or permanently on the affected land, increase costs related to the construction and continuing operations elsewhere, and adversely affect our financial position, results of operations and ability to make cash distributions to unitholders.
 
We conduct a portion of our operations through joint ventures, which subject us to additional risks that could adversely affect the success of these operations and our financial position, results of operations and ability to make cash distributions to unitholders.
 
We conduct a portion of our operations through joint ventures with third parties, including Spectra Energy Partners, LP, DCP Midstream Partners, LP, Trans Louisiana Gas Pipeline, Inc. and Pablo Gathering LLC. We may also enter into other joint venture arrangements in the future. These third parties may have obligations that are important to the success of the joint venture, such as the obligation to pay their share of capital and other costs of the joint venture. The performance of these third-party obligations, including the ability of the third parties to satisfy their obligations under these arrangements, is outside our control. If these parties do not satisfy their obligations under these arrangements, our business may be adversely affected.
 
Our joint venture arrangements may involve risks not otherwise present when operating assets directly, including, for example:
our joint venture partners may share certain approval rights over major decisions;

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our joint venture partners may not pay their share of the joint venture’s obligations, leaving us liable for their shares of joint venture liabilities;
we may be unable to control the amount of cash we will receive from the joint venture;
we may incur liabilities as a result of an action taken by our joint venture partners;
we may be required to devote significant management time to the requirements of and matters relating to the joint ventures;
our insurance policies may not fully cover loss or damage incurred by both us and our joint venture partners in certain circumstances;
our joint venture partners may be in a position to take actions contrary to our instructions or requests or contrary to our policies or objectives; and
disputes between us and our joint venture partners may result in delays, litigation or operational impasses.
The risks described above or the failure to continue our joint ventures or to resolve disagreements with our joint venture partners could adversely affect our ability to transact the business that is the subject of such joint venture, which would in turn adversely affect our financial position, results of operations and ability to make cash distributions to unitholders. The agreements under which we formed certain joint ventures may subject us to various risks, limit the actions we may take with respect to the assets subject to the joint venture and require us to grant rights to our joint venture partners that could limit our ability to benefit fully from future positive developments. Some joint ventures require us to make significant capital expenditures. If we do not timely meet our financial commitments or otherwise do not comply with our joint venture agreements, our rights to participate, exercise operator rights or otherwise influence or benefit from the joint venture may be adversely affected. Certain of our joint venture partners may have substantially greater financial resources than we have and we may not be able to secure the funding necessary to participate in operations our joint venture partners propose, thereby reducing our ability to benefit from the joint venture.
 
Under certain circumstances, Spectra Energy Partners, LP could have the right to purchase an ownership interest in SESH at fair market value.
 
We own a 50% ownership interest in SESH. The remaining 50% ownership interests are held by Spectra Energy Partners, LP. CenterPoint Energy owns 54.1% of our common and subordinated units, 100% of our Series A Preferred Units and a 40% economic interest in our general partner. Pursuant to the terms of the limited liability company agreement of SESH, as amended (the SESH LLC Agreement), if, at any time, CenterPoint Energy has a right to receive less than 50% of our distributions through its interests in us and in our general partner, or does not have the ability to exercise certain control rights, Spectra Energy Partners, LP could have the right to purchase our interest in SESH at fair market value, subject to certain exceptions.
 
An impairment of long-lived assets, including intangible assets, equity method investments or goodwill could reduce our earnings.

Long-lived assets, including intangible assets with finite useful lives and property, plant and equipment, are evaluated for impairment when events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment of long-lived assets is recognized if the carrying amount is not recoverable and exceeds fair value. For example, we recorded aggregate impairments for our Service Star business line of $38 million during the years ended December 31, 2016, 2015, 2014 and 2013, a $25 million impairment of our Atoka assets in our gathering and processing segment during the year ended December 31, 2015, and a $12 million impairment of jurisdictional pipelines in our transportation and storage segment during the year ended December 31, 2015.

Equity method investments are evaluated for impairment when events or circumstances indicate that the carrying value of the investment might not be recoverable. An impairment of an equity method investment is recognized if the fair value of the investment as a whole, and not the underlying assets, has declined and the decline is other than temporary. An example of an investment that we account for under the equity method is our investment in SESH. If we enter into additional joint ventures, we could have additional equity method investments.

Goodwill is evaluated for impairment on an annual basis as well as when events or circumstances change that would more likely than not reduce the fair value of a reporting unit is below its carrying amount. An impairment of goodwill is recognized if the carrying value of a reporting unit exceeds its fair value and the carrying amount of that reporting unit’s good will exceeds the implied value of that goodwill. For example, we recorded impairments to goodwill of $1,087 million during the year ended December 31, 2015. Although as a result of these impairments we had no goodwill recorded as of December 31, 2016 or 2015, we could record goodwill as a result of future acquisitions.

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We could experience future events or circumstances that result in an impairment of long-lived assets, including intangible assets, equity method investments, or goodwill. If we recognize an impairment, we would take an immediate non-cash charge to earnings with a correlative effect on equity and balance sheet leverage as measured by debt to total capitalization. As a result, an impairment could have an adverse effect on our results of operations and our ability to satisfy the financial ratios or other covenants under our existing or future debt agreements.

Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. Insufficient insurance coverage and increased insurance costs could adversely affect our financial position, results of operations and our ability to make cash distributions to unitholders.
 
Our operations are subject to all of the risks and hazards inherent in the gathering, processing, transportation and storage of natural gas and crude oil, including:
damage to pipelines and plants, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters, acts of terrorism and actions by third parties;
inadvertent damage from construction, vehicles, farm and utility equipment;
leaks of natural gas, NGLs, crude oil and other hydrocarbons or losses of natural gas, NGLs and crude oil as a result of the malfunction of equipment or facilities;
ruptures, fires and explosions; and
other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.
These risks could result in substantial losses due to personal injury or loss of life, severe damage to and destruction of property, plant and equipment and pollution or other environmental damage. These risks may also result in curtailment or suspension of our operations. A natural disaster or other hazard affecting the areas in which we operate could adversely affect our results of operations. We are not fully insured against all risks inherent in our business. We currently have general liability and property insurance in place to cover certain of our facilities in amounts that we consider appropriate. Such policies are subject to certain limits and deductibles. We have business interruption insurance coverage for some but not all of our operations. Insurance coverage may not be available in the future at current costs or on commercially reasonable terms, and the insurance proceeds received for any loss of, or any damage to, any of our facilities may not be sufficient to restore the loss or damage without adversely affecting our financial position, results of operations and our ability to make cash distributions to unitholders.
 
The use of derivative contracts by us and our subsidiaries in the normal course of business could result in financial losses that could adversely affect our financial position, results of operations and our ability to make cash distributions to unitholders.
 
We and our subsidiaries periodically use derivative instruments, such as swaps, options, futures and forwards, to manage our commodity and financial market risks. We and our subsidiaries could recognize financial losses as a result of volatility in the market values of these contracts, or should a counterparty fail to perform. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial instruments can involve management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.
 
Failure to attract and retain an appropriately qualified workforce could adversely impact our results of operations.
 
Our business is dependent on our ability to recruit, retain and motivate employees. Certain circumstances, such as an aging workforce without appropriate replacements, a mismatch of existing skill sets to future needs, competition for skilled labor or the unavailability of contract resources may lead to operating challenges such as a lack of resources, loss of knowledge or a lengthy time period associated with skill development. Our costs, including costs for contractors to replace employees, productivity costs and safety costs, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect our ability to manage and operate our business. If we are unable to successfully attract and retain an appropriately qualified workforce, our results of operations could be negatively affected.

We transitioned seconded employees from CenterPoint Energy and OGE Energy to the Partnership effective January 1, 2015, except for those 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. Employees of OGE Energy that we determine to hire are under no obligation to accept our offer of employment on the terms we provide, or at all.


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Our ability to grow is dependent on our ability to access external financing sources.
 
Our operating subsidiaries distribute all of their available cash to us, and we distribute all of our available cash to our unitholders. As a result, we and our operating subsidiaries rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund acquisitions and expansion capital expenditures. As a result, to the extent we or our operating subsidiaries are unable to finance growth externally, our and our operating subsidiaries’ cash distribution policy will significantly impair our and our operating subsidiaries’ ability to grow. In addition, because we and our operating subsidiaries distribute all available cash, our and our operating subsidiaries’ growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations.
 
To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level, which in turn may impact the available cash that we have to distribute on each unit. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt by us or our operating subsidiaries to finance our growth strategy would result in increased interest expense, which in turn may negatively impact the available cash that our operating subsidiaries have to distribute to us, and that we have to distribute to our unitholders.

We depend on access to the capital markets to fund our expansion capital expenditures. Historically, unit prices of midstream master limited partnerships have experienced periods of volatility. In addition, because our common units are yield-based securities, rising market interest rates could impact the relative attractiveness of our common units to investors. As a result of capital market volatility, we may be unable to issue equity or debt on satisfactory terms, or at all, which may limit our ability to expand our operations or make future acquisitions.
 
Our merger and acquisition activities may not be successful or may result in completed acquisitions that do not perform as anticipated, which could adversely affect our financial position, results of operations or future growth.
 
From time to time, we have made, and we intend to continue to make, acquisitions of businesses and assets. Such acquisitions involve substantial risks, including the following:
acquired businesses or assets may not produce revenues, earnings or cash flow at anticipated levels;
acquired businesses or assets could have environmental, permitting or other problems for which contractual protections prove inadequate;
we may assume liabilities that were not disclosed to us, that exceed our estimates, or for which our rights to indemnification from the seller are limited;
we may be unable to integrate acquired businesses successfully and realize anticipated economic, operational and other benefits in a timely manner, which could result in substantial costs and delays or other operational, technical or financial problems; and
acquisitions, or the pursuit of acquisitions, could disrupt our ongoing businesses, distract management, divert resources and make it difficult to maintain our current business standards, controls and procedures.
In addition, our growth strategy includes, in part, the ability to make acquisitions on economically acceptable terms. If we are unable to make acquisitions or if our acquisitions do not perform as anticipated, our future growth may be adversely affected.

Our and our operating subsidiaries’ debt levels may limit our and their flexibility in obtaining additional financing and in pursuing other business opportunities.
 
As of December 31, 2016, we had approximately $3 billion of long-term debt outstanding, excluding the premiums on senior notes. We have a $1.75 billion Revolving Credit Facility for working capital, capital expenditures and other partnership purposes, including acquisitions, of which $1.1 billion was available as of February 1, 2017. We have the ability to incur additional debt, subject to limitations in our credit facilities. The levels of our debt could have important consequences, including the following:
the ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or the financing may not be available on favorable terms, if at all;
a portion of cash flows will be required to make interest payments on the debt, reducing the funds that would otherwise be available for operations, future business opportunities and distributions;
our debt level will make us more vulnerable to competitive pressures or a downturn in our business or the economy generally; and

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our debt level may limit our flexibility in responding to changing business and economic conditions.
Our and our operating subsidiaries’ ability to service our and their debt will depend upon, among other things, their future financial and operating performance, which will be affected by prevailing economic conditions, commodity prices and financial, business, regulatory and other factors, some of which are beyond our and their control. If operating results are not sufficient to service our or our operating subsidiaries’ current or future indebtedness, we and they may be forced to take actions such as reducing distributions, reducing or delaying business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing debt, or seeking additional equity capital. These actions may not be effected on satisfactory terms, or at all. Please see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”
 
Our credit facilities contain operating and financial restrictions, including covenants and restrictions that may be affected by events beyond our control, which could adversely affect our financial condition, results of operations and ability to make cash distributions to our unitholders.
 
Our credit facilities contain customary covenants that, among other things, limit our ability to:
permit our subsidiaries to incur or guarantee additional debt;
incur or permit to exist certain liens on assets;
dispose of assets;
merge or consolidate with another company or engage in a change of control;
enter into transactions with affiliates on non-arm’s length terms; and
change the nature of our business.
Our credit facilities also require us to maintain certain financial ratios. Our ability to meet those financial ratios can be affected by events beyond our control, and we cannot assure you that we will meet those ratios. In addition, our credit facilities contain events of default customary for agreements of this nature.

Our ability to comply with the covenants and restrictions contained in our credit facilities may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, ratios or tests in our credit facilities, a significant portion of our indebtedness may become immediately due and payable. In addition, our lenders’ commitments to make further loans to us under the Revolving Credit Facility may be suspended or terminated. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. Please see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”
 
Affiliates of our general partner, including CenterPoint Energy and OGE Energy, may compete with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to us.
 
Under our omnibus agreement, CenterPoint Energy, OGE Energy and their affiliates have agreed to hold or otherwise conduct all of their respective midstream operations located within the United States through us. This requirement will cease to apply to both CenterPoint Energy and OGE Energy as soon as either CenterPoint Energy or OGE Energy ceases to hold any interest in our general partner or at least 20% of our common units. In addition, if CenterPoint Energy or OGE Energy acquires any assets or equity of any person engaged in midstream operations with a value in excess of $50 million (or $100 million in the aggregate with such party’s other acquired midstream operations that have not been offered to us), the acquiring party will be required to offer to us such assets or equity for such value. If we do not purchase such assets, the acquiring party will be free to retain and operate such midstream assets, so long as the value of the assets does not reach certain thresholds.
 
As a result, under the circumstances described above, CenterPoint Energy and OGE Energy have the ability to construct or acquire assets that directly compete with our assets. Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers and directors and CenterPoint Energy and OGE Energy. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our common unitholders.
 

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If we fail to maintain an effective system of internal controls, then we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our common units.
 
Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If our efforts to maintain internal controls are not successful, we are unable to maintain adequate controls over our financial processes and reporting in the future or we are unable to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002, our operating results could be harmed or we may fail to meet our reporting obligations. Ineffective internal controls also could cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common units.

Cyber-attacks, acts of terrorism or other disruptions could adversely impact our financial position, results of operations and ability to make cash distributions to unitholders.
 
We are subject to cyber-security risks related to breaches in the systems and technology that we use (i) to manage our operations and other business processes and (ii) to protect sensitive information maintained in the normal course of our businesses. The gathering, processing and transportation of natural gas from our gathering, processing and pipeline facilities and crude oil gathering pipeline systems are dependent on communications among our facilities and with third-party systems that may be delivering natural gas or crude oil into or receiving natural gas or crude oil and other products from our facilities. Disruption of those communications, whether caused by physical disruption such as storms or other natural phenomena, by failure of equipment or technology, or by manmade events, such as cyber-attacks or acts of terrorism, may disrupt our ability to deliver natural gas and control these assets. Cyber-attacks could also result in the loss of confidential or proprietary data or security breaches of other information technology systems that could disrupt our operations and critical business functions, adversely affect our reputation, and subject us to possible legal claims and liability. We are not fully insured against all cyber-security risks. In addition, our natural gas pipeline systems may be targets of terrorist activities that could disrupt our ability to conduct our business. It is possible that any of these occurrences, or a combination of them, could adversely affect our financial position, results of operations, and ability to make cash distributions to unitholders.
 
We may be unable to obtain or renew permits necessary for our operations, which could inhibit our ability to do business.
 
Performance of our operations require that we obtain and maintain a number of federal and state permits, licenses and approvals with terms and conditions containing a significant number of prescriptive limits and performance standards in order to operate. All of these permits, licenses, approval limits and standards require a significant amount of monitoring, record keeping and reporting in order to demonstrate compliance with the underlying permit, license, approval limit or standard. Noncompliance or incomplete documentation of our compliance status may result in the imposition of fines, penalties and injunctive relief. A decision by a government agency to deny or delay the issuance of a new or existing material permit or other approval, or to revoke or substantially modify an existing permit or other approval, could adversely affect our ability to initiate or continue operations at the affected location or facility and on our financial condition, results of operations and ability to make cash distributions to unitholders.
 
Additionally, in order to obtain permits and renewals of permits and other approvals in the future, we may be required to prepare and present data to governmental authorities pertaining to the potential adverse impact that any proposed pipeline or processing-related activities may have on the environment, individually or in the aggregate, including on public and Indian lands. Certain approval procedures may require preparation of archaeological surveys, endangered species studies and other studies to assess the environmental impact of new sites or the expansion of existing sites. Compliance with these regulatory requirements is expensive and significantly lengthens the time required to prepare applications and to receive authorizations.
 
Costs of compliance with existing environmental laws and regulations are significant, and the cost of compliance with future environmental laws and regulations may adversely affect our financial position, results of operations and ability to make cash distributions to unitholders.
 
We are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, wildlife conservation, natural resources and health and safety that could, among other things, delay or increase our costs of construction, restrict or limit the output of certain facilities and/or require additional pollution control equipment and otherwise increase costs. For instance, in May 2016, the EPA issued final NSPS governing methane emissions imposing more stringent controls on methane and volatile organic compounds emissions at new and modified oil and natural gas production, processing, storage, and transmission facilities. These rules have required changes to our operations, including the installation of new equipment to control emissions. The EPA has also announced that it intends to impose methane emission standards for existing sources and has issued information collection requests to companies with production, gathering and boosting,

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gas processing, storage, and transmission facilities. Additionally, several states are pursuing similar measures to regulate emissions of methane from new and existing sources. There are significant capital, operating and other costs associated with compliance with these environmental statutes, rules and regulations. As a result of this continued regulatory focus, future federal and state regulations relating to our gathering and processing, transmission, and storage operations remain a possibility and could result in increased compliance costs on our operations. Furthermore, if new or more stringent federal, state or local legal restrictions are adopted in areas where our oil and natural gas exploration and production customers operate, they could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells, some or all of which could adversely affect demand for our services to those customers.
 
There is inherent risk of the incurrence of environmental costs and liabilities in our operations due to our handling of natural gas, NGLs, crude oil, and produced water, as well as air emissions related to our operations and historical industry operations and waste disposal practices. These matters are subject to stringent and complex federal, state and local laws and regulations governing environmental protection, including the discharge of materials into the environment and the protection of plants, wildlife, and natural and cultural resources. These laws and regulations can restrict or impact our business activities in many ways, such as restricting the way we can handle or dispose of wastes or requiring remedial action to mitigate pollution conditions that may be caused by our operations or that are attributable to former operators. Joint and several strict liability may be incurred, without regard to fault, under certain of these environmental laws and regulations in connection with discharges or releases of wastes on, under or from our properties and facilities, many of which have been used for midstream activities for a number of years, oftentimes by third parties not under our control. Private parties, including the owners of the properties through which our gathering systems pass and facilities where our wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for non-compliance, with environmental laws and regulations or for personal injury or property damage. For example, an accidental release from one of our pipelines could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. We may be unable to recover these costs from insurance. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase compliance costs and the cost of any remediation that may become necessary. Further, stricter requirements could negatively impact our customers’ production and operations, resulting in less demand for our services.
 
Increased regulation of hydraulic fracturing could result in reductions or delays in natural gas production by our customers, which could adversely affect our financial position, results of operations and ability to make cash distributions to unitholders.
 
Hydraulic fracturing is common practice that is used by many of our customers to stimulate production of natural gas and crude oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing typically is regulated by state oil and natural gas commissions. In addition, certain federal agencies have proposed additional laws and regulations to more closely regulate the hydraulic fracturing process. For example, in May 2016, the EPA issued final new source performance standard requirements that impose more stringent controls on methane and volatile organic compounds emissions from oil and gas development and production operations, including hydraulic fracturing and other well completion activity. The EPA also released the final results of its comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on drinking water resources in December 2016. The EPA concluded that hydraulic fracturing activities can impact drinking water resources under some circumstances, including large volume spills and inadequate mechanical integrity of wells. The results of EPA’s study could spur action towards federal legislation and regulation of hydraulic fracturing or similar production operations. In past sessions, Congress has considered, but not passed, legislation to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act (SDWA) and to require disclosure of the chemicals used in the hydraulic fracturing process. The EPA has issued SDWA permitting guidance for hydraulic fracturing operations involving the use of diesel fuel in fracturing fluids in those states where the EPA is the permitting authority. Additionally, the Bureau of Land Management issued final rules to regulate hydraulic fracturing on federal lands in March 2015. Although these rules were struck down by a federal court in Wyoming in June 2016, an appeal of the decision is still pending.

Some states have adopted, and other states are considering adopting, legal requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular, in some cases banning hydraulic fracturing entirely. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where our oil and natural gas exploration and production customers operate, they could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells, some or all of which activities could adversely affect demand for our services to those customers.
 

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State and federal regulatory agencies recently have focused on a possible connection between the operation of injection wells used for oil and gas waste disposal and seismic activity. Similar concerns have been raised that hydraulic fracturing may also contribute to seismic activity. When caused by human activity, such events are called induced seismicity. In March 2016, the United States Geological Survey identified six states with the most significant hazards from induced seismicity, including Oklahoma, Kansas, Texas, Colorado, New Mexico, and Arkansas. In light of these concerns, some state regulatory agencies have modified their regulations or issued orders to address induced seismicity. For example, the Oklahoma Corporation Commission (OCC) has implemented volume reduction plans, and at times required shut-ins, for disposal wells injecting wastewater from oil and gas operations into the Arbuckle formation. The OCC also recently released well completion seismicity guidelines for operators in the SCOOP and STACK that call for hydraulic fracturing operations to be suspended following earthquakes of certain magnitudes in the vicinity. Certain environmental and other groups have also suggested that additional federal, state and local laws and regulations may be needed to more closely regulate the hydraulic fracturing process. We cannot predict whether additional federal, state or local laws or regulations applicable to hydraulic fracturing will be enacted in the future and, if so, what actions any such laws or regulations would require or prohibit. Increased regulation and attention given to induced seismicity could lead to greater opposition to, and litigation concerning, oil and gas activities utilizing hydraulic fracturing or injection wells for waste disposal. Additional legislation or regulation could also lead to operational delays or increased operating costs for our customers, which in turn could reduce the demand for our services.

Other governmental agencies, including the U.S. Department of Energy, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms.

Our operations may incur substantial liabilities to comply with climate change legislation and regulatory initiatives.
 
Because our operations emit various types of greenhouse gases, legislation and regulations governing greenhouse gas emissions could increase our costs related to operating and maintaining our facilities, and could delay future permitting. At the federal level, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, require the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sources in the United States on an annual basis, which include certain of our operations. Additional rules, such as the updates to the oil and gas new source performance standard requirements finalized by the EPA in May 2016 could affect our ability to obtain air permits for new or modified facilities or require our operations to incur additional expenses to control air emissions by installing emissions control technologies and adhering to a variety of work practice and other requirements. These requirements could increase the costs of development and production, reducing the profits available to us and potentially impairing our operator’s ability to economically develop our properties.

In addition, the U.S. Congress has in the past and may in the future consider legislation to reduce emissions of greenhouse gases, and there has been a wide-ranging policy debate, both nationally and internationally, regarding the impact of these gases and possible means for their regulation. Efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. In 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement opened for signing on April 22, 2016 and requires countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. A number of state and regional efforts have also emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. Any such future laws and regulations imposing reporting obligations on, or limiting emissions of, GHGs could require us to incur costs to reduce emissions of GHGs. Substantial limitations on GHG emissions could also adversely affect demand for oil and natural gas. Depending on the particular program, we could in the future be required to purchase and surrender emission allowances or otherwise undertake measures to reduce greenhouse gas emissions. Any additional costs or operating restrictions associated with new legislation or regulations regarding greenhouse gas emissions could adversely affect the demand for our services and our financial position, results of operations and ability to make cash distributions to unitholders.

Increased regulatory-imposed costs may increase the cost of consuming, and thereby reduce demand for, the products that we gather, treat and transport. To the extent financial markets view climate change and emissions of greenhouse gases as a financial risk, this view could negatively affect our ability to access capital markets or cause us to receive less favorable terms and conditions. Consequently, legislation and regulatory initiatives aimed at reducing greenhouse gases could have a material adverse effect on our financial position, results of operations and ability to make cash distributions to unitholders.

Finally, some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could adversely affect our results of operations.

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Our operations are subject to extensive regulation by federal regulatory authorities. Changes or additional regulatory measures adopted by such authorities could adversely affect our financial position, results of operations and ability to make cash distributions to unitholders.
 
The rates charged by several of our pipeline systems, including for interstate gas transportation service provided by our intrastate pipelines, are regulated by FERC. FERC and state regulatory agencies also regulate other terms and conditions of the services we may offer. If one of these regulatory agencies, on its own initiative or due to challenges by third parties, were to lower our tariff rates or deny any rate increase or other material changes to the types, or terms and conditions, of service we might propose or offer, the profitability of our pipeline businesses could suffer. If we were permitted to raise our tariff rates for a particular pipeline, there might be significant delay between the time the tariff rate increase is approved and the time that the rate increase actually goes into effect, which could also limit our profitability. Furthermore, competition from other pipeline systems may prevent us from raising our tariff rates even if regulatory agencies permit us to do so. The regulatory agencies that regulate our systems periodically implement new rules, regulations and terms and conditions of services subject to their jurisdiction. New initiatives or orders may adversely affect the rates charged for our services or otherwise adversely affect our financial position, results of operations and ability to make cash distributions to our unitholders.
 
Our natural gas interstate pipelines are regulated by FERC under the Natural Gas Act of 1938, or NGA, the Natural Gas Policy Act of 1978, or the NGPA, and the Energy Policy Act of 2005, or EPAct of 2005. Generally, FERC’s authority over interstate natural gas transportation extends to:
rates, operating terms, conditions of service and service contracts;
certification and construction of new facilities;
extension or abandonment of services and facilities or expansion of existing facilities;
maintenance of accounts and records;
acquisition and disposition of facilities;
initiation and discontinuation of services;
depreciation and amortization policies;
conduct and relationship with certain affiliates;
market manipulation in connection with interstate sales, purchases or natural gas transportation; and
various other matters.
Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under EPACT 2005, FERC has civil penalty authority under the NGA and the NGPA to impose penalties for current violations of up to $1 million per day for each violation and possible criminal penalties of up to $1 million per violation.

FERC’s jurisdiction extends to the certification and construction of interstate transportation and storage facilities, including, but not limited to expansions, lateral and other facilities and abandonment of facilities and services. Prior to commencing construction of significant new interstate transportation and storage facilities, an interstate pipeline must obtain a certificate authorizing the construction, or an order amending its existing certificate, from FERC. Certain minor expansions are authorized by blanket certificates that FERC has issued by rule. Typically, a significant expansion project requires review by a number of governmental agencies, including state and local agencies, whose cooperation is important in completing the regulatory process on schedule. Any failure by an agency to issue sufficient authorizations or permits in a timely manner for one or more of these projects may mean that we will not be able to pursue these projects or that they will be constructed in a manner or with capital requirements that we did not anticipate. Our inability to obtain sufficient permits and authorizations in a timely manner could materially and negatively impact the additional revenues expected from these projects.
 
FERC conducts audits to verify compliance with FERC’s regulations and the terms of its orders, including whether the websites of interstate pipelines accurately provide information on the operations and availability of services. FERC’s regulations require uniform terms and conditions for service, as set forth in agreements for transportation and storage services executed between interstate pipelines and their customers. These service agreements are required to conform, in all material respects, with the standard form of service agreements set forth in the pipeline’s FERC-approved tariff. Non-conforming agreements must be filed with, and accepted by, the FERC. In the event that FERC finds that an agreement, in whole or part, is materially non-conforming, it could reject the agreement or require us to seek modification, or alternatively require us to modify our tariff so that the non-conforming provisions are generally available to all customers.
 

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The rates, terms and conditions for transporting natural gas in interstate commerce on certain of our intrastate pipelines and for services offered at certain of our storage facilities are subject to the jurisdiction of FERC under Section 311 of the NGPA. Rates to provide such interstate transportation service must be “fair and equitable” under the NGPA and are subject to review, refund with interest if found not to be fair and equitable, and approval by FERC at least once every five years.
 
Our crude oil gathering pipelines are subject to common carrier regulation by FERC under the Interstate Commerce Act, or ICA. The ICA requires that we maintain tariffs on file with FERC setting forth the rates we charge for providing transportation services, as well as the rules and regulations governing such services. The ICA requires, among other things, that our rates must be “just and reasonable” and that we provide service in a manner that is nondiscriminatory. Shippers on our crude oil gathering pipelines may protest our tariff filings, file complaints against our existing rates, or FERC can investigate our rates on its own initiative. In the event that FERC finds that our existing or proposed rates are unjust and unreasonable, it could deny requested rate increases or could order us to reduce our rates and could require the payment of reparations to complaining shippers for up to two years prior to the complaint.
 
Our operations may also be subject to regulation by state and local regulatory authorities. Changes or additional regulatory measures adopted by such authorities could adversely affect our financial position, results of operations and ability to make cash distributions to unitholders.
 
Our pipeline operations that are not regulated by FERC may be subject to state and local regulation applicable to intrastate natural and transportation services. The relevant states in which we operate include North Dakota, Oklahoma, Arkansas, Louisiana, Texas, Missouri, Kansas, Mississippi, Tennessee and Illinois. State and local regulations generally focus on safety, environmental and, in some circumstances, prohibition of undue discrimination among shippers. Additional rules and legislation pertaining to these matters are considered and, in some instances, adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but we could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes. Other state and local regulations also may affect our business. Any such state or local regulation could have an adverse effect on our business and our financial position, results of operations and ability to make cash distributions to unitholders.
 
Our gathering lines may be subject to ratable take and common purchaser statutes. Ratable take statutes generally require gatherers to take, without undue discrimination, oil or natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes restrict our right as an owner of gathering facilities to decide with whom we contract to purchase or transport oil or natural gas. Federal law leaves economic regulation of natural gas gathering to the states. The states in which we operate have adopted complaint-based regulation of oil and natural gas gathering activities, which allows oil and natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to access to oil and natural gas gathering pipelines and rate discrimination.
 
Other state regulations may not directly regulate our business, but may nonetheless affect the availability of natural gas for processing, including state regulation of production rates and maximum daily production allowable from gas wells. While our gathering lines are currently subject to limited state regulation, there is a risk that state laws will be changed, which may give producers a stronger basis to challenge the regulatory status of a line, or the rates, terms and conditions of a gathering line providing transportation service.
 
A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.
 
Our natural gas gathering and intrastate transportation operations are generally exempt from the jurisdiction of FERC under the NGA, but FERC regulation may indirectly impact these businesses and the markets for products derived from these businesses. FERC’s policies and practices across the range of its oil and natural gas regulatory activities, including, for example, its policies on interstate open access transportation, ratemaking, capacity release, and market center promotion may indirectly affect intrastate markets. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate oil and natural gas pipelines. However, we cannot assure you that FERC will continue to pursue this approach as it considers matters such as pipeline rates and rules and policies that may indirectly affect the intrastate natural gas transportation business. Although FERC has not made a formal determination with respect to all of our facilities we consider to be gathering facilities, management believes that our natural gas gathering pipelines meet the traditional tests that FERC has used to determine that a pipeline is a gathering pipeline and are therefore not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our gathering facilities is subject to change based on future

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determinations by FERC, the courts or Congress. If FERC were to consider the status of an individual facility and determine that the facility and/or services provided by it are not exempt from FERC regulation under the NGA and that the facility provides interstate service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by FERC under the NGA or the NGPA. Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our financial condition, results of operations and ability to make cash distributions to our unitholders. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of substantial civil penalties, as well as a requirement to disgorge revenues collected for such services in excess of the maximum rates established by FERC.
 
Natural gas gathering may receive greater regulatory scrutiny at the state level; therefore, our natural gas gathering operations could be adversely affected should they become subject to the application of state regulation of rates and services. Our gathering operations could also be subject to safety and operational regulations relating to the design, construction, testing, operation, replacement and maintenance of gathering facilities. We cannot predict what effect, if any, such changes might have on our operations, but we could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

We may incur significant costs and liabilities resulting from compliance with pipeline safety laws and regulations, pipeline integrity and other similar programs and related repairs.

Our interstate pipeline operations are subject to certain pipeline safety laws and regulations administered by the U.S. Department of Transportation’s (DOT) Pipeline and Hazardous Materials Safety Administration (PHMSA). These laws and regulations require us to comply with a significant set of requirements for the design, construction, maintenance and operation of our interstate pipelines. Among other things, these laws and regulations require pipeline operators to develop integrity management programs for interstate pipelines located in “high consequence areas.” The regulations require operators, including us, to, among other things:
perform ongoing assessments of pipeline integrity;
develop a baseline plan to prioritize the assessment of a covered pipeline segment;
identify and characterize applicable threats that could impact a high consequence area;
improve data collection, integration, and analysis;
repair and remediate pipelines as necessary; and
implement preventive and mitigating action.

Failure to comply with applicable regulations could result in a number of consequences which may have an adverse effect on our operations.

Changes to pipeline safety laws and regulations that result in more stringent or costly safety standards could have a significant adverse effect on us. For example, in August 2011, PHMSA published an advance notice of proposed rulemaking (ANPRM) in which the agency was seeking public comment on a number of changes to regulations governing the safety of gas transmission pipelines and gathering lines, including, for example, revising the definitions of “high consequence areas” and “gathering lines” and strengthening integrity management requirements as they apply to existing regulated operators and to currently exempt operators should certain exemptions be removed. On April 8, 2016, the Pipeline and Hazardous Materials Safety Administration published a notice of proposed rulemaking (NPRM) responding to several of the integrity management topics raised in the August 2011 ANPRM and proposing new requirements to address safety issues for natural gas transmission and gathering lines that have arisen since the issuance of the ANPRM. The proposed rule would strengthen existing integrity management requirements, expand assessment and repair requirements to pipelines in areas with medium population densities, and extend regulatory requirements to onshore gas gathering lines that are currently exempt. Comments were due July 7, 2016. PHMSA issued, but has yet to publish, a similar rule for hazardous liquids (including oil) pipelines on January 13, 2017. This rule extends regulatory reporting requirements to all liquid gathering lines, require additional event-driven and periodic inspections, require use of leak detection systems on all hazardous liquid pipelines, modify repair criteria, and require certain pipelines to eventually accommodate inline inspection tools. It is unclear when or if this rule will go into effect as, on January 20, 2017, the Trump Administration requested that all regulations that had been sent to the Office of the Federal Register, but not yet published, be immediately withdrawn for further review. We are still monitoring and evaluating the effect of these requirements and proposals on our operations.

Although many of our pipelines fall within a class that is currently not subject to regulation by PHMSA, we may incur significant cost and liabilities associated with repair, remediation, preventive or mitigation measures associated with our non-exempt pipelines. This work is part of our normal integrity management program and we do not expect to incur any extraordinary

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costs during 2017 to complete the testing required by existing PHMSA regulations and their state counterparts. We have not estimated the costs for any repair, remediation, preventive or mitigation actions that may be determined to be necessary as a result of the testing program, which could be substantial, or any lost cash flows resulting from shutting down our pipelines during the pendency of such repairs. Should we fail to comply with PHMSA or comparable state regulations, we could be subject to penalties and fines. In addition, proposed rulemakings such as the NPRMs published on October 13, 2015 and April 8, 2016 could expand the scope of the natural gas and hazardous liquids integrity management programs and other related pipeline safety regulations to include additional requirements or previously exempt pipelines. We have not estimated the cost of complying with such proposed changes to the regulations administered by PHMSA.

Financial reform regulations under the Dodd-Frank Act could adversely affect our ability to use derivative instruments to hedge risks associated with our business.

At times, we may hedge all or a portion of our commodity risk and our interest rate risk. The federal government regulates the derivatives markets and entities, including businesses like ours, that participate in those markets through the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, which requires the Commodity Futures Trading Commission, or the CFTC, and the SEC to promulgate rules and regulations implementing the legislation. Under the CFTC’s regulations, we are subject to reporting and recordkeeping obligations for transactions involving non-financial swap transactions. The CFTC initially adopted regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents, but these rules were successfully challenged in federal district court by the Securities Industry Financial Markets Association and the International Swaps and Derivatives Association and largely vacated by the court. In December 2013, the CFTC published a Notice of Proposed Rulemaking designed to implement new position limits regulation and in December 2016, the CFTC re-proposal position limits regulations. The ultimate form and timing of the implementation of the regulatory regime affecting commodity derivatives remains uncertain.
 
The CFTC has imposed mandatory clearing requirements on certain categories of swaps, including certain interest rate swaps, but has exempted derivatives intended to hedge or mitigate commercial risk from the mandatory swap clearing requirement, where the counterparty such as us has a required identification number, is not a financial entity as defined by the regulations, and meets a minimum asset test. Management believes our hedging transactions qualify for this “commercial end-user” exception. The Dodd-Frank Act may also require us to comply with margin requirements in connection with our hedging activities, although the application of those provisions to us is uncertain at this time. The Dodd-Frank Act may also require the counterparties to our derivative instruments to spin off some of their hedging activities to a separate entity, which may not be as creditworthy as the current counterparty.
 
The Dodd-Frank Act and related regulations could significantly increase the cost of derivatives contracts for our industry (including requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivatives contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivatives contracts, and increase our exposure to less creditworthy counterparties, particularly if we are unable to utilize the commercial end user exception with respect to certain of our hedging transactions. If we reduce our use of hedging as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures and fund unitholder distributions. Finally, the legislation was intended, in part, to reduce the volatility of crude oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to crude oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could adversely affect our financial position, results of operations and our ability to make cash distributions to unitholders.


Risks Related to an Investment in Us
 
Our general partner and its affiliates, including CenterPoint Energy and OGE Energy, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to the detriment of us and our other common unitholders.

Affiliates of CenterPoint Energy and OGE Energy own and control our general partner and appoint all of the directors of our general partner. Some of the directors of our general partner are appointed to represent CenterPoint Energy or OGE Energy and are also officers and/or directors of CenterPoint Energy or OGE Energy, respectively. Although our general partner has a duty to manage us in a manner that is beneficial to us and our unitholders, the directors of our general partner who are appointed to represent CenterPoint Energy or OGE Energy have a fiduciary duty to perform their obligations as directors in a manner that is beneficial to CenterPoint Energy or OGE Energy, respectively. Conflicts of interest will arise between CenterPoint Energy, OGE

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Energy and our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of CenterPoint Energy and OGE Energy over our interests and the interests of our unitholders. These conflicts include the following situations, among others:

Neither the Partnership Agreement nor any other agreement requires CenterPoint Energy or OGE Energy to pursue a business strategy that favors us. The directors and officers of CenterPoint Energy and OGE Energy have a fiduciary duty to make decisions in the best interests of the stockholders of their respective companies, which may be contrary to our interests. CenterPoint Energy and OGE Energy may choose to shift the focus of their investment and growth to areas not served by our assets. In addition, CenterPoint Energy is the holder of our Series A Preferred Units and may favor its interests in voting in favor of actions relating to such units, including voting in favor of making distributions on such Series A Preferred Units even if no distributions are made on the common units.
Our general partner is allowed to take into account the interests of parties other than us, such as CenterPoint Energy and OGE Energy, in resolving conflicts of interest.
Some of the directors of our general partner are also officers and/or directors of CenterPoint Energy or OGE Energy and will owe fiduciary duties to their respective companies. These individuals may also devote significant time to the business of CenterPoint Energy and OGE Energy.
The Partnership Agreement replaces the fiduciary duties that would otherwise be owed to us by our general partner with contractual standards governing its duties, limits our general partner’s liabilities and restricts the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty.
Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.
Disputes may arise under our commercial agreements with CenterPoint Energy and OGE Energy.
Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership units and the creation, reduction or increase of cash reserves, each of which can affect the amount of distributable cash flow.
Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion or investment capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and the ability of the subordinated units to convert to common units.
Our general partner determines which costs incurred by it and its affiliates are reimbursable by us.
Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period.
The Partnership Agreement permits us to classify up to $300 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated or general partner units or to our general partner in respect of the incentive distribution rights.
The Partnership Agreement does not prohibit our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.
Our general partner intends to limit its liability regarding our contractual and other obligations.
Our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 90% of the common units. If our general partner and its affiliates reduce their ownership percentage to below 70% of the outstanding units, the ownership threshold to exercise the call right will be permanently reduced to 80%.
Our general partner controls the enforcement of the obligations that it and its affiliates owe to us.
Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
Our general partner may transfer its incentive distribution rights without unitholder approval.
Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of the Board of Directors or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.
 

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If a unitholder is not an Eligible Holder, the unitholder’s common units may be subject to redemption.
 
Our partnership agreement includes certain requirements regarding those investors who may own our common, subordinated, and preferred units. Eligible Holders are limited partners whose (i) federal income tax status is not reasonably likely to have a material adverse effect on the rates that can be charged by us on assets that are subject to regulation by FERC or an analogous regulatory body and (ii) nationality, citizenship or other related status would not create a substantial risk of cancellation or forfeiture of any property in which we have an interest, in each case as determined by our general partner with the advice of counsel. If the unitholder is not an Eligible Holder, in certain circumstances as set forth in our partnership agreement, the unitholder’s units may be redeemed by us at the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.
 
Our partnership agreement requires that we distribute all of our available cash to our unitholders and will rely primarily upon external financing sources, including commercial borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.
 
In addition, because we intend to distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement or in our credit facilities that limit our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which in turn may impact the available cash that we have to distribute to our unitholders.
 
The reimbursements due to our general partner and its affiliates for services provided to us or on our behalf will reduce our distributable cash flow. The amount and timing of such reimbursements will be determined by our general partner.
 
Prior to making any distribution on our common units, we will reimburse our general partner and its affiliates, including CenterPoint Energy and OGE Energy, for costs and expenses they incur and payments they make on our behalf. Pursuant to services agreements we have entered into with each of CenterPoint Energy and OGE Energy, we will reimburse CenterPoint Energy and OGE Energy for the payment of operating expenses related to our operations and for the provision of various general and administrative services performed for our benefit. Payments for these services may be substantial and will reduce the amount of distributable cash flow. Additionally, we will reimburse CenterPoint Energy and OGE Energy for direct or allocated costs and expenses incurred on our behalf, including administrative costs, such as compensation expense for those persons who provide services necessary to run our business, and insurance expenses. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of available cash to pay cash distributions to our common unitholders.
 
Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.
 
We cannot assure you that our credit ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances warrant. 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 paper program upon maturity and did not issue any additional commercial paper. If either, or both, of Moody’s Investors Service or Fitch Ratings lowers its credit ratings of the Partnership from an investment grade rating to a non-investment grade rating while our rating from Standard & Poor’s Ratings Services is below investment grade, the cost of our borrowings will increase. So long as any of our credit ratings are below investment grade, we may have higher future borrowing costs and we or our subsidiaries may be required to post cash collateral or letters of credit under certain contractual agreements. If cash collateral requirements were to occur at a time when we were experiencing significant working capital requirements or otherwise lacked liquidity, our financial position, results of operations and ability to make cash distributions to unitholders could be adversely affected.


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The credit and business risk profiles and the business plans of our sponsors, CenterPoint Energy and OGE Energy, could adversely affect our credit ratings and profile.
 
The credit and business risk profiles and the business plans of our sponsors, CenterPoint Energy and OGE Energy, may be factors in credit evaluations of us because, through their indirect ownership of our general partner, they can influence our business activities, including our cash distribution strategy, acquisition strategy, and business risk profile. The financial conditions of CenterPoint Energy and OGE Energy, including the degree of their financial leverage and their dependence on cash flows from us, as well as their business plans with respect to their investment in us, may be considered by credit rating agencies in their assessment of our credit ratings and profile.
 
CenterPoint Energy and OGE Energy, which indirectly own our general partner, have indebtedness outstanding and are partially dependent on the cash distributions from their general partner and limited partner interests in us to service such indebtedness and pay dividends on their common stock. Any distributions by us to such entities will be made only after satisfying our then-current obligations to our creditors. Our credit ratings and business risk profile could be adversely affected if the ratings and risk profiles of the entities that control our general partner were viewed as substantially lower or more risky than ours.
 
Our partnership agreement replaces our general partner’s fiduciary duties to holders of our common units with contractual standards governing its duties.
 
Our partnership agreement contains provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law and replaces those duties with several different contractual standards. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, free of any duties to us and our unitholders other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the partners where the language in the partnership agreement does not provide for a clear course of action. This provision entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:
how to allocate corporate opportunities among us and its other affiliates;
whether to exercise its limited call right;
whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the Board of Directors;
whether to elect to reset target distribution levels;
whether to transfer the incentive distribution rights to a third party; and
whether or not to consent to any merger or consolidation of the Partnership or amendment to the partnership agreement.
By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the partnership agreement, including the provisions discussed above.

Our partnership agreement restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
 
Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:
whenever our general partner, the Board of Directors or any committee thereof (including the conflicts committee) makes a determination or takes, or declines to take, any other action in their respective capacities, our general partner, the Board of Directors and any committee thereof (including the conflicts committee), as applicable, is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was in the best interests of the Partnership, and, except as specifically provided by our partnership agreement, will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;
our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith;
our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in

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bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
our general partner will not be in breach of its obligations under the partnership agreement (including any duties to us or our unitholders) if a transaction with an affiliate or the resolution of a conflict of interest is:
approved by the conflicts committee of the Board of Directors, although our general partner is not obligated to seek such approval;
approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates;
determined by the Board of Directors to be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
determined by the Board of Directors to be fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.
In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner or the conflicts committee must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the Board of Directors determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in the third and fourth subbullets above, then it will be presumed that, in making its decision, the Board of Directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the Partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

Our general partner may elect to cause us to issue common units to it in connection with a resetting of the minimum quarterly distribution and the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of our general partner or our unitholders. This may result in lower distributions to our common unitholders in certain situations.
 
Our general partner has the right, at any time when there are no subordinated units outstanding, if it has received incentive distributions at the highest level to which it is entitled (50%) for each of the prior four consecutive fiscal quarters and the amount of each such distribution did not exceed the adjusted operating surplus for such quarter, respectively, to reset the initial minimum quarterly distribution and cash target distribution levels at higher levels based on the average cash distribution amount per common unit for the two fiscal quarters prior to the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the reset minimum quarterly distribution) and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution amount.
 
We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when our general partner expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, our general partner may be experiencing, or may be expected to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued our common units, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for the general partner to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then-current business environment. This risk could be elevated if our incentive distribution rights have been transferred to a third party. Our general partner has the right to transfer the incentive distribution rights at any time, in whole or in part, and any transferee holding a majority of the incentive distribution rights shall have the same rights as our general partner with respect to resetting target distributions. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued new common units to our general partner in connection with resetting the target distribution levels related to our general partner incentive distribution rights.
 
Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.
 
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders have no right to elect our general partner or its Board of Directors on an annual or other continuing basis. Because CenterPoint Energy and OGE

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Energy collectively indirectly own 100% of our general partner, the Board of Directors has been, and, as long as CenterPoint Energy and OGE Energy own 100% of our general partner, will continue to be, chosen by CenterPoint Energy and OGE Energy. Furthermore, if the unitholders were dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. Please see “—Even if holders of our common units are dissatisfied, they will not be able to remove our general partner without its consent.” As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

Even if holders of our common units are dissatisfied, they will not be able to remove our general partner without its consent.
 
The unitholders are unable to remove our general partner without its consent because affiliates of our general partner own sufficient units to be able to prevent its removal. The vote of the holders of at least 75% of all outstanding units voting together as a single class is required to remove our general partner. As of February 1, 2017, affiliates of our general partner owned 79.8% of our aggregate outstanding common and subordinated units. Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on our common units will be extinguished. A removal of our general partner under these circumstances would adversely affect our common units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. “Cause” is narrowly defined under our partnership agreement to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud or willful misconduct in its capacity as our general partner. “Cause” does not include most cases of charges of poor management of the business, so the removal of our general partner because of the unitholders’ dissatisfaction with our general partner’s performance in managing us will most likely result in the termination of the subordination period and conversion of all subordinated units to common units.
 
Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.
 
Unitholders’ voting rights are further restricted by a provision of our partnership agreement providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the Board of Directors, cannot vote on any matter.
 
Our general partner’s interest in us and control of our general partner may be transferred to a third party without unitholder consent.
 
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Our partnership agreement does not restrict the ability of the owners of our general partner from transferring all or a portion of their respective limited liability company interest in our general partner to a third party. The new owners of our general partner would then be in a position to replace the Board of Directors and officers of our general partner with its own choices and thereby influence the decisions taken by the Board of Directors and officers.
 
The incentive distribution rights of our general partner may be transferred to a third party without unitholder consent.
 
Our general partner may transfer its incentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers its incentive distribution rights to a third party but retains its general partner interest, our general partner may not have the same incentive to grow the Partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its incentive distribution rights. For example, a transfer of incentive distribution rights by our general partner could reduce the likelihood of CenterPoint Energy or OGE Energy selling or contributing additional assets to us, as they would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.
 
We may issue additional units without your approval, which would dilute your existing ownership interests.

The Partnership Agreement does not limit the number of additional limited partner interests, including limited partner interests that rank senior to the common units, that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

our existing unitholders’ proportionate ownership interest in us will decrease;

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the amount of distributable cash flow on each unit may decrease;
because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;
because the amount payable to holders of incentive distribution rights is based on a percentage of the total distributable cash flow, the distributions to holders of incentive distribution rights will increase even if the per unit distribution on common units remains the same;
the ratio of taxable income to distributions may increase;
the relative voting strength of each previously outstanding unit may be diminished; and
the market price of the common units may decline.

In addition, upon a change of control or certain fundamental transactions, our Series A Preferred Units are convertible into common units at the option of the holders of such units. If a substantial portion of the Series A Preferred Units were converted into common units, common unitholders could experience significant dilution. In addition, if holders of such converted Series A Preferred Units were to dispose of a substantial portion of these common units in the public market, whether in a single transaction or series of transactions, it could adversely affect the market price for our common units. In addition, these sales, or the possibility that these sales may occur, could make it more difficult for us to sell our common units in the future.

Affiliates of our general partner may sell common units in the public or private markets, which could have an adverse impact on the trading price of the common units.
 
As of February 1, 2017, subsidiaries of CenterPoint Energy and OGE Energy held an aggregate of 136,983,998 common units and 207,855,430 subordinated units and CenterPoint Energy held 14,520,000 Series A Preferred Units. Upon a change of control or certain fundamental transactions, our Series A Preferred Units are convertible into common units at the option of the holders of such units. All of the subordinated units will convert into common units at the end of the subordination period and some may convert earlier under certain circumstances. In addition, we have agreed to provide CenterPoint Energy, OGE Energy and ArcLight with certain registration rights. The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.

Our general partner has a limited call right that may require our unitholders to sell their units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 90% of our common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price, as calculated pursuant to the terms of the Partnership Agreement. If our general partner and its affiliates reduce their ownership percentage to below 70% of the outstanding units, the ownership threshold to exercise the call right will be permanently reduced to 80%. As a result, our unitholders may be required to sell their common units at an undesirable time or price and may not receive any positive return on their investment. Our unitholders may also incur a tax liability upon any such sale of their units. As of February 1, 2017, affiliates of our general partner owned approximately 61.0% of our outstanding common units. At the end of the subordination period, assuming no additional issuances of common units (other than upon the conversion of the subordinated units), affiliates of our general partner will own approximately 79.8% of our aggregate outstanding common units. If we assume the conversion of our Series A Preferred Units using the closing price of our units as of February 1, 2017, affiliates of our general partner will then own 80.8% of our aggregate outstanding common units. Affiliates of our general partner may acquire additional common units from us in connection with future transactions or through open-market or negotiated purchases.

Our unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business.
 
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. The Partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we may do business. Our unitholders could be held liable for any and all of our obligations as if they were general partners if a court or government agency were to determine that:
we were conducting business in a state but had not complied with that particular state’s partnership statute; or
a unitholder’s right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitutes “control” of our business.

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Our partnership agreement designates the Court of Chancery of the State of Delaware as the exclusive forum for certain types of actions and proceedings that may be initiated by our unitholders, which limits our unitholders’ ability to choose the judicial forum for disputes with us or our general partner’s directors, officers or other employees.

Our partnership agreement provides, that, with certain limited exceptions, the Court of Chancery of the State of Delaware is the exclusive forum for any claims, suits, actions or proceedings (1) arising out of or relating in any way to our partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of our partnership agreement or the duties, obligations or liabilities among our partners, or obligations or liabilities of our partners to us, or the rights or powers of, or restrictions on, our partners or us), (2) brought in a derivative manner on our behalf, (3) asserting a claim of breach of a duty (including a fiduciary duty) owed by any of our, or our general partner’s, directors, officers, or other employees, or owed by our general partner, to us or our partners, (4) asserting a claim against us arising pursuant to any provision of the Delaware Revised Uniform Limited Partnership Act or (5) asserting a claim against us governed by the internal affairs doctrine. Any person or entity purchasing or otherwise acquiring any interest in our common units is deemed to have received notice of and consented to the foregoing provisions. Although management believes this choice of forum provision benefits us by providing increased consistency in the application of Delaware law in the types of lawsuits to which it applies, the provision may have the effect of discouraging lawsuits against us and our general partner’s directors and officers. The enforceability of similar choice of forum provisions in other companies’ certificates of incorporation or similar governing documents has been challenged in legal proceedings and it is possible that in connection with any action a court could find the choice of forum provisions contained in our partnership agreement to be inapplicable or unenforceable in such action. If a court were to find this choice of forum provision inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our financial position, results of operations and ability to make cash distributions to our unitholders.
 
The NYSE does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.
 
Our common units are listed on the NYSE. Because we are a publicly traded limited partnership, the NYSE does not require us to have, and we do not intend to have, a majority of independent directors on our Board of Directors, to establish a nominating and corporate governance committee, or to have a compensation committee composed entirely of independent directors. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements.
 
Unitholders may have liability to repay distributions that were wrongfully distributed to them.
 
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, which we refer to herein as the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Transferees of common units are liable for both the obligations of the transferor to make contributions to the Partnership that are known to the transferee at the time of transfer and for unknown obligations if the liabilities could have been determined from the partnership agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the Partnership are counted for purposes of determining whether a distribution is permitted.

Our general partner intends to limit its liability regarding our obligations.
 
Our general partner intends to limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are non-recourse to our general partner. Our partnership agreement permits our general partner to limit its liability, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.
 

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An increase in interest rates could adversely impact the price of our common units, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.
 
Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, the market price of our common units is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision purposes. Therefore, changes in interest rates may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on the price of our common units, our ability to issue additional equity to make acquisitions or for other purposes, our financial position, results of operations and our ability to make cash distributions at our intended levels.

Our Series A Preferred Units have rights, preferences and privileges that are not held by, and are preferential to the rights of, holders of our common units.

Our Series A Preferred Units rank senior to all of our other classes or series of equity securities with respect to distribution rights and rights upon liquidation. We cannot declare or pay a distribution to our common or subordinated unitholders for any quarter unless full distributions have been or contemporaneously are being paid on all outstanding Series A Preferred Units for such quarter. These preferences could adversely affect the market price for our common units, or could make it more difficult for us to sell our common units in the future.

Holders of the Series A Preferred Units will receive, on a non-cumulative basis and if and when declared by our 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 850 bps on the stated liquidation preference thereafter. In connection with certain transfers of the Series A Preferred Units, the Series A Preferred Units will automatically convert into one or more new series of preferred units (the “other preferred units”) on the later of the date of transfer or the second anniversary of the date of issue. The other preferred units will have the same terms as our Series A Preferred Units except that unpaid distributions on the other preferred units will accrue from the date of their issuance on a cumulative basis until paid. Our Series A Preferred Units are convertible into common units by the holders of such units in certain circumstances. Payment of distributions on our Series A Preferred Units, or on the common units issued following the conversion of such Series A Preferred Units, could impact our liquidity and reduce the amount of cash flow available for working capital, capital expenditures, growth opportunities, acquisitions, and other general partnership purposes. Our obligations to the holders of Series A Preferred Units could also limit our ability to obtain additional financing or increase our borrowing costs, which could have an adverse effect on our financial condition.

Our Series A Preferred Units contain covenants that may limit our business flexibility.

Our Series A Preferred Units contain covenants preventing us from taking certain actions without the approval of the holders of 66 2⁄3% of the Series A Preferred Units. The need to obtain the approval of holders of the Series A Preferred Units before taking these actions could impede our ability to take certain actions that management or our board of directors may consider to be in the best interests of our unitholders. The affirmative vote of 66 2⁄3% of the outstanding Series A Preferred Units, voting as a single class, is necessary to amend the Partnership Agreement in any manner that would or could reasonably be expected to have a material adverse effect on the rights, preferences, obligations or privileges of the Series A Preferred Units. The affirmative vote of 66 2⁄3% of the outstanding Series A Preferred Units and any outstanding series of other preferred units, voting as a single class, is necessary to (A) create or issue certain party securities with proceeds in an aggregate amount in excess of $700 million or create or issue any senior securities or (B) subject to our right to redeem the Series A Preferred Units, approve certain fundamental transactions.

Our Series A Preferred Units are required to be redeemed in certain circumstances if they are not eligible for trading on the NYSE, and we may not have sufficient funds to redeem our Series A Preferred Units if we are required to do so.

The holders of our Series A Preferred Units may request that we list those units for trading on the NYSE. If we are unable to list the Series A Preferred Units in certain circumstances, we will be required to redeem the Series A Preferred Units. There can be no assurance that we would have sufficient financial resources available to satisfy our obligation to redeem the Series A Preferred Units. In addition, mandatory redemption of our Series A Preferred Units could adversely affect our financial position, results of operations and ability to make cash distributions to unitholders.



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Tax Risks to Common Unitholders
 
Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, then our distributable cash flow to our unitholders would be substantially reduced.
 
The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested a ruling from the Internal Revenue Service, or IRS, regarding our qualification as a partnership for tax purposes.
 
Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. A change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
 
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35.0%, and would likely pay state and local income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions, or credits would flow through to such unitholders. Because a tax would be imposed upon us as a corporation, our distributable cash flow to our unitholders would be substantially reduced. Therefore, if we were treated as a corporation for federal income tax purposes there would be material reductions in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units. This could adversely affect our financial position, results of operations and ability to make cash distributions to unitholders.
 
Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our distributable cash flow to our unitholders.
 
Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of such additional tax on us by a state will reduce the distributable cash flow. Our partnership agreement provides that, if a law is enacted or an existing law is modified or interpreted in a manner that subjects us to entity-level taxation, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
 
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations of applicable law, possibly on a retroactive basis.
 
The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. From time to time, members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships.

Additionally, on January 24, 2017, final regulations by the IRS and the U.S. Department of the Treasury were published in the Federal Register that provide industry-specific guidance regarding whether income earned from certain activities will constitute qualifying income. We believe that we will continue to be able to meet the exception for us to be treated as a partnership for U.S. federal income tax purposes under the new rules. However, any other modification to the federal income tax laws and interpretations thereof could make it more difficult or impossible to meet such exception. We are unable to predict whether any such changes will ultimately be enacted, but it is possible that a change in law could affect us and may, if enacted, be applied retroactively. Any such changes could negatively impact the value of an investment in our common units.
 
Our unitholders’ share of our income will be taxable to them for U.S. federal income tax purposes even if they do not receive any cash distributions from us.
 
Because a unitholder will be treated as a partner to whom we will allocate taxable income which could be different in amount than the cash we distribute, a unitholder’s allocable share of our taxable income will be taxable to it, which may require the payment of federal income taxes and, in some cases, state and local income taxes on such unitholder’s share of our taxable income even if

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it receives no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

In response to current market conditions, we may engage in transactions to deliver and manage our liquidity that may result in income and gain to our unitholders without a corresponding cash distribution. For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, our unitholders may be allocated taxable income and gain resulting from the sale without receiving a cash distribution. Further, taking advantage of opportunities to reduce our existing debt, such as debt exchanges, debt repurchases, or modifications of our existing debt could result in “cancellation of indebtedness income” (also referred to as “COD income”) being allocated to our unitholders as taxable income. Unitholders may be allocated COD income, and income tax liabilities arising therefrom may exceed cash distributions. The ultimate effect of any such allocations will depend on the unitholder’s individual tax position with respect to its units. Unitholders are encouraged to consult their tax advisors with respect to the consequences to them of COD income.
 
If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest would likely reduce our distributable cash flow to unitholders.
 
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the conclusions of our counsel expressed in a prospectus or from the positions we take, and the IRS’s positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse effect on the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS would be borne indirectly by our unitholders and our general partner because the costs would likely reduce our distributable cash flow to our unitholders.

If the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, the IRS (and some states) may collect any resulting taxes (including any applicable penalties and interest) directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.

Pursuant to the Bipartisan Budget Act of 2015, if the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, it may collect any resulting taxes (including any applicable penalties and interest) directly from us. We will generally have the ability to shift any such tax liability to our general partner and our unitholders in accordance with their interests in us during the year under audit, but there can be no assurance that we will be able to do so (and will choose to do so) under all circumstances, or that we will be able to (or choose to) effect corresponding shifts in state income or similar tax liability resulting from the IRS adjustment in states in which we do business in the year under audit or in the adjustment year. If we make payments of taxes, penalties and interest resulting from audit adjustments, our cash available for distribution to our unitholders might be substantially reduced. In addition, because payment would be due during the year in which the audit is completed, unitholders during that year would bear the burden of the adjustment even if they were not unitholders during the audited taxable year.
 
Tax gain or loss on the disposition of our common units could be more or less than expected.
 
If any of our unitholders sells their common units, such unitholders must recognize a gain or loss for federal income tax purposes equal to the difference between the amount realized and such unitholder’s tax basis in those common units. Because distributions in excess of such unitholder’s allocable share of our net taxable income decrease such unitholder’s tax basis in such unitholder’s common units, the amount, if any, of such prior excess distributions with respect to the common units such unitholder sells will, in effect, become taxable income if such unitholder sells such common units at a price greater than its tax basis in those common units, even if the price such unitholder receives is less than its original cost. Furthermore, a substantial portion of the amount realized on any sale or other disposition of such unitholder’s common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if a unitholder sells its common units, it may incur a tax liability in excess of the amount of cash it receives from the sale.
 
Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.
 
Investment in our common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income (UBTI) and will be taxable to the exempt organization as UBTI on the exempt organization’s tax return in the year

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the exempt organization is allocated the income. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult a tax advisor before investing in our common units.
 
We treat each holder of our common units as having the same tax benefits without regard to the actual common units held. The IRS may challenge this treatment, which could adversely affect the value of the common units.
 
Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. A successful IRS challenge also could affect the timing of these tax benefits or the amount of gain from a unitholder’s sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to such unitholder’s tax returns.
 
We prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
 
We prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The U.S. Department of the Treasury recently adopted final Treasury Regulations allowing a similar monthly simplifying convention, for taxable years beginning on or after August 3, 2015. However, such final regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
A unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of those common units. If so, such unitholder would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.
 
Because a unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of the loaned common units, such unitholder may no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Therefore, our unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units.
 
We have adopted certain valuation methodologies and monthly conventions for U.S. federal income tax purposes that may result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.
 
When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between our general partner and certain of our unitholders.
 
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
 

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The sale or exchange of 50% or more of our capital and profits interests during any 12-month period will result in the termination of the Partnership for federal income tax purposes.
 
We will be considered to have technically terminated the Partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a 12-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year if the termination occurs on a day other than December 31 and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than 12 months of our taxable income or loss being includable in such unitholder’s taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has announced a publicly traded partnership technical termination relief program whereby, if a publicly traded partnership that technically terminated requests publicly traded partnership technical termination relief and such relief is granted by the IRS, among other things, the Partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.
 
As a result of investing in our common units, our unitholders will likely be subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.
 
In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We currently own property and conduct business in a number of states, most of which currently impose a personal income tax on individuals, and most of which also impose an income or similar tax on corporations and certain other entities. As we make acquisitions or expand our business, we may own property or conduct business in additional states that impose an income tax or similar tax. In certain states, tax losses may not produce a tax benefit in the year incurred and also may not be available to offset income in subsequent tax years. Some states may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the state. Withholding, the amount of which may be greater or less than a particular unitholders’ income tax liability to the state, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to unitholders for purposes of determining the amounts distributed by us.

Compliance with and changes in tax laws could adversely affect our performance.
 
We are subject to extensive tax laws and regulations, including federal and state income taxes and transactional taxes such as excise, sales/use, payroll, franchise and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted that could result in increased tax expenditures in the future. Many of these tax liabilities are subject to audits by the respective taxing authority. These audits may result in additional taxes as well as interest and penalties.


Item 1B. Unresolved Staff Comments.

None.


Item 2. Properties
 
For descriptions of our gathering systems, processing plants, transportation systems and storage facilities, please see Item 1. “Business—Our Assets and Operations.” Our real property falls into two categories: (i) property that we own in fee and (ii) property that we have the right to use under leases, easements, rights-of-way, permits or licenses. Our processing plants are located on property we own in fee, other than Roger Mills which is located on property that we use under lease. Our other gathering and processing assets and transportation and storage assets are generally located on property that we have the right to use under leases, easements, rights-of-way, permits and licenses. We believe that we generally have satisfactory title to the properties that we own and use in our business, subject to liens, restrictions, easements and other encumbrances that do not materially either detract from the value of our assets or interfere with the operation of our business.

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Record title to some of our property may reflect names of prior owners until we have made the appropriate filings in the jurisdictions in which such assets are located. Title to some of our assets may be subject to encumbrances. Substantially all of our pipelines are constructed on rights-of-way granted by the apparent owners of record of the properties. Lands over which pipeline rights-of-way have been obtained may be subject to prior liens that have not been subordinated to the rights-of-way grants. In some cases, not all of the apparent record owners have joined in the right-of-way grants, but in substantially all such cases the signatures of the majority of apparent record owners have been obtained. Permits for our pipelines have been obtained from public authorities to cross over or under, or to lay facilities along, water courses, county roads, municipal streets and state highways, and in some instances such permits are revocable at the election of the grantor, or we may be required to relocate the pipeline at our own expense.
 
Our principal executive offices are located at One Leadership Square, 211 North Robinson Avenue, Suite 150, Oklahoma City, Oklahoma 73102; our telephone number is 405-525-7788. We currently occupy 162,053 square feet of office space at our principal executive offices under a lease that expires June 30, 2019. Although we may require additional office space as our business expands, we believe that our current facilities are adequate to meet our needs for the immediate future.


Item 3. Legal Proceedings

In the normal course of business, we are confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits or claims made by third parties, including governmental agencies. When appropriate, management consults with legal counsel and other appropriate experts to assess the claim. If, in management’s opinion, we have incurred a probable loss as set forth by GAAP, an estimate is made of the loss and the appropriate accounting entries are reflected in our Consolidated Financial Statements. At the present time, based on currently available information, management believes that any reasonably possible losses in excess of accrued amounts arising out of pending or threatened lawsuits or claims would not be quantitatively material to our financial statements and would not have a material adverse effect on our consolidated financial position, results of operations or cash flows.


Item 4. Mine Safety Disclosures

Not applicable.




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Part II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Market Information

Our common units are listed on the NYSE under the symbol “ENBL.” The following table sets forth the high and low closing prices of the common units as well as the amount of cash distributions declared and paid on the common units for the years ended December 31, 2016 and 2015.
 
Common Units
 
 
 
High
 
Low
 
Distribution per
common unit
Year ended December 31, 2016
 
 
 
 
 
Fourth Quarter
$
16.54

 
$
14.33

 
$
0.318

Third Quarter
16.03

 
12.39

 
0.318

Second Quarter
16.16

 
7.72

 
0.318

First Quarter
8.94

 
5.52

 
0.318

 
 
 
 
 
 
Year ended December 31, 2015
 
 
 
 
 
Fourth Quarter
$
13.97

 
$
6.60

 
$
0.318

Third Quarter
16.46

 
11.74

 
0.318

Second Quarter
17.80

 
15.98

 
0.316

First Quarter
19.75

 
16.19

 
0.3125


On February 10, 2017, the Board of Directors declared a quarterly distribution of $0.318 per common unit, which will be paid on February 28, 2017, to unitholders of record at the close of business on February 21, 2017. The last reported sale price of our common units on the NYSE on February 1, 2017 was $16.21. As of February 1, 2017, there were 224,532,959 common units outstanding and approximately 14 unitholders of record of our common units. This number does not include unitholders whose units are held in trust by other entities. The actual number of unitholders is greater than the number of holders of record. We have also issued 207,855,430 subordinated units and ownership interests in the general partner, for which there is no established public trading market. All of the subordinated units and general partner interests are held by affiliates of our general partner.


Distributions of Available Cash

General

Our Partnership Agreement requires that, within 60 days after the end of each quarter, we distribute all of our Available Cash (defined below) to unitholders of record on the applicable record date.

Definition of Available Cash

Available cash is defined in our partnership agreement, which is an exhibit to this Annual Report on Form 10-K. Available cash generally means, for any quarter, all cash and cash equivalents on hand at the end of that quarter:
less, the amount of cash reserves established by our general partner to:
provide for the proper conduct of our business (including cash reserves for our future capital expenditures, future acquisitions and anticipated future debt service requirements and refunds of collected rates reasonably likely to be refunded as a result of a settlement or hearing related to FERC rate proceedings or rate proceedings under applicable law subsequent to that quarter);
comply with applicable law, any of our debt instruments or other agreements;
provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for distributions if the effect of the establishment of such reserves will prevent us from distributing the minimum quarterly distribution on all

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common units and any cumulative arrearages on such common units for the current quarter); or
provide funds for distributions on our preferred units;
plus, if our general partner so determines, all or any portion of the cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter.

Minimum Quarterly Distribution

The Minimum Quarterly Distribution, as set forth in the Partnership Agreement, is $0.2875 per unit per quarter, or $1.15 per unit on an annualized basis to the extent we have sufficient cash from our operations after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to our general partner. Our current quarterly distribution is $0.318 per unit, or $1.272 per unit annualized. However, there is no guarantee that we will pay the minimum quarterly distribution on our units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. Please read Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” for a discussion of the restrictions included in our credit agreement that may restrict our ability to make distributions.

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. Please read Note 5 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information.

Percentage Allocations of Available Cash from Operating Surplus
 
The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner (through the incentive distribution rights) based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Per Unit Target Amount.” The percentage interests shown for our unitholders for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner assume that our general partner has not transferred its incentive distribution rights and that there are no arrearages on common units.
 
Total Quarterly
Distribution Per Unit
Target Amount
 
Marginal Percentage
Interest in Distributions
 
Unitholders
 
General
Partner
Minimum Quarterly Distribution
$0.2875
 
100.0
%
 
%
First Target Distribution
up to $0.330625        
 
100.0
%
 
%
Second Target Distribution
above $0.330625 up to $0.359375      
 
85.0
%
 
15.0
%
Third Target Distribution
above $0.359375 up to $0.431250        
 
75.0
%
 
25.0
%
Thereafter
above $0.431250       
 
50.0
%
 
50.0
%

Subordinated Units

General
 
As of December 31, 2016, all subordinated units are held by CenterPoint Energy and OGE Energy. These units are considered subordinated because for a period of time, defined by the Partnership Agreement as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received distributions of available cash each quarter from operating surplus in an amount equal to the minimum quarterly distribution plus any arrearages on minimum quarterly distributions on the common units from prior quarters. In addition, the subordinated units are not entitled to arrearages on minimum

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quarterly distributions. On the expiration of the subordination period, the subordinated units will convert to common units on a one-for-one basis.

 Subordination Period

The subordination period began on the closing date of the IPO and expires on the first to occur of the following dates: (1) the first business day following the distribution of available cash in respect of any quarter beginning with the quarter ending June 30, 2017 that the following tests are met: (a) distributions of available cash from operating surplus 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 that date; (b) the adjusted operating surplus generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum $1.15 (the annualized minimum quarterly distribution) on all of the common units and subordinated units outstanding during those periods on a fully diluted weighted average basis; and (c) there are no arrearages in the payment of the minimum quarterly distributions on the common units or (2) the first business day following the distribution of available cash in respect of any quarter beginning with the quarter ending June 30, 2015 that the following tests are met: (a) 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) for the four consecutive quarter period immediately preceding that date; (b) the adjusted operating surplus generated during the four consecutive quarter period immediately preceding that date equaled or exceed $1.725 per unit (150% of the annualized minimum quarterly distribution) on all of the common units and subordinated units outstanding during that period on a fully diluted weighted average basis plus the corresponding incentive distribution rights; and (c) there are no arrearages in the payment of the minimum quarterly distributions on the common units.


Equity Compensation Plans

The information relating to our equity compensation plans required by Item 5 is incorporated by reference to such information as set forth in Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters” contained herein.



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Item 6. Selected Financial Data

The following tables set forth, for the periods and as of the dates indicated, the selected historical financial and operating data of Enable Midstream Partners, LP, which is derived from the historical books and records of the Partnership. On May 1, 2013 (formation), OGE Energy and ArcLight indirectly contributed 100% of the equity interests in Enogex to the Partnership in exchange for common units and, for OGE Energy only, interests in our general partner. The transaction was considered a business combination for accounting purposes, with the Partnership considered the acquirer of Enogex. Subsequent to May 1, 2013, the financial and operating data of the Partnership are consolidated to reflect the acquisition of Enogex and the retention of certain assets and liabilities by CenterPoint Energy.
 
Year Ended December 31,
 
2016
 
2015
 
2014
 
2013
 
2012
 
(In millions, except for per unit data)
Results of Operations Data:
 
 
 
 
 
 
 
 
 
Revenues
$
2,272

 
$
2,418

 
$
3,367

 
$
2,489

 
$
952

Cost of natural gas and natural gas liquids, excluding depreciation and amortization
1,017

 
1,097

 
1,914

 
1,313

 
129

Operation and maintenance, General and administrative
465

 
522

 
527

 
429

 
267

Depreciation and amortization
338

 
318

 
276

 
212

 
106

Impairments
9

 
1,134

 
8

 
12

 

Taxes other than income
58

 
59

 
56

 
54

 
34

Operating income (loss)
385

 
(712
)
 
586

 
469

 
416

Interest expense
(99
)
 
(90
)
 
(70
)
 
(67
)
 
(85
)
Equity in earnings of equity method affiliates
28

 
29

 
20

 
15

 
31

Interest income—affiliated companies

 

 

 
9

 
21

Step acquisition gain

 

 

 

 
136

Other, net

 
2

 
(1
)
 

 

Income (loss) before income taxes
314

 
(771
)
 
535

 
426

 
519

Income tax expense (benefit)
1

 

 
2

 
(1,192
)
 
203

Net income (loss)
$
313

 
$
(771
)
 
$
533

 
$
1,618

 
$
316

Less: Net income (loss) attributable to noncontrolling interest
1

 
(19
)
 
3

 
3

 

Net income (loss) attributable to limited partners
$
312

 
$
(752
)
 
$
530

 
$
1,615

 
$
316

Less: Series A Preferred Unit distributions
22

 

 

 

 
 
Net income (loss) attributable to common and subordinated units(1)
$
290

 
$
(752
)
 
$
530

 
$
289

 
 
Basic and diluted (loss) earnings per common limited
partner unit(1)(2)
$
0.69

 
$
(1.78
)
 
$
1.29

 
$
0.74

 
 
Basic and diluted (loss) earnings per subordinated limited
partner unit(3)
$
0.68

 
$
(1.78
)
 
$
1.28

 
 
 
 
Distributions declared per unit(4)
 
 
 
 
$
0.4534

 
$
0.6086

 
 
Distributions declared per unit(5)
$
1.2720

 
$
1.2645

 
$
0.8577

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance Sheet Data (at period end):
 
 
 
 
 
 
 
 
 
Property, plant and equipment, net
$
10,143

 
$
10,131

 
$
9,582

 
$
8,990

 
$
4,705

Total assets
11,212

 
11,226

 
11,837

 
11,232

 
6,482

Long-term debt, including current portion
2,993

 
3,270

 
2,544

 
2,483

 
1,762

Partners’ Equity
7,794

 
7,531

 
8,823

 
8,181

 
3,221


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Year Ended December 31,
 
2016
 
2015
 
2014
 
2013
 
2012
 
(In millions, except for operating data)
Cash Flow Data:
 
 
 
 
 
 
 
 
 
Net cash flows provided by (used in):
 
 
 
 
 
 
 
 
 
Operating activities
$
721

 
$
726

 
$
769

 
$
648

 
$
451

Investing activities
(367
)
 
(946
)
 
(815
)
 
(140
)
 
(645
)
Financing activities
(335
)
 
212

 
(50
)
 
(400
)
 
194

 
 
 
 
 
 
 
 
 
 
Other Financial Data (6):
 
 
 
 
 
 
 
 
 
Gross margin
$
1,255

 
$
1,321

 
$
1,453

 
$
1,176

 
$
823

Adjusted EBITDA
873

 
801

 
881

 
729

 
561

DCF(7)
639

 
538

 
634

 
494

 
 
 
 
 
 
 
 
 
 
 
 
Operating Data:
 
 
 
 
 
 
 
 
 
Gathered volumes—TBtu
1,143

 
1,148

 
1,221

 
1,113

 
874

Gathered volumes—TBtu/d
3.13

 
3.14

 
3.34

 
3.05

 
2.39

Natural gas processed volumes—TBtu
658

 
651

 
569

 
397

 
73

Natural gas processed volumes—TBtu/d
1.80

 
1.78

 
1.56

 
1.09

 
0.20

NGLs produced—MBbl/d(8)
78.70

 
73.55

 
66.74

 
44.51

 

NGLs sold—MBbl/d(8)(9)
78.16

 
75.55

 
68.67

 
44.91

 
0.25

Condensate sold—MBbl/d
5.27

 
5.13

 
4.38

 
1.88

 

Crude Oil - Gathered volumes—MBbl/d(10)
25.00

 
13.86

 
3.64

 

 

Transported volumes—TBtu
1,788

 
1,814

 
1,808

 
1,608

 
1,378

Transportation volumes—TBtu/d
4.88

 
4.97

 
4.95

 
4.41

 
3.76

Interstate firm contracted capacity—Bcf/d
7.04

 
7.19

 
7.73

 
8.01

 
7.94

Intrastate average deliveries—TBtu/d
1.72

 
1.84

 
1.61

 
1.58

 

____________________
(1)
Net income (loss) attributable to common and subordinated units and basic and diluted earnings per unit reflect net income (loss) attributable to Enable Midstream Partners, LP subsequent to its formation as a limited partnership on May 1, 2013, as no limited partner units were outstanding prior to this date.
(2)
Historical basic and diluted earnings per common limited partner unit reflects the 1 for 1.279082616 reverse unit split effected on March 25, 2014.
(3)
Basic and diluted earnings per subordinated unit reflect net income (loss) attributable to the Partnership for periods subsequent to its IPO, as no subordinated units were outstanding prior to this date.
(4)
Distributions attributable to periods prior to the IPO are in accordance with the First Amended and Restated Agreement of Limited Partnership. Distributions declared per unit prior to the IPO relate to common units, as no subordinated units were outstanding prior to the date of the IPO.
(5)
Distributions attributable to periods subsequent to the IPO are in accordance with the Partnership Agreement. Distributions declared per unit relate to common and subordinated units.
(6)
See “Reconciliation of Non-GAAP Financial Measuresin Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for a reconciliation of Gross margin, Adjusted EBITDA and DCF to their most directly comparable financial measure calculated and presented in accordance with GAAP.
(7)
DCF attributable to periods in years prior to the year of our formation are not shown.
(8)
Excludes condensate.
(9)
NGLs sold includes volumes of NGLs withdrawn from inventory or purchased for system balancing purposes.
(10)
Initial operation of our crude oil gathering system began on November 1, 2013.


Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and notes included in this report.



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Overview
 
We are a Delaware limited partnership formed in May 2013 to own, operate and develop strategically located midstream assets. We completed our IPO in April 2014, and we are traded on the NYSE under the symbol “ENBL.” We were formed by CenterPoint Energy, OGE Energy and ArcLight. Our general partner is owned by CenterPoint Energy and OGE Energy.


Our Operations

Our assets and operations are organized into two reportable segments: (i) gathering and processing and (ii) transportation and storage. Our gathering and processing segment primarily provides natural gas and crude oil gathering and natural gas processing services to our producer customers. Our transportation and storage segment provides interstate and intrastate natural gas pipeline transportation and storage services primarily to our producer, power plant, LDC and industrial end-user customers.

Our gathering and processing assets include approximately 12,600 miles of natural gas gathering pipelines, 14 natural gas processing plants with approximately 2.5 Bcf/d of processing capacity and approximately 992,000 horsepower of compression as of December 31, 2016 in the Anadarko, Arkoma and Ark-La-Tex Basins. In addition, our gathering and processing assets include approximately 175 miles of crude oil gathering pipelines and 160 miles of produced water gathering pipelines serving the Bakken Shale in the Williston Basin.

Our transportation and storage assets include approximately 9,990 miles of natural gas intrastate and interstate transportation pipelines across nine states, eight natural gas storage facilities with approximately 85.0 Bcf of storage capacity and approximately 824,500 horsepower of compression. As part of these transportation and storage assets, we own a 50% interest in, and provide field operations for, SESH, an approximately 290-mile interstate pipeline providing access to the Southeast power generation market.


Items Affecting the Comparability of Our Financial Results

The comparability of our current financial condition and results of operations with our historical financial conditions and results of operations may be affected by the items described below.

Capitalization

In April 2014, the Partnership completed its IPO of 25,000,000 units and received net proceeds of $464 million. The Partnership retained the net proceeds of the offering for general partnership purposes, including proceeds to fund expansion capital expenditures and to pre-fund demand fees expected to be incurred over the next three years relating to certain expiring transportation and storage contracts.

On February 18, 2016, the Partnership completed the private placement of 14,520,000 Series A Preferred Units 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 accounted for 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. In connection with the private placement, Enable GP adopted the Partnership’s Third Amended and Restated Agreement of Limited Partnership on February 18, 2016, which, among other things, authorized the issuance of Series A Preferred Units. The Series A Preferred Units rank senior to the Partnership’s common units with respect to the payment of distributions and the 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; receive on a non-cumulative basis 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 850 bps on the stated liquidation preference thereafter.

On November 29, 2016, the Partnership closed a public offering of 10,000,000 common units at a price to the public of $14.00 per common unit. In connection with the offering, the Partnership, the underwriters and an affiliate of ArcLight entered into an underwriting agreement that provided an option for the underwriters to purchase up to an additional 1,500,000 common units, with 75,719 common units to be sold by the Partnership and 1,424,281 to be sold by the affiliate of ArcLight. The underwriters exercised the option to purchase all of the additional common units, and the Partnership received proceeds (net of underwriting

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discounts, structuring fees and offering expenses) of $137 million from the offering. Please read "Liquidity and Capital Resources".

Financing

In January 2014, the Partnership initiated our $1.4 billion commercial paper program. This program is used for general corporate purposes. Commercial paper issuances effectively reduce our borrowing capacity under our current Revolving Credit Facility. The Partnership’s ability to access the commercial paper market is dependent on its credit rating. On February 2, 2016, Standard & Poor’s Ratings Services lowered both the credit rating and the short-term rating of the Partnership from an investment grade to a non-investment grade rating. As a result, we expect our access to the commercial paper program to be limited unless these ratings improve.

On May 27, 2014, the Partnership completed the private offering of 2019 Notes, 2024 Notes and 2044 Notes, with registration rights. The Partnership received aggregate proceeds of $1.63 billion. Certain of the proceeds were used to repay the 2013 Term Loan Agreement, the EOIT $250 million variable rate term loan, the EOIT $200 million 6.875% senior notes due July 15, 2014 and for general corporate purposes. See Note 10 for discussion of the repayment of the EOIT $200 million 6.875% senior notes. A wholly owned subsidiary of CenterPoint Energy guaranteed collection of the Partnership’s obligations under the 2019 Notes and 2024 Notes, which expired on May 1, 2016.  

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. On July 31, 2015, the Partnership entered into a term loan agreement providing for an unsecured, three-year $450 million term loan agreement (2015 Term Loan Agreement). Please read “—Liquidity and Capital Resources.”


Trends and Outlook

We expect our business to continue to be impacted by the trends affecting our industry that are discussed below. Our outlook is based on assumptions regarding the impact of these trends that we have developed by interpreting the information currently available to us. If our assumptions or interpretation of available information prove to be incorrect, our future financial condition and results of operations may differ materially from our expectations.

Commodity Price Environment

Our business is impacted by commodity prices which have declined and otherwise experienced significant volatility in recent years. In early 2016, natural gas and crude oil prices dropped to their lowest levels in over 10 years. Both natural gas and crude oil prices increased moderately in the second half of 2016. If current commodity prices levels persist, or if commodity price levels decline, our future volumes and cash flows may be negatively impacted.

Commodity prices impact the drilling and production of natural gas and crude oil in the areas served by our systems, and the volumes on our systems are negatively impacted if producers decrease drilling and production in those areas served. Both our gathering and processing segment and our transportation and storage segment can be impacted by drilling and production. Our gathering and processing segment primarily serve producers, and many producers utilize the services provided by our transportation and storage segment. A decrease in volumes will decrease the cash flows from our systems. In addition, our processing arrangements expose us to commodity price fluctuations. For more information regarding the impact of commodity prices, drilling and production on the volumes on our systems as well as our exposure to commodity prices under our processing arrangements, see Part I, Item 1A. “Risk Factors—Risks Related to Our Business.”

We have attempted to mitigate the impact of commodity prices on our business by entering into hedges, focusing on contracting fee-based business and converting existing commodity-based contracts to fee-based contracts. For additional information regarding our commodity price risk, see Item 7A. “Quantitative and Qualitative Disclosures About Market RiskCommodity Price Risk.”

Commodity Supply and Demand Dynamics

Despite recent low commodity prices, our long-term view is that natural gas and crude oil production in the U.S. will increase. Over the past several years, there has been a fundamental shift in U.S. natural gas and crude oil production towards tight gas formations and shale plays. Advancements in technology have allowed producers to efficiently extract natural gas and crude oil from these formations and plays. As a result, the proven reserves of natural gas and crude oil in the United States have significantly increased and the price of natural gas and crude oil has decreased compared to historical periods.

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Natural gas continues to be a critical component of energy demand in the United States. Over the long term, management believes that the prospects for continued natural gas demand are favorable and will be driven by population and economic growth, as well as the continued displacement of coal-fired power plants by natural gas-fired power plants due to the price of natural gas and stricter government environmental regulations on the mining and burning of coal. The EIA projects that the majority of domestic consumption growth will be in the electric power, industrial and liquefaction for export sectors where the aggregate natural gas demand of these sectors is expected to grow from approximately 17.8 Tcf in 2016 to approximately 21.0 Tcf in 2040. We believe that increasing consumption of natural gas over the long term in these sectors will continue to drive demand for our natural gas gathering, processing, transportation and storage services.

Capital Market Volatility

We may access the capital markets to fund our expansion capital expenditures. Historically, unit prices of midstream master limited partnerships have experienced periods of volatility. In addition, because our common units are yield-based securities, rising market interest rates could impact the relative attractiveness of our common units to investors. Further, fluctuations in energy and commodity prices can create volatility in our common unit prices, which could impact investor appetite for our common units. Volatility in energy and commodity prices, as well as other macro-economic factors could impact the relative attractiveness of our debt securities to investors. As a result of capital market volatility, we may be unable to issue equity securities or debt on satisfactory terms, or at all, which may limit our ability to expand our operations or make future acquisitions. See Part I, Item 1A. “Risk Factors—Risks Related to Our Business.”

Regulatory Compliance

The regulation of gathering and transmission pipelines, storage and related facilities by FERC and other federal and state regulatory agencies, including the DOT, has a significant impact on our business. For example, the DOT’s Pipeline and Hazardous Materials Safety Administration, or PHMSA, has established pipeline integrity management programs that require more frequent inspections of pipeline facilities and other preventative measures, which may increase our compliance costs and increase the time it takes to obtain required permits. Additionally, increased regulation of oil and natural gas producers, including regulation associated with hydraulic fracturing, could reduce regional supply of oil and natural gas and therefore throughput on our gathering systems. For more information, see Item 1. “BusinessRate and Other Regulation.”

Customer Concentration
 
We rely on certain key natural gas producer customers for a significant portion of our natural gas and NGLs supply. For the year ended December 31, 2016, our top ten natural gas producer customers accounted for approximately 66% of our gathered volumes. These customers include affiliates of Continental, Vine, GeoSouthern, XTO, Apache, Tapstone, Chesapeake, BP, Covey Park and Marathon. See Item 1A. “Risk Factors—Risks Related to Our Business.”

We rely on certain key utilities and producers for a significant portion of our transportation and storage demand. For the year ended December 31, 2016, our top transportation and storage customers by revenue were affiliates of CenterPoint Energy, Spire, XTO, AEP, OGE Energy, Continental, Chesapeake, MEP, EOG and Entergy. See Part I, Item 1A. “Risk Factors—Risks Related to Our Business.”

Credit Risk
 
We are exposed to certain credit risks relating to our ongoing business operations. Credit risk includes the risk that counterparties that owe us money or energy will breach their obligations. If the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected, and we could incur losses. We examine the creditworthiness of third party customers to whom we extend credit and manage our exposure to credit risk through credit analysis, credit approval, credit limits and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees, or seek to renegotiate our contract to reduce credit exposure.


Measures We Use to Evaluate Results of Operations

We use a variety of operational and financial measures to evaluate our results of operations and our financial condition and to manage our business. The measures that we use to analyze our business include: (i) throughput volumes, (ii) operation and maintenance and general and administrative expenses, (iii) Gross margin, (iv) Adjusted EBITDA, (v) Adjusted interest expense, (vi) DCF and (vii) Distribution coverage ratio.

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Throughput Volumes

Throughput volume is operating data. The volume of natural gas that we gather, process, transport and store depends significantly on the level of production from natural gas wells connected to our systems. Gathering and processing as well as transportation and storage can be impacted by drilling and production because the customers for our gathering and processing services are primarily producers, and many producers utilize our transportation and storage services. Aggregate production volumes are impacted by the overall amount of drilling and completion activity, as production must be maintained or increased by new drilling or other activity, because the production rate of a well declines over time. Producers’ willingness to engage in new drilling is determined by a number of factors, which include: the prevailing and projected prices of natural gas, NGLs and crude oil; the cost to drill and operate a well; the availability and cost of capital; technological advances in drilling and production techniques; and environmental and other government regulations. We generally expect the level of drilling to positively correlate with long-term trends in commodity prices. Similarly, we generally expect the level of production to positively correlate with drilling activity.

To maintain and increase throughput volumes on our gathering and processing systems, we must compete to connect to new wells as production from existing wells declines. We actively monitor drilling activity in the areas served by our gathering and processing systems to pursue new customers and new wells. To maintain and increase the throughput volumes on our transportation and storage systems, we must compete for the business of producers and other customers who have existing and new sources of supply in the areas served by our systems, and we must compete for the business of power plants, LDCs, industrial end users and other customers who have existing and new sources of demand in the areas served by our systems.

We actively monitor customer activity in the areas we serve to pursue new supply and demand opportunities. In both gathering and processing and transportation and storage, we compete for customers based on service offerings, operating flexibility, receipt and delivery points, available capacity and price.

Operation and Maintenance and General and Administrative Expenses

Operation and Maintenance and General and Administrative Expenses is a GAAP financial measure. We seek to maximize the profitability of our operations by effectively managing operation and maintenance and general and administrative expenses. These expenses are comprised primarily of labor expenses, lease costs, utility costs, insurance premiums, repair expenses and maintenance expenses. These labor expenses, lease costs, utility costs and insurance premiums have remained relatively stable across periods in the current low inflation environment, but repair and maintenance expense can fluctuate from period to period based on the activities performed and the timing of expenses. The level of drilling activity impacts competition for personnel, supplies and equipment. Increased competition could place upward pressure on the cost of labor, supplies and miscellaneous equipment.

Use of Non-GAAP Financial Measures

Gross margin, Adjusted EBITDA, Adjusted interest expense, DCF and Distribution coverage ratio are not financial measures presented in accordance with GAAP. These financial measures are subject to adjustments that have the effect of excluding amounts that are included in the most directly comparable measure calculated and presented in accordance with GAAP. Because these non-GAAP financial measures exclude amounts that are included in the most directly comparable GAAP financial measures, they have important limitations as an analytical tool. We nevertheless believe that the presentation of these non-GAAP financial measures provides useful information to investors regarding our financial condition and results of operations because they are the financial measures used by management to evaluate and manage our business.

We have provided definitions for Gross margin, Adjusted EBITDA, Adjusted interest expense, DCF and Distribution coverage ratio. Although the use of non-GAAP financial measures with the same or similar titles is common in our industry, comparability may vary from one company to another. Because Gross margin, Adjusted EBITDA, Adjusted interest expense, DCF and Distribution coverage ratio may be defined differently by other companies in our industry, our presentation of these non-GAAP financial measures may not be directly comparable to non-GAAP financial measures of other companies with the same or similar titles.

Gross margin is most directly comparable to the GAAP financial measure revenue. When used as a financial measure, Adjusted EBITDA is most directly comparable to the GAAP financial measure net income attributable limited partners. When used as a liquidity measure, Adjusted EBITDA is most directly comparable to the GAAP liquidity measure net cash provided by operating activities. Adjusted interest expense is most directly comparable to the GAAP financial measure interest expense. DCF is most directly comparable to the GAAP financial measure net income attributable to limited partners. Distribution coverage ratio is computing utilizing DCF, which is most directly comparable to the GAAP financial measure net income attributable to limited partners. These non-GAAP financial measures should not be considered a substitute for the most directly comparable financial

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measures. Reconciliations of these non-GAAP financial measures to their most directly comparable GAAP financial measures are provided in “—Reconciliation of non-GAAP Financial Measures” below.

Gross Margin

We define gross margin as total revenues minus costs of natural gas and natural gas liquids, excluding depreciation and amortization. Total revenues consist of the fees that we charge our customers and the sales price of natural gas and natural liquids that we sell. The cost of natural gas and natural gas liquids consists of the purchase price of natural gas and natural gas liquids that we purchase. We deduct the cost of natural gas and natural gas liquids from total revenue to arrive at a measure of the core profitability of our mix of fee-based and commodity-based customer arrangements. We use gross margin as a performance measure to analyze the core profitability of our customer arrangements. Please read “—Results of Operations” and “—Non-GAAP Financial Measures.”