Azure Midstream Partners, LP - FORM S-1

Attached files

file	filename
EX-99.1 - EX-99.1 - Azure Midstream Partners, LP	d769078dex991.htm
EX-3.1 - EX-3.1 - Azure Midstream Partners, LP	d769078dex31.htm
EX-23.1 - EX-23.1 - Azure Midstream Partners, LP	d769078dex231.htm
EX-21.1 - EX-21.1 - Azure Midstream Partners, LP	d769078dex211.htm
EX-23.4 - EX-23.4 - Azure Midstream Partners, LP	d769078dex234.htm
EX-23.3 - EX-23.3 - Azure Midstream Partners, LP	d769078dex233.htm
EX-23.2 - EX-23.2 - Azure Midstream Partners, LP	d769078dex232.htm

AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON NOVEMBER 12, 2014

Registration No. 333-

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

AZURE MIDSTREAM PARTNERS, LP

(Exact Name of Registrant as Specified in Its Charter)

Delaware

4922

38-3941102

(State or Other Jurisdiction of

Incorporation or Organization)

(Primary Standard Industrial

Classification Code Number)

(I.R.S. Employer

Identification No.)

12377 Merit Drive, Suite 300

Dallas, Texas 75251

(972) 674-5200

(Address, Including Zip Code, and Telephone Number, Including Area Code, of Registrant’s Principal Executive Offices)

Eric T. Kalamaras

Chief Financial Officer

12377 Merit Drive, Suite 300

Dallas, Texas 75251

(972) 674-5200

(Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent for Service)

Copies to:

Douglas E. McWilliams

Jeffrey K. Malonson

Vinson & Elkins L.L.P.

1001 Fannin Street, Suite 2500

Houston, Texas 77002

(713) 758-2222

Joshua Davidson

Andrew J. Ericksen

Baker Botts L.L.P.

910 Louisiana Street

Houston, Texas 77002

(713) 229-1234

Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement becomes effective.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box: ¨

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

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. (Check one):


Large accelerated filer	¨	Accelerated filer	¨
Non-accelerated filer	x (Do not check if a smaller reporting company)	Smaller reporting company	¨

CALCULATION OF REGISTRATION FEE



Title of Each Class of Securities to be Registered	Proposed Maximum Aggregate Offering Price(1)(2)	Amount of Registration Fee
Common units representing limited partner interests	$175,000,000	$20,335

(1)	Includes common units issuable upon exercise of the underwriters’ option to purchase additional common units.

(2)	Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o).

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

The information in this preliminary prospectus is not complete and may be changed. The securities described herein may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell nor does it seek an offer to buy such securities in any jurisdiction where the offer or sale is not permitted.

SUBJECT TO COMPLETION, DATED , 2015

PROSPECTUS

LOGO

Common Units

Representing Limited Partner Interests

Azure Midstream Partners, LP

This is the initial public offering of our common units representing limited partner interests of Azure Midstream Partners, LP. We were recently formed by Azure Midstream Holdings LLC. We are offering common units in this offering. Prior to this offering, there has been no public market for our common units. We currently expect the initial public offering price to be between $ and $ per common unit. We intend to apply to list our common units on the New York Stock Exchange under the symbol “AZUR.”

Investing in our common units involves risks. Please read “Risk Factors” beginning on page 23.

These risks include the following:

•

We may not generate 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 our unitholders.

•

Our assets will consist of a 40% limited partner interest in Azure Midstream Operating Company, LP (“Azure Midstream Operating”), as well as the general partner interest in Azure Midstream Operating. Because our interest in Azure Midstream Operating represents our only cash-generating asset, our cash flow will depend entirely on the performance of Azure Midstream Operating and its ability to distribute cash to us.

•

We depend on a relatively small number of customers for a significant portion of our revenues. The loss of, or material nonpayment or nonperformance by, or the curtailment of production by, any one or more of these customers could materially adversely affect our financial condition, results of operations and cash flows.

•

The lack of diversification of our assets and geographic locations could adversely affect our ability to make distributions to our common unitholders.

•

Azure Midstream Holdings LLC will own a 60% limited partner interest in Azure Midstream Operating and will control our general partner, which has sole responsibility for conducting our business and managing our operations, and we will own the general partner of Azure Midstream Operating which is responsible for managing the operations of Azure Midstream Operating. Our general partner and its affiliates, including Azure Midstream Holdings LLC, have conflicts of interest with, and defined fiduciary duties with respect to, us and our unitholders and may favor their own interests to our detriment and that of our unitholders. Additionally, we have no control over Azure Midstream Holdings LLC’s business decisions and operations, and Azure Midstream Holdings LLC is under no obligation to adopt a business strategy that favors us.

•

Our partnership agreement replaces our general partner’s fiduciary duties to holders of our units with contractual standards governing its duties.

•

Unitholders have very limited voting rights and are not entitled to appoint or remove our general partner or elect the board of directors of our general partner.

•

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as Azure Midstream Operating and us not being subject to material incremental entity-level taxation. If the Internal Revenue Service were to treat us as a corporation for federal income tax purposes, or if we or Azure Midstream Operating become subject to entity-level taxation for state tax purposes, our distributable cash flow would be substantially reduced.

In addition, we qualify as an “emerging growth company” as defined in Section 2(a)(19) of the Securities Act and, as such, are allowed to provide in this prospectus more limited disclosures than an issuer that would not so qualify. Furthermore, for so long as we remain an emerging growth company, we will qualify for certain limited exceptions from investor protection laws such as the Sarbanes-Oxley Act of 2002 and the Investor Protection and Securities Reform Act of 2010. Please read “Summary—Emerging Growth Company Status” and “Risk Factors.”

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.


	Per Common Unit	Total
Initial public offering price	$	$
Underwriting discounts and commissions(1)	$	$
Proceeds to Azure Midstream Partners, LP (before expenses)	$	$

(1)

Excludes a structuring fee of % payable to Citigroup Global Markets Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated. Please read “Underwriting.”

The underwriters may purchase up to an additional common units from Azure Midstream Partners, LP at the public offering price, less the underwriting discounts and commissions and the structuring fee, within 30 days from the date of this prospectus.

The underwriters expect to deliver the common units to purchasers on or about , 2015 through the book-entry facilities of The Depository Trust Company.


Citigroup		BofA Merrill Lynch

The date of this prospectus is , 2015.

Our Assets and Areas of Operations

LOGO

TABLE OF CONTENTS


SUMMARY			1
Overview			1
Our Assets			2
Business Strategies			4
Competitive Strengths			6
Our Sponsors			7
Risk Factors			7
Formation Transactions and Partnership Structure			8
Ownership Structure			10
Management of Our Partnership			11
Principal Executive Offices and Internet Address			12
Emerging Growth Company Status			12
Conflicts of Interest and Fiduciary Duties			12
Summary Historical and Pro Forma Financial Information			19
Non-GAAP Financial Measures			21
RISK FACTORS			23
Risks Related to Our Business			23
Risks Inherent in an Investment in Us			38
Tax Risks to Common Unitholders			49
USE OF PROCEEDS			54
CAPITALIZATION			55
DILUTION			56
OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS			57
General			57
Our Minimum Quarterly Distribution			59
Unaudited Pro Forma Distributable Cash Flow for the Twelve Months Ended September 30, 2014 and the Year Ended December 31, 2013			60
Unaudited Estimated Distributable Cash Flow for the Twelve Months Ending December 31, 2015			64
HOW WE MAKE DISTRIBUTIONS TO OUR PARTNERS			73
Distributions of Available Cash			73
Operating Surplus and Capital Surplus			74
Capital Expenditures			76
Subordination Period			77
Distributions of Available Cash From Operating Surplus During the Subordination Period			79
Distributions of Available Cash From Operating Surplus After the Subordination Period			79
General Partner Interest			79
Incentive Distribution Rights			79
Percentage Allocations of Available Cash From Operating Surplus			80
Azure Midstream Holdings’ Right to Reset Incentive Distribution Levels			80
Distributions From Capital Surplus			83
Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels			83
Distributions of Cash Upon Liquidation			84
SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA			87
Non-GAAP Financial Measures			89
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			91
Overview			91
How We Generate Our Revenue			91
Our Operations			93
How We Evaluate Our Operations			93
Items Affecting Comparability of Our Financial Results			95


General Trends and Outlook			97
Results of Our Operations			100
Liquidity and Capital Resources			104
Quantitative and Qualitative Disclosures about Market Risk			108
Impact of Seasonality			109
Critical Accounting Policies and Estimates			109
INDUSTRY OVERVIEW			112
Contractual Arrangements			113
Transportation and Storage Services Contractual Arrangements			114
U.S. Natural Gas Market Fundamentals			114
NGLs Market Opportunity			117
LNG Market Opportunity			120
Overview of Areas of Operation			121
BUSINESS			124
Overview			124
Business Strategies			125
Competitive Strengths			126
Our Assets			128
Gas Gathering Agreements			131
Our Sponsors			132
Competition			132
Seasonality			133
Insurance			133
Safety and Maintenance Regulation			133
Regulation of Operations			135
Environmental Matters			137
Title to Properties and Rights of Way			140
Employees			140
Legal Proceedings			141
MANAGEMENT			142
Management of Azure Midstream Partners, LP			142
Director Independence			142
Committees of the Board of Directors			143
Directors and Executive Officers of Azure Midstream Partners GP, LLC			143
Board Leadership Structure			145
Board Role in Risk Oversight			146
Reimbursement of Expenses of Our General Partner			146
Compensation of Our Directors			146
Executive Compensation			146
Long-Term Incentive Plan			148
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT			151
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS			152
Distributions and Payments to Our General Partner and its Affiliates			152
Agreements Governing the Transactions			153
Competition			156
Procedures for Review, Approval and Ratification of Transactions with Related Persons			156
CONFLICTS OF INTEREST AND DUTIES			157
Conflicts of Interest			157
Duties			161
DESCRIPTION OF THE COMMON UNITS			164
The Units			164
Transfer Agent and Registrar			164
Transfer of Common Units			164


THE PARTNERSHIP AGREEMENT			166
Organization and Duration			166
Purpose			166
Cash Distributions			166
Capital Contributions			166
Voting Rights			167
Applicable Law; Forum, Venue and Exclusive Jurisdiction			168
Limited Liability			168
Issuance of Additional Interests			169
Amendment of the Partnership Agreement			170
Merger, Consolidation, Conversion, Sale or Other Disposition of Assets			172
Dissolution			172
Liquidation and Distribution of Proceeds			173
Withdrawal or Removal of Our General Partner			173
Transfer of General Partner Interest			174
Transfer of Ownership Interests in the General Partner			174
Transfer of Subordinated Units and Incentive Distribution Rights			174
Change of Management Provisions			175
Limited Call Right			175
Non-Taxpaying Holders; Redemption			175
Non-Citizen Assignees; Redemption			176
Meetings; Voting			176
Voting Rights of Incentive Distribution Rights			177
Status as Limited Partner			177
Indemnification			177
Reimbursement of Expenses			178
Books and Reports			178
Right to Inspect Our Books and Records			178
Registration Rights			179
UNITS ELIGIBLE FOR FUTURE SALE			180
Issuance of Additional Interests			180
Partnership Agreement and Registration Rights Agreement			180
Lock-up Agreement			181
Registration Statement on Form S-8			181
MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES			182
Taxation of the Partnership			182
Tax Consequences of Unit Ownership			184
Tax Treatment of Operations			188
Disposition of Units			189
Uniformity of Units			191
Tax-Exempt Entities and Other Investors			192
Administrative Matters			193
State, Local and Other Tax Considerations			194
INVESTMENT BY EMPLOYEE BENEFIT PLANS			195
UNDERWRITING			196
LEGAL MATTERS			203
EXPERTS			203
WHERE YOU CAN FIND MORE INFORMATION			204
FORWARD-LOOKING STATEMENTS			205
INDEX TO FINANCIAL STATEMENTS			F-1
APPENDIX A—FORM OF AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF AZURE MIDSTREAM PARTNERS, LP			A-1
APPENDIX B—GLOSSARY OF TERMS			B-1

iii

You should rely only on the information contained in this prospectus or in any free writing prospectus we may authorize to be delivered to you. We have not, and the underwriters have not, authorized any other person to provide you with information different from that contained in this prospectus and any free writing prospectus. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted.

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. Please read “Risk Factors” and “Forward-Looking Statements.”

Industry and Market Data

This prospectus includes industry data and forecasts that we obtained from industry publications and surveys, public filings and internal company sources. Industry publications, surveys and forecasts generally state that the information contained therein has been obtained from sources believed to be reliable, but there can be no assurance as to the accuracy or completeness of the included information. Statements as to our market position and market estimates are based on independent industry publications, government publications, third-party forecasts, management’s estimates and assumptions about our markets and our internal research. While we are not aware of any misstatements regarding the market, industry or similar data presented herein, such data involve risks and uncertainties and are subject to change based on various factors, including those discussed under the headings “Risk Factors” and “Forward-Looking Statements” in this prospectus.

Trademarks and Trade Names

We own or have rights to various trademarks, service marks and trade names that we use in connection with the operation of our business. This prospectus may also contain trademarks, service marks and trade names of third parties, which are the property of their respective owners. Our use or display of third parties’ trademarks, service marks, trade names or products in this prospectus is not intended to, and should not be read to, imply a relationship with or endorsement or sponsorship of us. Solely for convenience, the trademarks, service marks and trade names referred to in this prospectus may appear without the ^®, TM or SM symbols, but such references are not intended to indicate, in any way, that we will not assert, to the fullest extent under applicable law, our rights or the right of the applicable licensor to these trademarks, service marks and trade names.

Certain Terms Used in this Prospectus

Unless the context otherwise requires, references in this prospectus to the following terms have the meanings set forth below:

•

the “Acquisition” refers to our acquisition of TGGT and ETG in November 2013;

•

“Azure Energy” refers to Azure Midstream Energy LLC, the operating subsidiary of Azure Midstream Holdings prior to this offering that will be contributed to Azure Midstream Operating in connection with the closing of this offering;

•

“Azure GP” or our “general partner” refers to Azure Midstream Partners GP, LLC, a Delaware limited liability company and our general partner;

•

“Azure Midstream Holdings” refers to Azure Midstream Holdings LLC, a Delaware limited liability company owned by Energy Spectrum Partners, Tenaska Capital Management, BG, EXCO and other investors and certain members of our management. Azure Midstream Holdings owns a 60% limited partner interest in Azure Midstream Operating and 100% of our general partner;

•

“Azure Midstream Partners, LP,” “partnership,” “we,” “our,” “us” or like terms, when used in a historical context, refer to the natural gas gathering, compression, treating and processing business conducted by Azure Midstream Holdings through its operating subsidiary, Azure Energy. When used in the present tense or future tense, these terms refer to Azure Midstream Partners, LP, a Delaware limited partnership, and its subsidiaries, including Azure Midstream Operating and Azure Midstream Operating Company GP, LLC, the general partner of Azure Midstream Operating;

•

“Azure Midstream Operating” refers to Azure Midstream Operating Company, LP, a newly formed partnership owned by us and Azure Midstream Holdings, and its subsidiaries, of which we will own a 40% limited partner interest;

•

“Azure Midstream Predecessor” refers to the assets, liabilities and results of operations of TGGT prior to the Acquisition;

•

“BG” refers to BG Group, plc and its subsidiaries;

•

“Energy Spectrum Partners” refers to Energy Spectrum Partners VI, LP and its parallel and co-investment funds;

•

“ETG” refers to TPF II East Texas Gathering, LLC, which we acquired in November 2013;

•

“EXCO” refers to EXCO Resources, Inc. and its subsidiaries;

•

“MRC” refers to a contractual minimum revenue producer commitment;

•

“MVC” refers to a contractual minimum volume producer commitment;

•

our “Predecessor” refers to Azure Midstream Predecessor, our predecessor for accounting purposes;

•

“Tenaska Capital Management” refers to TPF II, L.P. and its parallel and co-investment funds; and

•

“TGGT” refers to TGGT Holdings, LLC, a joint venture formed in 2009 by BG and EXCO, which we acquired in November 2013.

In addition, we have provided definitions for some of the terms we use to describe our business and industry and other terms used in this prospectus in the “Glossary of Terms” beginning on page B-1 of this prospectus.

SUMMARY

This summary provides a brief overview of information contained elsewhere in this prospectus. You should read the entire prospectus carefully, including the historical financial statements and related notes contained herein, before investing in our common units. Unless otherwise indicated, the information presented in this prospectus assumes (i) an initial public offering price of $ per common unit (the midpoint of the price range set forth on the cover page of this prospectus) and (ii) that the underwriters’ option to purchase additional common units is not exercised. You should read “Risk Factors” for more information about important risks that you should consider carefully before investing in our common units.

We will own a 40% limited partner interest in Azure Midstream Operating and the general partner interest in Azure Midstream Operating. We will consolidate Azure Midstream Operating into our financial statements. Unless otherwise stated, financial results and operating data are shown on a 100% basis and are not adjusted for the 60% noncontrolling limited partner interest in Azure Midstream Operating owned by Azure Midstream Holdings. Azure Midstream Holdings owns a 60% limited partner interest in Azure Midstream Operating and 100% of our general partner.

Azure Midstream Partners, LP

Overview

We are a fee-based, growth-oriented Delaware limited partnership focused on owning, operating, developing and acquiring midstream energy infrastructure that is strategically located in core producing areas of unconventional resource basins in North America. We currently provide natural gas gathering, compression, treating and processing services in North Louisiana and East Texas in the prolific Haynesville and Bossier shale formations, the liquids-rich Cotton Valley formation and the shallower producing sands in the Travis Peak formation. According to the U.S. Energy Information Administration (the “EIA”), these formations comprise the third largest natural gas basin in the United States in terms of natural gas production.

At the consummation of this offering, our assets will consist of a 40% limited partner interest in Azure Midstream Operating, as well as the general partner interest in Azure Midstream Operating. Through our ownership of Azure Midstream Operating’s general partner, we will control all of Azure Midstream Operating’s assets and operations. We will have a right of first offer to acquire the remaining 60% limited partner interest in Azure Midstream Operating from Azure Midstream Holdings prior to that interest being sold to a third party. As of September 30, 2014, Azure Midstream Operating’s gathering systems included approximately 1,365 miles of pipeline, which gathered an average of approximately 991 MMcf/d of natural gas during the nine months ended September 30, 2014.

During the nine months ended September 30, 2014, we generated over 90% of our revenues under long-term, fixed-fee and fixed-spread natural gas gathering and sales agreements that are intended to mitigate our direct commodity price exposure and enhance the stability of our cash flows. Our customers include some of the largest natural gas producers in North America, such as BG, EXCO, BP plc, Chesapeake Energy Corporation, Devon Energy Corporation, Encana Corporation, EOG Resources, Inc. and EP Energy Corporation. Substantially all of our gas gathering revenue is underpinned by minimum volume commitments, minimum revenue commitments or acreage dedications, including life of lease arrangements. The contracted revenue under minimum volume and revenue commitments on our systems represented approximately 56.9% of our revenue for the nine months ended September 30, 2014. Our minimum volume and revenue commitments have original terms that range from five to ten years and, as of September 30, 2014, had a weighted average remaining term of 5.2 years. As of that date, our acreage dedications and life of lease arrangements with BG, BP plc and EXCO covered approximately 187,000 acres in the aggregate.

The following table sets forth the pro forma net income and pro forma Adjusted EBITDA of Azure Midstream Operating and the pro forma Adjusted EBITDA attributable to us for the periods indicated (in thousands).


	Nine Months Ended September 30, 2014		Year Ended December 31, 2013
Pro forma net income (loss) (100%)	$	16,182	$	(180,021	)
Pro forma Adjusted EBITDA attributable to Azure Midstream Operating (100%)	$	78,250	$	130,590
Pro forma Adjusted EBITDA attributable to us (40%)	$	31,300	$	52,236

For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated in accordance with United States generally accepted accounting principles (“GAAP”), please read “—Non-GAAP Financial Measures.”

Our Assets

We acquired a significant portion of our midstream assets through our November 15, 2013 acquisition of TGGT, a joint venture formed in 2009 by two of our largest customers, BG and EXCO. At the same time, we acquired ETG, which comprises the remainder of our initial assets, from Tenaska Capital Management. These assets comprise all of the assets of Azure Midstream Operating, and we classify them into three main systems: Holly, Center and Legacy. The following table provides information regarding the assets of Azure Midstream Operating. Unless otherwise noted, all information is as of or for the nine-month period ended September 30, 2014.


System	Formations Served	Approximate Length (Miles)		Approximate Number of Receipt Points(1)		Approximate Acreage Dedication (Acres)		Average Remaining Term of MVC/MRC (Years)		Average Daily Throughput (MMcf/d)(2)		Daily Throughput Capacity (MMcf/d)
Holly	Haynesville/ Bossier/ Cotton Valley		335		716		69,000		4.2		625		2,100

Center	Haynesville/ Bossier/ Cotton Valley		372		144		370,000		5.2		132		900

Legacy	Cotton Valley/ Haynesville/ Travis Peak		658		518		100,000		—		234		500

(1)

Receipt points include connections to individual wells, connections to batteries and pads containing multiple wells, and connections to central receipt points from producer and third party owned gathering systems.

(2)

The EXCO and BG contracts include an aggregate minimum volume commitment (“MVC”) of 600,000 MMbtu/d (584 MMcf/d) for the Holly and Center system. EXCO and BG have the right to ship any or all of this commitment on either or both of these systems in accordance with the contracts. Please read “Business—Gas Gathering Agreements.”

Detailed information regarding each of our operating systems is provided below.

•

Holly system. The Holly system is primarily located within the DeSoto, Red River and Caddo parishes of North Louisiana and currently serves the Haynesville and Bossier shale formations and the liquids-rich Cotton Valley formation. We believe this area is the “core of the core” of the Haynesville shale because of the quality of the geology and the high production profile of the wells drilled to date, with estimated ultimate recovery (“EUR”) approaching ten billion cubic feet per well, as estimated by Wood Mackenzie. As of September 30, 2014, the Holly system consisted of approximately 335 miles of high- and low-pressure pipeline serving approximately 69,000 dedicated gross acres, with throughput of approximately 625 MMcf/d for the preceding nine month period. The system also includes four amine treating plants with combined capacity of 920 MMcf/d and two 1,340 horsepower compressors. The Holly system has life of lease acreage dedications with BG and EXCO, as well as additional primary producer contracts with Chesapeake Energy Corporation, Encana Corporation and EP Energy Corporation. As of September 30, 2014, the system connected to eight downstream access points, providing shippers with access to significant off-take capacity. For the nine months ended September 30, 2014, natural gas gathered from BG and EXCO represented approximately 95% of the Holly system’s throughput.

•

Center system. The Center system is primarily located within the San Augustine, Nacogdoches, Sabine, Panola and Shelby counties in East Texas and currently serves multiple formations including the Haynesville, Bossier and the liquids-rich James Lime formation. As of September 30, 2014, the system consisted of approximately 372 miles of high-pressure pipeline serving approximately 370,000 dedicated gross acres. The Center system is designed to efficiently access large acreage positions held by major producers within the East Texas region. There are over 20 producers contracted on the Center system, with EUR potential from five to twelve billion cubic feet per well, as estimated by Wood Mackenzie. The Center system covers a wide range of undedicated and undeveloped acreage, and the system’s capacity is able to support incremental growth without deploying large amounts of additional capital. Approximately 98% of the natural gas transported on this system requires treating for carbon dioxide (“CO2”), which we treat for an additional fee. As of September 30, 2014, the system included six amine treating plants with combined capacity of 952 MMcf/d, two 1,340 horsepower compressors and access to five major interconnect access points that offer our customers superior deliverability. The system also includes our new Fairway processing plant with a processing capacity of 10 MMcf/d, which is designed to extract NGL content from natural gas ranging between 2.7 and 6.4 gallons per Mcf (“GPM”) from the James Lime formation for liquids processing. The major producers contracted on the Center system are BG, EXCO, EOG Resources, Inc., Samson Resources Corporation, SM Energy Company, Chesapeake Energy Corporation, Newfield Exploration Company, Devon Energy Corporation and Goodrich Petroleum Corp.

•

Legacy system. The Legacy system is primarily located within Harrison, Panola and Rusk counties in Texas and Caddo parish in Louisiana and currently serves the Cotton Valley formation, the Haynesville shale formation and the shallower producing sands in the Travis Peak formation. The Cotton Valley formation has historically been a natural gas play, although improvements in technology have increased production of oil and NGLs in the area. The Cotton Valley formation is productive when accessed through horizontal drilling and fracture stimulation technologies. We believe these qualities, when combined with the liquids-rich nature of the natural gas, concentrated oil content, high initial rates of production and competitive well costs, make the formation attractive for producers in the area. As of September 30, 2014, the Legacy system consisted of approximately 658 miles of high- and low-pressure gathering lines and served approximately 100,000 dedicated acres with access to seven major downstream markets, which we believe provides superior delivery capability compared to our competitors. As of September 30, 2014, the Legacy system had ten 1,340 horsepower compressors and two additional compressors comprising 870 horsepower, for a total of 14,270 horsepower of compression. The system has access to four third-party processing plants, including the Carthage Hub, which serves as a connection point for a number of intrastate and interstate pipelines. Our Legacy system gathers high-Btu natural gas with an NGL content

between 2.0 and 5.2 GPM. Our major customers contracted on the Legacy system are BG, BP plc, Devon Energy Corporation, Endeavor Energy Resources, L.P., EXCO, Sabine Oil & Gas LLC and Samson Resources Corporation.

Prior to the Acquisition, TGGT operated approximately 1,060 miles of gathering pipelines that transported natural gas from supply basins to major intrastate and interstate pipelines in the region. These gathering systems and treating facilities were operated primarily to provide midstream services to BG and EXCO to support their drilling and development programs. Consequently, TGGT’s management team did not pursue third-party volumes aggressively. As a result, our average daily throughput for the nine-month period ended September 30, 2014 of 625, 132 and 234 MMcf/d on our Holly, Center and Legacy systems, respectively, is currently below our daily throughput capacity by 1,475, 768 and 266 MMcf/d for our Holly, Center and Legacy systems, respectively. We believe this excess capacity creates an opportunity for us to significantly increase volumes on our existing systems with minimal incremental capital expenditures, thereby giving us substantial operating leverage. For additional information on our average daily throughput and daily throughput capacity of our existing assets, please see “—Our Assets.”

We intend to increase throughput volumes on our existing pipeline systems by continuing to work with our existing customers to enhance our service offerings to maximize the value of their production and our economics. Additionally, we intend to further increase throughput volumes and diversify our customer base over time by aggressively competing for contracted volumes with new customers as their existing contracts with other pipeline operators expire. We believe that our recently constructed pipeline systems allow us to offer producers in our basins customized services with greater flexibility than many of our competitors. In addition to our differentiated service offerings, we believe that the lower maintenance capital associated with our new pipeline systems, together with our available throughput capacity, allows us to offer more attractive economic terms to producers than competitors with older assets while achieving compelling margins from our services.

We believe recent improvements in permitting applications and rig counts demonstrate stability in drilling in the areas in which we operate. Drilling activity in our areas of operations, as measured by drilling permit applications and rig counts, has increased over the last 20 months. During October 2014, 53 drilling permit applications were filed in the counties and parishes in which we operate, up 43% from 37 in February 2013. An average of 61 permitting applications were filed per month for the six months ended October 31, 2014, representing a 15% increase from the 53 permitting applications filed per month for the six months ended February 28, 2013. Average rig counts in our areas of operations have increased 11% over the same time period, from 37 in February 2013 to 41 in October 2014.

Business Strategies

Our principal business objective is to increase the quarterly cash distribution that we pay to our unitholders over time while ensuring the ongoing stability of our cash flows. We expect to achieve this objective through the following business strategies:

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volumes on our systems. Further, we are implementing a gas allocation process, often referred to as component balancing, which will ensure our producer customers receive an accurate portion of value for natural gas liquids. Other midstream providers may blend a producer’s NGL-rich gas with another producer’s lean gas thereby diluting value to the NGL-rich gas stream and accreting value to the leaner gas stream. We believe implementing component balancing will enable us to more effectively compete for third-party gas services, particularly those that require processing. As such, we expect to attract additional volumes of gas that may require processing to our systems.

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Execute on organic growth and development opportunities. While our existing gathering systems provide us with significant organic growth opportunities, we also intend to execute organic growth and development opportunities associated with increases in natural gas, NGLs and crude oil production by increasing our midstream service offerings with existing customers and obtaining new customers. Further, we intend to expand our operations into new basins with underserved crude oil and natural gas midstream infrastructure where we can serve as a key strategic provider to strong customers under long-term commitments. We believe such opportunities exist in unconventional resource plays that are well positioned for accelerated production growth, such as the Permian Basin and Marcellus shale, due to the inadequate level of existing natural gas transportation infrastructure in these plays relative to demand for such infrastructure as a result of increased drilling activity. We expect to accomplish these objectives by leveraging our management team’s expertise in successfully constructing, developing and optimizing midstream infrastructure assets. For example, members of our management team constructed and developed the Laser Northeast Gathering System, a 36-mile high pressure gathering system header pipeline in the Marcellus shale that was ultimately sold to Williams Partners, L.P. in 2012 for $750 million, and were the initial developers of Laser Midstream Energy that developed assets in South Texas, East Texas and North Louisiana and was sold to Eagle Rock Energy Partners, L.P. in 2007 for $140 million. We also are actively pursuing projects to increase throughput or increase margins on our existing systems. For example, we are evaluating opportunities to build a new cryogenic natural gas processing plant where we expect processing demand to exceed future supply, thereby offering us incremental margins for NGLs and additional natural gas throughput.

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Pursue accretive acquisitions from our sponsor and third parties. We intend to pursue acquisitions of additional ownership interests in Azure Midstream Operating from Azure Midstream Holdings over time. We also intend to pursue accretive acquisitions of complementary assets from third parties.

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Acquisitions from Azure Midstream Holdings. We believe that Azure Midstream Holdings’ economic interest in us incentivizes it to offer us acquisition opportunities, including additional interests in Azure Midstream Operating, although it is under no obligation to do so. We will have a right of first offer to acquire the remaining 60% limited partner interest in Azure Midstream Operating from Azure Midstream Holdings prior to that interest being sold to a third party. We believe that Azure Midstream Holdings is strongly positioned to continue pursuing and developing integrated midstream solutions projects, which may involve the development, construction and operation of pipelines, processing plants and associated infrastructure, which would allow customers to deliver crude oil and natural gas to transmission pipelines. Furthermore, we believe that the ability of Azure Midstream Holdings to pursue and develop integrated energy infrastructure projects will create potential acquisition opportunities for us in the future.

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Acquisitions from third parties. In the near term, we intend to pursue acquisition opportunities from third parties that we can finance on an accretive basis. Such acquisitions could be pursued independently by us or jointly with Azure Midstream Holdings.

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opportunities to acquire crude oil, NGL and natural gas assets that (i) complement our existing business, (ii) allow us to integrate additional midstream services, (iii) balance our commodity profile and (iv) enhance our basin diversity. We anticipate that our highly qualified management team and energy-focused sponsors will provide us with an advantage in pursuing these acquisitions as compared to other competitors. We and our sponsors are frequently involved in discussions with third parties regarding the purchase of natural gas and crude oil midstream energy infrastructure assets. We intend to continue to evaluate opportunities to acquire or develop other midstream energy infrastructure assets that complement our existing business and allow us to leverage our management team’s development and industry expertise throughout the midstream value chain.

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Generate stable and predictable fee-based cash flows. We intend to continue pursuing accretive opportunities to provide fixed-fee and fixed-spread services to existing and new customers, limiting our direct exposure to commodity price volatility when possible. We plan to focus on obtaining additional long-term commitments from customers, which may include minimum volume and revenue commitments, acreage dedications or life of lease arrangements. The long-term, fixed-fee and and fixed-spread nature of our contracts reduces direct commodity exposure and provides relatively predictable revenue streams.

Competitive Strengths

We believe that we will be able to successfully execute our business strategies because of the following competitive strengths:

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Stable and predictable fee-based cash flows. During the nine months ended September 30, 2014, we generated over 90% of our revenues under long-term, fixed-fee and fixed-spread natural gas gathering and sales agreements that are intended to mitigate our direct commodity price exposure and enhance the stability of our cash flows. Contracted revenue under minimum volume and revenue commitments on our systems represented 56.9% of our revenue for the nine months ended September 30, 2014. Our minimum volume and revenue commitments have original terms that range from five to ten years and, as of September 30, 2014, had a weighted average remaining term of 5.2 years. Additionally, we believe the services we provide are critical to enhancing natural gas production and that we are able to provide the most economic transportation solution for our customers. As a result, our high-quality service results in recurring revenues and strong customer relationships, further supporting the stability of our cash flows. These relationships in turn result in organic growth opportunities as our customers expand their drilling operations or their field development creates the need for additional midstream services. We believe that our advantaged position in leading producing regions, our highly efficient operations and the long-term nature of our customer relationships enhance our ability to generate stable and growing cash flows.

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New and strategically located assets in core areas of a prolific unconventional basin. Our midstream energy infrastructure assets are strategically positioned within core areas of the Haynesville shale. The formations in the basins served by our assets have been accessed by experienced producers who have been able to achieve a high level of EURs on the wells completed. We believe that producers will continue their drilling and completion activities in our areas of operation in a variety of commodity price environments because the return economics associated with core-area wells remain favorable in lower pricing environments compared to less economic areas of production. We believe our core producers can earn acceptable rates of return above their cost of capital when natural gas prices are slightly above $3.00 per Mcf. Additionally, continued drilling activity in these formations positions us to pursue attractive growth opportunities by further developing and optimizing our systems and by developing or acquiring complementary systems within our geographic areas of operation. Our highly efficient, modern infrastructure provides us the ability to deliver throughput volumes with a lower amount of compression while reducing gas losses and to add additional throughput volumes with marginal incremental costs and capital expenditures.

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Experienced management team with proven record of asset acquisition, construction, development, operational efficiency and integration expertise with publicly traded partnerships. Our senior management team has an average of nearly 30 years of energy experience and a proven track record of identifying and consummating significant acquisitions, including partnering with major producers to construct and develop midstream infrastructure for natural gas, NGLs and crude oil. Members of our management team were the key developers of the Laser Northeast Gathering System in the Marcellus that was sold to Williams Partners, L.P. in 2012 and have been instrumental in developing other critical midstream assets across multiple basins. Further, our Chief Executive Officer, Chief Financial Officer and Vice President of Engineering and Construction have prior experience serving as senior officers of publicly traded limited partnerships, which affords us a competitive advantage versus many of our peers that have less or no experience managing public companies. We employ engineering, construction and operations teams that have significant experience in designing, constructing and operating large midstream energy projects and have demonstrated a continued focus on improving operational efficiency of our acquired assets. For example, since Azure Midstream Holdings’ acquisition of TGGT and ETG in November 2013, our management team has reduced or eliminated approximately 25% of the total operating and corporate cost structure within the first six months of operating the combined companies.

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Relationships with large and committed sponsors. Our sponsors, Energy Spectrum Partners and Tenaska Capital Management, are experienced energy investors with proven track records of making substantial, long-term investments in high-quality midstream energy assets. Further, our sponsors, either directly or indirectly, may be a source of accretive transactions that could provide substantial advantages in increasing our operating scale, expanding our geographic footprint or enhancing our midstream value chain service offerings. While there are no assurances that we will benefit from our relationship with our sponsors, we believe our relationship with them will be a competitive advantage, as they both bring not only significant financial and management experience, but also numerous relationships throughout the energy industry that we believe will benefit us as we seek to grow our business. In addition, we believe our sponsors, as the indirect owners of our incentive distribution rights and a significant portion of our limited partner interest, will be motivated to promote and support the successful execution of our business strategies.

Our Sponsors

Azure Midstream Holdings was formed in 2013 by members of our management team and our sponsors, Energy Spectrum Partners and Tenaska Capital Management. Energy Spectrum Partners, together with its affiliated funds, is an energy and midstream focused private equity firm that has raised over $3.5 billion in capital commitments focused on investing in North America’s energy infrastructure. Tenaska Capital Management, together with its affiliated funds, is a leading private equity firm focused on North America energy investments that has completed over $6.5 billion of acquisitions and development projects, primarily in the power and midstream sectors. Combined, our sponsors currently have an interest in 13 midstream companies representing over $2.5 billion of capital either invested in or targeting midstream energy investments.

Risk Factors

An investment in our common units involves risks associated with our business, our partnership structure and the tax characteristics of our common units. The following list of risk factors should be read carefully in conjunction with the risks under the caption “Risk Factors.”

Risks Related to Our Business

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Our assets will consist of a 40% limited partner interest in Azure Midstream Operating, as well as the general partner interest in Azure Midstream Operating. Because our interest in Azure Midstream Operating represents our only cash-generating asset, our cash flow will depend entirely on the performance of Azure Midstream Operating and its ability to distribute cash to us.

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The lack of diversification of our assets and geographic locations could adversely affect our ability to make distributions to our common unitholders.

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Risks Inherent in an Investment in Us

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Azure Midstream Holdings will own a 60% limited partner interest in Azure Midstream Operating and will control our general partner, which has sole responsibility for conducting our business and managing our operations, and we will own the general partner of Azure Midstream Operating, which is responsible for managing the operations of Azure Midstream Operating. Our general partner and its affiliates, including Azure Midstream Holdings, have conflicts of interest with, and defined fiduciary duties with respect to, us and our unitholders and may favor their own interests to our detriment and that of our unitholders. Additionally, we have no control over Azure Midstream Holdings’ business decisions and operations, and Azure Midstream Holdings is under no obligation to adopt a business strategy that favors us.

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Our partnership agreement replaces our general partner’s fiduciary duties to holders of our units with contractual standards governing its duties.

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Unitholders have very limited voting rights and are not entitled to appoint or remove our general partner or elect the board of directors of our general partner.

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For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements that apply to other public companies, including those relating to auditing standards and disclosure about our executive compensation.

Tax Risks to Common Unitholders

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Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as Azure Midstream Operating and us not being subject to material incremental entity-level taxation. If the IRS were to treat us as a corporation for federal income tax purposes, or if we or Azure Midstream Operating become subject to entity-level taxation for state tax purposes, our distributable cash flow would be substantially reduced.

Formation Transactions and Partnership Structure

We are a Delaware limited partnership recently formed by Azure Midstream Holdings to own, operate, develop and acquire midstream assets. At the closing of this offering, the following transactions, which we refer to as the formation transactions, will occur:

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we and Azure Midstream Operating will enter into an omnibus agreement with Azure Midstream Holdings and certain of its affiliates that will govern our right of first offer to purchase Azure Midstream Holdings’ retained 60% limited partner interest in Azure Midstream Operating and certain related indemnification matters;

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we will acquire the general partner interest and a 40% limited partner interest in Azure Midstream Operating;

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we will issue common units and subordinated units to Azure Midstream Holdings, representing an aggregate % limited partner interest in us;

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we will issue to our general partner the general partner interest in us and all of our incentive distribution rights, which will entitle our general partner to increasing percentages of the cash that we distribute in excess of $ per unit per quarter;

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we will issue common units to the public, representing a % limited partner interest in us;

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we will enter into a $150 million new revolving credit facility that will be undrawn at closing; and

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we will use the net proceeds from this offering (including any net proceeds from the exercise of the underwriters’ option to purchase additional common units from us) as described in “Use of Proceeds.”

Ownership Structure

The following is a simplified diagram of our ownership structure after giving effect to this offering and the related transactions.

LOGO


Public Common Units(1)		%(2)
Interests of Azure Midstream Holdings:
Common Units		%(2)
Subordinated Units		%
Incentive Distribution Rights	—	(3)
Non-economic General Partner Interest	0.0	%(4)

Total	100.0	%

(1)

Includes up to common units that may be purchased by certain of our officers, directors, employees and other persons associated with us pursuant to a directed unit program, as described in “Underwriting.”

(2)

The number of common units to be issued to Azure Midstream Holdings includes common units that will be issued at the expiration of the underwriters’ option to purchase additional common units, assuming the underwriters do not exercise their option. Any exercise of the underwriters’ option to purchase additional units would reduce the common units shown above as issued to Azure Midstream Holdings by the number to be purchased by the underwriters in connection with such exercise. If and to the extent the underwriters exercise their option to purchase additional common units, the number of common units purchased by the underwriters pursuant to any such exercise will be sold to the public, and any remaining common units not purchased by the underwriters pursuant to any exercise of the option will be issued to Azure Midstream Holdings at the expiration of the 30-day option period. All of the net proceeds from any exercise of the underwriters’ option to purchase additional common units will be used to make a cash distribution to Azure Midstream Holdings.

(3)

Incentive distribution rights represent a variable interest in distributions and thus are not expressed as a fixed percentage. Please read “How We Make Distributions to Our Partners—Incentive Distribution Rights.” Distributions with respect to the incentive distribution rights will be classified as distributions with respect to equity interests. All of our incentive distribution rights will be issued to our general partner, which is owned by Azure Midstream Holdings.

(4)

Our general partner owns the non-economic general partner interest in us. Please read “How We Make Distributions to Our Partners—General Partner Interest.”

Management of Our Partnership

Azure Midstream Partners GP, LLC, our general partner, has sole responsibility for conducting our business and for managing our operations and will be controlled by Azure Midstream Holdings. Neither our general partner, nor any of its affiliates, will receive any compensation in connection with the management of our business, but they will be entitled to reimbursement for all direct and indirect expenses they incur on our behalf. Some of Azure Midstream Holdings’ executive officers will also serve as executive officers and directors of our general partner. Neither our general partner nor the board of directors of our general partner will be elected by our unitholders. As a result of its ownership of our general partner, Azure Midstream Holdings will have the right to elect the entire board of directors of our general partner. Within twelve months of the date of this prospectus, we will have at least three directors who are independent as defined under the independence standards established by the NYSE. For more information about our current directors and executive officers, please read “Management—Directors and Executive Officers of Azure Midstream Partners GP, LLC.”

To maintain operational flexibility, our operations will be conducted through, and our operating assets will be owned by, various operating subsidiaries. However, neither we nor our subsidiaries will have any employees. Our general partner has the sole responsibility for providing the personnel necessary to conduct our operations, whether through directly hiring employees or by obtaining the services of personnel employed by Azure Midstream Holdings or others. All of the personnel that will conduct our business immediately following the closing of this offering will be employed or contracted by our general partner and its affiliates, including Azure Midstream Holdings, but we sometimes refer to these individuals in this prospectus as our employees because they provide services directly to us.

Principal Executive Offices and Internet Address

Our principal executive offices are located at 12377 Merit Drive, Suite 300, Dallas, Texas, and our telephone number is (972) 674-5200. Our website will be located at . We expect to make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission (the “SEC”), available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

Emerging Growth Company Status

We are an “emerging growth company” as defined in the Jumpstart Our Business Startups Act (the “JOBS Act”). For as long as we are an emerging growth company, unlike other public companies, we will not be required to:

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provide three years of audited financial statements and management’s discussion and analysis of financial conditions and results of operations;

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provide five years of selected financial data;

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provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal controls over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act of 2002;

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comply with any new requirements adopted by the Public Company Accounting Oversight Board (the “PCAOB”);

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comply with any new audit rules adopted by the PCAOB after April 5, 2012, unless the SEC determines otherwise;

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provide certain disclosure regarding executive compensation required of larger public companies; or

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obtain unitholder approval of any golden parachute payments not previously approved.

We will cease to be an “emerging growth company” upon the earliest of:

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the last day of the fiscal year in which we have $1.0 billion or more in annual revenues;

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the last day of the fiscal year in which we have at least $700 million in market value of our common units held by non-affiliates as of the end of our second fiscal quarter;

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when we issue more than $1.0 billion of non-convertible debt over a three-year period; or

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the last day of the fiscal year following the fifth anniversary of this offering.

In addition, Section 107 of the JOBS Act also provides that an emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. In other words, an emerging growth company can, and we will, delay the adoption of certain accounting standards until those standards would otherwise apply to private companies.

Conflicts of Interest and Fiduciary Duties

General. Under our partnership agreement, our general partner has a duty to manage us in a manner it believes is not adverse to our interests. However, because our general partner is a wholly owned subsidiary of Azure Midstream Holdings, the officers and directors of our general partner also have a duty to manage our general partner in a manner that is beneficial to Azure Midstream Holdings. Consequently, conflicts of interest may arise in the future between us and our unitholders, on the one hand, and our general partner and its affiliates, including Azure Midstream Holdings, on the other hand.

Partnership agreement modifications to fiduciary duties. Delaware law provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to the limited partners and the partnership, provided that partnership agreements may not eliminate the implied contractual covenant of good faith and fair dealing. This implied covenant is a judicial doctrine utilized by Delaware courts in connection with interpreting ambiguities in partnership agreements and other contracts, and does not form the basis of any separate or independent fiduciary duty in addition to the express contractual duties set forth in our partnership agreement. Under the implied contractual covenant of good faith and fair dealing, 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.

As permitted by Delaware law, our partnership agreement contains various provisions replacing the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing the duties of the general partner and contractual methods of resolving conflicts of interest. The effect of these provisions is to restrict the remedies available to our unitholders for actions that might otherwise constitute breaches of our general partner’s fiduciary duties. Our partnership agreement also provides that affiliates of our general partner, including Azure Midstream Holdings, are not restricted from competing with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to us. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement, and pursuant to the terms of our partnership agreement each holder of common units consents to various actions and potential conflicts of interest contemplated in our partnership agreement that might otherwise be considered a breach of fiduciary or other duties under Delaware law.

For a more detailed description of the conflicts of interest and fiduciary duties of our general partner, please read “Conflicts of Interest and Fiduciary Duties.”

The Offering

Common units offered to the public

common units.

common units if the underwriters exercise their option to purchase an additional common units (the “option units”) in full.

Units outstanding after this offering

common units and subordinated units, for a total of limited partner units, regardless of whether or not the underwriters exercise their option to purchase any of the option units. Of this amount, common units will be issued to Azure Midstream Holdings at the closing of this offering and, assuming the underwriters do not exercise their option to purchase any of the option units, all such option units will be issued to Azure Midstream Holdings 30 days following this offering, upon the expiration of the underwriters’ option exercise period. However, if the underwriters exercise their option to purchase any portion of the option units, we will (i) issue to the public the number of option units purchased by the underwriters pursuant to such exercise and (ii) issue to Azure Midstream Holdings, upon the expiration of the option exercise period, all remaining option units. Any such option units issued to Azure Midstream Holdings will be issued for no additional consideration. Accordingly, the exercise of the underwriters’ option will not affect the total number of common units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units. In addition, our general partner will own the non-economic general partner interest in us.

Use of proceeds

We intend to use the estimated net proceeds of approximately $ million from this offering, based upon the assumed initial public offering price of $ per common unit (the midpoint of the price range set forth on the cover of this prospectus), after deducting underwriting discounts, the structuring fee and offering expenses, to make a cash contribution to Azure Midstream Operating of $ million, the entirety of which will be used to repay a portion of Azure Energy’s indebtedness.

Cash distributions

Upon completion of this offering, our partnership agreement will provide for a minimum quarterly distribution of $ per common unit and subordinated unit ($ per common unit and subordinated unit on an annualized basis) to the extent we have sufficient cash after establishment of reserves and payment of fees and expenses, including payments to our general partner and its affiliates. We refer to this cash as “available cash,” and it is defined in our partnership agreement included in this prospectus as Appendix A. Our ability to pay the minimum quarterly distribution is subject to various restrictions and other factors described in more detail under the caption “Our Cash Distribution Policy and Restrictions on Distributions.”

For the first quarter that our common units are publicly traded, we will pay a prorated distribution covering the period from the completion of this offering through , 2015, based on the actual length of that period.

Our partnership agreement requires us to distribute all of our available cash each quarter in the following manner:

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first, to the holders of common units, until each common unit has received the minimum quarterly distribution of $ plus any arrearages from prior quarters;

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second, to the holders of subordinated units, until each subordinated unit has received the minimum quarterly distribution of $ ; and

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third, to all unitholders, pro rata, until each unit has received a distribution of $ .

If cash distributions to our unitholders exceed $ per unit in any quarter, the holders of our incentive distribution rights will receive distributions according to the following percentage allocations:


	Marginal Percentage Interest in Distributions
Total Quarterly Distribution Target Amount	Unitholders		Holder of Our Incentive Distribution Rights
$		100.0%		—
above $ up to $		100.0%		—
above $ up to $		85.0%		15.0	%
above $ up to $		75.0%		25.0	%
above $		50.0%		50.0	%

We refer to these distributions as “incentive distributions.” Please read “How We Make Distributions to Our Partners.”

If we do not have sufficient available cash at the end of each quarter, we may, but are under no obligation to, borrow funds to pay the minimum quarterly distribution to our unitholders.

We believe, based on our financial forecast and related assumptions included in “Our Cash Distribution Policy and Restrictions on Distributions,” that we will have sufficient available cash to pay the minimum quarterly distribution of $ per unit on all of our common units and subordinated units for each quarter in the twelve months ending December 31, 2015. However, we do not have a legal obligation to pay quarterly distributions at our minimum quarterly distribution rate or at any other rate except as provided in our partnership agreement. There is no guarantee that we will distribute quarterly cash distributions to our unitholders in any quarter. Please read “Our Cash Distribution Policy and Restrictions on Distributions.”

Subordinated units

Azure Midstream Holdings will initially indirectly own all of our subordinated units. The principal difference between our common units and subordinated units is that in any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distribution until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages.

Conversion of subordinated units

The subordination period will end on the first business day after we have earned and paid distributions of available cash of at least (i) $ (the minimum quarterly distribution on an annualized basis) on each outstanding common and subordinated unit for each of three consecutive, non-overlapping four-quarter periods ending on or after , 2018, or (ii) $ (150% of the annualized minimum quarterly distribution) on each outstanding common and subordinated unit and the related distributions on the incentive distribution rights for any four-quarter period ending on or after , 2016, in each case provided there are no arrearages in the payment of the minimum quarterly distributions on our common units at that time.

When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and thereafter common units will no longer be entitled to arrearages. Please read “How We Make Distributions to Our Partners—Subordination Period.”

Issuance of additional units

Our partnership agreement authorizes us to issue an unlimited number of additional units without the approval of our unitholders. Please read “Units Eligible for Future Sale” and “The Partnership Agreement—Issuance of Additional Interests.”

Limited voting rights

Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business. Our unitholders will have no right to elect our general partner or its directors on an annual or other continuing basis. Our general partner may not be removed

except by a vote of the holders of at least 66²/₃% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon consummation of this offering, Azure Midstream Holdings will indirectly own an aggregate of % of our outstanding voting units (or % of our outstanding voting units, if the underwriters exercise their option to purchase additional common units in full). This will provide Azure Midstream Holdings the ability to prevent the removal of our general partner. In addition, any vote to remove our general partner during the subordination period must provide for the election of a successor general partner by the holders of a majority of the common units and a majority of the subordinated units, voting as separate classes. This will also provide Azure Midstream Holdings the ability to prevent the removal of our general partner. Please read “The Partnership Agreement—Voting Rights.”

Limited call right

If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner will have the right, but not the obligation, to purchase all of the remaining common units at a price equal to the greater of (i) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (ii) the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. Please read “The Partnership Agreement—Limited Call Right.”

Estimated ratio of taxable income to distributions

We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending December 31, , you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be % or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $ per unit, we estimate that your average allocable federal taxable income per year will be no more than approximately $ per unit. Thereafter, the ratio of allocable taxable income to cash distributions to you could substantially increase. Please read “Material U.S. Federal Income Tax Consequences—Tax Consequences of Unit Ownership” for the basis of this estimate.

Material federal income tax consequences

For a discussion of the material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read “Material U.S. Federal Income Tax Consequences.”

Directed unit program

Exchange listing

We intend to apply to list our common units on the NYSE under the symbol “AZUR.”

Summary Historical and Pro Forma Financial and Operating Data

Azure Midstream Holdings acquired our initial assets through purchases of (i) 100% of the equity interest in TGGT from BG and EXCO and (ii) 100% of the equity interest in ETG from Tenaska Capital Management on November 15, 2013. Subsequent to the acquisitions of TGGT and ETG, Azure Midstream Holdings indirectly owned and operated TGGT and ETG through its wholly owned subsidiary, Azure Energy.

The summary historical consolidated financial data presented as of September 30, 2014 and for the nine-month period ended September 30, 2014 are derived from the unaudited historical condensed consolidated financial statements of Azure Midstream Holdings included elsewhere in this prospectus. The summary historical consolidated financial data presented for the nine-month period ended September 30, 2013 are derived from the unaudited historical condensed consolidated financial statements of the Azure Midstream Predecessor included elsewhere in this prospectus. The summary historical consolidated financial data presented as of December 31, 2013 and for the period from November 15, 2013 to December 31, 2013 are derived from the audited historical consolidated financial statements of Azure Midstream Holdings included elsewhere in this prospectus. The summary historical consolidated financial data presented as of December 31, 2012 and for the period from January 1, 2013 to November 14, 2013 and the year ended December 31, 2012 are derived from the audited historical consolidated financial statements of the Predecessor included elsewhere in this prospectus.

The summary unaudited pro forma consolidated financial data for the nine-month period ended September 30, 2014 and for the year ended December 31, 2013 have been derived from the unaudited pro forma consolidated financial statements of the partnership included elsewhere in this prospectus. The summary unaudited pro forma consolidated statement of operations data for the year ended December 31, 2013 include the pro forma effects of the TGGT and ETG acquisitions and the pro forma effects of the offering transaction described under the caption “Summary—Formation Transactions and Partnership Structure” as if the TGGT and ETG acquisitions and the offering transaction had occurred on January 1, 2013. The summary unaudited pro forma consolidated statement of operations data for the nine-month period ended September 30, 2014 include the pro forma effects of the offering transaction as if it had occurred on January 1, 2013. As part of the offering transaction, Azure Midstream Holdings will cause Azure Energy to be contributed to Azure Midstream Operating in exchange for all of the limited partner interests of Azure Midstream Operating. Azure Midstream Holdings will then contribute an approximate 40% limited partner interest in Azure Midstream Operating to the partnership.

The partnership will control Azure Midstream Operating through its ownership of Azure Midstream Operating’s general partner. Consequently, the partnership’s future consolidated financial statements will include Azure Midstream Operating as a consolidated subsidiary, and Azure Midstream Holdings’ 60% limited partner interest will be reflected as a non-controlling interest.

For a detailed discussion of the following table, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The following table presents our summary historical and pro forma consolidated financial and operating data as of the dates and for the periods indicated and should also be read in conjunction with the historical audited and unaudited consolidated financial statements and related notes of Azure Midstream Holdings and the Predecessor included elsewhere in this prospectus. Among other things, those historical financial statements include more detailed information regarding the basis of presentation for the information below. For a reconciliation of Adjusted EBITDA to its most directly comparable financial measures

calculated in accordance with GAAP, please read “—Non-GAAP Financial Measures” below. We define distributable cash flow as Adjusted EBITDA less interest and income taxes paid and maintenance capital expenditures.


	Azure Midstream Holdings LLC			Predecessor				Azure Midstream Holdings LLC		Predecessor		Pro Forma Azure Midstream Partners, LP
	Period from November 15, 2013 to December 31, 2013			Period From January 1, 2013 to November 14, 2013		Year Ended December 31, 2012		Nine-Month Period Ended September 30, 2014		Nine-Month Period Ended September 30, 2013		Nine-Month Period Ended September 30, 2014		Year Ended December 31, 2013
	(in thousands, except for volumes)
Statement of Operations Data:
Total operating revenues	$	24,819		$	180,332	$	246,451	$	134,833	$	158,560	$	134,833	$	219,704
Operating expenses:
Cost of purchased gas and NGLs sold		4,505			21,054		22,794		30,095		18,239		30,095		25,812
Operating expense		5,455			33,850		48,586		23,685		28,993		23,685		48,693
General and administrative		458			11,166		17,514		10,760		9,820		10,760		14,719
Transaction costs		6,135			—		—		—		—		—		—
Asset impairments(1)		—			583		50,771		228		583		228		238,061
Depreciation and amortization		3,480			31,143		32,132		21,989		26,713		21,989		28,737

Total expenses		20,033			97,796		171,797		86,757		84,348		86,757		356,022

Income (loss) from operations		4,786			82,536		74,654		48,076		74,212		48,076		(136,318	)
Interest expense		5,046			10,321		16,145		31,145		9,331		31,145		40,304
Other expense		576			2,316		3,441		326		1,695		326		2,890
Income tax expense		106			361		425		423		317		423		509

Net income (loss) from continuing operations	$	(942	)	$	69,538	$	54,643	$	16,182	$	62,869	$	16,182	$	(180,021	)

Net (loss) income attributed to non-controlling interest													9,709		(108,013	)

Net (loss) income attributable to Azure Midstream Partners, LP(2)												$	6,473	$	(72,008	)

Net (loss) income per limited partner unit (basic and diluted):
Common units												$		$
Subordinated units												$		$
Balance Sheet Data (as of the period end):
Cash and cash equivalents	$	15,576				$	8,050	$	26,034			$	26,034
Property, plant and equipment—net		823,102					1,142,208		823,068				823,068
Total assets		1,080,340					1,201,634		1,074,563
Total debt		550,000					493,671		534,013
Members’ equity		499,058					678,608		515,240
Other Financial Data:
Adjusted EBITDA(3)	$	14,206		$	114,153	$	157,596	$	78,250	$	101,389	$	78,250	$	130,590
Adjusted EBITDA attributable to Azure Midstream Partners, LP(4)													31,300		52,236
Capital expenditures		5,326			29,208		191,001		16,363		27,604
Operating Data:
Average throughput volumes of natural gas (MMcf/d)		843			1,217		1,471		991		1,302

(1)

The unaudited pro forma statement of operations for the year ended December 31, 2013 includes an impairment charge of $238.1 million, of which $237.0 million is an impairment that was recognized by ETG prior to the Acquisition and is the result of adjusting the carrying value of the ETG assets to their net realizable fair value immediately prior to the Acquisition. The $237.0 million impairment was included within the ETG statement of operations for the period from January 1, 2013 to November 15, 2013. The remaining impairment charge of $1.1 million was recognized by our Predecessor and is the result of adjusting the carrying value of assets held for sale to their net realizable fair value.

(2)

Calculated as 40% of net income (loss) from continuing operations.

(3)

For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated in accordance with GAAP, please read “—Non-GAAP Financial Measures” below.

(4)

Calculated as 40% of Adjusted EBITDA.

Non-GAAP Financial Measures

We include in this prospectus the non-GAAP financial measures of EBITDA and Adjusted EBITDA. We provide a reconciliation of this non-GAAP financial measure to their most directly comparable financial measures as calculated and presented in accordance with GAAP.

EBITDA and Adjusted EBITDA

We define EBITDA as net income (loss), plus (1) interest expense, (2) income tax expense, and (3) depreciation and amortization expense. We define Adjusted EBITDA as EBITDA, plus (1) non-cash expenses, (2) adjustments related to deferred revenue and cash receipts under our minimum revenue producer commitments (“MRC”) and minimum volume producer commitments (“MVC”) and (3) adjustments associated with certain other and non-cash items.

EBITDA and Adjusted EBITDA are used as supplemental financial measures by management and external users of our financial statements, such as investors, commercial banks and research analysts, to assess the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities. Additionally, Adjusted EBITDA is used to assess the financial performance of our assets without the impact of non-cash expenses, adjustments associated with cash received under the MRC and MVC requirements of our gas gathering agreements and certain other items.

The GAAP measure most directly comparable to EBITDA and Adjusted EBITDA is net income. Our non-GAAP financial measures of EBITDA and Adjusted EBITDA should not be considered as an alternative to net income. You should not consider EBITDA and Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. EBITDA and Adjusted EBITDA have limitations as analytical tools and should not be considered as alternatives to, or more meaningful than, performance measures calculated in accordance with GAAP. Some of these limitations are: certain items excluded from EBITDA and Adjusted EBITDA are significant components in understanding and assessing our financial performance, such as our cost of capital and tax structure; EBITDA and Adjusted EBITDA do not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments; EBITDA and Adjusted EBITDA do not reflect changes in, or cash requirements for, our working capital needs; although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and EBITDA and Adjusted EBITDA do not reflect any cash requirements for such replacements; and our computations of EBITDA and Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.

The following table presents a reconciliation of EBITDA and Adjusted EBITDA to net income (loss) for each of the periods indicated:


	Azure Midstream Holdings LLC			Predecessor				Azure Midstream Holdings LLC		Predecessor		Pro Forma Azure Midstream Partners, LP
	Period from November 15, 2013 to December 31, 2013			Period from January 1, 2013 to November 14, 2013		Year Ended December 31, 2012		Nine-Month Period Ended September 30, 2014		Nine-Month Period Ended September 30, 2013		Nine-Month Period Ended September 30, 2014		Year Ended December 31, 2013
	(in thousands)
Reconciliation of EBITDA and Adjusted EBITDA to Net Income (Loss)
Net Income (Loss)	$	(942	)	$	69,538	$	54,643	$	16,182	$	62,869	$	16,182	$	(180,021	)

Add:
Depreciation and amortization		3,480			31,143		32,132		21,989		26,713		21,989		28,737
Interest expense		5,046			10,321		16,145		31,145		9,331		31,145		40,304
Income tax expense		106			361		425		423		317		423		509

EBITDA	$	7,690		$	111,363	$	103,345	$	69,739	$	99,230	$	69,739	$	(110,471	)

Add:
Impairment of assets(1)		—			583		50,771		228		583		228		238,061
Deferred revenue(2)		684			—		—		4,621		—		4,621		684
Other adjustments(3)		5,832			2,207		3,480		3,662		1,576		3,662		2,316

Adjusted EBITDA	$	14,206		$	114,153	$	157,596	$	78,250	$	101,389	$	78,250	$	130,590

Adjusted EBITDA attributable to Azure Midstream Partners, LP(4)												$	31,300	$	52,236

(1)

(2)

Adjustments related to deferred revenues associated with our MRC and MVC producer agreements account for our inclusion of expected cash receipts under these MRC and MVC agreements. With respect to our MRC agreement, the volumes supplied by the customer are currently less than the annual MRC requirement, and we are therefore entitled to receive an annual deficiency payment. The customer’s deficiency payment to us may be credited against future volumes supplied by the customer in excess of the annual MRC. We record the cash receipts associated with the deficiency payments as deferred revenue because the customer is entitled to utilize the deficiency payment to offset future volumes supplied in excess of the annual MRC over the term of the contract. We include a proportional amount of the expected MRC and MVC cash receipts in each quarter in respect of the annual period for which we actually receive the payment to ensure our Adjusted EBITDA reflects the amount of cash we are entitled to receive on an annual basis under these MRC and MVC agreements. For a discussion of adjustments related to deferred revenue associated with our minimum revenue commitments, please read “Our Cash Distribution Policy and Restrictions on Distributions—Unaudited Estimated Distributable Cash Flow for the Twelve Months Ending December 31, 2015.”

(3)

Other adjustments are comprised of legal expenses and transaction expenses associated with the Acquisition, volumetric natural gas imbalance adjustments, gains and losses on sales of assets and non-cash compensation expense.

(4)

Calculated as 40% of Adjusted EBITDA.

RISK FACTORS

Investing in our common units involves a high degree of risk. You should carefully consider the risks described below with all of the other information included in this prospectus before deciding to invest in our common units. Limited partner interests are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. You should consider carefully the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units.

If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we may not be able to pay the minimum quarterly distributions on our common units, the trading price of our common units could decline and you could lose all or part of your investment.

Risks Related to Our Business

In order to make our minimum quarterly distribution of $ per common unit and subordinated unit per quarter, or $ per unit per year, we will require available cash of approximately $ million per quarter, or approximately $ million per year, based on the common units and subordinated units outstanding immediately after completion of this offering. We may not generate sufficient cash flow each quarter to support the payment of the minimum quarterly distribution or to increase our quarterly distributions in the future.

Our ability to distribute cash to our unitholders is or may be limited by a number of factors, including, among others:

•

the level and timing of capital expenditures we make;

•

our debt service requirements and other liabilities;

•

our ability to make borrowings under our debt agreements to pay distributions;

•

fluctuations in our working capital needs;

•

restrictions on distributions contained in any of our debt agreements;

•

the cost of acquisitions, if any;

•

fees and expenses of our general partner and its affiliates we are required to reimburse;

•

the amount of cash reserves established by our general partner; and

•

other business risks affecting our cash levels.

For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read “Our Cash Distribution Policy and Restrictions on Distributions.”

The assumptions underlying the forecast of distributable cash flow, as set forth in “Our Cash Distribution Policy and Restrictions on Distributions,” are inherently uncertain and subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted.

The forecast of distributable cash flow set forth in “Our Cash Distribution Policy and Restrictions on Distributions” includes our forecasted results of operations, Adjusted EBITDA and distributable cash flow for the twelve months ending December 31, 2015. Our ability to pay the full minimum quarterly distribution during the

forecast period is based on a number of assumptions that may not prove to be correct, which are discussed in “Our Cash Distribution Policy and Restrictions on Distributions.” Management has prepared the financial forecast and has not received an opinion or report on it from our or any other independent auditor. The assumptions underlying the forecast are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted. Even if our actual results are consistent with the forecasted results, we may not pay the full minimum quarterly distribution or any amount on our common units or subordinated units, in which event the market price of our common units may decline materially.

Our only asset is a 40% limited partner interest in Azure Midstream Operating, over which we have operating control through our ownership of its general partner. Because our interest in Azure Midstream Operating represents our only cash-generating asset, our cash flow and ability to pay quarterly distributions on our units will depend entirely on the performance of Azure Midstream Operating and its ability to distribute cash to us.

We are a holding company with no material operations and only limited assets, and the source of our earnings and operating cash flow will consist exclusively of cash distributions from Azure Midstream Operating. Therefore, our ability to make quarterly distributions to our unitholders will be completely dependent on the performance of Azure Midstream Operating and its ability to distribute funds to us.

Azure Midstream Operating’s limited partnership agreement requires it to distribute all of its available cash each quarter, less the amounts of cash reserves that its general partner determines are necessary or appropriate in its reasonable discretion to provide for the proper conduct of Azure Midstream Operating’s business, to enable it to make distributions to us so that we can make timely distributions, or to comply with applicable law or any of Azure Midstream Operating’s debt or other agreements. For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read “Our Cash Distribution Policy and Restrictions on Distributions.”

The amount of cash Azure Midstream Operating generates from its operations will fluctuate from quarter to quarter based on, among other things:

•

the volume of natural gas it gathers, compresses, treats and processes;

•

the fees it charges and the margins it realizes for its services;

•

regulatory action affecting the supply of or demand for natural gas, its operations, the rates it can charge, how it contracts for services, its existing contracts, its operating costs or its operating flexibility;

•

the level of its operating, maintenance and general and administrative costs; and

•

prevailing economic conditions.

In addition, the actual amount of cash Azure Midstream Operating will have available for distribution to its partners, including us, also will depend on other factors, such as:

•

the level of capital expenditures it makes;

•

its debt service requirements and other liabilities;

•

restrictions contained in its debt agreements;

•

its ability to borrow funds;

•

fluctuations in its working capital needs;

•

the cost of acquisitions, if any; and

•

the amount of cash reserves established by the general partner.

Any decrease in the volumes of natural gas that Azure Midstream Operating gathers, compresses, treats or processes would adversely affect our financial condition, results of operations and cash flows to the extent not mitigated by minimum volume or revenue commitments.

Our financial performance depends to a large extent on the volumes of natural gas gathered, compressed, treated and processed on Azure Midstream Operating’s assets. To the extent not protected by minimum volume or revenue commitments, decreases in the volumes of natural gas gathered, compressed, treated and processed would directly and adversely affect our revenues and results of operations. These volumes can be influenced by factors beyond our control, including:

•

compliance with environmental or other governmental requirements;

•

adverse weather conditions and natural disasters;

•

increases in storage levels of natural gas;

•

increased use of alternative energy sources;

•

decreased demand for natural gas;

•

fluctuations in commodity prices, including the prices of natural gas;

•

economic conditions;

•

environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures, and unauthorized discharges of pollutants into the surface and subsurface environment;

•

supply disruptions;

•

availability of supply connected to Azure Midstream Operating’s systems; and

•

availability and adequacy of infrastructure to gather, compress, treat and process supply into and out of Azure Midstream Operating’s systems.

The volumes of natural gas gathered, compressed, treated and processed on Azure Midstream Operating’s assets also depend on the production of natural gas from the Haynesville, Bossier and Cotton Valley formations that these systems serve. Supply of natural gas can be affected by many of the factors listed above, including commodity prices and weather. In order to maintain or increase throughput levels on Azure Midstream Operating’s systems, it must obtain new sources of natural gas. The primary factors affecting Azure Midstream Operating’s ability to obtain non-dedicated sources of natural gas include (i) the level of successful leasing, permitting and drilling activity in its areas of operation, (ii) its ability to compete successfully for volumes from new wells and (iii) its ability to compete successfully for volumes from sources connected to other pipelines. Azure Midstream Operating has no control over the level of drilling activity in its areas of operation, the amount of reserves associated with wells connected to its systems or the rate at which production from a well declines. In addition, it has no control over producers or their drilling or production decisions, which are affected by, among other things, the availability and cost of capital, levels of reserves, availability of drilling rigs and other costs of production and equipment.

A significant percentage of our revenue is attributable to a relatively small number of customers. EXCO and BG each accounted for approximately 37.0% of our revenue for the year ended December 31, 2013 and each accounted for approximately 29.0% of our revenue for the nine months ended September 30, 2014. If our customers curtail or reduce production in our areas of operation it could reduce throughput on our systems and through our facilities and, therefore, adversely affect our financial condition, results of operations and cash flows.

Some of our customers may have material financial and liquidity issues or may, as a result of operational incidents or other events, be disproportionately affected as compared to larger, better-capitalized companies. Any material nonpayment or nonperformance by any of our key customers could have a material adverse effect on our financial condition, results of operations and cash flows. We expect our exposure to concentrated risk of non-payment or non-performance to continue as long as we remain substantially dependent on a relatively small number of customers for a substantial portion of our revenue.

The lack of diversification of our assets and geographic locations could adversely affect our ability to make distributions to our common unitholders.

Our operations are focused on natural gas gathering, compression, treating and processing services. Our assets are located exclusively in the Haynesville and Bossier shale formations, the Cotton Valley formation and the shallower producing sands in the Travis Peak formation in North Louisiana and East Texas, and we intend to focus our future capital expenditures largely on developing our business in these areas. As a result, our financial condition, results of operations and cash flows depend upon the demand for our services in these regions. Due to our lack of industrial and geographic diversity, adverse developments in our current segment of the midstream industry or our existing areas of operation, including adverse developments due to catastrophic events, weather or regulatory action, could have a significantly greater impact on our financial condition, results of operations and cash flows than if we maintained more diverse assets and locations. For example, a significant portion of the gas we gather in the Haynesville shale formations and Bossier shale formations is dry gas. Due to declines in natural gas prices, some of our customers have substantially reduced their dry gas production in these regions and announced their intent to reduce capital expenditures for dry gas drilling activities.

We may be unable to renew or replace expiring contracts at favorable rates or on a long-term basis.

Our primary exposure to market risk occurs at the time our existing contracts expire and are subject to renegotiation and renewal. Our minimum volume and revenue commitments have original terms that range from five years to ten years and, as of September 30, 2014, had a weighted average remaining term of 5.2 years. The extension or replacement of existing contracts depends on a number of factors beyond our control, including:

•

the level of existing and new competition to provide services to our markets;

•

the macroeconomic factors affecting natural gas economics for our current and potential customers;

•

the balance of supply and demand, on a short-term, seasonal and long-term basis, in our markets;

•

the extent to which the customers in our markets are willing to contract on a long-term basis; and

•

the effects of federal, state or local regulations on the contracting practices of our customers.

Any failure to extend or replace a significant portion of our existing contracts, or extending or replacing them at unfavorable or lower rates, could have a material adverse effect on our business, results of operations, financial condition and ability to make quarterly cash distributions to our unitholders.

We may not be able to increase Azure Midstream Operating’s third-party gathering, compression, treating and processing volumes and resulting revenue due to competition and other factors, which could limit our ability to grow.

Part of our growth strategy includes maximizing the utilization of our assets by increasing volume throughput from existing customers and connecting new customers to our systems. Our ability to increase our throughput and resulting revenue is subject to numerous factors beyond our control, including competition from third parties and the extent to which we have available capacity when third-party shippers require it. Some of our competitors have greater financial resources and access to larger supplies of natural gas than those available to us, which could allow those competitors to price their services more aggressively than we do.

Our efforts to attract new customers may be adversely affected by our desire to provide services pursuant to fixed-fee and fixed-spread contracts. Our potential customers may prefer to obtain services pursuant to other forms of contractual arrangements under which we would be required to assume direct commodity exposure.

The amount of cash we have available for distribution to our unitholders depends primarily on our cash flow and not solely on profitability, which may prevent us from making distributions, even during periods in which we record net income.

You should be aware that the amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record a net loss for financial accounting purposes, and conversely, we may fail to make cash distributions during periods when we record net income for financial accounting purposes.

Our construction or purchase of new assets may not result in revenue increases and may be subject to numerous risks, which could adversely affect our cash flows, results of operations and financial condition and, as a result, our ability to distribute cash to our unitholders.

The construction of additions or modifications to Azure Midstream Operating’s existing systems and the construction or purchase of new midstream assets involve numerous uncertainties beyond our control. Financing may not be available on economically acceptable terms or at all. Furthermore, if we undertake projects, they may not be completed on schedule, at the budgeted cost, or at all. We may not receive any material increase in operating cash flow from a project for some time, particularly in the case of greenfield projects, or the cash flow we receive may not meet our expectations. If we experience unanticipated or extended delays in generating operating cash flow from construction projects, we may need to reduce or reprioritize our capital budget in order to meet our capital requirements,

We often rely on estimates of future production in deciding whether to construct additional or new pipelines or facilities. These estimates may prove to be inaccurate because of the numerous technological, economic and other uncertainties inherent in estimating quantities of future production. As a result, new facilities may not be able to attract sufficient volumes to achieve our expected investment return. We also may construct assets in reliance on firm capacity commitments by third-party facilities downstream of our facilities. If such third-party facilities are not available when we expect them, we could be adversely affected.

In addition, the construction of additions to our existing gathering and processing assets will generally require us to obtain new rights-of-way prior to constructing new pipelines or facilities. We may be unable to timely obtain such rights-of-way to connect new natural gas supplies to our existing gathering lines or capitalize on other attractive growth opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or to expand or renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, our cash flows could be adversely affected.

If any of the risks described above occur, it could have a material adverse effect on our results of operations, financial condition and cash flows and our ability to make distributions to our unitholders.

We may be unable to grow by acquiring the interest in Azure Midstream Operating owned by Azure Midstream Holdings, which could limit our ability to increase our distributable cash flow.

A portion of our strategy to grow our business and increase distributions to our unitholders is dependent on our ability to make acquisitions that result in an increase in our distributable cash flow. The acquisition component of our growth strategy is based, in large part, on our expectation of ongoing divestitures by Azure Midstream Holdings of portions of its remaining ownership interest in Azure Midstream Operating to us. We have only a right of first offer pursuant to an agreement to purchase the 60% limited partner interest in Azure Midstream Operating being retained by Azure Midstream Holdings at the closing of this offering. Azure

Midstream Holdings is not obligated to offer us the opportunity to purchase this interest. We may never purchase all or any portion of this interest for several reasons, including the following:

•

Azure Midstream Holdings may choose not to sell the interest;

•

We may decide not to make an offer for the interest;

•

We may be unable to agree on acceptable purchase terms with Azure Midstream Holdings; and

•

We may be unable to obtain financing for the purchase on acceptable terms, or we may be prohibited by the terms of credit facilities, indentures or other contracts from purchasing some or all of the interest, and Azure Midstream Holdings may be prohibited by the terms of its credit facilities, indentures or other contracts from selling some or all of such interest. If we or Azure Midstream Holdings must seek waivers of such provisions or refinance debt governed by such provisions in order to consummate a sale of the interest, we or Azure Midstream Holdings may be unable to do so in a timely manner or at all.

We do not know when or if any such interest will be offered to us to purchase, and we can offer no assurance that we will be able to successfully consummate any future acquisition of such interest in Azure Midstream Operating. Furthermore, if Azure Midstream Holdings reduces its ownership interest in us, it may be less willing to sell its remaining ownership interest in Azure Midstream Operating to us. In addition, there are no restrictions on Azure Midstream Holdings’ ability to transfer its ownership interest in Azure Midstream Operating to a third party. If we do not acquire a significant portion of Azure Midstream Holdings’ remaining 60% interest in Azure Midstream Operating, our ability to grow our business and increase our distributions to unitholders may be limited.

If we are unable to make acquisitions on economically acceptable terms from third parties, our future growth will be limited, and the acquisitions we do make may reduce, rather than increase, our cash generated from operations on a per unit basis.

Our ability to grow depends, in part, on our ability to make acquisitions that increase our cash generated from operations on a per unit basis. The acquisition component of our strategy is based, in large part, on our expectation of ongoing divestitures of midstream energy assets by industry participants. However, there can be no assurance that any such divestitures will be made, and a material decrease in divestitures of midstream energy assets would limit our opportunities for future acquisitions and could have a material adverse effect on our business, results of operations, financial condition and ability to make quarterly cash distributions to our unitholders.

If we are unable to make accretive acquisitions, whether because, among other reasons, (i) we are unable to identify attractive third-party acquisition opportunities, (ii) we are unable to negotiate acceptable purchase contracts, (iii) we are unable to obtain financing for these acquisitions on economically acceptable terms or (iv) we are unable to obtain necessary governmental or third-party consents, then our future growth and ability to increase distributions will be limited. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations on a per unit basis.

Any acquisition involves potential risks, including, among other things:

•

mistaken assumptions about volumes, revenue and costs, including synergies and potential growth;

•

an inability to secure adequate customer commitments to use the acquired systems or facilities;

•

an inability to integrate successfully the assets or businesses we acquire;

•

the assumption of unknown liabilities for which we are not indemnified or for which our indemnity is inadequate;

•

the diversion of management’s and employees’ attention from other business concerns; and

•

unforeseen difficulties operating in new geographic areas or business lines.

If any acquisition eventually proves not to be accretive to our distributable cash flow per unit, it could have a material adverse effect on our business, results of operations, financial condition and ability to make quarterly cash distributions to our unitholders.

If third-party pipelines or other midstream facilities interconnected to Azure Midstream Operating’s gathering, compression, treating or processing systems become partially or fully unavailable, or if the volumes Azure Midstream Operating gathers, compresses, treats and processes does not meet the natural gas quality requirements of such pipelines or facilities, our operating margin and cash flow and our ability to make distributions to our unitholders could be adversely affected.

Azure Midstream Operating’s gathering, compression, treating and processing assets connect to other pipelines or facilities owned and operated by unaffiliated third parties, such as Regency Energy Partners, LP, Acadian Energy Inc., Gulf South Pipeline Company, LP, Natural Gas Pipeline of America, the Carthage Hub, Waskom Gas Processing Company and DCP Midstream Partners, LP. The continuing operation of such third-party pipelines, processing facilities and other midstream facilities is not within our control. These pipelines, plants and other midstream facilities may become unavailable because of testing, turnarounds, line repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements and curtailments of receipt or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues. If any of these pipelines or other midstream facilities become unable to receive, transport or process natural gas, or if the volumes Azure Midstream Operating gathers, compresses, treats or processes do not meet the natural gas quality requirements of such pipelines or facilities, our operating margin and ability to make cash distributions to our unitholders could be adversely affected.

Because of the natural decline in production from existing wells in Azure Midstream Operating’s areas of operation, our success depends, in part, on producers replacing declining production and also on our ability to secure new sources of natural gas. Any decrease in the volumes of natural gas that Azure Midstream Operating gathers, compresses, treats and processes could adversely affect our business and operating results.

The natural gas volumes that support our business depend on the level of production from natural gas wells connected to Azure Midstream Operating’s systems, which may be less than expected and will naturally decline over time. As a result, our cash flows associated with these wells will also decline over time. In order to maintain or increase throughput levels on Azure Midstream Operating’s systems, we must obtain new sources of natural gas. The primary factors affecting our ability to obtain sources of natural gas include (i) the level of successful drilling activity in Azure Midstream Operating’s areas of operation, (ii) our ability to compete for volumes from successful new wells and (iii) our ability to compete successfully for volumes from sources connected to other pipelines.

We have no control over the level of drilling activity in Azure Midstream Operating’s areas of operation, the amount of reserves associated with wells connected to Azure Midstream Operating’s systems or the rate at which production from a well declines. In addition, we have no control over producers or their drilling or production decisions, which are affected by, among other things:

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the availability and cost of capital;

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prevailing and projected natural gas prices;

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demand for natural gas;

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levels of reserves;

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geologic considerations;

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compliance with environmental or other governmental requirements, including the permitting of drilling activity and the regulation of hydraulic fracturing; and

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the costs of producing the gas, the availability and costs of drilling rigs and other equipment.

Fluctuations in energy prices can also greatly affect the development of natural gas reserves. Drilling and production activity generally decreases as natural gas prices decrease. Declines in natural gas prices could have a negative impact on exploration, development and production activity, and if sustained, could lead to a material decrease in such activity. Sustained reductions in exploration or production activity in Azure Midstream Operating’s areas of operation could lead to reduced utilization of its assets.

Due to these and other factors, even if oil, NGLs and natural gas reserves are known to exist in areas served by Azure Midstream Operating’s assets, producers may choose not to develop those reserves. If reductions in drilling activity result in our inability to maintain the current levels of throughput on our systems, those reductions could reduce our revenue and cash flow and adversely affect our ability to make cash distributions to our unitholders.

Our exposure to commodity price risk may vary over time.

For the nine months ended September 30, 2014, we generated over 90% of our revenues pursuant to fixed-fee and fixed-spread contracts under which we are paid based on the volumes of natural gas and NGLs that we gather, compress, treat and process, rather than the underlying value of the natural gas and NGLs. Consequently, our existing operations and cash flows have limited direct exposure to commodity price risk. Although we intend to enter into similar fixed-fee and fixed-spread contracts with new customers in the future, our efforts to negotiate such contractual terms may not be successful. In addition, we may acquire or develop additional midstream assets in a manner that increases our exposure to commodity price risk. Future exposure to the volatility of natural gas and NGLs prices could have a material adverse effect on our business, results of operations and financial condition.

A change in the jurisdictional characterization of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of such assets, which may cause our revenues to decline and our operating expenses to increase.

All of our natural gas gathering, compressing, treating and processing operations are exempt from Federal Energy Regulatory Commission, or FERC, regulation under the Natural Gas Act of 1938, or NGA. Section 1(b) of the Natural Gas Act of 1938, or NGA, exempts natural gas gathering facilities from regulation by FERC under the NGA. In a declaratory order dated May 4, 2007, FERC declared our subsidiary, TGG Pipeline, Ltd., to be a natural gas gathering facility and it is not subject to FERC regulation. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish whether a pipeline is a gathering pipeline not subject to FERC jurisdiction. However, the classification and regulation of our natural gas gathering facilities may be subject to change based on future determinations by FERC, the courts, or Congress. If FERC were to consider the status of an individual facility and determine that the facility or services provided by it are not exempt from FERC regulation under the NGA, 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 Natural Gas Policy Act of 1978, or 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.

Other FERC regulations may indirectly impact our businesses and the markets for products derived from these businesses. FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on open access transportation, ratemaking, gas quality, capacity release and market center promotion, may indirectly affect the natural gas gathering market. Should Azure Midstream Operating fail to comply with all applicable FERC administered statutes, rules, regulations and orders, it could be subject to substantial penalties and fines, which could have a material adverse effect on our results of operations and cash

flows. FERC has civil penalty authority pursuant to the Energy Policy Act of 2005 to impose penalties for violations of the NGA and NGPA of up to $1,000,000 per day for each violation and disgorgement of profits associated with any violation.

State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take and common purchaser requirements designed to prohibit discrimination in favor of one producer over another or one source of supply over another, as well as complaint-based rate regulation. The regulations can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. Texas has adopted regulations that generally allow natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to gathering access and discrimination. Other state regulations may not directly apply to our business, but may nonetheless affect the availability of natural gas for purchase, processing and sale, including Texas’ regulation of production rates and maximum daily production allowable from natural gas wells.

Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels. Our gathering operations could be adversely affected in the future should they become subject to the application of state or federal regulation of rates and services. These operations may also be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of such facilities. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes. For more information regarding federal and state regulation of our operations, please read “Business—Regulation of Operations.”

Increased regulation of hydraulic fracturing could result in reductions or delays in natural gas production by our customers, which could adversely impact our revenues by decreasing the volumes of natural gas that Azure Midstream Operating gathers, compresses, treats and processes.

An increasing percentage of our customers’ natural gas production is being developed from unconventional sources, such as deep natural gas shales. These reservoirs require hydraulic fracturing completion processes to release the natural gas from the rock so it can flow through casing to the surface. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate production. Several federal agency reviews have been conducted or are underway that focus on the environmental impacts of hydraulic fracturing activities including a current study by the U.S. Environmental Protection Agency (“EPA”) which is expected to be published in a draft report for public comment and peer review in 2014. At the same time, certain environmental groups have advocated for additional laws to more closely and uniformly regulate the hydraulic fracturing process, and legislation has been proposed from time to time by some members of Congress to provide for such regulation. In addition, some states have adopted and other states are considering adopting legal requirements imposing more stringent restrictions on hydraulic fracturing while local governments may also seek to adopt ordinances within their jurisdictions limiting aspects of fracturing activities. Additional regulation of hydraulic fracturing through the adoption of new laws, regulations and ordinances at the federal, state or local levels could lead to delays, increased operating costs and process prohibitions that could reduce the volumes of natural gas that move through our gathering, compression, treating and processing systems, which would materially adversely affect our revenues and results of operations.

Our operations are subject to environmental laws and regulations that may expose us to significant costs and liabilities and have an adverse effect on our results of operations and cash flows.

Azure Midstream Operating’s gathering, compression, treating and processing operations are subject to stringent federal, state and local environmental laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations that are applicable to Azure Midstream Operating’s operations including acquisition of a

permit before conducting regulated activities, restrictions on the types, quantities and concentration of materials that can be released into the environment; limitation or prohibition of construction and operating activities in environmentally sensitive areas such as wetlands, wilderness regions and other protected areas; requiring capital expenditures to comply with pollution control requirements and imposition of substantial liabilities for pollution resulting from Azure Midstream Operating’s operations. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, which can often require difficult and costly actions. Failure to comply with these laws and regulations may result in a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties or other sanctions, the imposition of remedial obligations and the issuance of orders enjoining future operations or imposing additional compliance requirements on such operations.

Certain environmental laws impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances, petroleum hydrocarbons or wastes have been released, even under circumstances where the materials have been released by a predecessor operator. Moreover, private parties, including the owners of the properties through which Azure Midstream Operating’s gathering, compression, treating or processing systems pass and facilities where its wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as seek damages for personal injury and property damage allegedly caused by an accidental release of hazardous substances, petroleum substances or wastes. The adoption of stricter environmental laws, regulations or enforcement policies could significantly increase our operational or compliance costs and the cost of any remediation that may become necessary. Similarly, the adoption of environmental laws or regulations that result in more stringent drilling restrictions or prohibit the drilling of new natural gas wells for any extended period of time could increase our natural gas customers’ operating and compliance costs as well as reduce the rate of production of crude oil, NGLs or natural gas from operators with whom we have a business relationship, which could have a material adverse effect on our results of operations and cash flows.

The adoption of climate change legislation or regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the services we provide.

In December 2009, the EPA published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has adopted rules under the Clean Air Act that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources that are potential major sources of certain principal, or criteria, pollutant emissions, which reviews could require meeting “best available control technology” standards for those GHG emissions. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore production facilities and onshore processing, transmission and storage facilities in the United States on an annual basis, which includes certain assets we operate. While Congress has from time to time considered adopting legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs. The adoption of any legislation or regulation that requires reporting of GHGs or otherwise restricts emissions of GHGs from our equipment and operations could require us to incur significant added costs to reduce emissions of GHGs or could adversely affect demand for the natural gas Azure Midstream Operating gathers, compresses, treats or processes. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHG in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climate events that could have an adverse effect on our assets and operations.

Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation.

The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (“2011 Pipeline Safety Act”) is the most recent federal legislation to amend the Natural Gas Pipeline Safety Act of 1968 (“NGPSA”), requiring increased safety measures for natural gas transportation pipelines. Among other things, the 2011 Pipeline Safety Act 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, pipeline material strength testing, and verification of the maximum allowable pressure of certain pipelines. The 2011 Pipeline Safety Act also increases the maximum penalty for violation of pipeline safety regulations from $100,000 to $200,000 per violation per day of violation and from $1 million to $2 million for a related series of violations. The safety enhancement requirements and other provisions of the 2011 Pipeline Safety Act as well as any implementation of PHMSA rules thereunder could require us to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could be significant and have a material adverse effect on our results of operations or financial position.

We may incur significant costs and liabilities resulting from pipeline integrity programs and related repairs.

Pursuant to authority under the NGPSA, as amended by the Pipeline Safety Improvement Act of 2002, the PIPES Act and the 2011 Pipeline Safety Act, PHMSA has established a series of rules requiring pipeline operators to develop and implement integrity management programs for natural gas transmission pipelines that, in the event of a pipeline leak or rupture, could affect “high consequence areas,” which are areas where a release could have the most significant adverse consequences, including high population areas, certain drinking water sources and unusually sensitive ecological areas. These regulations require the operators of covered pipelines to: (i) perform ongoing assessments of pipeline integrity; (ii) identify and characterize applicable threats to pipeline segments that could impact a high consequence area; (iii) improve data collection, integration and analysis; (iv) repair and remediate the pipeline as necessary; and (v) implement preventive and mitigating actions.

In addition, states have adopted regulations similar to existing PHMSA regulations for intrastate gathering and transmission lines. At this time, we cannot predict the ultimate cost of compliance with these regulations

Moreover, changes to pipeline safety laws by Congress and regulations by PHMSA that result in more stringent or costly safety standards could have a significant adverse effect on us and similarly situated midstream operators. For instance, in August 2011, PHMSA published an advance notice of proposed rulemaking 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. PHMSA continues to evaluate the public comments received with respect to more stringent integrity management programs.

Restrictions in our new credit facility could adversely affect our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.

Upon the closing of the offering, we will enter into a $150 million revolving credit facility. Our new credit facility will contain various covenants and restrictive provisions that will limit our ability to, among other things:

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incur or guarantee additional debt;

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make distributions on or redeem or repurchase units;

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make certain investments and acquisitions;

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incur certain liens or permit them to exist;

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enter into certain types of transactions with affiliates;

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merge or consolidate with another company; and

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transfer, sell or otherwise dispose of assets.

Our new credit facility also will contain covenants requiring us to maintain certain financial ratios. Our ability to meet those financial ratios and tests can be affected by events beyond our control and we cannot provide assurance that we will meet those ratios and tests. In addition, our credit facility will contain events of default customary for transactions of this nature. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Azure Midstream Partners, LP Credit Agreement” for additional information regarding our revolving credit facility.

Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. The occurrence of a significant accident or other event that is not fully insured could curtail our operations and have a material adverse effect on our ability to distribute cash and, accordingly, the market price for our common units.

Azure Midstream Operating’s operations are subject to all of the hazards inherent in the gathering, compression, treating and processing of natural gas, including:

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damage to pipelines and processing facilities, related equipment and surrounding properties caused by natural disasters, acts of terrorism and acts of third parties;

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damage from construction, farm and utility equipment as well as other subsurface activity;

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leaks or losses of natural gas or as a result of the malfunction of equipment or facilities;

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fires, ruptures and explosions; and

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other hazards that could also result in personal injury and loss of life, pollution and natural resource damages, and suspension of operations.

These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental or natural resource damage, and they may result in curtailment or suspension of our related operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations.

To mitigate financial losses resulting from these operational hazards, we maintain comprehensive general liability insurance, as well as insurance coverage against certain losses resulting from physical damages, business interruption and pollution events that are considered sudden and accidental. However, we are not fully insured against all risks inherent to our business and our insurance coverage does not provide 100 percent reimbursement of potential losses resulting from these hazards. Insurance coverage is generally not available to us for pollution events that are considered gradual, and we have limited or no insurance coverage for certain risks such as political risk, war and terrorism. Our insurance coverage does not cover penalties or fines assessed by governmental authorities. If a significant accident or unplanned event occurs that is not fully insured, it could adversely affect our revenues, earnings and cash flows and have a material adverse effect on our ability to make cash distributions to you.

In addition, we may not be able to maintain or obtain insurance of the type and amount we desire at acceptable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may increase substantially. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage.

Some of Azure Midstream Operating’s facilities may be subject to claims by neighbors that the facilities interfere with the use or enjoyment of their property.

Although Azure Midstream Operating’s facilities are generally in rural areas, some may be in proximity to residences or other inhabited tracts. These neighbors may claim that Azure Midstream Operating’s gathering, compression, treating and processing assets interfere with their use or enjoyment of such property and its resale value. We may not be able to recover the costs to defend, settle or litigate these claims through insurance or increased revenues, which may materially reduce our revenues, earnings and cash flows and have a material adverse effect on our ability to make cash distributions to you.

Azure Midstream Operating does not own all of the land on which its pipelines and facilities are located, which could result in disruptions to its operations.

Azure Midstream Operating does not own all of the land on which its pipelines and facilities have been constructed, and it is, therefore, subject to the possibility of more onerous terms or increased costs to retain necessary land use if it does not have valid rights-of-way or if such rights-of-way lapse or terminate. Azure Midstream Operating obtains the rights to construct and operate its pipelines on land owned by third parties and governmental agencies for a specific period of time. Azure Midstream Operating’s loss of these rights, through its inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to you.

We are exposed to the credit risk of our customers in the ordinary course of our business.

We extend credit to our customers as a normal part of our business. As a result, we are exposed to the risk of loss resulting from the nonpayment and/or nonperformance of our customers. While we have established credit policies, including assessing the creditworthiness of our customers and requiring appropriate terms or credit support from them based on the results of such assessments, we may not have adequately assessed the creditworthiness of our existing or future customers. Furthermore, unanticipated future events could result in a deterioration of the creditworthiness of our contracted customers. Any resulting nonpayment and/or nonperformance by our customers could have a material adverse effect on our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.

The loss of key personnel could adversely affect our ability to operate.

We depend on the leadership, involvement and services of a relatively small group of our general partner’s key executive management personnel, and other officers and key technical and commercial personnel. The services of these individuals may not be available to us in the future. Because competition for experienced personnel in the midstream industry is intense, we may not be able to find acceptable replacements with comparable skills and experience. Accordingly, the loss of the services of one or more of these individuals could have a material adverse effect on our ability to operate our business.

We do not have any officers or employees and rely solely on officers of our general partner and employees of Azure Midstream Holdings.

We are managed and operated by the board of directors and officers of our general partner. Affiliates of Azure Midstream Holdings conduct businesses and activities of their own in which we have no economic interest, including businesses and activities relating to Azure Midstream Holdings. As a result, there could be material competition for the time and effort of the officers and employees who provide services to our general partner and Azure Midstream Holdings. If the officers of our general partner and the employees of Azure Midstream Holdings do not devote sufficient attention to the management and operation of our business, our financial results may suffer, and our ability to make distributions to our unitholders may be reduced.

A shortage of skilled labor in the midstream natural gas industry could reduce employee productivity and increase costs, which could have a material adverse effect on our business and results of operations.

The gathering, compression, treating and processing of natural gas requires skilled laborers in multiple disciplines such as equipment operators, mechanics and engineers, among others. We have from time to time encountered shortages for these types of skilled labor. If we experience shortages of skilled labor in the future, our labor and overall productivity or costs could be materially and adversely affected. If our labor prices increase or if we experience materially increased health and benefit costs with respect to our general partner’s employees, our results of operations could be materially and adversely affected.

Debt we incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.

Our future level of debt could have important consequences to us, including the following:

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our ability to obtain additional financing, if necessary, for working capital, capital expenditures (including required drilling pad connections and well connections pursuant to our gas gathering agreements as well as acquisitions) or other purposes may be impaired or such financing may not be available on favorable terms;

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our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flow required to make interest payments on our debt;

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we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and

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our flexibility in responding to changing business and economic conditions may be limited.

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service any future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, investments or capital expenditures, selling assets or issuing equity. We may not be able to effect any of these actions on satisfactory terms or at all.

Increases in interest rates could adversely affect our business.

We will have negative exposure to a material increase in interest rates. In connection with this offering we will enter into a $150 million revolving credit facility. Immediately after the consummation of this offering on a pro forma basis, we do not expect to have any outstanding indebtedness. However, we may in the future make borrowings under our new revolving credit facility or other debt agreements that we may enter into in the future. As a result, our results of operations, cash flows and financial condition could be materially adversely affected by a material increase in interest rates.

Our industry is highly competitive, and increased competitive pressure could adversely affect our business and operating results.

We compete with similar enterprises in the Haynesville, Bossier and Cotton Valley formations for production from third parties. Some of our competitors may expand or construct gathering, compression, treating and processing systems facilities that would create additional competition for the activities we perform. In addition, our customers who are significant producers of natural gas may develop their own gathering, compression, treating and processing systems facilities in lieu of using Azure Midstream Operating’s systems. 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 our customers. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and, as a result, our ability to make cash distributions to our unitholders.

A natural disaster, catastrophe or other event could result in severe personal injury, property damage and environmental damage, which could curtail our operations and otherwise materially adversely affect our cash flow and, accordingly, affect the market price of our common units.

Some of our operations involve risks of personal injury, property damage and environmental damage, which could curtail our operations and otherwise materially adversely affect our cash flow. For example, natural gas facilities operate at high pressures, sometimes in excess of 1,100 pounds per square inch. Pipelines may suffer inadvertent damage from construction, farm and utility equipment. Virtually all of our operations are exposed to potential natural disasters, including hurricanes, tornadoes, storms and floods. The location of our assets and our customers’ assets in the U.S. Gulf Coast region makes them particularly vulnerable to hurricane or tropical storm risk.

If one or more facilities that we own or that deliver natural gas or other products to us are damaged by severe weather or any other disaster, accident, catastrophe or event, our operations could be significantly interrupted. Similar interruptions could result from damage to production or other facilities that supply our facilities or other stoppages arising from factors beyond our control. These interruptions might involve significant damage to people, property or the environment, and repairs might take from a week or less for a minor incident to six months or more for a major interruption. Any event that interrupts the revenues generated by our operations, or which causes us to make significant expenditures not covered by insurance, could reduce our cash available for paying distributions and, accordingly, adversely affect the market price of our common units.

We believe that we maintain adequate insurance coverage, although insurance will not cover many types of interruptions that might occur and will not cover amounts up to applicable deductibles. As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. For example, changes in the insurance markets subsequent to the hurricanes in 2005 and 2008 have made it more difficult for us to obtain certain types of coverage. As a result, we may not be able to renew existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position, results of operations and cash flows. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.

Terrorist attacks or cyber-attacks could have a material adverse effect on our business, financial condition or results of operations.

Terrorist attacks or cyber-attacks may significantly affect the energy industry, including our operations and those of our customers, as well as general economic conditions, consumer confidence and spending and market liquidity. Strategic targets, such as energy-related assets, may be at greater risk of future attacks than other targets in the United States. Our insurance may not protect us against such occurrences. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations.

Risks Inherent in an Investment in Us

Azure Midstream Holdings will own a 60% limited partner interest in Azure Midstream Operating and will control our general partner, which has sole responsibility for conducting our business and managing our operations, and we will own the general partner of Azure Midstream Operating, which is responsible for managing the operations of Azure Midstream Operating. Our general partner and its affiliates, including Azure Midstream Holdings, have conflicts of interest with, and limited duties with respect to, us and our unitholders, and may favor their own interests to our detriment and that of our unitholders. Additionally we have no control over Azure Midstream Holdings’ business decisions and operations, and Azure Midstream Holdings is under no obligation to adopt a business strategy that favors us.

Following the offering, Azure Midstream Holdings will own and control our general partner. Some of the directors and all of the executive officers of our general partner are officers of Azure Midstream Holdings. Although our general partner has a duty to manage us in a manner it believes is not adverse to our interests, the directors and officers of our general partner have duties to manage our general partner in a manner beneficial to Azure Midstream Holdings. Conflicts of interest may arise between Azure Midstream Holdings and its affiliates, including our general partner, on the one hand, and us or any of our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:

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neither our partnership agreement nor any other agreement requires Azure Midstream Holdings to pursue a business strategy that favors us. Azure Midstream Holdings’ directors and officers have a fiduciary duty to make these decisions in a manner that is beneficial to the owners of Azure Midstream Holdings and affiliated entities, which may be contrary to our interests;

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our general partner is allowed to take into account the interests of parties other than us in exercising certain rights under our partnership agreement, including with respect to resolving conflicts of interest;

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Azure Midstream Holdings is not limited in its ability to compete with us;

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Azure Midstream Holdings may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to Azure Midstream Holdings’ incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations;

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Azure Midstream Holdings is under no obligation to offer us any additional interest in Azure Midstream Operating;

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some officers of Azure Midstream Holdings who provide services to us also will devote significant time to the business of Azure Midstream Holdings, and will be compensated by Azure Midstream Holdings for the services rendered to it;

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our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner, 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. By purchasing common units, unitholders will be deemed to have consented to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law;

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our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and reserves, each of which can affect the amount of cash that is distributed to unitholders;

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our general partner determines the amount of our estimated maintenance capital expenditures, which reduces 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;

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our general partner determines which costs incurred by it and its affiliates are reimbursable by us;

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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;

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our partnership agreement permits us to distribute up to $ 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 units or the incentive distribution rights;

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our partnership agreement does not restrict 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;

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our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, is entitled to be indemnified by us;

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our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of the common units;

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our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates; and

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our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

Please read “Conflicts of Interest and Fiduciary Duties.”

Azure Midstream Holdings and other affiliates of our general partner are not restricted in their ability to compete with us.

Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership of interests in us. Affiliates of our general partner, including Azure Midstream Holdings, are not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. Azure Midstream Holdings will be under no obligation to make any acquisition opportunities available to us. Moreover, while Azure Midstream Holdings may offer us the opportunity to buy additional assets from it, it is under no contractual obligation to accept any offer we might make with respect to such opportunity.

Azure Midstream Holdings currently holds interests in, and may make investments in and purchases of, entities that acquire, own and operate other natural gas midstream 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 Azure Midstream Holdings. 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. Please read “Conflicts of Interest and Fiduciary Duties.”

Ongoing cost reimbursements due to our general partner and its affiliates for services provided, which will be determined by our general partner, will be substantial and will reduce our distributable cash flow.

Prior to making distributions on our common units, we will reimburse our general partner and its affiliates for all expenses they incur on our behalf. These expenses will include all costs incurred by our general partner and its affiliates in managing and operating us, including costs for rendering corporate staff and support services to us. There is no limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us. In addition, under Delaware partnership law, our general partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our general partner. To the extent our general partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash otherwise available for distribution to our unitholders.

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

Because we distribute all of our available cash to our unitholders, we expect that we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our share of Azure Midstream Operating’s growth capital expenditures and acquisitions. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow. Furthermore, we anticipate using the net proceeds of this offering to make a cash contribution to Azure Midstream Operating of $ million, the entirety of which will be used to repay a portion of Azure Energy’s indebtedness. As a result, the net proceeds of this offering will not be used to grow our business.

In addition, because we distribute all of our available cash, our 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 growth 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 on our ability to issue additional units, including units ranking senior to the common units. The incurrence of 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.

We will be required to deduct estimated maintenance capital expenditures from operating surplus, which may result in less distributable cash flow than if actual maintenance capital expenditures were deducted.

Our partnership agreement requires us to deduct estimated, rather than actual, maintenance capital expenditures from our operating surplus. The amount of estimated maintenance capital expenditures deducted from operating surplus will be subject to review and change by our conflicts committee at least once a year. In years when our estimated maintenance capital expenditures are higher than actual maintenance capital expenditures, the amount of distributable cash flow will be lower than if actual maintenance capital expenditures were deducted from our operating surplus. If we underestimate the appropriate level of estimated maintenance capital expenditures, we may have less distributable cash flow in future periods when actual capital expenditures begin to exceed our previous estimates. Over time, if we do not set aside sufficient cash reserves or have available sufficient sources of financing and make sufficient expenditures to maintain our asset base, we will be unable to pay distributions at the anticipated level and could be required to reduce our distributions.

If you are not an eligible taxable holder, you will not be entitled to allocations of income or loss or distributions or voting rights on your common units and your common units will be subject to redemption.

In order to avoid any material adverse effect on the maximum applicable rates that can be charged to customers by our subsidiaries on assets that are subject to rate regulation by FERC or analogous regulatory body, we have adopted certain requirements regarding those investors who may own our common units. Eligible holders are individuals or entities subject to United States federal income taxation on the income generated by us or entities not subject to United States federal income taxation on the income generated by us, so long as all of the entity’s owners are subject to such taxation. Please read “Description of the Common Units—Transfer of Common Units.” If you are not a person who fits the requirements to be an eligible taxable holder, you will not receive allocations of income or loss or distributions or voting rights on your units and you run the risk of having your units redeemed by us at the market price calculated in accordance with our partnership agreement as of the date of redemption. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Please read “The Partnership Agreement—Non-Citizen Assignees; Redemption.”

Our partnership agreement replaces our general partner’s fiduciary duties to holders of our units with contractual standards governing its duties.

Our partnership agreement contains provisions that eliminate and replace the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. 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, or otherwise, free of fiduciary 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 parties where the language in our partnership agreement does not provide for a clear course of action. This entitles our general partner to consider only the interests and factors that it desires, and it has no 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:

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how to allocate business opportunities among us and its other affiliates;

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whether to exercise its call right;

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how to exercise its voting rights with respect to the units it owns;

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whether to exercise its registration rights;

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whether to elect to reset target distribution levels; and

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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 unitholder is treated as having consented to the provisions in the partnership agreement, including the provisions discussed above. Please read “Conflicts of Interest and Fiduciary Duties—Fiduciary Duties.”

Unitholders have very limited voting rights and are not entitled to appoint or remove our general partner or elect the board of directors of our general partner, which could reduce the price at which our common units will trade.

Unitholders have only limited voting rights and, therefore, limited ability to influence management’s decisions regarding our business. Unlike holders of stock in a public corporation, unitholders will not have “say-on-pay” advisory voting rights. Unitholders did not elect our general partner or the board of directors of our general partner and will have no right to elect our general partner or the board of directors of our general partner on an annual or other continuing basis. The directors of our general partner are chosen by Azure Midstream Holdings. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. 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.

The unitholders will be unable initially to remove our general partner without its consent because our general partner and its affiliates will own sufficient units upon the closing of this offering to prevent its removal. The vote of the holders of at least 66²/₃% of all outstanding common units and subordinated units voting together as a single class is required to remove our general partner. At the closing of this offering, our general partner and its affiliates will own approximately % of the total outstanding common units and subordinated units on an aggregate basis (or % of our total outstanding common units and subordinated units on an aggregate basis if the underwriters’ option to purchase additional common units is exercised in full), in each case, excluding common units purchased by certain of our officers, directors, employees and certain other persons affiliated with us under our directed unit program.

In addition, any vote to remove our general partner during the subordination period must provide for the election of a successor general partner by the holders of a majority of the common units and a majority of the subordinated units, voting as separate classes. This will provide Azure Midstream Holdings the ability to prevent the removal of our general partner.

Our partnership agreement restricts the remedies available to holders of our 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:

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whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, meaning that it did not act, or omit from acting, with the belief that such act or omission was adverse to the interest of the partnership, and will not be subject to any higher standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

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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 bad faith or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful; and

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our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is:

(i)

approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval; or

(ii)

approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, other than one where our general partner is permitted to act in its sole discretion, any determination by our general partner 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 then it will be presumed that, in making its decision, taking any action or failing to act, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Please read “Conflicts of Interest and Fiduciary Duties.”

Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit its liability under contractual arrangements between us and third parties 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 nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s duties, 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.

Azure Midstream Holdings may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to its incentive distribution rights, without the approval of the conflicts committee of our general partner’s board of directors or the holders of our common units. This could result in lower distributions to holders of our common units.

Azure Midstream Holdings has the right, as the initial indirect holder of our incentive distribution rights, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (50.0%) for the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distribution levels at the time of the exercise of the reset election. Following a reset election by Azure Midstream Holdings, the minimum quarterly distribution will be adjusted to equal 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.

If Azure Midstream Holdings elects to reset the target distribution levels, it will be entitled to receive common units as consideration for such election. The number of common units to be issued to Azure Midstream Holdings will equal the number of common units that would have entitled Azure Midstream Holdings to an aggregate quarterly cash distribution in the quarter prior to the reset election equal to the distribution to Azure Midstream Holdings on the incentive distribution rights in the quarter prior to the reset election. We anticipate that Azure Midstream Holdings 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. It is possible, however, that Azure Midstream Holdings could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive incentive distributions based on the initial target distribution levels. This risk could be elevated if our incentive distribution rights have been transferred to a third party. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that our common unitholders would have otherwise received had we not issued new common units to Azure Midstream Holdings in connection with resetting the target distribution levels. Please read “How We Make Distributions to Our Partners—Azure Midstream Holdings’ Right to Reset Incentive Distribution Levels.”

Increases in interest rates could adversely impact our unit price and our ability to issue additional equity, to incur debt to capture growth opportunities or for other purposes, or to make cash distributions at our intended levels.

If interest rates rise, the 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, our unit price 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-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity, to incur debt to expand or for other purposes, or to make cash distributions at our intended levels.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person or group 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 of our general partner, cannot vote on any matter.

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. Furthermore, our partnership agreement does not restrict the ability of the owners of our general partner from transferring all or a portion of their respective ownership 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 exert significant control over the decisions made by the board of directors and officers. This effectively permits a “change of control” without the vote or consent of the unitholders.

The incentive distribution rights may be transferred by Azure Midstream Holdings to a third party without unitholder consent.

Azure Midstream Holdings may transfer all or a portion of its incentive distribution rights to a third party at any time without the consent of our unitholders. If Azure Midstream Holdings transfers the incentive distribution rights to a third party but retains its ownership interest in our general partner, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if Azure Midstream Holdings had retained ownership of the incentive distribution rights. For example, a transfer of incentive distribution rights by Azure Midstream Holdings could reduce the likelihood of Azure Midstream Holdings accepting offers made by us relating to assets owned by it, as it would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.

Immediately effective upon closing, you will experience substantial dilution of $ in tangible net book value per common unit.

The assumed initial public offering price of $ per unit exceeds our pro forma net tangible book value of $ per unit. Based on the assumed initial public offering price of $ per unit, you will incur immediate and substantial dilution of $ per common unit after giving effect to the offering of common units and the application of the related net proceeds. Dilution results primarily because the assets being contributed by our general partner and its affiliates are recorded in accordance with GAAP at their historical cost and not their fair value. Please read “Dilution.”

We may issue additional units, including units that are senior to the common units, without your approval, which would dilute your existing ownership interests.

Our partnership agreement does not limit the number of additional limited partner interests 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:

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each unitholder’s proportionate ownership interest in us will decrease;

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the amount of distributable cash flow on each unit may decrease;

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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;

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the ratio of taxable income to distributions may increase;

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the relative voting strength of each previously outstanding unit may be diminished; and

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the market price of the common units may decline.

There are no limitations in our partnership agreement on our ability to issue units ranking senior to the common units.

In accordance with Delaware law and the provisions of our partnership agreement, we may issue additional partnership interests that are senior to the common units in right of distribution, liquidation and voting. The issuance by us of units of senior rank may, among other adverse effects, (i) reduce or eliminate the amount of distributable cash flow to our common unitholders; (ii) diminish the relative voting strength of the total common units outstanding as a class; or (iii) subordinate the claims of the common unitholders to our assets in the event of our liquidation.

Azure Midstream Holdings may sell common units in the public markets or otherwise, which sales could have an adverse impact on the trading price of the common units.

After the sale of the common units offered hereby, Azure Midstream Holdings will hold common units and subordinated units, assuming the underwriters’ option to purchase additional common units is not exercised. All of the subordinated units will convert into common units at the end of the subordination period and may convert earlier. Additionally, we have agreed to provide Azure Midstream Holdings with certain registration rights. Please read “Units Eligible for Future Sale.” The sale of these units in 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 unitholders to sell their common units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price equal to the greater of (i) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (ii) the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders may also incur a tax liability upon a sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Securities Exchange Act of 1934, or the Exchange Act. Upon consummation of this offering, and assuming the underwriters do not exercise their option to purchase additional common units, our general partner and its affiliates will own an aggregate of % of our common and subordinated units. At the end of the subordination period, assuming no additional issuances of units (other than upon the conversion of the subordinated units), our general partner and its affiliates will own % of our common units. For additional information about the limited call right, please read “The Partnership Agreement—Limited Call Right.”

Your 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. Our partnership is organized under Delaware law, and we will initially own assets and conduct business in Texas and Louisiana. You could be liable for any and all of our obligations as if you were a general partner if:

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a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or

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your right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

For a discussion of the implications of the limitations of liability on a unitholder, please read “The Partnership Agreement—Limited Liability.”

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 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. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that are known to the substituted limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. The price of our common units may fluctuate significantly, which could cause you to lose all or part of your investment.

Prior to the offering, there has been no public market for the common units. After the offering, there will be only publicly-traded common units, including common units purchased by certain of our officers, directors, employees and certain other persons affiliated with us under our directed unit program. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. You may not be able to resell your common units at or above the initial public offering price. Additionally, a lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

The initial public offering price for the common units will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units may decline below the initial public offering price. The market price of our common units may also be influenced by many factors, some of which are beyond our control, including:

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our quarterly distributions;

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our quarterly or annual earnings or those of other companies in our industry;

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events affecting Azure Midstream Holdings;

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announcements by us or our competitors of significant contracts or acquisitions;

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changes in accounting standards, policies, guidance, interpretations or principles;

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general economic conditions;

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the failure of securities analysts to cover our common units after the consummation of this offering or changes in financial estimates by analysts;

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future sales of our common units; and

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other factors described in these “Risk Factors.”

The JOBS Act contains provisions that, among other things, relax certain reporting requirements for “emerging growth companies,” including certain requirements relating to auditing standards and compensation disclosure. We are classified as an emerging growth company. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things, (1) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act of 2002, (2) comply with any new requirements adopted by the PCAOB, (3) comply with any new audit rules adopted by the PCAOB after April 5, 2012 unless the SEC determines otherwise or (4) provide certain disclosure regarding executive compensation required of larger public companies.

If we fail to establish and maintain effective internal controls over financial reporting, our ability to accurately report our financial results could be adversely affected.

We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes- Oxley Act of 2002, and are therefore not required to make a formal assessment of the effectiveness of our internal controls over financial reporting for that purpose. Upon becoming a publicly traded partnership, we will be required to comply with the SEC’s rules implementing Sections 302 and 404 of the Sarbanes-Oxley Act of 2002, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal controls over financial reporting. Though we will be required to disclose material changes made to our internal controls and procedures on a quarterly basis, we will not be required to make our first annual assessment of our internal controls over financial reporting pursuant to Section 404 until the year following our first annual report required to be filed with the SEC. To comply with the requirements of being a publicly traded partnership, we may need to implement additional internal controls, reporting systems and procedures and hire additional accounting, finance and legal staff. Furthermore, while we generally must comply with Section 404 of the Sarbanes-Oxley Act of 2002 for our fiscal year ending December 31, 2015, we are not required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until our first annual report subsequent to our ceasing to be an “emerging growth company” within the meaning of Section 2(a)(19) of the Securities Act. Accordingly, we may not be required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until our annual report for the fiscal year ending December 31, 2019. Once it is required to do so, our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed, operated or reviewed.

The New York Stock Exchange does not require a publicly-traded partnership like us to comply with certain of its corporate governance requirements.

We intend to apply to list our common units on the NYSE. Because we will be a publicly-traded partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance

committee. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements. Please read “Management—Management of Azure Midstream Partners, LP.”

We will incur increased costs as a result of being a publicly-traded partnership.

We have no history operating as a publicly-traded partnership. As a publicly-traded partnership, we will incur significant legal, accounting and other expenses that we did not incur prior to this offering. In addition, the Sarbanes-Oxley Act of 2002, as well as rules implemented by the SEC and the NYSE, require publicly-traded entities to adopt various corporate governance practices that will further increase our costs. Before we are able to make distributions to our unitholders, we must first pay or reserve cash for our expenses, including the costs of being a publicly-traded partnership. As a result, the amount of cash we have available for distribution to our unitholders will be affected by the costs associated with being a publicly-traded partnership.

Prior to this offering, we have not filed reports with the SEC. Following this offering, we will become subject to the public reporting requirements of the Exchange Act. We expect these rules and regulations to increase certain of our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a publicly-traded partnership, we are required to have at least three independent directors, create an audit committee and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our SEC reporting requirements.

We also expect to incur significant expense in order to obtain director and officer liability insurance. Because of the limitations in coverage for directors, it may be more difficult for us to attract and retain qualified persons to serve on our board or as executive officers.

We estimate that we will incur approximately $3.0 million of incremental costs per year associated with being a publicly-traded partnership; however, it is possible that our actual incremental costs of being a publicly-traded partnership will be higher than we currently estimate.

Our partnership agreement will designate the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings.

Our partnership agreement requires that any claims, suits, actions or proceedings: (1) arising out of or relating in any way to the partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of the partnership agreement or the duties, obligations or liabilities among limited partners or of limited partners to us, or the rights or powers of, or restrictions on, the limited partners or us); (2) brought in a derivative manner on our behalf; (3) asserting a claim of breach of a fiduciary duty owed by any director, officer or other employee of us or our general partner, or owed by our general partner, to us or the limited partners; (4) asserting a claim arising pursuant to any provision of the Delaware Act; or (5) asserting a claim governed by the internal affairs doctrine shall be exclusively brought in the Court of Chancery of the State of Delaware (or, if such court does not have subject matter jurisdiction thereof, any other court located in the State of Delaware with subject matter jurisdiction), regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims. By purchasing a common unit, a limited partner is irrevocably consenting to these limitations and provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or such other Delaware courts) in connection with any such claims, suits, actions or proceedings. Please read “The Partnership Agreement—Applicable Laws; Forum, Venue and Exclusive Jurisdiction.”

This choice of forum provision may limit a unitholders’ ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our partnership

agreement 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 business, financial condition or results of operations.

Tax Risks to Common Unitholders

In addition to reading the following risk factors, you should read “Material U.S. Federal Income Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as Azure Midstream Operating and us not being subject to material incremental entity-level taxation. If the IRS were to treat us as a corporation for federal income tax purposes, or if we or Azure Midstream Operating become subject to entity-level taxation for state tax purposes, our distributable cash flow would be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes.

Despite the fact that we are organized as a limited partnership under Delaware law, we would be treated as a corporation for U.S. federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement. However, we have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.

If we or Azure Midstream Operating were treated as a corporation for federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us or Azure Midstream Operating as a corporation, our distributable cash flow would be substantially reduced. Therefore, treatment of us or Azure Midstream Operating as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

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 or Azure Midstream Operating to entity-level taxation for U.S. 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. At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. Specifically, we and Azure Midstream Operating will initially own assets and conduct business in Texas, which imposes a franchise tax at a maximum effective rate of 0.7% of our gross income apportioned to Texas. In the future, we or Azure Midstream Operating may expand our operations. Imposition of a similar tax on us or Azure Midstream Operating in other jurisdictions that we may expand to could substantially reduce our distributable cash flow.

The tax treatment of publicly-traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.

The present U.S. 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 changes or differing interpretations at any time. For example, from time to time, members of Congress propose and consider

substantive changes to the existing U.S. federal income tax laws that affect publicly-traded partnerships. One such legislative proposal would have eliminated the qualifying income exception to the treatment of all publicly-traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes, or other proposals, will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units. Any modification to U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the qualifying income requirement to be treated as a partnership for U.S. federal income tax purposes. For a discussion of the importance of our treatment as a partnership for federal income purposes, please read “Material U.S. Federal Income Tax Consequences—Taxation of the Partnership—Partnership Status” for a further discussion.

If the IRS were to contest the federal income tax positions we take, it may adversely impact the market for our common units, and the costs of any such contest would reduce our distributable cash flow.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take. 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. A court may not agree with some or all of our counsel’s conclusions or positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. Moreover, the costs of any contest between us and the IRS will result in a reduction in our distributable cash flow and thus will be borne indirectly by our unitholders.

Even if you do not receive any cash distributions from us, you will be required to pay taxes on your share of our taxable income.

You will be required to pay federal income taxes and, in some cases, state and local income taxes on your share of our taxable income, whether or not you receive cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax due from you with respect to that income.

Tax gain or loss on disposition of our common units could be more or less than expected.

If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis in those units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, 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 you sell your common units, you may incur a tax liability in excess of the amount of cash you receive from the sale. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Units—Recognition of Gain or Loss” for a further discussion of the foregoing.

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 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 and will be taxable to them. Allocations and/or distributions to non-U.S. persons will be subject to withholding taxes imposed at the highest effective tax rate applicable to such non-U.S. persons, and each non-U.S. person will be required to file United States federal 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 your tax advisor before investing in our common units. Please read “Material U.S. Federal Income Tax Consequences—Tax-Exempt Entities and Other Investors.”

We will treat each purchaser of common units as having the same tax benefits without regard to the common units actually purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of our 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. Our counsel is unable to opine as to the validity of this approach. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. Please read “Material U.S. Federal Income Tax Consequences —Tax Consequences of Unit Ownership—Section 754 Election” for a further discussion of the effect of the depreciation and amortization positions we adopted.

We will prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common 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 will prorate our items of income, gain, loss and deduction 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 use of this proration method may not be permitted under existing Treasury regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. The U.S. Treasury Department has issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly-traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed 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. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Units—Allocations Between Transferors and Transferees.”

A unitholder whose units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of units) may be considered to have disposed of those units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and could recognize gain or loss from the disposition.

Because there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered to have disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

We may adopt certain valuation methodologies that could result in a shift of income, gain, loss and deduction between the general partner and the 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 the 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 income, gain, loss and deduction between the 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 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.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have terminated 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 twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Immediately following this offering, Azure Midstream Holdings will indirectly own % of the total interests in our capital and profits. Therefore, a transfer by Azure Midstream Holdings of all or a portion of its interests in us could, in conjunction with the trading of common units held by the public, result in a termination of our partnership for federal income tax purposes. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once.

Our 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 for one calendar year and could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in taxable income for the unitholder’s taxable year that includes our termination. Our termination would not affect our classification as a partnership for federal income tax purposes, but it would result in our being treated as a new partnership for U.S. federal income tax purposes following the termination. If we were treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we were unable to determine that a termination occurred. The IRS recently announced a relief procedure whereby if a publicly-traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership may be permitted to provide only a single Schedule K-1 to unitholders for the two short tax periods included in the year in which the termination occurs. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Units—Constructive Termination” for a discussion of the consequences of our termination for federal income tax purposes.

You will likely be subject to state and local taxes and income tax return filing requirements in jurisdictions where you do not live as a result of investing in our common units.

In addition to U.S. federal income taxes, you may be subject to other taxes, including foreign, 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 you do not live in any of those jurisdictions. You will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements.

We will initially own assets and conduct business in Texas. Texas currently does not impose a personal income tax on individuals, but does impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. It is your responsibility to file all United States federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units.

USE OF PROCEEDS

Immediately following the repayment of a portion of the outstanding balance under the Azure Energy credit agreement, we will enter into a new $150 million revolving credit facility that will be undrawn at closing and Azure Midstream Holdings will refinance the existing Azure Energy credit agreement. As of September 30, 2014, the Azure Energy credit agreement had an outstanding balance of $529.4 million and bore interest at a rate of 6.5%. Borrowings under the Azure Energy credit agreement incurred within the last year were used to finance the Acquisition.

The net proceeds from any exercise of the underwriters’ option to purchase additional common units (approximately $ million based on an assumed initial offering price of $ per common unit, if exercised in full) will be used to make a cash distribution to Azure Midstream Holdings. If the underwriters do not exercise their option to purchase additional common units, we will issue common units to Azure Midstream Holdings at the expiration of the option period for no additional consideration to us. If and to the extent the underwriters exercise their option to purchase additional common units, the number of units purchased by the underwriters pursuant to such exercise will be issued to the public and the remainder, if any, will be issued to Azure Midstream Holdings at the expiration of the option exercise period. Accordingly, the exercise of the underwriters’ option will not affect the total number of units outstanding. Please read “Underwriting.”

An increase or decrease in the assumed initial public offering price of $1.00 per common unit would cause the net proceeds from the offering, after deducting underwriting discounts, commissions and structuring fees, to increase or decrease by approximately $ million.

CAPITALIZATION

The following table shows:

•

the historical cash and cash equivalents and capitalization of Azure Midstream Holdings as of September 30, 2014; and

•

our pro forma capitalization as of September 30, 2014, as adjusted to reflect this offering, the other transactions described under “Summary—Formation Transactions and Partnership Structure” and the application of the net proceeds from this offering as described under “Use of Proceeds.”

We derived this table from, and it should be read in conjunction with, and is qualified in its entirety by reference to, the historical and pro forma financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”


	As of September 30, 2014
	Historical		Pro Forma, as adjusted(1)
	(in thousands)
Cash and cash equivalents	$	26,034	$

Long-term debt(2)	$	534,013	$

Owner/Partners’ equity:
Azure Midstream Holdings equity		515,240
Public—common units		—
Azure Midstream Holdings—common units(3)		—
Azure Midstream Holdings—subordinated units(3)		—

Total members’/partners’ equity attributable to Azure Midstream Partners, LP		—
Non-controlling interest		—

Total members’/partners’ equity		515,240

Total capitalization	$	1,049,253	$

(1)

Assumes the issuance of common units at the midpoint of the price range set forth on the cover of this prospectus.

(2)

As of September 30, 2014, the long-term debt included within the balance sheet of Azure Midstream Holdings consisted of $529.4 million outstanding borrowings under the Azure Energy credit agreement, $3.6 million under capital leases and $1.0 million of other long-term debt.

(3)

Subsequent to the offering, Azure Midstream Holdings will own the non-economic general partner interest in Azure Midstream Partners, LP.

DILUTION

Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the pro forma net tangible book value per unit after the offering. On a pro forma basis as of September 30, 2014, after giving effect to the offering of common units at an assumed initial public offering price of $ per common unit (the midpoint of the price range set forth on the cover of this prospectus) and the application of the related net proceeds, and assuming the underwriters’ option to purchase additional common units is not exercised, our net tangible book value was $ million, or $ per unit. Net tangible book value excludes $ million of net intangible assets. Purchasers of common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for financial accounting purposes, as illustrated in the following table:


Assumed initial public offering price per common unit		$
Pro forma net tangible book value per unit before the offering(1)	$
Increase in net tangible book value per unit attributable to purchasers in the offering

Less: Pro forma net tangible book value per unit after the offering(2)

Immediate dilution in tangible net book value per common unit to new investors(3)(4)		$

(1)

Determined by dividing the number of common and subordinated units to be issued to Azure Midstream Holdings for its contribution of assets and liabilities to Azure Midstream Operating into the net tangible book value of the contributed assets and liabilities.

(2)

Determined by dividing the total number of units to be outstanding after the offering ( common units and subordinated units) and the application of the related net proceeds into our pro forma net tangible book value, after giving effect to the application of the expected net proceeds of the offering.

(3)

If the initial public offering price were to increase or decrease by $1.00 per common unit, then dilution in net tangible book value per common unit would equal $ and $ , respectively.

(4)

Because the total number of units outstanding after this offering will not be impacted by any exercise of the underwriters’ option to purchase additional common units and we will not retain any proceeds from such exercise, there will be no change to dilution in net tangible book value per common unit to purchasers in the offering due to any such exercise of the option.

The following table sets forth the number of units that we will issue and the total consideration contributed to us by affiliates of our general partner and by the purchasers of common units in this offering upon consummation of the transactions contemplated by this prospectus (assuming the underwriters do not exercise their option to purchase additional common units):


	Units Acquired				Total Consideration
	Number	Percent			Number	Percent
General partner and affiliates(1)(2)				%	$			%
New investors				%				%

Total			100.0	%	$		100.0	%

(1)

The units to be acquired by our general partner and its affiliates consist of common units and subordinated units.

(2)

The assets being contributed by our general partner and its affiliates were recorded at historical cost in accordance with GAAP. Book value of the consideration provided by our general partner and its affiliates, as of September 30, 2014, after giving effect to the application of the net proceeds of this offering is as follows (in millions):


Book value of net assets contributed		$
Less: Contribution to Azure Midstream Operating from net proceeds of this offering

Total consideration		$

OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

You should read the following discussion of our cash distribution policy in conjunction with the specific assumptions included in this section. For more detailed information regarding the factors and assumptions upon which our cash distribution policy is based, please read “Assumptions and Considerations” below. In addition, you should read “Forward-Looking Statements” and “Risk Factors” for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.

For additional information regarding our historical and pro forma operating results, you should refer to our historical and pro forma financial statements included elsewhere in this prospectus.

General

Rationale for Our Cash Distribution Policy. Our cash distribution policy reflects a basic judgment that our unitholders will be better served if we distribute our cash available after expenses and reserves rather than retaining it. Because we believe we will generally finance capital investments from external financing sources, we believe that our investors are best served by our distributing all of our available cash. Because we are not subject to an entity-level federal income tax, we have more cash to distribute to you than would be the case were we subject to such tax. Our cash distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly.

Available Cash. Available cash, for any quarter, consists of all cash 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;

•

comply with applicable law, any of our debt instruments or other agreements or any other obligation; or

•

provide funds for distributions to our partners for any one or more of the next four quarters;

•

plus, if our general partner so determines, all or a portion of cash on hand immediately prior to the date of determination of available cash for the quarter, including cash on hand, resulting from working capital borrowings made subsequent to the end of such quarter.

Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy. There is no guarantee that unitholders will receive quarterly distributions from us. Our distribution policy may be changed at any time and is subject to certain restrictions, including:

•

Our cash flow initially will depend completely on Azure Midstream Operating’s distributions to us as one of its partners. Because we control Azure Midstream Operating’s general partner, we have the authority to determine the amount of Azure Midstream Operating’s distributions, including the amount of cash reserved by Azure Midstream Operating and not distributed. We have duties to make decisions with respect to Azure Midstream Operating in the interests of all of its partners, including Azure Midstream Holdings. Our decision to make distributions, if any, and the amount of those distributions, if any, could result in a reduction in cash distributions to our unitholders from levels we currently anticipate pursuant to our stated distribution policy.

•

Our distribution policy may be affected by restrictions on distributions under the revolving credit facility that we will enter into at the closing of this offering. One such restriction would prohibit us from making cash distributions while an event of default has occurred and is continuing under the revolving credit facility. The revolving credit facility will contain covenants requiring us to maintain certain financial ratios and tests. Should we be unable to satisfy these restrictions or otherwise be in default under the revolving credit facility, we would be prohibited from making cash distributions to our unitholders, notwithstanding our stated cash distribution policy.

•

While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions requiring us to make cash distributions, may be amended. During the subordination period, our partnership agreement may not be amended without the approval of our public common unitholders, except in a limited number of circumstances when our general partner can amend our partnership agreement without any unitholder approval. For a description of these limited circumstances, please read “The Partnership Agreement—Amendment of the Partnership Agreement—No Unitholder Approval.” However, after the subordination period has ended, our partnership agreement may be amended with the consent of our general partner and the approval of a majority of the outstanding common units, including common units owned by our general partner and its affiliates. At the closing of this offering, Azure Midstream Holdings will own our general partner and will own approximately % of our total outstanding common units and subordinated units on an aggregate basis (or % of our total outstanding common units and subordinated units on an aggregate basis if the underwriters’ option to purchase additional common units is exercised in full). Please read “The Partnership Agreement—Amendment of the Partnership Agreement.”

•

If, and to the extent, our available cash materially declines from quarter to quarter, we may elect to change our current cash distribution policy and reduce the amount of our quarterly distributions in order to service or repay our debt or fund growth capital expenditures.

•

Our general partner will have the authority to establish reserves for the prudent conduct of our business and for future cash distributions to our unitholders, the establishment of which could result in a reduction in cash distributions to you from levels we currently anticipate pursuant to our stated distribution policy.

•

Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.

•

Under Section 17-607 of the Delaware Revised Uniform Limited Partnership 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.

•

We may lack sufficient cash to pay distributions to our unitholders due to increases in our general and administrative expense, principal and interest payments on our outstanding debt, tax expenses, working capital requirements and anticipated cash needs. Our available cash is directly impacted by our cash expenses necessary to run our business and will be reduced dollar-for-dollar to the extent such expenses increase. Please read “How We Make Distributions to Our Partners—Distributions of Available Cash.”

Our Ability to Grow is Dependent on Our Ability to Access External Growth Capital. Azure Midstream Operating will distribute all of its cash after reserves and expenses to its partners, including us. Accordingly, we expect Azure Midstream Operating to fund its growth capital expenditures or acquisitions through capital contributions from us and from Azure Midstream Holdings. We will distribute all of our available cash to our unitholders. As a result, we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our capital contributions to Azure Midstream Operating. To the extent we are unable to finance capital contributions to Azure Midstream Operating externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we and Azure Midstream Operating distribute substantially all of our available cash, our 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 growth 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. Our partnership agreement does not limit our ability to issue additional units, including units ranking senior to the common units. Commercial borrowings or the incurrence of other debt by us or Azure Midstream Operating to finance our growth strategy will result in increased interest expense, which in turn may impact the available cash that Azure Midstream Operating has to distribute to its partners, including us, and that we have to distribute to our unitholders.

Our Minimum Quarterly Distribution

Upon completion of this offering, our partnership agreement will provide for a minimum quarterly distribution of $ per unit per whole quarter, or $ per unit per whole year, to be paid no later than 45 days after the end of each fiscal quarter. This equates to an aggregate cash distribution of approximately $ million per whole quarter or approximately $ million per whole year, in each case based on the number of common units and subordinated units outstanding immediately after completion of this offering. If the underwriters exercise their option to purchase additional common units, the net proceeds will be used to pay a distribution to Azure Midstream Holdings. Our ability to make cash distributions at the minimum quarterly distribution rate pursuant to this policy will be subject to the factors described above under the caption “—General—Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.”

The subordination period will terminate automatically if (i) we have earned and paid at least $ per quarter on each outstanding common unit and subordinated unit for any three consecutive, non-overlapping four-quarter periods ending on or after , 2018 or (ii) we have earned and paid at least $ per quarter (150% of the minimum quarterly distribution) on each outstanding common and subordinated unit for any four-quarter period on or after , 2016. Upon the termination of the subordination period, all remaining subordinated units will convert into common units on a one-for-one basis and the common units will no longer be entitled to arrearages. Please read “How We Make Distributions to Our Partners—Subordination Period.”

If distributions on our common units are not paid with respect to any fiscal quarter at the minimum quarterly distribution rate, our unitholders will not be entitled to receive such payments in the future except that, to the extent we have available cash in any future quarter during the subordination period in excess of the amount necessary to make cash distributions to holders of our common units at the minimum quarterly distribution rate, we will use this excess available cash to pay these deficiencies related to prior quarters before any cash distribution is made to holders of our subordinated units. Please read “How We Make Distributions to Our Partners—Subordination Period.”

We do not have a legal or contractual obligation to pay distributions at our minimum quarterly distribution rate or at any other rate except as provided in our partnership agreement. Our distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly. Under our partnership agreement, available cash is defined to generally mean, for each fiscal quarter, cash generated from our business in excess of the amount of reserves our general partner determines is necessary or appropriate to provide for the conduct of our business, to comply with applicable law, any of our debt instruments or other agreements, or to provide for future distributions to our unitholders for any one or more of the upcoming four quarters.

Our partnership agreement provides that any determination made by our general partner in its capacity as our general partner must be made in good faith and that any such determination will not be subject to any higher standard imposed by our partnership agreement, the Delaware limited partnership statute or any other law, rule or regulation or at equity. Holders of our common units may pursue judicial action to enforce provisions of our partnership agreement, including those related to requirements to make cash distributions as described above. However, our partnership agreement provides that our general partner is entitled to make the determinations described above without regard to any standard other than the requirement to act in good faith. Our partnership agreement provides that, in order for a determination by our general partner to be made in “good faith,” our general partner must not act, or omit from acting, with the belief that such act or omission was adverse to the interest of the partnership. Please read “How We Make Distributions to Our Partners.”

Our cash distribution policy, as expressed in our partnership agreement, may not be modified or repealed without amending our partnership agreement. However, the actual amount of our cash distributions for any quarter is subject to fluctuations based on the amount of cash we generate from our business and the amount of

reserves our general partner establishes in accordance with our partnership agreement as described above. Our partnership agreement may be amended with the approval of our general partner and holders of a majority of our outstanding common units and any units issued upon the reset of the incentive distribution rights, voting together as a class.

We expect to pay our distributions on or about the 15th of February, May, August and November to holders of record on or about the 1st of each such month. If the distribution date does not fall on a business day, we will make the distribution on the business day immediately preceding the indicated distribution date. We will adjust the quarterly distribution for the period from the closing of this offering through , 2015 based on the actual length of the period.

In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our minimum quarterly distribution of $ per unit each quarter through the quarter ending December 31, 2015. In those sections, we present two tables, consisting of:

•

“Unaudited Pro Forma Distributable Cash Flow for the Twelve Months Ended September 30, 2014 and the Year Ended December 31, 2013,” in which we present the amount of cash we would have had available for distribution for the twelve months ended September 30, 2014 and for our fiscal year ended December 31, 2013. This table is derived from our unaudited pro forma financial statements that are included in this prospectus beginning on page F-2. The unaudited pro forma financial statements are based on our historical financial statements for the nine months ended September 30, 2014 and the year ended December 31, 2013, as adjusted to give pro forma effect to:

•

the transactions to be completed as of the closing of this offering as described under “Summary—Formation Transactions and Partnership Structure”; and

•

the application of the net proceeds of this offering as described under “Use of Proceeds.”

•

“Unaudited Estimated Distributable Cash Flow for the Twelve Months Ending December 31, 2015,” in which we present our financial forecast of our results of operations and the estimated distributable cash flow necessary for us to pay the full minimum quarterly distribution on all units for the twelve months ending December 31, 2015, and the significant assumptions upon which that forecast is based.

Unless otherwise specifically noted, the following discussion refers to 100% of Azure Midstream Operating, of which Azure Midstream Partners, LP will own a 40% interest upon the consummation of this offering. References to “non-controlling interest” describes the portion of income that is attributable to the 60% limited partner interest in Azure Midstream Operating retained by Azure Midstream Holdings. All comparisons below are made to historical periods which have been adjusted on a pro forma basis.

Unaudited Pro Forma Distributable Cash Flow for the Twelve Months Ended September 30, 2014 and the Year Ended December 31, 2013

If we had completed the transactions contemplated in this prospectus on October 1, 2013, our pro forma distributable cash flow generated for the twelve months ended September 30, 2014 would have been approximately $18.7 million. This amount would have been sufficient to make cash distributions at the minimum quarterly distribution rate of $ per unit per quarter (or $ per unit on an annualized basis) on all of the common units and subordinated units. Our unaudited pro forma distributable cash flow assumes that the underwriters do not exercise their option to purchase additional common units. Assuming the underwriters exercise in full their option to purchase additional common units, our pro forma distributable cash flow for the twelve months ended September 30, 2014 would have been sufficient to make the full minimum quarterly distribution on all the common units and subordinated units.

If we had completed the transactions contemplated in this prospectus on January 1, 2013, our pro forma distributable cash flow generated for the year ended December 31, 2013 would have been approximately

$31.4 million. This amount would have been sufficient to make cash distributions at the minimum quarterly distribution rate of $ per unit per quarter (or $ per unit on an annualized basis) on all of the common units and subordinated units. Our unaudited pro forma distributable cash flow assumes that the underwriters do not exercise their option to purchase additional common units. Assuming the underwriters exercise in full their option to purchase additional common units, our pro forma distributable cash flow for the year ended December 31, 2013 would have been sufficient to the full minimum quarterly distribution on all the common units and subordinated units.

Unaudited pro forma distributable cash flow from operating surplus includes an incremental general and administrative expense we will incur as a result of being a separate publicly-traded limited partnership, including compensation and benefit expenses of corporate administrative employees, costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and director compensation. We expect these general and administrative expenses will initially total approximately $3.0 million per year.

We based the pro forma adjustments upon currently available information and specific estimates and assumptions. The pro forma amounts below do not purport to present our results of operations had the transactions contemplated in this prospectus actually been completed as of the dates indicated. In addition, cash available to pay distributions is primarily a cash accounting concept, while our pro forma financial statements have been prepared on an accrual basis. As a result, you should view the amount of pro forma distributable cash flow only as a general indication of the amount of distributable cash flow that we might have generated had we been formed in the periods set forth herein.

The following table illustrates, on a pro forma basis, for the twelve months ended September 30, 2014 and the year ended December 31, 2013, the amount of distributable cash flow, assuming that the transactions contemplated by this prospectus had been consummated at the beginning of such periods and that the underwriters did not exercise their option to purchase additional common units in this offering.

Azure Midstream Partners, LP

Unaudited Pro Forma Distributable Cash Flow


	Pro Forma
	Twelve Months Ended September 30, 2014			Year Ended December 31, 2013
	(in thousands)
Total operating revenues	$	183,025		$	219,704
Operating expenses:
Cost of purchased gas and NGLs sold		37,473			25,812
Operating expense		35,533			48,693
General and administrative		13,274			14,719
Asset impairments		237,706			238,061
Depreciation and amortization		29,054			28,737

Total operating expenses		353,040			356,022

Loss from operations		(170,015	)		(136,318	)
Interest expense		42,589			40,304
Other expense		1,524			2,890

Loss before income taxes		(214,128	)		(179,512	)
Income tax expense		578			509

Net loss		(214,706	)		(180,021	)
Net loss attributable to non-controlling interest(1)		(128,824	)		(108,013	)

Net loss attributable to Azure Midstream Partners, LP		(85,882	)		(72,008	)
Net loss attributable to non-controlling interest(1)		(128,824	)		(108,013	)

Net loss		(214,706	)		(180,021	)
Add:
Depreciation and amortization		29,054			28,737
Interest expense(2)		42,589			40,304
Income tax expense(3)		578			509
Asset impairments(4)		237,706			238,061
Deferred revenue(5)		5,305			684
Other adjustments(6)		4,402			2,316

Adjusted EBITDA(7)		104,928			130,590
Adjusted EBITDA attributable to non-controlling interest(1)		62,957			78,354

Adjusted EBITDA attributable to Azure Midstream Partners, LP		41,971			52,236
Deduct:
Cash paid for interest(8)		12,476			5,355
Cash paid for income taxes(8)		136			184
Estimated maintenance capital expenditures(9)		7,631			12,306
Estimated growth capital expenditures(10)		1,908			3,077
Incremental general and administrative expenses(11)		3,000			3,000
Add:
Contributions from Azure Midstream Holdings to fund estimated growth capital expenditures(9)		1,908			3,077

Distributable cash flow attributable to Azure Midstream Partners, LP	$	18,728		$	31,391

Cash distributions:
Distributions to public common unitholders(12)	$			$
Distributions to Azure:
Common units(12)
Subordinated units(12)

Total distributions(12)	$			$

Excess	$			$

(1)

Represents Azure Midstream Holdings’ 60% ownership of Azure Midstream Operating.

(2)

Pro forma interest expense for the twelve months ended September 30, 2014 and December 31, 2013 has been calculated assuming average outstanding long-term debt of $540.8 million and $544.8 million, respectively, and an average interest rate of 6.5%. The average outstanding long-term debt and average interest rate represent borrowings under the Azure Energy credit agreement.

(3)

Represents the Texas margin tax, which is classified as income tax for reporting purposes.

(4)

The unaudited pro forma statement of operations for the twelve months ended September 30, 2014 and the year ended December 31, 2013 includes an impairment charge of $237.7 million and $238.1 million, respectively, of which $237.0 million is an impairment that was recognized by ETG prior to the Acquisition and is the result of adjusting the carrying value of the ETG assets to their net realizable fair value immediately prior to the Acquisition. The $237.0 million impairment was included within the ETG statement of operations for the period from January 1, 2013 to November 15, 2013. The remaining impairment charge was recognized by our Predecessor and is the result of adjusting the carrying value of assets held for sale to their net realizable fair value.

(5)

(6)

(7)

Adjusted EBITDA is defined as EBITDA, plus (1) non-cash expenses, (2) adjustments related to deferred revenue and cash receipts under our MRC and MVC producer commitments and (3) adjustments associated with certain other items. For a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated in accordance with GAAP, please read “Summary—Non-GAAP Financial Measures.” We define distributable cash flow as Adjusted EBITDA less interest and income taxes paid and maintenance capital expenditures.

(8)

Represents estimated cash paid for interest and cash paid for income taxes attributable to our 40% interest in Azure Midstream Operating. For purposes of determining our pro forma distributable cash for the twelve months ended September 30, 2014 and the year ended December 31, 2013, we have assumed that Azure Midstream Operating total cash paid for interest and cash paid for income taxes was $31.2 million and $0.3 million, respectively, for the twelve month period ended September 30, 2014 and $13.4 million and $0.5 million, respectively, for the year ended December 31, 2013.

(9)

Represents estimated maintenance capital expenditures attributable to our 40% interest in Azure Midstream Operating. We historically have not provided an estimate of maintenance capital expenditures, and therefore for purposes of determining our pro forma distributable cash we have assumed that 80% of our historical total capital expenditures are maintenance capital expenditures and 20% of our total capital expenditures are growth capital expenditures. For purposes of determining our pro forma distributable cash for the twelve months ended September 30, 2014 and the year ended December 31, 2013, we have assumed that Azure Midstream Operating has paid estimated maintenance capital expenditures from operating cash flow. On an aggregate basis Azure Midstream Operating’s total estimated maintenance capital expenditures would have been $19.0 million and $30.8 million for the twelve months ended September 30, 2014 and December 31, 2013, respectively. Our partnership agreement requires that we subtract from operating surplus each quarter the capital contribution we estimate we will need to make to Azure Midstream Operating to fund our portion of the maintenance capital necessary to maintain our operating capacity. Following the closing of this offering, we expect that Azure Midstream Operating will continue to fund maintenance capital expenditures through operating cash flow, and we and Azure Midstream Holdings will each bear our respective share of such maintenance capital expenditures based on our respective interests in Azure Midstream Operating. For a further discussion of maintenance capital expenditures, please read “—Assumptions and Considerations—Costs and Expenses—Capital Expenditures.”

(10)

Represents estimated growth capital expenditures attributable to our 40% interest in Azure Midstream Operating. We historically have not provided an estimate of growth capital expenditures, and therefore for purposes of determining our pro forma distributable cash we have assumed that 80% of our historical total capital expenditures are maintenance capital expenditures and 20% of our total capital expenditures are growth capital expenditures. Following the closing of this offering, we expect that Azure Midstream Operating will fund growth capital expenditures from debt and equity liquidity sources. For purposes of our pro forma distributable cash for the twelve months ended September 30, 2014 and the year ended December 31, 2013, we have assumed that Azure Midstream Holdings funded 100% of the growth capital expenditures. On an aggregate basis, Azure Midstream Operating Company’s growth capital expenditures were $4.8 million for the twelve months ended September 30, 2014 and $7.7 million for the year ended December 31, 2013. For a further discussion of capital expenditures, please read “—Assumptions and Considerations.”

(11)

We expect to incur additional general and administrative costs of approximately $3.0 million as a result of being a publicly-traded partnership.

(12)

The table below sets forth the assumed number of outstanding common units and subordinated units upon the closing of this offering and the aggregate distribution amounts payable on such units during the year following the closing of this offering at our minimum quarterly distribution rate of $ per unit per quarter ($ per unit on an annualized basis).

No Exercise of the Underwriters’
Option to Purchase Additional
Common Units

Full Exercise of the
Underwriters’
Option to Purchase
Additional
Common Units

Distributions

Number
of Units

One
Quarter

Annualized

Number
of Units

One
Quarter

Annualized

Publicly held common units

Common units held by Azure Midstream Holdings

Subordinated units held by Azure Midstream Holdings

Total

Unaudited Estimated Distributable Cash Flow for the Twelve Months Ending December 31, 2015

Set forth below is a table of unaudited estimated distributable cash flow for the twelve months ending December 31, 2015. The financial forecast presents, to the best of our knowledge and belief, the expected results of operations, Adjusted EBITDA and distributable cash flow for the forecast period.

Our financial forecast reflects our judgment as of the date of this prospectus of conditions we expect to exist and the course of action we expect to take during the twelve months ending December 31, 2015. The assumptions discussed below under “—Assumptions and Considerations” are those we believe are significant to our financial forecast results, including the anticipated in-service dates of our growth projects. We believe our actual results of operations and cash flows will approximate those reflected in our financial forecast. However, we can give you no assurance that our forecast results will be achieved. There will likely be differences between our forecast and the actual results, and those differences could be material. If the forecast is not achieved, we may not be able to pay the cash distribution at the minimum quarterly distribution rate or at any rate on all our units. In order to fund distributions to our unitholders at the minimum quarterly distribution rate of $ per unit for the twelve months ending December 31, 2015, our distributable cash flow for the twelve months ending December 31, 2015, must be at least $ million.

We do not as a routine matter make public projections as to future operations, earnings, or other results. However, we have prepared the table of unaudited estimated distributable cash flow and related assumptions set forth below to substantiate our belief that we will have sufficient available cash to pay the minimum quarterly distribution to all our unitholders for each quarter in the twelve months ending December 31, 2015. This forecast is a forward-looking statement and should be read together with the historical and pro forma combined financial statements and the accompanying notes included elsewhere in this prospectus and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The accompanying prospective financial information was not prepared with a view toward complying with the guidelines of the SEC or guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in our view, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of our knowledge and belief, the expected course of action and the expected future financial performance. Please read below under “—Assumptions and Considerations” for further information regarding the assumptions we have made for the financial forecast. However, this information is not presented as fact and should not be relied upon as being necessarily indicative of future results. Readers of this prospectus are cautioned not to place undue reliance on the prospective financial information.

Neither our independent auditors, nor any other independent accountants, have compiled, examined, or performed any procedures with respect to the prospective financial information, and neither have any of them expressed any opinion or any other form of assurance on such information or its achievability, and assume no responsibility for, and disclaim any association with, the prospective financial information.

When considering our financial forecast, you should keep in mind the risk factors and other cautionary statements under “Risk Factors.” Any of the risks discussed in this prospectus, to the extent they are realized, could cause our actual results of operations to vary significantly from those which would enable us to generate the unaudited estimated distributable cash flow.

Actual payments of distributions on our common units and subordinated units are expected to be approximately $ million for the twelve months ending December 31, 2015. This equals the expected aggregate amount of cash distributions of approximately $ million per quarter for this period. Quarterly distributions will be paid within 45 days after the close of each quarter.

We do not undertake any obligation to release publicly the results of any future revisions we may make to the financial forecast or to update this financial forecast to reflect events or circumstances after the date of this prospectus. You are cautioned not to place undue reliance on this information.

Azure Midstream Partners, LP

Unaudited Estimated Distributable Cash Flow


	Estimated
	Twelve Months Ending December 31, 2015
	(in thousands)
Total operating revenues	$	151,972

Operating expenses:
Cost of purchased gas and NGLs sold		19,057
Operating expenses		33,847
General and administrative		12,975
Depreciation and amortization		31,254

Total operating costs and expenses		97,133

Income from operations		54,839
Interest expense		826

Income before income taxes		54,013
Income tax expense		465

Net income		53,548
Net income attributable to non-controlling interest(1)		32,129

Net income attributable to Azure Midstream Partners, LP		21,419
Net income attributable to non-controlling interest(1)		32,129

Net income		53,548
Add:
Depreciation and amortization		31,254
Interest expense(2)		890
Income tax expense(3)		465
Deferred revenue(4)		6,371

Adjusted EBITDA(5)		92,528
Adjusted EBITDA attributable to non-controlling interest(1)		55,517

Adjusted EBITDA attributable to Azure Midstream Partners, LP		37,011
Deduct:
Cash paid for interest		890
Cash paid for income taxes(3)		186
Estimated maintenance capital expenditures(6)		3,442
Estimated growth capital expenditures(7)		6,908
Incremental general and administrative expenses(8)		3,000
Add:
Borrowings to fund growth capital expenditures(7)		6,908

Distributable cash flow attributable to Azure Midstream Partners, LP	$	29,493

Annualized minimum quarterly distributions:
Distributions to public common unitholders	$
Distributions to Azure:
Common units
Subordinated units

Total minimum annual cash distributions	$

Excess	$

(1)

Represents Azure Midstream Holdings’ 60% ownership of Azure Midstream Operating.

(2)

Pro forma interest expense for the twelve months ending December 31, 2015 has been calculated assuming average outstanding long-term debt of $4.3 million and an average interest rate of 3.75% under our new revolving credit facility. We have also assumed an annual commitment fee of 0.50% on the unused portion of the revolving credit facility.

(3)

Represents the Texas margin tax, which is classified as income tax for reporting purposes. The amount deducted for distributable cash flow purposes represents cash paid for income taxes attributable to our 40% interest in Azure Midstream Operating.

(4)

deficiency payment to us may be credited against future volumes supplied by the customer in excess of the annual MRC. We record the cash receipts associated with the deficiency payments as deferred revenue because the customer is entitled to utilize the deficiency payment to offset future volumes supplied in excess of the annual MRC over the term of the contract. We include a proportional amount of the expected MRC and MVC cash receipts in each quarter in respect of the annual period for which we actually receive the payment to ensure our Adjusted EBITDA reflects the amount of cash we are entitled to receive on an annual basis under these MRC and MVC agreements. For a discussion of adjustments related to deferred revenue associated with our minimum revenue commitments, please read “Our Cash Distribution Policy and Restrictions on Distributions—Unaudited Estimated Distributable Cash Flow for the Twelve Months Ending December 31, 2015.”

(5)

Adjusted EBITDA is defined as EBITDA, plus (1) non-cash expenses, (2) adjustments related to deferred revenue and cash receipts under our MRC and MVC producer commitments and (3) adjustments associated with certain other items. We define distributable cash flow as Adjusted EBITDA less interest and income taxes paid and maintenance capital expenditures.

(6)

Represents estimated maintenance capital expenditures attributable to our 40% interest in Azure Midstream Operating. For purposes of determining our pro forma distributable cash for the twelve months ending December 31, 2015, we have assumed that Azure Midstream Operating has paid maintenance capital expenditures from operating cash flow. On an aggregate basis, Azure Midstream Operating’s total maintenance capital expenditures are estimated to be $8.6 million for the twelve months ending December 31, 2015. Our proportionate share of the $8.6 million are estimated to be approximately $3.4 million. Our partnership agreement requires that we subtract from operating surplus each quarter the capital contribution we estimate we will need to make to Azure Midstream Operating to fund our portion of the maintenance capital necessary to maintain our operating capacity. Following the closing of this offering, we expect that Azure Midstream Operating will continue to fund maintenance capital expenditures through operating cash flow, and we and Azure Midstream Holdings will each bear our respective share of such maintenance capital expenditures based on our respective interests in Azure Midstream Operating. For a further discussion of maintenance capital expenditures, please read “—Assumptions and Considerations—Costs and Expenses—Capital Expenditures.”

(7)

Represents estimated growth capital expenditures attributable to our 40% interest in Azure Midstream Operating. Initially, we intend to fund these expenditures with borrowings under our revolving credit facility. Following the closing of this offering, we and Azure Midstream Holdings will each have the right to contribute capital to fund our respective share of Azure Midstream Operating’s growth capital expenditures based on our respective interest in Azure Midstream Operating. For the purposes of this forecast, we have assumed that Azure Midstream Holdings will fund its 60% share of growth capital expenditures during the forecast period. If Azure Midstream Holdings elects not to fund any such growth capital expenditures, we will have the opportunity to fund all or a portion of Azure Midstream Holdings’ proportionate share of such growth capital expenditures in exchange for additional interests in Azure Midstream Operating. For a further discussion of growth capital expenditures, please read “—Assumptions and Considerations—Costs and Expenses—Capital Expenditures.”

(8)

We expect to incur incremental general and administrative costs of approximately $3.0 million as a result of being a publicly-traded partnership.

Assumptions and Considerations

The forecast has been prepared by and is the responsibility of management. The forecast reflects our judgment as of the date of this prospectus of conditions we expect to exist and the course of action we expect to take during the twelve months ending December 31, 2015. While the assumptions discussed below are not all-inclusive, they include those that we believe are material to our forecasted results of operations, and any assumptions not discussed below we deemed not to be material. We believe we have a reasonable, objective basis for these assumptions. We believe our actual results of operations will approximate those reflected in our forecast, but we can give no assurance that our forecasted results will be achieved. There will likely be differences between our forecast, and our actual results and those differences could be material. If the forecasted results are not achieved, we may not be able to make cash distributions on our common units at the minimum quarterly distribution rate or at all.

General Assumptions and Considerations

•

Historically, the fixed-fee services provided to our top two customers, EXCO and BG, and their affiliates have accounted for a significant portion of our total throughput and revenues. We expect that production from EXCO and BG on our gathering systems will continue to represent a significant portion of total throughput volumes and revenues in the forecast period. For the twelve months ending December 31, 2015, we expect that EXCO and BG will each individually account for approximately 34% of our natural gas throughput, approximately 33% of our total revenue and approximately 41% of our total transportation, gathering, compression and treating revenues across all three of our systems. The average volumes received from EXCO and BG during the forecast period are estimated to be below the annually adjusted minimum volume commitment of 584 MMcf/d allocated to the Holly and Center systems, mitigating sensitivity to further reductions in EXCO and BG drilling projections during the forecast period.

•

Actual throughput volume is the primary factor that will influence the difference in the amount of distributable cash flow for the twelve months ending December 31, 2015 as compared to our forecast. Our estimates do not assume any incremental revenue, expenses or other costs associated with potential future acquisitions. If all other assumptions are held constant, a 10.0% reduction in throughput volumes below forecasted levels would result in a $2.0 million decline in distributable cash flow. A substantial portion of our distributable cash flow is underpinned by long-term minimum volume commitments from EXCO and BG and minimum revenue commitments from another customer. These commitments comprise 63% of our estimated total operating revenue and 78% of our total transportation, gathering, compression and treating revenues for the twelve months ending December 31, 2015.

•

Because we expect to generate substantially all of our revenues pursuant to long-term contracts that include fixed-fee rates and fixed-spread rates, annual rate escalators and minimum volume commitments, assumptions pertaining to future commodity price levels do not have a material direct impact on the forecast period.

•

For the year ending December 31, 2015, we have assumed $122.8 million of our total revenue will be generated from transportation, gathering, compression and treating fees. The remaining $29.2 million in total operating revenue in the forecast period is associated with natural gas and NGL sales that are partially offset by $19.1 million in associated natural gas and NGL purchases.

Volumes

We estimate that our average throughput volumes will be 0.8 Bcf/d of natural gas for the twelve months ending December 31, 2015, compared to 1.0 Bcf/d for the twelve months ended September 30, 2014 and 1.2 Bcf/d for the year ended December 31, 2013. The expected decrease in average throughput volumes of 0.2 Bcf/d, or 20%, compared to the twelve months ended September 30, 2014 and the expected decrease in average throughput volumes of 0.4 Bcf/d, or 33%, compared to the year ended December 31, 2013 is primarily attributable to decreased drilling activity by our customers EXCO and BG. We had 68 new well connects for the year ended December 31, 2013 compared to 41 new well connects for the twelve months ended September 30, 2014 and 28 new well connects expected during the twelve months ending December 31, 2015. The minimum volume commitments and minimum revenue commitments provide that we will receive a certain amount of cash from our customers even during these times of lower production.

Revenues

We estimate that our total revenues for the twelve months ending December 31, 2015 will be $152.0 million, as compared to $183.0 million for the twelve months ended September 30, 2014 and $219.7 million for the year ended December 31, 2013. The expected decrease in total revenues of $31.0 million, or 17%, compared to the twelve months ended September 30, 2014 and decrease in total revenues of $67.7 million, or 31%,

compared to the year ended December 31, 2013 is driven by lower producer volumes from customers EXCO and BG as a result of reduced levels of drilling activity. The decrease of $36.7 million, or 17%, in total revenue for the twelve months ended September 30, 2014 compared to the year ended December 31, 2013 is also a result of lower producer volumes due to reduced levels of drilling activity.

We estimate that our total transportation, gathering, compression and treating revenues will be $122.8 million for the twelve months ending December 31, 2015 as compared to $132.4 million for the twelve months ended September 30, 2014 and $184.8 million for the year ended December 31, 2013. The expected decrease in transportation, gathering, compression and treating revenue of $9.6 million, or 7%, compared to the twelve months ended September 30, 2014 and decrease in transportation, gathering, compression and treating revenue of $62.0 million, or 34%, compared to the year ended December 31, 2013 is driven by lower producer volumes from customers EXCO and BG as a result of reduced levels of drilling activity. The decrease of $52.4 million, or 28%, in transportation, gathering, compression and treating revenues for the twelve months ended September 30, 2014 compared to the year ended December 31, 2013 is also a result of lower producer volumes due to reduced levels of drilling activity. During the twelve months ending December 31, 2015, we expect EXCO and BG to have lower production and reduced capital spending levels in the Haynesville, Bossier and Cotton Valley formation areas compared to the twelve months ended September 30, 2014 and the year ended December 31, 2013. However, based on the current price of natural gas, as well as the anticipated price of natural gas in the near future, we expect near-term future production and volumes to remain at current levels. Additionally, our minimum volume and minimum revenue commitments provide that we will receive a certain amount of cash from our customers even during these times of lower production.

We estimate that total natural gas sales and NGL sales revenues will be $29.2 million for the twelve months ending December 31, 2015 as compared to $48.8 million for the twelve months ended September 30, 2014 and $34.9 million for the year ended December 31, 2013. The expected decrease in natural gas sales and NGL sales revenues is due primarily to an estimated reduction in natural gas and NGL purchase and sales activities and the exclusion of short-term natural gas purchase contracts. During the twelve months ended September 30, 2014, we procured a contract to gather up to an additional 40 MMcf/d of throughput volumes on our Legacy system that contributed to the increase in cost of purchased natural gas and the resulting natural gas sales for the twelve months ended September 30, 2014 compared to the year ended December 31, 2013 and the twelve months ending December 31, 2015. Due to the short-term nature of the contract, we did not factor these volumes into our 2015 forecast, resulting in a reduction in natural gas sales for the period ending December 31, 2015.

The net margin earned from our natural gas and NGL purchase and sales activities encompasses the purchase of natural gas from our producers and sale to third party marketing, transportation and processing companies. The natural gas and NGLs purchase and sales activities margin is based upon fixed and variable components, with the variable component impacted by fluctuations in commodity prices, interruptible gas supply opportunities and physical operations. Due to the variable component of natural gas and NGLs purchase and sales activities, we take the lower end of the expected range when forecasting natural gas and NGLs sales activities, which reduces the forecast of natural gas sales and NGLs sales.

Sensitivity Analysis. The actual volume of natural gas that we gather on our systems will influence whether the amount of distributable cash flow for the twelve months ending December 31, 2015 is above or below our forecast. If the actual volume of natural gas we gather on our systems is below our forecast, we may not have sufficient cash available to pay the aggregate annualized minimum quarterly distribution to all of our unitholders for the forecast period. If the actual volume of natural gas we gather on our systems for the twelve months ending December 31, 2015 is 10% lower than our forecast, we would expect a corresponding reduction in our revenues of $7.0 million to $144.9 million. The reduction in revenue is expected to be partially offset by an increase in deferred revenue associated with our minimum volume and minimum revenue commitments, resulting in an expected reduction to distributable cash flow attributable to Azure Midstream Partners, LP of $2.0 million. Accordingly, we would expect to have sufficient cash from operations to pay 100% of both the aggregate annualized minimum quarterly distribution to holders of our common units and the aggregate annualized minimum quarterly distribution to the holders of our subordinated units.

Cost of purchased gas and NGLs sold

We estimate that our cost of purchased gas and NGLs sold for the twelve months ending December 31, 2015 will be $19.1 million, as compared to $37.5 million for the twelve months ended September 30, 2014 and $25.8 million for the year ended December 31, 2013. The expected decrease in cost of purchased gas and NGLs sold of $18.4 million, or 49%, compared to the twelve months ended September 30, 2014 and the expected decrease in cost of purchased gas and NGLs sold of $6.8 million, or 26%, compared to the year ended December 31, 2013 is due primarily to an estimated reduction in natural gas and NGL purchase and sales activities and the exclusion of short-term gas purchase contracts as discussed above.

Operating Expense

We estimate that operating expense for the twelve months ending December 31, 2015 will be $33.8 million, as compared to $35.5 million for the twelve months ended September 30, 2014 and $48.7 million for the year ended December 31, 2013. The expected decrease in operating expense of $1.7 million, or 5%, for the twelve months ended September 30, 2014 and the expected decrease in operating expense of $14.9 million, or 30%, for the year ended December 31, 2013 is primarily due to decreases as a result of management’s continuing focus on executing an effective asset optimization program including moving and consolidating compression facility locations, releasing under-utilized rental compression and treating equipment, and reduced treating costs. Other cost reductions were related to a reduction of underutilized contractors and other personnel, and creating generally more efficient operations since the Acquisition.

General and Administrative

We estimate that our general and administrative expense will be approximately $13.0 million (excluding $3.0 million of expenses as a result of being a publicly traded partnership) for the twelve months ending December 31, 2015, compared to general and administrative expenses of $13.3 million for the twelve months ended September 30, 2014 and $14.7 million for the year ended December 31, 2013. The expected decrease in general and administrative expense of $0.3 million, or 2%, for the twelve months ended September 30, 2014 and the expected decrease in general and administrative expense of $1.7 million, or 12%, compared to the year ended December 31, 2013 are driven by the reduction of transaction and transition costs associated with the Acquisition, partially offset by the increases in personnel expenses, business development and stand-alone information technology costs. In addition, in the forecast period we expect to incur an additional $3.0 million of estimated expenses as a result of being a publicly traded partnership, which are not reflected in the historical periods. For more information regarding the general and administrative expense allocation, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate our Business—Operating Expenses—General and Administrative Expenses.”

Asset Impairments

We do not expect to have any asset impairment expense for the twelve months ending December 31, 2015, as compared to $237.7 million for the twelve months ended September 30, 2014 and $238.1 million for the year ended December 31, 2013. The twelve months ended September 30, 2014 and the year ended December 31, 2013 both include an impairment charge of $237.0 million that was recognized by ETG prior to the Acquisition and is the result of adjusting the carrying value of the ETG assets to their net realizable fair value prior to the Acquisition. Additionally, the year ended December 31, 2013 included additional asset impairments of $1.1 million resulting from adjusting the net book value of assets held for sale in order to reflect their net realizable fair market value.

Depreciation and Amortization

We estimate that depreciation and amortization expense for the twelve months ending December 31, 2015 will be $31.3 million, compared to $29.1 million for the twelve months ended September 30, 2014 and $28.7 million for the year ended December 31, 2013. Estimated depreciation and amortization expense reflects

management’s estimates, which are based on consistent average depreciable asset lives and depreciation methodologies. The expected increase in depreciation and amortization expense of $2.2 million, or 8%, for the twelve months ended September 30, 2014 and $2.6 million, or 9%, for the year ended December 31, 2013, is primarily due to the amortization of our intangible assets resulting from our Acquisition and the increase in depreciation associated with increased maintenance capital expenditures.

Capital Expenditures

We estimate that total capital expenditures for the twelve months ending December 31, 2015 will be $25.9 million, compared to total capital expenditures of $23.8 million for the twelve months ended September 30, 2014 and $34.5 million for the year ended December 31, 2013. We will categorize our capital expenditures as either maintenance or growth capital expenditures. Our forecast estimate is based upon the following assumptions:

Maintenance Capital Expenditures

Historically, we have not made a distinction between maintenance and growth capital expenditures.

Our estimate that Azure Midstream Operating’s total maintenance capital expenditures will be approximately $8.6 million for the twelve months ending December 31, 2015 reflects our management’s judgment of the amount of capital that will be needed to maintain the current throughput across our systems and the current operating capacity of our assets for the long-term. Projected maintenance capital expenditures primarily consist of expenditures for well connections, gathering laterals, repairs, maintenance and asset integrity expenditures.

Historical total maintenance capital expenditures for the pro forma twelve months ended September 30, 2014 and for the pro forma twelve months ended December 31, 2013 primarily include the construction of well connections and gathering laterals to maintain operating income and operating capacity. Additionally, we constructed a $5.0 million salt water disposal facility located on our Legacy System during 2013. Beginning in 2014, we have incurred approximately $3.0 million in repairs, maintenance, and asset integrity maintenance capital expenses that were previously operating expenses. For the twelve months ending December 31, 2015, we estimate repairs, maintenance and asset integrity maintenance capital expenditures will comprise $3.4 million of the $8.6 million in total maintenance capital expenditures.

Growth Capital Expenditures

We estimate Azure Midstream Operating’s total growth capital expenditures will be $17.3 million for the twelve months ending December 31, 2015, of which $16.5 million relates to a compression project which will provide centralized compression on the Holly System, reducing line pressures to approximately 450 psig from 1,250 psig. The project is expected to be in service during the third quarter of 2015. The project is expected to provide incremental fee based revenue and a minimal increase in volumes from existing and incremental production due to a decrease in system line pressure.

For the pro forma twelve months ended September 30, 2014 and for the pro forma year ended December 31, 2013, total growth capital expenditures represented approximately 20% of capital spending. Approximately $6.0 million was spent on the construction of the new Fairway processing plant in our Center System. Fairway is a processing plant with processing capacity of 10 MMcf/d, which is designed to extract NGL content from natural gas ranging between 3.5 and 7.5 GPM, from the James Lime formation for liquids processing. Other growth capital expenditures included pipeline extensions and the installation of incremental gathering laterals to expand our gathering footprint and connect new production to our system.

Interest Expense and Related Charges

We estimate that total interest expense and related charges will be $0.9 million for the twelve months ending December 31, 2015, compared to $42.5 million for the twelve months ended September 30, 2014 and $40.3 million for the year ended December 31, 2013. In connection with the closing of the offering, we will enter into a new $150 million revolving credit facility. Initially, the new revolving credit facility will have zero outstanding borrowings, and will be used by us for working capital, capital contributions, certain acquisitions, distributions, unit repurchases and other general partnership purposes. Within the twelve months ending December 31, 2015, we have assumed that we funded our portion, $6.9 million, of Azure Midstream Operating’s total estimated growth capital expenditures of $17.3 million, with borrowings under the new revolving credit facility. We assumed these were the only borrowings under the new revolving credit facility during the twelve months ended December 31, 2015. We assumed average outstanding borrowings of $4.3 million, and we have assumed an interest rate of 3.75%, which is the applicable interest rate under the new revolving credit facility. We have also assumed an annual commitment fee of 0.50% on the unused portion of the revolving credit facility. The interest expense and related charges for the twelve months ended September 30, 2014 and the year ended December 31, 2013 are associated with outstanding borrowings under the Azure Energy credit agreement and have been calculated assuming average outstanding long-term debt of $540.8 million and $544.8 million, respectively, and an average interest rate of 6.5%.

Liquidity and Capital Resources

Capital and liquidity has historically been provided by our operating cash flow and we expect this will continue in the future. Additionally, other sources of liquidity will include borrowing capacity under the $150 million revolving credit facility we will enter into in connection with the offering and proceeds from the issuance of additional limited partner units. We expect the combination of these capital resources will be adequate to meet our short-term working capital requirements, long-term capital expenditures and expected quarterly cash distributions.

Regulatory, Industry and Economic Factors

Our forecast for the twelve months ending December 31, 2015 is based on the following significant assumptions related to regulatory, industry and economic factors:

•

There will not be any new federal, state or local regulation of the midstream energy sector, or any new interpretation of existing regulations, that will be materially adverse to our business.

•

There will not be any major adverse change in the midstream energy sector, commodity prices or in market, insurance or general economic conditions.

•

There will not be any material accidents, weather-related incidents, unscheduled downtime or similar unanticipated events with respect to our facilities or those of third parties on which we depend.

•

We will not make any acquisitions or other significant growth capital expenditures (other than as described above).

HOW WE MAKE DISTRIBUTIONS TO OUR PARTNERS

Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.

Distributions of Available Cash

General

Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending , 2015 we distribute all of our available cash to unitholders of record on the applicable record date. We will adjust the minimum quarterly distribution for the period from the completion of the offering through , 2015 based on the actual length of that period.

Definition of Available Cash

Available cash, for any quarter, generally consists of 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;

•

comply with applicable law, any of our debt instruments or other agreements or any other obligation; or

•

provide funds for distributions to our partners for any one or more of the next four quarters;

•

plus, if our general partner so determines, all or any portion of cash on hand immediately prior to the date of distribution of available cash for the quarter, including cash on hand resulting from working capital borrowings made after the end of the quarter.

The purpose and effect of the last bullet point above is to allow our general partner, if it so decides, to use cash received by us after the end of the quarter but on or before the date of distribution of available cash for that quarter, including cash on hand resulting from working capital borrowings made after the end of the quarter, to pay distributions to partners. Under our partnership agreement, working capital borrowings are borrowings that are made under a credit agreement, commercial paper facility or similar financing arrangement with the intent to repay such borrowings within twelve months from sources, and that are used solely for working capital purposes or to pay distributions to partners.

Intent to Distribute the Minimum Quarterly Distribution

Within 45 days after the end of each quarter, beginning with the quarter ending , 2015, we intend to distribute to the holders of common and subordinated units on a quarterly basis at least the minimum quarterly distribution of $ per unit, or $ on an annualized basis, to the extent we have sufficient cash after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. However, there is no guarantee that we will pay the minimum quarterly distribution on our units in any quarter. The amount of distributions paid under our cash distribution policy and the decision to make any distribution will be determined by our general partner, taking into consideration the terms of our partnership agreement. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

General Partner Interest and Incentive Distribution Rights

Our general partner owns a non-economic general partner interest in us, which does not entitle it to receive cash distributions. However, our general partner may in the future own common units or other equity securities in us and will be entitled to receive distributions on any such interests.

Azure Midstream Holdings currently indirectly holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50.0%, of the cash we distribute from operating surplus (as defined below) in excess of $ per unit per quarter. The maximum distribution of 50.0% does not include any distributions that Azure Midstream Holdings may receive on any limited partner units that it owns.

Operating Surplus and Capital Surplus

General

All cash distributed to unitholders will be characterized as being paid from either “operating surplus” or “capital surplus.” Our partnership agreement requires that we distribute available cash from operating surplus differently than available cash from capital surplus.

Operating Surplus

We define operating surplus as:

•

$ million (as described below); plus

•

all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions (as defined below) provided that cash receipts from the termination of a commodity hedge or interest rate hedge not related to the financing of a growth capital expenditure prior to its specified termination date shall be included in operating surplus in equal quarterly installments over the remaining scheduled life of such commodity hedge or interest rate hedge related to the financing of a growth capital expenditure; plus

•

working capital borrowings made after the end of a period but on or before the date of determination of operating surplus for the period; plus

•

cash distributions paid in respect of equity issued (including incremental distributions on incentive distribution rights), other than equity issued on the closing date of this offering, to finance all or a portion of growth capital expenditures in respect of the period from such financing until the earlier to occur of the date the capital asset commences commercial service and the date that it is abandoned or disposed of; plus

•

cash distributions paid in respect of equity issued (including incremental distributions on incentive distribution rights) to pay the construction period interest on debt incurred, or to pay construction period distributions on equity issued, to finance the growth capital expenditures referred to above, in each case, in respect of the period from such financing until the earlier to occur of the date the capital asset is placed in service and the date that it is abandoned or disposed of; less

•

all of our operating expenditures (as defined below) after the closing of this offering; less

•

the amount of cash reserves established by our general partner to provide funds for future operating expenditures; less

•

all working capital borrowings not repaid within twelve months after having been incurred, or repaid within such twelve-month period with the proceeds of additional working capital borrowings; less

•

any loss realized on disposition of an investment capital expenditure.

As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders and is not limited to cash generated by our operations. For example, it includes a basket of $ million that will enable us, if we choose, to distribute as operating surplus cash we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. In addition, the effect of including, as described above, certain cash distributions on equity interests in operating surplus will be to increase operating surplus by the amount of any such cash distributions. As a result, we may also distribute as operating surplus up to the amount of any such cash that we receive from non-operating sources.

The proceeds of working capital borrowings increase operating surplus and repayments of working capital borrowings are generally operating expenditures, as described below, and thus reduce operating surplus when made. However, if a working capital borrowing is not repaid during the twelve-month period following the borrowing, it will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowing is in fact repaid, it will be excluded from operating expenditures because operating surplus will have been previously reduced by the deemed repayment.

We define operating expenditures in our partnership agreement, which generally means all of our cash expenditures, including, but not limited to, taxes, reimbursement of expenses to our general partner or its affiliates, payments made under interest rate hedge agreements or commodity hedge agreements (provided that (i) with respect to amounts paid in connection with the initial purchase of an interest rate hedge contract or a commodity hedge contract, such amounts will be amortized over the life of the applicable interest rate hedge contract or commodity hedge contract and (ii) payments made in connection with the termination of any interest rate hedge contract or commodity hedge contract prior to the expiration of its stipulated settlement or termination date will be included in operating expenditures in equal quarterly installments over the remaining scheduled life of such interest rate hedge contract or commodity hedge contract), officer compensation, repayment of working capital borrowings, debt service payments and maintenance capital expenditures (as discussed in further detail below), provided that operating expenditures will not include:

•

repayment of working capital borrowings where such borrowings have previously been deemed to have been repaid (as described above);

•

payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness, other than working capital borrowings;

•

growth capital expenditures;

•

actual maintenance capital expenditures (as discussed in further detail below);

•

investment capital expenditures;

•

payment of transaction expenses (including taxes) relating to interim capital transactions;

•

distributions to our partners (including distributions in respect of our incentive distribution rights);

•

repurchases of equity interests except to fund obligations under employee benefit plans; or

•

any other expenditures or payments using the proceeds of this offering that are described in “Use of Proceeds.”

Capital Surplus

Capital surplus is defined in our partnership agreement as any distribution of available cash in excess of our cumulative operating surplus. Accordingly, except as described above, capital surplus would generally be generated by:

•

borrowings other than working capital borrowings;

•

sales of our equity and debt securities; and

•

sales or other dispositions of assets, other than inventory, accounts receivable and other assets sold in the ordinary course of business or as part of ordinary course retirement or replacement of assets.

Characterization of Cash Distributions

Our partnership agreement requires that we treat all available cash distributed by us as coming from operating surplus until the sum of all available cash distributed since the closing of this offering equals the operating surplus from the closing of this offering through the end of the quarter immediately preceding that

distribution. Our partnership agreement requires that we treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. As described above, operating surplus includes a basket of $ million, and therefore does not reflect actual cash on hand that is available for distribution to our unitholders. Rather, this provision will enable us, if we choose, to distribute as operating surplus up to that amount of cash we receive in the future from interim capital transactions that would otherwise be distributed as capital surplus. We do not anticipate that we will make any distributions from capital surplus.

Capital Expenditures

Maintenance capital expenditures are cash expenditures that are made to maintain our asset base, operating capacity or operating income, or to maintain the existing useful life of any of our capital assets, in each case over the long term. Examples of maintenance capital expenditures are expenditures for the repair, refurbishment and replacement of our assets, to maintain equipment reliability, integrity and safety, and to address environmental laws and regulations. In addition, we may designate a portion of our maintenance capital expenditures to connect new wells to maintain throughput to the extent such capital expenditures are necessary to maintain, over the long term, our operating capacity or operating income. We capitalize the costs of major maintenance activities, or turnarounds, and depreciate the costs over the expected useful life of such maintenance cost. Expenditure levels will increase as pipelines age and require higher levels of inspection, maintenance and capital replacement.

Because our maintenance capital expenditures can be irregular, the amount of our actual maintenance capital expenditures may differ substantially from period to period, which could cause similar fluctuations in the amounts of operating surplus and adjusted operating surplus if we subtracted actual maintenance capital expenditures from operating surplus.

Our partnership agreement requires that an estimate of the average quarterly maintenance capital expenditures necessary to maintain our operating capacity over the long-term be subtracted from operating surplus each quarter as opposed to the actual amounts spent. The amount of estimated maintenance capital expenditures deducted from operating surplus for those periods will be subject to review and change by our general partner at least once a year. The estimate will be made at least annually and whenever an event occurs that is likely to result in a material adjustment to the amount of our maintenance capital expenditures, such as a major acquisition or the introduction of new governmental regulations that will impact our business. Our partnership agreement does not set a limit on the amount of maintenance capital expenditures that our general partner may estimate. For purposes of calculating operating surplus, any adjustment to this estimate will be prospective only. For a discussion of the amounts we have allocated toward estimated maintenance capital expenditures, please read “Our Cash Distribution Policy and Restrictions on Distributions.”

The use of estimated maintenance capital expenditures in calculating operating surplus will have the following effects:

•

the amount of actual maintenance capital expenditures in any quarter will not directly reduce operating surplus but will instead be factored into the estimate of the average quarterly maintenance capital expenditures. This may result in the subordinated units converting into common units when the use of actual maintenance capital expenditures would result in lower operating surplus during the subordination period and potentially result in the tests for conversion of the subordinated units not being satisfied;

•

it may increase our ability to distribute as operating surplus cash we receive from non-operating sources; and

•

it may be more difficult for us to raise our distribution above the minimum quarterly distribution and pay incentive distributions on the incentive distribution rights held by our general partner.

plants, and new well connections, in each case to the extent such capital expenditures are expected to expand our operating capacity or operating income. In the future, if we make acquisitions that increase system throughput or capacity, the associated capital expenditures will also be considered growth capital expenditures.

Investment capital expenditures are those capital expenditures that are neither maintenance capital expenditures nor growth capital expenditures. Investment capital expenditures largely will consist of capital expenditures made for investment purposes. Examples of investment capital expenditures include traditional capital expenditures for investment purposes, such as purchases of securities, as well as other capital expenditures that might be made in lieu of such traditional investment capital expenditures, such as the acquisition of a capital asset for investment purposes or development of assets that are in excess of the maintenance of our existing operating capacity or operating income, but which are not expected to expand, for more than the short term, our operating capacity or operating income.

As described below, neither investment capital expenditures nor growth capital expenditures are included in operating expenditures, and thus will not reduce operating surplus. Because growth capital expenditures include interest payments (and related fees) on debt incurred to finance all or a portion of the construction, replacement or improvement of a capital asset in respect of a period that begins when we enter into a binding obligation to commence construction of a capital improvement and ending on the earlier to occur of the date any such capital asset commences commercial service and the date that it is abandoned or disposed of, such interest payments also do not reduce operating surplus. Losses on disposition of an investment capital expenditure will reduce operating surplus when realized, and cash receipts from an investment capital expenditure will be treated as a cash receipt for purposes of calculating operating surplus only to the extent the cash receipt is a return on principal.

Capital expenditures that are made in part for maintenance capital purposes, investment capital purposes or growth capital purposes will be allocated as maintenance capital expenditures, investment capital expenditures or growth capital expenditures by our general partner.

Subordination Period

General

Our partnership agreement provides that, during the subordination period (which we define below), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $ per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions from operating surplus until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be sufficient available cash from operating surplus to pay the minimum quarterly distribution on the common units.

Determination of Subordination Period

Azure Midstream Holdings will initially indirectly own all of our subordinated units. Except as described below, the subordination period will begin on the closing date of this offering and expire on the first business day after the distribution to unitholders in respect of any quarter, beginning with the quarter ending , 2018 if each of the following has occurred:

•

distributions of available cash from operating surplus on each of the outstanding common and subordinated units equaled or exceeded the annualized minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

•

the “adjusted operating surplus” (as defined below) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the annualized minimum quarterly distribution on all of the outstanding common and subordinated units during those periods on a fully-diluted weighted-average basis; and

•

there are no arrearages in payment of the minimum quarterly distribution on the common units.

Early Termination of Subordination Period

Notwithstanding the foregoing, the subordination period will automatically terminate, and all of the subordinated units will convert into common units on a one-for-one basis, on the first business day after the distribution to unitholders in respect of any quarter, beginning with the quarter ending , 2016 if each of the following has occurred:

•

distributions of available cash from operating surplus on each of the outstanding common and subordinated units exceeded $ (150.0% of the annualized minimum quarterly distribution) for the four-quarter period immediately preceding that date;

•

the “adjusted operating surplus” (as defined below) generated during the four-quarter period immediately preceding that date equaled or exceeded the sum of $ (150.0% of the annualized minimum quarterly distribution) on all of the outstanding common and subordinated units during that period on a fully diluted weighted average basis, plus the related distribution on the incentive distribution rights; and

•

there are no arrearages in payment of the minimum quarterly distributions on the common units.

Conversion Upon Removal of the General Partner

In addition, if the unitholders remove our general partner other than for cause, the subordinated units held by any person will immediately and automatically convert into a new class of common units on a one-for-one basis, provided (i) neither such person nor any of its affiliates voted any of its units in favor of the removal and (ii) such person is not an affiliate of the successor general partner.

Expiration of the Subordination Period

When the subordination period ends, each outstanding subordinated unit will convert into one common unit and will then participate pro rata with the other common units in distributions of available cash.

Adjusted Operating Surplus

Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods if not utilized to pay expenses. Adjusted operating surplus consists of:

•

operating surplus generated with respect to that period (excluding any amounts attributable to the items described in the first bullet point under “—Operating Surplus and Capital Surplus—Operating Surplus” above); less

•

any net increase in working capital borrowings with respect to that period; less

•

any net decrease in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus

•

any net decrease in working capital borrowings with respect to that period; plus

•

any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium; plus

•

any net decrease made in subsequent periods in cash reserves for operating expenditures initially established with respect to such period to the extent such decrease results in a reduction of adjusted operating surplus in subsequent periods pursuant to the third bullet point above.

Distributions of Available Cash From Operating Surplus During the Subordination Period

Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

•

first, to the common unitholders, pro rata, until we distribute for each common unit an amount equal to the minimum quarterly distribution for that quarter and any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters;

•

second, to the subordinated unitholders, pro rata, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

•

thereafter, in the manner described in “—Incentive Distribution Rights” below.

Distributions of Available Cash From Operating Surplus After the Subordination Period

Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:

•

first, to all common unitholders, pro rata, until we distribute for each common unit an amount equal to the minimum quarterly distribution for that quarter; and

•

thereafter, in the manner described in “—Incentive Distribution Rights” below.

General Partner Interest

Incentive Distribution Rights

Incentive distribution rights represent the right to receive increasing percentages (15.0%, 25.0% and 50.0%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently indirectly holds the incentive distribution rights, but may transfer these rights at any time.

If for any quarter:

•

we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

•

we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then our partnership agreement requires that we distribute any additional available cash from operating surplus for that quarter among the unitholders and the holders of our incentive distribution rights in the following manner:

•

first, to all unitholders, pro rata, until each unitholder receives a total of $ per unit for that quarter (the “first target distribution”);

•

second, 85.0% to all common unitholders and subordinated unitholders, pro rata, and 15.0% to the holders of our incentive distribution rights, until each unitholder receives a total of $ per unit for that quarter (the “second target distribution”);

•

third, 75.0% to all common unitholders and subordinated unitholders, pro rata, and 25.0% to the holders of our incentive distribution rights, until each unitholder receives a total of $ per unit for that quarter (the “third target distribution”); and

•

thereafter, 50.0% to all common unitholders and subordinated unitholders, pro rata, and 50.0% to the holders of our incentive distribution rights.

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 Azure Midstream Holdings based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of Azure Midstream Holdings 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 and Azure Midstream Holdings 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 assume Azure Midstream Holdings has not transferred its incentive distribution rights and there are no arrearages on common units.


		Marginal Percentage Interest in Distributions
	Total Quarterly Distribution per Unit Target Amount	Unitholders			Incentive Distribution Rights
Minimum Quarterly Distribution	$		100.0	%		—
First Target Distribution	above $ up to $		100.0	%		—
Second Target Distribution	above $ up to $		85.0	%		15.0	%
Third Target Distribution	above $ up to $		75.0	%		25.0	%
Thereafter	above $		50.0	%		50.0	%

Azure Midstream Holdings’ Right to Reset Incentive Distribution Levels

Azure Midstream Holdings, as the indirect holder of our incentive distribution rights, has the right under our partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial target distribution levels and to reset, at higher levels, the target distribution levels upon which the incentive distribution payments would be set. If Azure Midstream Holdings transfers all or a portion of the incentive distribution rights in the future, then the holder or holders of a majority of our incentive distribution rights will be entitled to exercise this right. The following discussion assumes that Azure Midstream Holdings holds all of the incentive distribution rights at the time that a reset election is made. The right to reset the target distribution levels upon which the incentive distributions are based may be exercised, without approval of our unitholders or the conflicts committee of Azure Midstream Holdings, at any time when there are no subordinated units outstanding and we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distribution for the prior four consecutive fiscal quarters. The reset target distribution levels will be higher than the target distribution levels prior to the reset such that there will be no incentive distributions paid under the reset target distribution levels until cash distributions per unit following the reset event increase as described below. We anticipate that Azure Midstream Holdings would exercise this reset right in order to facilitate acquisitions or internal growth projects that would otherwise not be sufficiently accretive to cash distributions per common unit, taking into account the existing levels of incentive distribution payments being made.

In connection with the resetting of the target distribution levels and the corresponding relinquishment by Azure Midstream Holdings of incentive distribution payments based on the target cash distributions prior to the reset, Azure Midstream Holdings will be entitled to receive a number of newly issued common units based on the formula described below that takes into account the “cash parity” value of the cash distributions related to the incentive distribution rights for the quarter prior to the reset event as compared to the cash distribution per common unit in such quarter.

The number of common units to be issued in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels would be equal to the quotient determined by dividing (x) the amount of cash distributions received in respect of the incentive distribution rights for the fiscal quarter ended immediately prior to the date of such reset election by (y) the amount of cash distributed per common unit with respect to such quarter. Azure Midstream Holdings would be entitled to receive distributions in respect of these common units in subsequent periods.

Following a reset election, a baseline minimum quarterly distribution amount will be calculated as an amount equal to the cash distribution amount per unit for the fiscal quarter immediately preceding the reset election (which amount we refer to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to be correspondingly higher such that we would make distributions from operating surplus for each quarter thereafter as follows:

•

first, to all common unitholders, pro rata, until each unitholder receives an amount per unit equal to 115.0% of the reset minimum quarterly distribution for that quarter;

•

second, 85.0% to all unitholders, pro rata, and 15.0% to Azure Midstream Holdings, until each unitholder receives an amount per unit equal to 125.0% of the reset minimum quarterly distribution for the quarter;

•

third, 75.0% to all unitholders, pro rata, and 25.0% to Azure Midstream Holdings, until each unitholder receives an amount per unit equal to 150.0% of the reset minimum quarterly distribution for the quarter; and

•

thereafter, 50.0% to all unitholders, pro rata, and 50.0% to Azure Midstream Holdings

Because a reset election can only occur after the subordination period expires, the reset minimum quarterly distribution will have no significance except as a baseline for the target distribution levels.

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and Azure Midstream Holdings at various cash distribution levels (i) pursuant to the cash distribution provisions of our partnership agreement in effect at the completion of this offering, as well as (ii) following a hypothetical reset of the minimum quarterly distribution and target distribution levels based on the assumption that the average quarterly cash distribution amount per common unit during the fiscal quarter immediately preceding the reset election was $ .


	Quarterly Distribution per Unit Prior to Reset		Marginal Percentage Interest in Distributions
	Quarterly Distribution per Unit Prior to Reset		Unitholders			Incentive Distribution Rights			Quarterly Distribution Per Unit Following Hypothetical Reset
Minimum Quarterly Distribution	$			100.0	%		—		$	(1	)
First Target Distribution	above $	up to $		100.0	%		—			above $ (1) up to $ (2	)
Second Target Distribution	above $	up to $		85.0	%		15.0	%		above $ (2) up to $ (3	)
Third Target Distribution	above $	up to $		75.0	%		25.0	%		above $ (3) up to $ (4	)
Thereafter	above $			50.0	%		50.0	%		above $ (4	)

(1)

This amount is equal to the hypothetical reset minimum quarterly distribution.

(2)

This amount is 115.0% of the hypothetical reset minimum quarterly distribution.

(3)

This amount is 125.0% of the hypothetical reset minimum quarterly distribution.

(4)

This amount is 150.0% of the hypothetical reset minimum quarterly distribution.

The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and Azure Midstream Holdings, including in respect of incentive distribution rights, based on an amount distributed for the quarter immediately prior to the reset. The table assumes that immediately prior to the reset there would be common units outstanding and the average distribution to each common unit would be $ per quarter for the quarter prior to the reset.

Quarterly Distribution
Per Unit Prior to Reset

Cash
Distributions
to Common
Unitholders
Prior to Reset

Cash
Distributions
to the Holder
of Our
Incentive
Distribution
Rights Prior
to Reset

Total
Distributions

Minimum Quarterly Distribution

First Target Distribution

above $

up to $

—

Second Target Distribution

above $

up to $

—

Third Target Distribution

above $

up to $

—

Thereafter

above $

—

The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and the holder of our incentive distribution rights in respect of its incentive distribution rights, for the quarter immediately after the reset occurs. The table reflects that as a result of the reset there would be common units outstanding and the distribution to each common unit would be $ . The number of common units to be indirectly issued to Azure Midstream Holdings upon the reset was calculated by dividing (x) the amount received by Azure Midstream Holdings in respect of its incentive distribution rights for the quarter prior to the reset as shown in the table above, or $ , by (y) the cash distributed on each common unit for the quarter prior to the reset as shown in the table above, or $ .

Quarterly Distribution Per
Unit After Reset

Cash
Distributions
to Common
Unitholders

Cash Distributions to Holder of
Our Incentive Distribution
Rights After Reset

After Reset

Common
Units(1)

Incentive
Distribution
Rights

Total

Total
Distributions

Minimum Quarterly Distribution

First Target Distribution

above $

up to $

—

Second Target Distribution

above $

up to $

—

Third Target Distribution

above $

up to $

—

Thereafter

above $

—

(1)

Represents distributions in respect of the common units indirectly issued to Azure Midstream Holdings upon the reset.

The holder of our incentive distribution rights will be entitled to cause the target distribution levels to be reset on more than one occasion, provided that it may not make a reset election except at a time when it has received incentive distributions for the prior four consecutive fiscal quarters based on the highest level of incentive distributions that it is entitled to receive under our partnership agreement.

Distributions From Capital Surplus

How Distributions From Capital Surplus Will Be Made

Our partnership agreement requires that we make distributions of available cash from capital surplus, if any, in the following manner:

•

first, to all common unitholders and subordinated unitholders, pro rata, until the minimum quarterly distribution is reduced to zero, as described below;

•

second, to the common unitholders, pro rata, until we distribute for each common unit an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and

•

thereafter, we will make all distributions of available cash from capital surplus as if they were from operating surplus.

Effect of a Distribution From Capital Surplus

Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the distribution of capital surplus to the fair market value of the common units prior to the announcement of the distribution. Because distributions of capital surplus will reduce the minimum quarterly distribution and target distribution levels after any of these distributions are made, it may be easier for Azure Midstream Holdings to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the minimum quarterly distribution is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

Once we reduce the minimum quarterly distribution and target distribution levels to zero, all future distributions will be made such that 50.0% is paid to all unitholders, pro rata, and 50.0% is paid to the holder or holders of incentive distribution rights, pro rata.

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our common units into fewer common units or subdivide our common units into a greater number of common units, our partnership agreement specifies that the following items will be proportionately adjusted:

•

the minimum quarterly distribution;

•

the target distribution levels;

•

the initial unit price, as described below under “—Distributions of Cash Upon Liquidation”;

•

the per unit amount of any outstanding arrearages in payment of the minimum quarterly distribution on the common units; and

•

the number of subordinated units.

For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the initial unit price would each be reduced to 50.0% of its initial level. If we combine our common units into a lesser number of units or subdivide our common units into a greater number of units, we will combine or subdivide our subordinated units using the same ratio applied to the common units. Our partnership agreement provides that we do not make any adjustment by reason of the issuance of additional units for cash or property.

In addition, if as a result of a change in law or interpretation thereof, we or any of our subsidiaries are treated as an association taxable as a corporation or are otherwise subject to additional taxation as an entity for U.S. federal, state, local or non-U.S. income or withholding tax purposes, Azure Midstream Holdings may, in its sole discretion, reduce the minimum quarterly distribution and the target distribution levels for each quarter by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter (after deducting Azure Midstream Holdings’ estimate of our additional aggregate liability for the quarter for such income and withholdings taxes payable by reason of such change in law or interpretation) and the denominator of which is the sum of (x) available cash for that quarter, plus (y) Azure Midstream Holdings’ estimate of our additional aggregate liability for the quarter for such income and withholding taxes payable by reason of such change in law or interpretation thereof. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in distributions with respect to subsequent quarters.

Distributions of Cash Upon Liquidation

General

If we dissolve in accordance with the partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and the holders of the incentive distribution rights, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of units to a repayment of the initial value contributed by unitholders for their units in this offering, which we refer to as the “initial unit price” for each unit. The allocations of gain and loss upon liquidation are also intended, to the extent possible, to entitle the holders of common units to a preference over the holders of subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the common unitholders to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of Azure Midstream Holdings

Manner of Adjustments for Gain

The manner of the adjustment for gain is set forth in the partnership agreement. If our liquidation occurs before the end of the subordination period, we will generally allocate any gain to the partners in the following manner:

•

first, to our general partner to the extent of certain prior losses specially allocated to our general partner;

•

second, to the common unitholders, pro rata, until the capital account for each common unit is equal to the sum of: (i) the initial unit price; (ii) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and (iii) any unpaid arrearages in payment of the minimum quarterly distribution;

•

third, to the subordinated unitholders, pro rata, until the capital account for each subordinated unit is equal to the sum of: (i) the initial unit price; and (ii) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;

•

fourth, to all unitholders, pro rata, until we allocate under this bullet an amount per unit equal to: (i) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less (ii) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed to the unitholders, pro rata, for each quarter of our existence;

•

fifth, 85.0% to all unitholders, pro rata, and 15.0% to the holder of our incentive distribution rights, until we allocate under this paragraph an amount per unit equal to: (i) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less (ii) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85.0% to the unitholders, pro rata, and 15.0% to Azure Midstream Holdings for each quarter of our existence;

•

sixth, 75.0% to all unitholders, pro rata, and 25.0% to the holder of our incentive distribution rights, until we allocate under this paragraph an amount per unit equal to: (i) the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less (ii) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that we distributed 75.0% to the unitholders, pro rata, and 25.0% to the holder of our incentive distribution rights for each quarter of our existence; and

•

thereafter, 50.0% to all unitholders, pro rata, and 50.0% to the holder of our incentive distribution rights.

The percentage interests set forth above for Azure Midstream Holdings assume Azure Midstream Holdings has not transferred the incentive distribution rights.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (iii) of the second bullet point above and all of the third bullet point above will no longer be applicable.

We may make special allocations of gain among the partners in a manner to create economic uniformity among the common units into which the subordinated units convert and the common units held by public unitholders.

Manner of Adjustments for Losses

If our liquidation occurs before the end of the subordination period, we will generally allocate any loss to our general partner and the unitholders in the following manner:

•

first, to holders of subordinated units in proportion to the positive balances in their capital accounts until the capital accounts of the subordinated unitholders have been reduced to zero;

•

second, to the holders of common units in proportion to the positive balances in their capital accounts, until the capital accounts of the common unitholders have been reduced to zero; and

•

thereafter, 100.0% to our general partner.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.

We may make special allocations of loss among the partners in a manner to create economic uniformity among the common units into which the subordinated units convert and the common units held by public unitholders.

Adjustments to Capital Accounts

Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for federal income tax purposes, unrecognized gain resulting from the adjustments to the unitholders and the holder of our incentive distribution rights in the same manner as we allocate gain upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, our partnership agreement requires that we generally allocate any later negative adjustments to the capital accounts resulting

from the issuance of additional units or upon our liquidation in a manner that results, to the extent possible, in the partners’ capital account balances equaling the amount that they would have been if no earlier positive adjustments to the capital accounts had been made. By contrast to the allocations of gain, and except as provided above, we generally will allocate any unrealized and unrecognized loss resulting from the adjustments to capital accounts upon the issuance of additional units to the unitholders and our general partner based on their respective percentage ownership of us. In this manner, prior to the end of the subordination period, we generally will allocate any such loss equally with respect to our common and subordinated units. If we make negative adjustments to the capital accounts as a result of such loss, future positive adjustments resulting from the issuance of additional units will be allocated in a manner designed to reverse the prior negative adjustments, and special allocations will be made upon liquidation in a manner that results, to the extent possible, in our unitholders’ capital account balances equaling the amounts they would have been if no earlier adjustments for loss had been made.

SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

The selected historical consolidated financial data presented as of September 30, 2014 and for the nine-month period ended September 30, 2014 are derived from the unaudited historical condensed consolidated financial statements of Azure Midstream Holdings included elsewhere in this prospectus. The selected historical consolidated financial data presented for the nine-month period ended September 30, 2013 are derived from the unaudited historical condensed consolidated financial statements of the Azure Midstream Predecessor included elsewhere in this prospectus. The selected historical consolidated financial data presented as of December 31, 2013 and for the period from November 15, 2013 to December 31, 2013 are derived from the audited historical consolidated financial statements of Azure Midstream Holdings included elsewhere in this prospectus. The selected historical consolidated financial data presented as of December 31, 2012 and for the period from January 1, 2013 to November 14, 2013 and the year ended December 31, 2012 are derived from the audited historical consolidated financial statements of the Predecessor included elsewhere in this prospectus.

The selected unaudited pro forma consolidated financial data for the nine-month period ended September 30, 2014 and for the year ended December 31, 2013 have been derived from the unaudited pro forma consolidated financial statements of the partnership included elsewhere in this prospectus. The selected unaudited pro forma consolidated statement of operations data for the year ended December 31, 2013 include the pro forma effects of the TGGT and ETG acquisitions and the pro forma effects of the offering transaction described under the caption “Summary—Formation Transactions and Partnership Structure” as if the TGGT and ETG acquisitions and the offering transaction had occurred on January 1, 2013. The selected unaudited pro forma consolidated statement of operations data for the nine-month period ended September 30, 2014 include the pro forma effects of the offering transaction as if it had occurred on January 1, 2013. As part of the offering transaction, Azure Midstream Holdings will cause Azure Energy to be contributed to Azure Midstream Operating in exchange for all of the limited partner interests of Azure Midstream Operating. Azure Midstream Holdings will then contribute an approximate 40% limited partner interest in Azure Midstream Operating to the partnership.

For a detailed discussion of the following table, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The following table presents our selected historical and pro forma consolidated financial and operating data as of the dates and for the periods indicated and should also be read in conjunction with the historical audited and unaudited consolidated financial statements and related notes of Azure Midstream Holdings and the Predecessor included elsewhere in this prospectus. Among other things, those historical financial statements include more detailed information regarding the basis of presentation for the information below. For a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated in accordance with GAAP, please read “—Non-GAAP Financial Measures” below. We define distributable cash flow as Adjusted EBITDA less interest and income taxes paid and maintenance capital expenditures.


	Azure Midstream Holdings LLC			Predecessor				Azure Midstream Holdings LLC		Predecessor		Pro Forma Azure Midstream Partners, LP
	Period from November 15, 2013 to December 31, 2013			Period From January 1, 2013 to November 14, 2013		Year Ended December 31, 2012		Nine-Month Period Ended September 30, 2014		Nine-Month Period Ended September 30, 2013		Nine-Month Period Ended September 30, 2014		Year Ended December 31, 2013
	(in thousands, except for volumes)
Statement of Operations Data:
Total operating revenues	$	24,819		$	180,332	$	246,451	$	134,833	$	158,560	$	134,833	$	219,704
Operating expenses:
Cost of purchased gas and NGLs sold		4,505			21,054		22,794		30,095		18,239		30,095		25,812
Operating expense		5,455			33,850		48,586		23,685		28,993		23,685		48,693
General and administrative		458			11,166		17,514		10,760		9,820		10,760		14,719
Transaction costs		6,135			—		—		—		—		—		—
Asset impairments(1)		—			583		50,771		228		583		228		238,061
Depreciation and amortization		3,480			31,143		32,132		21,989		26,713		21,989		28,737

Total expenses		20,033			97,796		171,797		86,757		84,348		86,757		356,022

Income (loss) from operations		4,786			82,536		74,654		48,076		74,212		48,076		(136,318	)
Interest expense		5,046			10,321		16,145		31,145		9,331		31,145		40,304
Other expense		576			2,316		3,441		326		1,695		326		2,890
Income tax expense		106			361		425		423		317		423		509

Net income (loss) from continuing operations	$	(942	)	$	69,538	$	54,643	$	16,182	$	62,869	$	16,182	$	(180,021	)

Net (loss) income attributed to non-controlling interest													9,709		(108,013	)

Net (loss) income attributable to Azure Midstream Partners, LP(2)												$	6,473	$	(72,008	)

Net (loss) income per limited partner unit (basic and diluted):
Common Units												$		$
Subordinated Units												$		$
Balance Sheet Data (as of the period end):
Cash and cash equivalents	$	15,576				$	8,050	$	26,034			$	26,034
Property, plant and equipment—net		823,102					1,142,208		823,068				823,068
Total assets		1,080,340					1,201,634		1,074,563
Total debt		550,000					493,671		534,013
Members’ equity		499,058					678,608		515,240
Other Financial Data:
Adjusted EBITDA(3)	$	14,206		$	114,153	$	157,596	$	78,250	$	101,389	$	78,250	$	130,590
Adjusted EBITDA attributable to Azure Midstream Partners, LP(4)													31,300		52,236
Capital expenditures		5,326			29,208		191,001		16,363		27,604
Operating Data:
Average throughput volumes of natural gas (MMcf/d)		843			1,217		1,471		991		1,302

(1)

(2)

Calculated as 40% of net income (loss) from continuing operations.

(3)

(4)

Calculated as 40% of Adjusted EBITDA.

Non-GAAP Financial Measures

EBITDA and Adjusted EBITDA

The following table presents a reconciliation of EBITDA and Adjusted EBITDA to net income (loss) for each of the periods indicated:


	Azure Midstream Holdings LLC			Predecessor				Azure Midstream Holdings LLC		Predecessor		Pro Forma Azure Midstream Partners, LP
	Period from November 15, 2013 to December 31, 2013			Period from January 1, 2013 to November 14, 2013		Year Ended December 31, 2012		Nine-Month Period Ended September 30, 2014		Nine-Month Period Ended September 30, 2013		Nine-Month Period Ended September 30, 2014		Year Ended December 31, 2013
	(in thousands)
Reconciliation of EBITDA and Adjusted EBITDA to Net Income (Loss)
Net Income (Loss)	$	(942	)	$	69,538	$	54,643	$	16,182	$	62,869	$	16,182	$	(180,021	)

Add:
Depreciation and amortization		3,480			31,143		32,132		21,989		26,713		21,989		28,737
Interest expense		5,046			10,321		16,145		31,145		9,331		31,145		40,304
Income tax expense		106			361		425		423		317		423		509

EBITDA	$	7,690		$	111,363	$	103,345	$	69,739	$	99,230	$	69,739	$	(110,471	)

Add:
Impairment of assets(1)		—			583		50,771		228		583		228		238,061
Deferred revenue(2)		684			—		—		4,621		—		4,621		684
Other adjustments(3)		5,832			2,207		3,480		3,662		1,576		3,662		2,316

Adjusted EBITDA	$	14,206		$	114,153	$	157,596	$	78,250	$	101,389	$	78,250	$	130,590

Adjusted EBITDA attributable to Azure Midstream Partners, LP(4)												$	31,300	$	52,236

(1)

(2)

(3)

(4)

Calculated as 40% of Adjusted EBITDA.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read the following discussion of financial condition and results of operations in conjunction with the historical and unaudited pro forma consolidated financial statements and related notes included elsewhere in this prospectus. Among other things, those financial statements and related notes include more detailed information regarding the basis of presentation for the following information. All references in this section to “we,” “our,” “us” or similar terms refer to Azure Midstream Partners, LP, including Azure Midstream Operating, when used in the present or future tense and refer to Azure Midstream Holdings and its subsidiaries, including Azure Energy, and the Predecessor and its subsidiaries when used in historical context.

Overview

We are a fee-based, growth-oriented Delaware limited partnership focused on owning, operating, developing and acquiring midstream energy infrastructure that is strategically located in core producing areas of unconventional resource basins in North America. We currently provide natural gas gathering, compression, treating and processing services in North Louisiana and East Texas in the prolific Haynesville and Bossier shale formations, the liquids-rich Cotton Valley formation and the shallower producing sands in the Travis Peak formation. According to the EIA, these formations comprise the third largest natural gas basin in the United States in terms of natural gas production.

Our business and operations are conducted through Azure Midstream Operating, a recently formed partnership between Azure Midstream Holdings and us. As of September 30, 2014, our gathering systems had approximately 1,365 miles of pipeline and during the nine-month period ended September 30, 2014, our systems gathered an average of approximately 991 MMcf/d of natural gas. At the consummation of this offering, our assets will consist of a 40% limited partner interest in Azure Midstream Operating, as well as the general partner interest in Azure Midstream Operating. Unless otherwise stated, financial results and operating data are shown on a 100% basis and are not adjusted for the 60% noncontrolling interest in Azure Midstream Operating.

How We Generate Our Revenue

During the nine-months ended September 30, 2014, we generated over 90% of our revenues under long-term, fixed-fee and fixed-spread natural gas gathering and sales agreements that are intended to mitigate our direct commodity price exposure and enhance the stability of our cash flows. Our customers include some of the largest natural gas producers in North America, such as BG, EXCO, BP plc, Chesapeake Energy Corporation, Devon Energy Corporation, Encana Corporation, EOG Resources, Inc. and EP Energy Corporation. Substantially all of our gas gathering revenue is underpinned by minimum volume commitments, minimum revenue commitments or acreage dedications, including life of lease arrangements. The contracted revenue under minimum volume and revenue commitments on our systems represented approximately 56.9% of our revenue for the nine months ended September 30, 2014. Our minimum volume and revenue commitments have original terms that range from five to ten years and, as of September 30, 2014, had a weighted average remaining term of 5.2 years. As of that date, our acreage dedications and life of lease arrangements with BG, BP plc and EXCO covered approximately 187,000 acres in the aggregate.

Additionally, we own and operate a gas processing facility and multiple treating facilities located in East Texas and North Louisiana. Our processing and treating assets service long-lived natural gas regions, including the Haynesville and Bossier shale formations. These gas basins also include multiple natural gas formations such as the James Lime and Cotton Valley formations. Our systems process or treat natural gas from the associated wells. Where applicable, we process the raw natural gas into residue gas by extracting NGLs and removing impurities and transport natural gas to interstate and transmission pipelines for delivery to customers. Our processing and treating systems have receipt points consisting primarily of individual well connections and, secondarily, central delivery points, which are linked to multiple wells. Our gathering systems interconnect with interstate and intrastate natural gas pipelines operated by eight independent pipeline operators. For our gas

processing and treating services, we receive additional fees, with gross receipts determined by the volume of gas that is processed or treated. Similar to our gathering agreements, we do not take direct commodity price risk thereby protecting our cash flow from commodity price volatility.

Other revenue producing activities include the sale of natural gas purchased from third parties, for which we take title, and the sale of natural gas condensate. Natural gas revenues are reported as a component of revenues within natural gas and NGL sales. Our natural gas sales are completed under contracts with limited commodity price exposure, and we report the natural gas and condensate revenues and the associated purchases and expenses on a gross basis within our statement of operations. The cost of natural gas purchased from third parties is reported as a component of operating costs and expenses.

Gas Gathering Agreements

We derive revenue primarily from long-term, fixed-fee gas gathering agreements (“GGAs”) with some of the largest and most active producers in our areas of operation. The following describes the material provisions included in certain of our significant gas gathering agreements described above, including our natural gas gathering agreement with BG and EXCO and our minimum revenue commitment gas gathering agreement.

BG and EXCO Minimum Volume Commitment

We have entered into gas gathering agreements with both BG and EXCO (collectively, the “BG/EXCO GGA”) pursuant to which BG and EXCO have jointly agreed to a minimum volume commitment (“MVC”) with respect to their collective production gathered by our Holly and Center systems, the material terms of which are discussed below. The minimum volume of natural gas required to be delivered to these systems is calculated on an annual basis based upon the daily average of such volumes delivered during the applicable contract year. While the MVC feature of the contract is set to terminate on December 1, 2018, the BG/EXCO GGA is a life of lease contract. Accordingly, BG and EXCO will not be obligated to deliver a minimum volume of natural gas from their production gathered by our Holly and Center systems after such date, although the production from BG and EXCO’s dedicated acreage in these fields will still be required to be delivered to our gathering systems.

The collective MVC is 600,000 MMbtu/d (584 MMcf/d) and the BG/EXCO GGA includes the following provisions:

•

to the extent throughput volumes exceed the MVC in the applicable contract year, the MVC in the following contract year will be reduced by an amount equal to 25% of these excess volumes. As of September 30, 2014, BG and EXCO have shipped an average of 628 MMcf/d since the inception of the agreement, which, if sustained through the end of the contract year, would reduce the MVC for the 2015 calendar year to 588,000 MMbtu/d (573 MMcf/d); and

•

to the extent that there is a shortfall of the annual MVC, then we will charge a flat fee per MMbtu times the shortfall amount, to be paid 50% by BG and 50% by EXCO. If BG and EXCO’s actual throughput volumes are less than their MVC for the applicable contract year, they must make a deficiency payment to us within three months after the end of that contract year.

We do not defer revenue associated with the BG/EXCO GGA because BG and EXCO are not entitled to utilize the deficiency payment to offset gathering fees in the following contract year. The MVC is subject to suspension in the event of a force majeure or a breach by us of the BG/EXCO GGA.

Minimum Revenue Commitment

basis based on volumes of gas transported at agreed upon rates, subject to certain adjustments. The contract has a ten-year term expiring December 31, 2020, and continues year-to-year thereafter. Volumes supplied by the customer are currently less than the annual MRC requirement, and we are therefore entitled to a deficiency payment. As a result, the customer’s deficiency payments may be credited against future volumes supplied by the customer in excess of the annual MRC. We record the deficiency payments received as deferred revenue because the customer is entitled to utilize the deficiency payment to offset future volumes supplied in excess of the annual MRC over the term of the contract. We recognize the deferred revenue under this arrangement in revenue once all contingencies or potential performance obligations associated with the related deficiency volumes have either (i) been satisfied through the gathering of future excess volumes or (ii) expired (or lapsed) through the passage of time.

Our Operations

Our results are driven primarily by the volumes of natural gas that we gather, compress, treat and process across our systems. We contract with producers to gather natural gas from pad sites and central receipt points connected to our systems. These receipt points are connected to our gathering pipelines, through which we compress natural gas and deliver it to third-party processing plants or downstream pipelines for ultimate delivery to end users. We currently contract primarily all of our gathering services under long-term, fee-based gas gathering agreements, which limit our direct commodity price exposure. Under these agreements, we are paid a fixed-fee based on the volume and thermal content of the natural gas we gather. We also generate revenues under fixed-spread natural gas sales arrangements, whereby we purchase natural gas volumes that have been processed by our third-party processing facilities or treated by our own facilities at an index price less a fixed price, and we then sell these volumes at the same index price, plus or minus a fixed price differential, or a fixed-spread. As of September 30, 2014, we had long-term gas gathering and sales agreements with 72 gas producing customers in the Haynesville, Bossier, and Cotton Valley formations. These agreements provide us with a revenue stream that is not subject to direct commodity price risk.

We have indirect exposure to changes in commodity prices. Rising prices may cause our customers to increase drilling activity, and conversely falling prices may delay drilling or temporarily shut in production. Either scenario would impact the volumes of natural gas we gather. If our customers delay drilling or temporarily shut-in production due to falling commodity prices, our minimum volume and revenue commitments assure us that we will receive a certain amount of cash from our customers.

Our assets are in both liquids-rich and “dry” gas regions, and we believe that our gathering systems are well positioned to capture additional volumes from increased producer activity in these regions in the future due to our geographic footprint, available excess capacity and strong customer relationships. Please read “Business—Our Assets.” Dry gas regions contain natural gas reserves that are primarily comprised of methane, as compared to liquids-rich regions that contain NGLs in addition to methane.

How We Evaluate Our Operations

Our management uses a variety of financial and operational metrics to analyze our performance. We view these metrics as important factors in evaluating our profitability and review these measurements on at least a monthly basis for consistency and trend analysis. These metrics include (i) throughput volume, (ii) EBITDA and Adjusted EBITDA, (iii) distributable cash flow, (iv) operating expenses and (v) capital spending.

Throughput Volume

The volume of natural gas that we gather depends on the level of production from natural gas wells connected to our gathering systems. Aggregate production volumes are impacted by the overall amount of drilling and completion activity because production must be maintained or increased by new drilling or other activity as the production rate of a natural gas well declines over time. Producers’ willingness to engage in new drilling is determined by a number of factors, the most important of which are the prevailing and projected prices of natural gas and NGLs, the cost to drill and operate a well, the availability and cost of capital, and environmental and government regulations. We generally expect the level of drilling to positively correlate with long-term trends in commodity prices. Similarly, production levels nationally and regionally generally tend to positively correlate with drilling activity.

We must continually obtain new supplies of natural gas to maintain or increase the throughput volume on our systems. Our ability to maintain or increase existing throughput volumes and obtain new supplies of natural gas is impacted by:

•

successful drilling activity within our dedicated acreage;

•

the level of work-overs and recompletions of wells on existing pad sites to which our gathering systems are connected;

•

the number of new pad sites in our dedicated acreage awaiting lateral connections;

•

our ability to compete for volumes from successful new wells in the areas in which we operate outside of our existing dedicated acreage;

•

our ability to utilize the remaining uncommitted capacity on, or add additional capacity to, our gathering systems;

•

our ability to gather natural gas that has been released from commitments with our competitors; and

•

our ability to acquire or develop new systems with associated volumes and contracts.

We actively monitor producer activity in the areas served by our gathering systems to pursue new supply opportunities.

EBITDA and Adjusted EBITDA

We define EBITDA as net income (loss), plus (1) interest expense, (2) income tax expense and (3) depreciation and amortization expense. We define Adjusted EBITDA as EBITDA, plus (1) non-cash expenses, (2) adjustments related to deferred revenue and cash receipts under our MRCs and MVCs and (3) adjustments associated with certain other and non-cash items.

Distributable Cash Flow

Although we have not quantified distributable cash flow on a historical basis, after the closing of this offering we intend to use distributable cash flow, which we define as Adjusted EBITDA less cash paid for interest expense and maintenance capital expenditures, to analyze our performance. Distributable cash flow will not reflect changes in working capital balances, other than deferred revenues. Distributable cash flow is used as a supplemental financial measure by our management and by external users of our financial statements such as investors, commercial banks and research analysts, to assess the ability of our assets to generate cash sufficient to support our indebtedness and make future cash distributions to our unitholders, and the attractiveness of capital projects and acquisitions and the overall rates of return on our investment opportunities.

EBITDA, Adjusted EBITDA and distributable cash flow are not financial measures presented in accordance with GAAP. We believe that the presentation of these non-GAAP financial measures will provide useful information to investors in assessing our financial condition and results of operations. Because EBITDA, Adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry, our

definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. Please read “Selected Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measures.”

Operating Expenses

We seek to maximize the profitability of our operations in part by minimizing, to the extent appropriate, expenses directly tied to operating and maintaining our assets. Direct labor costs, repair and non-capitalized maintenance costs, integrity management costs, treating chemical costs, utilities and contract services are the most significant portion of our operating expenses. Other than utilities expense, these expenses are largely independent of volumes delivered through our gathering systems, but may fluctuate depending on the activities performed during a specific period.

Capital Spending

Our management seeks to effectively manage our maintenance capital expenditures, including turnaround costs. These capital expenditures relate to the maintenance and integrity of our pipelines and facilities. We capitalize the costs of major maintenance activities, or turnarounds, and depreciate the costs over the period until the next planned turnaround of the affected unit. Historically, we have not made a distinction between maintenance and growth capital expenditures. In the future, we will categorize maintenance capital expenditures as those that are made to maintain our asset base, operating capacity or operating income, or to maintain the existing useful life of any of our capital assets, in each case over the long term. Examples of maintenance capital expenditures are expenditures for the repair, refurbishment and replacement of our assets, to maintain equipment reliability, integrity and safety and to address environmental laws and regulations. In addition, we may designate a portion of our maintenance capital expenditures to connect new wells to maintain throughput to the extent such capital expenditures are necessary to maintain, over the long term, our operating capacity or operating income. We capitalize the costs of major maintenance activities, or turnarounds, and depreciate the costs over the expected useful life of such maintenance cost. Expenditure levels will increase as pipelines age and require higher levels of inspection, maintenance and capital replacement.

Growth capital expenditures are cash expenditures to construct new midstream infrastructure, including those expenditures incurred in order to extend the useful lives of our assets, reduce costs, increase revenues, or increase system throughput or capacity from current levels. Examples of growth capital expenditures include the construction, development or acquisition of additional gathering pipelines, compressor stations, processing plants, and new well connections, in each case to the extent such capital expenditures are expected to expand our operating capacity or operating income. In the future, if we make acquisitions that increase system throughput or capacity, the associated capital expenditures will also be considered growth capital expenditures.

Items Affecting Comparability of Our Financial Results

The historical financial results of Azure Midstream Holdings and the Predecessor discussed below may not be comparable to our future financial results for the reasons described below:

Growing Asset Base

The historical financial results of the Predecessor are those of TGGT prior to the Acquisition, and therefore include only a subset of our assets. Effective November 15, 2013, we completed the acquisition of ETG, and, as a result, the financial and operating data of Azure Midstream Holdings for the year ended December 31, 2013 includes only 45 days of results for ETG in addition to a full year of operating results for TGGT. Because Azure Midstream Holdings acquired the TGGT assets on November 15, 2013, the financial and operational data for 2013 discussed below are generally bifurcated between the period our Predecessor owned these assets and the period from our acquisition of those assets, as well as ETG, through the end of the year. We incurred acquisition-related costs of $6.1 million associated with the Acquisition, which have been included within transaction costs during the period from November 15, 2013 to December 31, 2013.

Ownership Structure

Prior to the Acquisition, our Predecessor operated approximately 1,060 miles of gathering pipelines that transported natural gas from supply basins to major intrastate and interstate pipelines in the region. These gathering systems and treating facilities were operated primarily to provide midstream services to BG and EXCO to support their drilling and development programs, and our Predecessor’s management team did not pursue third-party volumes aggressively. As a result, our average daily throughput of 625, 125 and 234 MMcf/d on our Holly, Center and Legacy systems, respectively, is currently below our daily throughput capacity by 1,475, 768 and 266 MMcf/d for our Holly, Center and Legacy systems, respectively. We believe this excess capacity creates an opportunity for us to significantly increase volumes on our existing systems with minimal incremental capital expenditures, thereby giving us substantial operating leverage. We intend to increase throughput volumes on our existing pipeline systems by continuing to work with our existing customers to enhance our service offerings to maximize the value of their production and our economics. Additionally, we intend to increase throughput volumes and diversify our customer base over time by aggressively competing for contracted volumes with new customers as their existing contracts with other pipeline operators expire. We believe that our recently constructed pipeline systems allow us to offer producers in our basins customized services with greater flexibility than many of our competitors. In addition to our differentiated service offerings, we believe that the lower maintenance capital associated with our new pipeline systems, together with our available throughput capacity, allows us to offer more attractive economic terms to producers than competitors with older assets while achieving compelling margins from our services. Consequently, the historical financial results of Azure Midstream Holdings reflect, and our future financial results are expected to reflect, the implementation of a significantly different operating strategy.

Additionally, after the consummation of this offering, we will own a 40% interest in Azure Midstream Operating rather than the 100% ownership interest reflected as part of Azure Midstream Holdings, and our Predecessor’s historical financial results. We will control Azure Midstream Operating through our ownership of its general partner. Our unaudited pro forma financial statements consolidate, and our financial statements after the closing of this offering will consolidate, all of Azure Midstream Operating’s financial results with ours in accordance with GAAP. Consequently, our future consolidated financial statements will include Azure Midstream Operating as a consolidated subsidiary, and Azure Midstream Holdings’ 60% limited partner interest will be reflected as a non-controlling interest.

General and Administrative Expenses

In connection with the Acquisition, we incurred acquisition related costs of $6.1 million and these costs were expensed as incurred during the period from November 15, 2013 to December 31, 2013. Following the Acquisition, the respective employees of EXCO and BG continued as employees of their respective subsidiaries through December 31, 2013 under transition service agreements with Azure Midstream Holdings. EXCO and BG invoiced Azure Midstream Holdings for the payroll and benefits cost of the employees, as well as for information technology and treasury support services in accordance with the respective transition service agreements. Azure Midstream Holdings also entered into a transition services agreement with Tenaska Capital Management to assist with the transition of accounting services, natural gas flow management and other administrative functions through December 31, 2013. Azure Midstream Holdings recognized operating expenses and general and administrative expenses of $1.6 million and $1.9 million, respectively, during the period from November 15, 2013 to December 31, 2013 for such services under these agreements. We recorded our assets at fair value as of November 15, 2013 in connection with the Acquisition in accordance with GAAP. The fair value of our assets was less than our Predecessor’s book value of those assets, which had the effect of decreasing the depreciation expense associated with our assets subsequent to the Acquisition.

After the completion of this offering, we expect to incur approximately $3.0 million in incremental, annual general and administrative expenses as a result of becoming a publicly-traded partnership. These costs include fees associated with annual and quarterly reports to unitholders, tax returns, K-1 preparation and distribution, investor relations, registrar and transfer agent fees, incremental insurance costs, executive compensation, accounting, auditing, legal services and independent director compensation.

Financing

There are differences in the way we will finance our operations as compared to the way our Predecessor and Azure Midstream Holdings financed their respective operations. Historically, our Predecessor’s operations were financed as part of BG and EXCO’s midstream joint venture operations. In addition, our Predecessor largely relied on internally generated cash flows and capital contributions from BG and EXCO to satisfy its capital expenditure requirements.

Azure Midstream Holdings and Azure Energy entered into a term loan and revolving credit facility in connection with the Acquisition. As a result, interest expense and related charges associated with the period Azure Midstream Holdings owned our assets is not comparable to the period in which the Predecessor owned our assets.

In connection with the closing of this offering, we will enter into a new revolving credit facility. As a result, interest expense and related charges for the period following the closing of this offering is not comparable to the period in which the Predecessor owned our assets.

Our partnership agreement requires that we distribute all of our available cash to our unitholders. As a result, we expect to rely primarily upon external financing sources, including commercial bank borrowings under our new credit facility and the issuance of debt and equity securities, to fund our acquisitions and growth capital expenditures. Upon the completion of this offering, we intend to have no debt and an available borrowing capacity of $150 million under our new $150 million revolving credit facility.

General Trends and Outlook

We expect our business to continue to be affected by the following key factors. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results.

Natural Gas and NGL Supply and Demand

Our gathering and processing operations are generally dependent upon natural gas production from our customer’s upstream activity in their areas of operation. The decline in natural gas prices as a result of significant new supplies of domestic natural gas production has caused a related decrease in dry natural gas drilling by many producers in the United States. Depressed natural gas prices could affect production rates over time and levels of investment by our customers in exploration for and development of new oil and natural gas reserves. In addition, there is a natural decline in production from existing wells that are connected to our gathering systems. We believe our long-term minimum volume commitment contracts substantially reduce our volumetric risk over that period of time. Although we expect our customers will continue to devote substantial resources to the development of the Haynesville and Bossier shale plays and the Cotton Valley formation, we have no control over this activity and our customers have the ability to reduce or curtail such development at their discretion.

Natural Gas Price Impact on Production Levels

Natural gas prices have a direct impact on dry natural gas drilling. Consequently, volatility in natural gas prices can affect producers’ capital programs, drilling activity and production levels. Recent trends in drilling and production levels in the Haynesville shale exemplify this direct relationship with natural gas prices. Natural gas production in the Haynesville shale steadily trended upward through 2011 peaking in 2012 at over 10 Bcf/d. However, as natural gas prices fell during 2012, producers reduced their drilling programs and natural gas production in the Haynesville shale steadily declined to approximately 7 Bcf/d by 2013. Over the same period, the average number of active rigs running in the Haynesville shale declined from 57 in 2012 to 40 in 2013. Natural gas prices again trended upward in 2013 into early 2014, and gas production levels stabilized at approximately 7 Bcf/d. We believe production has stabilized at this level, and production is likely to increase with a commensurate increase in natural gas prices.

Although natural gas prices have recently trended lower in the latter half of 2014 from nearly $5.00 per Mcf, the natural gas forward strip remains in contango, indicating natural gas prices are likely to rise over the short-term. We believe our core producers can earn acceptable rates of return above their costs of capital at natural gas prices slightly above $3.00 per Mcf. As a result, we believe overall production within our operating areas have stabilized and are likely to trend upward over the intermediate term. Spear & Associates, Inc. estimates the Haynesville shale will have 45 average active rigs in 2014 and 47 average active rigs in 2015, positively impacting natural gas production levels during those periods.

Additionally, we continue to see higher production out of the horizontal Cotton Valley near our Legacy system where a higher concentration of NGL-rich gas and crude oil is accelerating production. We are actively pursuing opportunities to capture volume from this higher growth production area.

Natural Gas Prices (Henry Hub), December 2010—September 2014 (U.S. $ per Mcf)

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Source: EIA

Natural Gas Forward Strip Prices (Henry Hub), Calendar 2014—Calendar 2018 (U.S. $ per Mcf)

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Source: Factset

Rising Operating Costs and Inflation

The current level of exploration, development and production activities across the United States has resulted in increased competition for personnel and equipment. This competition has caused, and we believe will continue to cause, increases in the prices we pay for labor, supplies and property, plant and equipment. An increase in the general level of prices in the economy could have a similar effect on the operating costs we incur. We attempt to recover increased costs from our customers, but there may be a delay in doing so or we may be unable to recover these costs. To the extent we are unable to procure necessary supplies or recover higher costs, our operating results will be negatively impacted.

Regulatory Compliance

The regulation of natural gas gathering and transportation activities by the Federal Energy Regulatory Commission (“FERC”) and other federal and state regulatory agencies, including the Department of Transportation (“DOT”), has a significant impact on our business. For example, the DOT’s Pipeline and Hazardous Materials Safety Administration (“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 natural gas producers, including regulation associated with hydraulic fracturing, could reduce regional supplies of natural gas and therefore throughput on our gathering systems. For more information see “Business—Regulation of Operations.”

Growth Opportunities

We acquired a significant portion of our midstream assets through our acquisition of TGGT, a joint venture formed in 2009 by two of our largest customers, BG and EXCO. At that time, TGGT operated approximately 1,060 miles of gathering pipelines that transported natural gas from supply basins to major intrastate and interstate pipelines in the region. Prior to the Acquisition, TGGT operated approximately 1,060 miles of gathering pipelines that transported natural gas from supply basins to major intrastate and interstate pipelines in the region. These gathering systems and treating facilities were operated primarily to provide midstream services to BG and EXCO to support their drilling and development programs. Consequently, TGGT’s management team did not pursue third-party volumes aggressively. As a result, our average daily throughput for the nine-month period ended September 30, 2014 of 625, 125 and 234 MMcf/d on our Holly, Center and Legacy systems, respectively, is currently below our daily throughput capacity by 1,475, 768 and 266 MMcf/d for our Holly, Center and Legacy systems, respectively. We believe this excess capacity creates an opportunity for us to significantly increase volumes on our existing systems with minimal incremental capital expenditures, thereby giving us substantial operating leverage.

We expect to acquire additional interests in Azure Midstream Operating over time. Through its participation in any increases to our cash distributions through the incentive distribution rights, as well as its substantial limited partner interest in us, Azure Midstream Holdings is positioned to directly benefit from growth in the volumes on our systems from our customers and acquisition of other midstream assets from Azure Midstream Holdings and third parties. However, Azure Midstream Holdings is under no obligation to offer us the opportunity to purchase any portion of its retained interest in Azure Midstream Operating.

Results of Our Operations

The following table and discussion presents Azure Midstream Holdings historical consolidated financial data and the historical financial data of our Predecessor for the periods indicated. We will refer to the period from November 15, 2013 to December 31, 2013 as the “2013 Holdings Period” and the period from January 1, 2013 to November 14, 2013 as the “2013 Predecessor Period.” The financial data for the periods in which our Predecessor owned our assets does not necessarily represent the results of operations that would have been achieved had we owned and operated these assets during the periods.

For a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated in accordance with GAAP, please read “Summary—Non-GAAP Financial Measures.” We define distributable cash flow as Adjusted EBITDA less interest and income taxes paid and maintenance capital expenditures.


	Azure Midstream Holdings LLC			Predecessor				Azure Midstream Holdings LLC		Predecessor
	Period from November 15, 2013 to December 31, 2013			Period from January 1, 2013 to November 14, 2013		Year Ended December 31, 2012		Nine-Month Period Ended September 30, 2014		Nine-Month Period Ended September 30, 2013
	(in thousands, except for volumes)
Statement of Operations Data:
Revenues:
Operating revenues—affiliates	$	16,389		$	135,665	$	198,243	$	78,741	$	125,014
Operating revenues—non-affiliates		8,430			44,667		48,208		56,092		33,546

Total operating revenues		24,819			180,332		246,451		134,833		158,560

Operating expenses:
Cost of purchased gas and NGLs sold		4,505			21,054		22,794		30,095		18,239
Operating expense		5,455			33,850		48,586		23,685		28,993
General and administrative		458			11,166		17,514		10,760		9,820
Transaction costs		6,135			—		—		—		—
Asset impairments		—			583		50,771		228		583
Depreciation and amortization		3,480			31,143		32,132		21,989		26,713

Total expenses		20,033			97,796		171,797		86,757		84,348

Income from operations		4,786			82,536		74,654		48,076		74,212
Interest expense		5,046			10,321		16,145		31,145		9,331
Other expense		576			2,316		3,441		326		1,695
Income tax expense		106			361		425		423		317

Net income (loss)	$	(942	)	$	69,538	$	54,643	$	16,182	$	62,869

Other Financial Data:
Adjusted EBITDA	$	14,206		$	114,153	$	157,596	$	78,250	$	101,389
Capital expenditures		5,326			29,208		191,001		16,363		27,604

Operating Data:
Average throughput volumes of natural gas (MMcf/d)		843			1,217		1,471		991		1,302

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Nine-Month Period Ended September 30, 2014 Compared to Nine-Month Period Ended September 30, 2013

Volumes

Average throughput volumes were 991 MMcf/d for the nine-month period ended September 30, 2014, a decrease of 311 MMcf/d, or 24%, from the average throughput volumes of 1,302 MMcf/d for the nine-month period ended September 30, 2013. Volume declines were primarily attributable to decreased drilling activity by our customers EXCO and BG period over period. During the first quarter of 2014, EXCO and BG lowered production guidance and reduced capital spending for the second and third quarters of 2014 in the Haynesville, Bossier and Cotton Valley formation areas. In addition, our volumes for the nine-month period ended September 30, 2013 were positively impacted by the completion of a number of wells by EXCO and BG at the end of 2012, which contributed to our volumes in 2013. There were no similar wells completed at the end of 2013 that carried over into 2014.

Revenues

Our revenues are primarily attributable to the volume of natural gas that we transport, gather, compress and treat, and the fixed rates we charge per volume of natural gas for these services. We deliver these volumes of natural gas to multiple interconnect and downstream access points or to third-party processing plants, which serve as connection points for a number of intrastate and interstate pipelines. Our secondary source of revenues are attributable to sales of natural gas and NGLs purchased from third parties.

Total operating revenues were $134.8 million for the nine-month period ended September 30, 2014, a decrease of $23.8 million, or 15%, from the total operating revenues of $158.6 million for the nine-month period ended September 30, 2013. Total transportation, gathering, compression and treating revenues were $95.2 million and $133.1 million for the nine-month period ended September 30, 2014 and 2013, respectively. The decrease in total transportation, gathering, compression and treating revenues resulted from lower throughput volumes. Total natural gas and NGL sales were $39.6 million and $25.5 million for the nine-month period ended September 30, 2014 and 2013, respectively. The increase in total natural gas and NGL sales revenue period over period is due to higher natural gas and NGL sales volumes and higher weighted average natural gas and NGL sales prices during the nine-month period ended September 30, 2014 as compared to the nine-month period ended September 30, 2013.

Cost of Purchased Gas and NGLs Sold

Our cost of purchased gas and NGLs sold was $30.1 million for the nine-month period ended September 30, 2014, an increase of $11.9 million, or 65%, from the cost of purchased gas and NGLs sold of $18.2 million for the nine-month period ended September 30, 2013. $6.1 million of the increase in cost of purchased gas and NGLs sold is due to higher natural gas prices and $5.0 million of this increase is due to higher volumes period over period. Additionally, cost of purchased gas and NGLs sold increased $0.8 million as a result of expenses associated with cost of gas and NGLs sold from our new processing plant that was placed into service in March 2014.

Operating Expense

Operating expense was $23.7 million for the nine-month period ended September 30, 2014, a decrease of $5.3 million, or 18%, from the operating expenses of $29.0 million for the nine-month period ended September 30, 2013. The decrease in operating expense was due to our continued focus on asset optimization, including moving and consolidating compression facility locations and the release of under-utilized rental compression and treating equipment. We incurred $0.5 million in non-recurring operating expenses during the nine-month period ended September 30, 2014 associated with transition services as a result of the Acquisition.

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General and Administrative Expense

General and administrative expense was $10.8 million for the nine-month period ended September 30, 2014, an increase of $1.0 million, or 10%, from the general and administrative expense of $9.8 million for the nine-month period ended September 30, 2013. The increase was primarily driven by approximately $1.0 million of non-recurring transition and transaction expenses included in the 2014 period associated with the Acquisition. These transition costs were partially offset by a reduction in corporate personnel expenses as we reduced the number of corporate personnel to better align with the needs of our newly acquired assets.

Asset Impairments

We recognized a $0.2 million impairment during the nine-month period ended September 30, 2014, and the Predecessor recognized a $0.6 million impairment during the nine-month period ended September 30, 2013. These impairments resulted from adjusting the net book value of assets held for sale to their net realizable fair market value.

Depreciation and Amortization

Depreciation and amortization was $22.0 million for the nine-month period September 30, 2014, a decrease of $4.7 million, or 18%, from the depreciation and amortization of $26.7 million for the nine-month period ended September 30, 2013. As a result of the application of purchase accounting, the assets acquired and liabilities assumed were adjusted to their fair market values as of the Acquisition date, and we assigned useful lives based on various factors, including age and historical data associated with the assets acquired.

Interest Expense and Related Charges

Interest expense and related charges were $31.1 million for the nine-month period ended September 30, 2014, an increase of $21.8 million from the interest expense and related charges of $9.3 million for the nine-month period ended September 30, 2013. The increase is primarily driven by increased outstanding borrowings under the Azure Energy credit agreement compared to outstanding borrowings under the Predecessor’s credit agreement.

Period from November 15, 2013 to December 31, 2013 (“2013 Holdings Period”) and Period from January 1, 2013 to November 14, 2013 (“2013 Predecessor Period”) Compared to Year End December 31, 2012

Volumes

Average throughput volumes were 843 MMcf/d for the 2013 Holdings Period and 1,217 MMcf/d for the 2013 Predecessor Period, or a weighted average of 1,090 MMcf/d during the 2013 fiscal year, compared to 1,471 MMcf/d for the year ended December 31, 2012. Volume declines were primarily attributable to decreased drilling activity by our customers EXCO and BG period over period. As gas prices decreased from 2011 to 2012, our producers continued to assess product pricing and project economics to make further decisions on rig counts and well completions in our areas of operation. As a result, our producers decreased rig counts from 2012 to 2013.

Revenues

Total revenues were $24.8 million for the 2013 Holdings Period and $180.3 million for the 2013 Predecessor Period compared to $246.5 million for the year ended December 31, 2012. Total transportation, gathering, compression and treating revenues were $19.6 million during the 2013 Holdings Period and $151.0 million during the 2013 Predecessor Period compared to $211.5 million for the year ended December 31, 2012. The decrease in transportation, gathering, compression and treating revenues is due to declines in producer

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volumes as a result of reduced drilling activity in 2013 compared to 2012. Total natural gas and NGL sales were $5.2 million during the 2013 Holdings Period and $29.3 million for the 2013 Predecessor Period compared to $34.9 million for the year ended December 31, 2012.

Cost of Purchased Gas and NGLs Sold

Our cost of natural gas and NGLs sold was $4.5 million for the 2013 Holdings Period and $21.1 million for the 2013 Predecessor Period compared to $22.8 million for the year ended December 31, 2012. The increase in cost of natural gas sold is a result of increases in the weighted average sales price period over period.

Operating Expense

Operating expense was $5.5 million for the 2013 Holdings Period and $33.9 million for the 2013 Predecessor Period compared to $48.6 million for the year ended December 31, 2012. The decrease in operating expense was primarily attributed to lower rental expenses incurred in 2013 compared to 2012 as a result of the release of under-utilized rental compression and treating equipment, as well as the result of management’s efforts to manage an effective asset optimization program including moving and consolidating compression facility locations. These cost savings actions resulted in a decrease in operating expense of $8.2 million period over period.

General and Administrative Expense

General and administrative expense was $0.5 million for the 2013 Holdings Period and $11.2 million for the 2013 Predecessor Period compared to $17.5 million for the year ended December 31, 2012. The decrease in general and administrative expense was primarily attributed to lower payroll related costs due to decreases in employee headcount period over period.

Asset Impairments

We did not recognize an asset impairment during the 2013 Holdings Period. During the 2013 Predecessor Period asset impairments were $0.6 million compared to $50.8 million during the year ended December 31, 2012. The asset impairment recognized during the 2013 Predecessor Period was associated with adjustments to the net book value of assets held for sale in order to reflect their net realizable fair market value. The asset impairments recognized during the year ended December 31, 2012 were mainly associated with an impairment of approximately $34.9 million for certain assets associated with the installation of temporary treating facilities at the Holly 6 amine treating facility, a $9.2 million impairment related to canceled capital projects and a $5.5 million impairment on the Danville gathering system, which was sold by the Predecessor prior to the Acquisition. The remaining asset impairments of $1.2 million recognized during the year ended December 31, 2012 were associated with recording assets held for sale to their net realizable fair market value.

Transaction Costs

We incurred approximately $6.1 million in acquisition-related costs during the 2013 Holdings Period in connection with the Acquisition. The Predecessor had no such acquisition-related costs.

Depreciation and Amortization

Depreciation and amortization was $3.5 million for the 2013 Holdings Period and $31.1 million for the 2013 Predecessor Period compared to $32.1 million for the year ended December 31, 2012. This increase was primarily attributed to timing of the completion of capital projects during the 2013 Predecessor Period, which increased depreciation and amortization expense.

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Interest Expense and Related Charges

Interest expense and related charges was $5.0 million for the 2013 Holdings Period and $10.3 million for the 2013 Predecessor Period compared to $16.1 million for the year ended December 31, 2012. The decrease in interest expense and related charges was primarily attributed to timing of principal payments made by the Predecessor during the 2013 Predecessor Period, resulting in lower outstanding borrowings during the period compared to the year ended December 31, 2012, offset by increases in interest expense and related charges during the 2013 Holdings Period due to the outstanding borrowings incurred in connection with the Acquisition.

Liquidity and Capital Resources

Sources and Uses of Cash

Capital and liquidity has historically been provided by our operating cash flow. We expect our ongoing sources of liquidity following this offering to include operating cash flow, borrowing capacity under the $ million revolving credit facility we expect to enter into in connection with the offering and proceeds from the issuance of additional limited partner units. We expect the combination of these capital resources will be adequate to meet our short-term working capital requirements, long-term capital expenditures and expected quarterly cash distributions.

Cash Flows

The following table reflects cash flows for the applicable periods for Azure Midstream Holdings and the Azure Midstream Predecessor:


	Azure Midstream Holdings LLC			Predecessor						Azure Midstream Holdings LLC			Predecessor
	Period from November 15, 2013 to December 31, 2013)			Period from January 1, 2013 to November 14, 2013			Year Ended December 31, 2012			Nine-Month Period Ended September 30, 2014			Nine-Month Period Ended September 30, 2013
	Period from November 15, 2013 to December 31, 2013)			Period from January 1, 2013 to November 14, 2013			Year Ended December 31, 2012			Nine-Month Period Ended September 30, 2014			Nine-Month Period Ended September 30, 2013
	(in thousands)
Operating activities	$	1,884		$	113,584		$	129,055		$	47,380		$	96,832
Investing activities		(924,746	)		(27,603	)		(178,565	)		(16,904	)		(26,021	)
Financing activities		938,438			(88,671	)		21,525			(20,018	)		(73,671	)

Nine-Month Period Ended September 30, 2014 Compared to Nine-Month Period Ended September 30, 2013

Operating Activities: Net cash provided by operating activities was $47.4 million for the nine-month period ended September 30, 2014, a decrease of $49.4 million, or 51%, from the net cash provided by operating activities of $96.8 million for the nine-month period ended September 30, 2013. The decrease in net cash provided by operating activities is mainly a result of lower net income for the nine-month period ended September 30, 2014 compared to the same period in 2013. Additionally, net non-cash charges were $2.5 million lower during the nine-month period ended September 30, 2014 compared to the same period in 2013. The changes in our operating assets and liabilities resulted in a source of cash in the amount of $3.1 million during the nine-month period ended September 30, 2014, which was mainly attributed to a source of cash from changes in our accounts receivable and other long-term liabilities of $8.7 million and $4.2 million, respectively, offset by a use of cash from changes in our accounts payable and accrued liabilities and other current assets of $9.7 million and $0.2 million, respectively. Changes in operating assets and liabilities resulted in a source of cash in the

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amount of $3.3 million during the nine-month period ended September 30, 2013, which was mainly attributed to a source of cash from changes in our accounts receivable of $4.6 million and other current assets of $1.5 million offset by a use of cash from changes in our accounts payable and accrued liabilities of $2.8 million.

Investing Activities: Net cash used in investing activities was $16.9 million for the nine-month period ended September 30, 2014, a decrease of $9.1 million, or 35%, from the net cash used in investing activities of $26.0 million during the nine-month period ended September 30, 2013. The decrease is mainly attributed to declines in capital expenditures period over period. We made $16.4 million in capital expenditures during the nine-month period ended September 30, 2014 compared to our Predecessor’s capital expenditures of $27.6 million during the nine-month period ended September 30, 2013. Our Predecessor’s capital expenditures for the nine-month period ended September 30, 2013 included further enhancements to our Holly facilities, as well as the construction of a saltwater disposal facility in our Legacy area.

Financing Activities: Net cash used in financing activities was $20.0 million for the nine-month period ended September 30, 2014, a decrease of $53.7 million, or 73%, from the net cash used in financing activities of $73.7 million for the nine-month period ended September 30, 2013. The decrease was mainly attributed to lower repayments of long-term debt period over period. Specifically, our repayments under Azure Energy’s credit agreement were $20.6 million during the nine-month period ended September 30, 2014 compared to our Predecessor’s repayments under the Predecessor’s credit agreement of $71.6 million during the nine-month period ended September 30, 2013.

2013 Holdings Period and 2013 Predecessor Period Compared to Year End December 31, 2012

Operating Activities: Net cash provided by operating activities was $1.9 million during the 2013 Holdings Period and $113.6 million during the 2013 Predecessor Period compared to $129.1 million during the year ended December 31, 2012. The decrease in cash provided by operating activities was primarily a result of higher non-cash charges of $88.0 million for the year ended December 31, 2012, which was primarily driven by an impairment of assets of $50.8 million and depreciation expense of $32.1 million. Noncash charges were $35.2 million during the 2013 Predecessor Period and $4 million during the 2013 Holdings Period. Changes in operating assets and liabilities resulted in a use of cash of $13.6 million during the year ended December 31, 2012 and resulted in a source of cash of $8.8 million and a use of cash of $1.2 million during the 2013 Predecessor Period and 2013 Holdings Period, respectively.

Investing Activities: Net cash used in investing activities was $178.6 million for the year ended December 31, 2012 compared to $27.6 million for the 2013 Predecessor Period and $924.7 million for the 2013 Holdings Period. This increase in cash used in investing activities was primarily the result of the $919.4 million in cash we paid for the Acquisition, compared to cash paid by the Predecessor for capital expenditures of $191.0 million and $29.2 million during the year ended December 31, 2012 and the 2013 Predecessor Period, respectively. Predecessor capital expenditures in 2012 included the finalization of our Center and Holly facilities in 2012. Our Predecessor completed much of the build out of the facility infrastructure in 2012 and the first half of 2013. Capital expenditures subsequent to that time period have been related to well connections and gathering laterals construction.

Financing Activities: Net cash provided by financing activities was $938.4 million during the 2013 Holdings Period and net cash used in financing activities was $88.7 million during the 2013 Predecessor period compared to net cash provided by financing activities of $21.5 million during the year ended December 31, 2012. The increase was primarily the result of the $550.0 million in proceeds received from the Azure Energy term loan and $410.0 million in proceeds received from the issuance of members equity in connection with the Acquisition offset by repayments made by the Predecessor on the Predecessor Credit Agreement during the 2013 Predecessor Period.

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Capital Requirements

The midstream business is capital intensive and can require significant investment to maintain and upgrade existing operations, connect new wells to the system, organically grow into new areas and comply with environmental and safety regulations. Going forward, our capital requirements will consist of the following:

•

For the 2013 Holdings Period, our total capital expenditures were $924.8 million, consisting of $916.2 million associated with the acquisition of TGGT, $3.2 million associated with the acquisition of ETG and $5.3 million associated with capital expenditures. Our Predecessor incurred $29.2 million and $191.0 million in capital expenditures during the 2013 Predecessor Period and the year ended December 31, 2012, respectively.

We are forecasting $25.9 million in total Azure Midstream Operating capital expenditures for the twelve months ended December 31, 2015. Please read “Our Cash Distribution Policy and Restrictions on Distributions—Assumptions and Considerations.”

We anticipate that we will continue to make significant capital expenditures in the future. Consequently, our ability to develop and maintain sources of funds to meet our capital requirements is critical to our ability to meet our growth objectives and our future growth capital expenditures may vary significantly from period to period based on the investment opportunities available to us. We expect to fund future capital expenditures from cash flow generated from our operations, borrowings under our new $ million revolving credit facility, the issuance of debt or additional partnership units or other sources of capital available to us.

Distributions

We intend to pay a quarterly distribution at an initial rate of $ per unit, which equates to an aggregated distribution of $ million per quarter, or $ million on an annualized basis, based on all of the units anticipated to be outstanding immediately after the closing of this offering. We do not have a legal obligation to make distributions except as provided in our partnership agreement.

Azure Midstream Partners, LP Credit Agreement

In connection with the completion of this offering, we intend to enter into a new $150.0 million revolving credit facility that will mature on November 15, 2018. Our new revolving credit facility will also include the ability to access an incremental $100.0 million accordion feature, subject to lender approval, and will be available for working capital, capital expenditures, certain acquisitions, distributions, unit repurchases and other general partnership purposes.

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Borrowings under our revolving credit facility are expected to bear interest at LIBOR plus a margin varying from 2.75% to 3.75% depending on our most recent consolidated leverage ratio (as defined in the agreement governing our revolving credit facility). Interest on LIBOR loans is expected to be payable on the last day of each interest period or, in the case of interest periods longer than three months, every three months. The unused portion of our revolving credit facility is expected to be subject to a commitment fee of 0.50% that declines depending on our most recent consolidated leverage ratio.

Our revolving credit facility is expected to contain covenants and conditions that, among other things, limit our ability to incur or guarantee additional debt, make certain cash distributions (with an exception for distributions permitted under the partnership agreement, subject to certain customary conditions), incur certain liens or permit them to exist, make certain investments and acquisitions, enter into certain types of transactions with affiliates, merge or consolidate with another company, and transfer, sell or otherwise dispose of assets. We also expect to be subject to covenants that require us to maintain certain financial ratios. For example, we may not permit the ratio of (i) total consolidated debt (as defined in the agreement governing our revolving credit facility) as of the last day of each fiscal quarter to (ii) consolidated EBITDA (as defined in the agreement governing our revolving credit facility) for the four consecutive fiscal quarters ending on the last day of such fiscal quarters to exceed (A) at any time other than during a qualified acquisition period (as defined in the agreement governing our revolving credit facility), 4.50 to 1.00 and (B) during a qualified acquisition period, 5.00 to 1.00. In addition, we may not permit the ratio of (i) consolidated EBITDA for the four consecutive fiscal quarters ending on the last day of each fiscal quarter to (ii) consolidated interest expense (as defined in the credit agreement governing our revolving credit facility) to be less than 2.50 to 1.00.

Azure Midstream Operating Company GP, LLC and Azure Midstream Operating and its subsidiaries will be guarantors of our revolving credit facility. We will pledge substantially all of our assets, including our 40% limited partner interest in Azure Midstream Operating and its subsidiaries, as collateral under the revolving credit facility. We will also pledge substantially all of the assets of Azure Midstream Operating Company GP, LLC and Azure Midstream Operating and its subsidiaries as collateral under our revolving credit facility.

Credit Risk and Customer Concentration

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. A significant percentage of our revenue is attributable to two producer customers, EXCO and BG, which are also considered related parties given their approximate 7% combined ownership in Azure Midstream Holdings. EXCO and BG individually accounted for more than 10% of our $24.8 million, $180.3 million and $246.5 million consolidated revenue for the 2013 Holdings Period, 2013 Predecessor Period and the year ended December 31, 2012, respectively, individually accounting for 33%, 37% and 40%, respectively, of our consolidated revenue for these periods. EXCO and BG individually accounted for approximately 29%, respectively, of our consolidated revenues for the nine-month period ended September 30, 2014. Effective upon close of the Acquisition, we executed an agreement with EXCO and BG that includes a minimum throughput commitment of 600,000 MMbtu/d. If one of these customers were to default on their contractual obligations or if we were unable to renew our contract with these customers on favorable terms, we may not be able to replace either of these customers in a timely fashion, on favorable terms if at all. In any of these situations, our cash flows and our ability to make cash distributions to our unitholders may be adversely affected. We expect our exposure to concentrated risk of non-payment or non-performance to continue as long as we remain substantially dependent on a relatively small number of customers for a substantial portion of our revenue.

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Contractual Obligations

The table below summarizes Azure Midstream Holdings consolidated contractual obligations and other commitments as of December 31, 2013:


Contractual Obligation	Total		Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 years
	(in thousands)
Long-term debt and interest(1)	$	707,509	$	63,044	$	179,186	$	465,279	$	—
Operating leases		8,491		3,567		3,998		926		—

Total	$	716,000	$	66,611	$	183,184	$	466,205	$	—

(1)

Prior to or in connection with the completion of the Offering, we intend to enter into a new revolving credit facility and Azure Midstream Holdings will refinance the Azure Energy credit facility and term loan.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

We have exposure to changes in interest rates on our indebtedness associated with our credit agreement. It is possible that future monetary conditions can tighten or weaken, resulting in higher or lower interest rates. Interest rates on floating rate indebtedness and future debt offerings could be higher or lower than current levels, causing our financing costs to change accordingly.

A hypothetical decrease or increase in interest rates of 1.0% would have decreased or increased, respectively, our interest expense by $0.7 million, $3.8 million and $3.9 million for the 2013 Holdings Period, the 2013 Predecessor Period and the nine-month period ended September 30, 2014, respectively.

Commodity Price Risk

Because we generated over 90% of our revenues for the nine months ended September 30, 2014 pursuant to long-term, fixed-fee and fixed-spread natural gas gathering and sales agreements that include minimum volume commitments, acreage dedications or life of lease arrangements, our only direct commodity price exposure relates to the sale of condensate volumes. Our total operating revenues for the nine months ended September 30, 2014 were $134.8 million, of which total transportation, gathering, compression and treating revenues pursuant to fixed-fee agreements were $95.2 million, and revenues from natural gas and NGL sales pursuant to fixed-spread arrangements were $34.6 million which are offset by our cost of purchased gas and NGLs sold of $30.1 million. Our sales of condensate volumes, which are included within natural gas and NGL sales in our statement of operations, were $5.0 million for the nine-months ended September 30, 2014. Our fixed-fee and fixed-spread natural gas gathering and sales agreements are intended to mitigate our direct commodity price exposure and enhance the stability of our cash flows.

Natural gas and NGL prices are impacted by changes in the supply and demand for natural gas and NGL products, as well as market uncertainty. Because of our limited exposure to commodity prices, we have not entered into any derivative contracts to manage our exposure to commodity price risk. Natural gas and NGL prices can also affect our profitability indirectly by influencing the level of drilling activity in our areas of operations. For a further discussion of the volatility of natural gas and NGL prices and their impact on our profitability, please read “Risk Factors.”

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Impact of Seasonality

Our results of operations on our gathering systems are not materially affected by seasonality.

Critical Accounting Policies and Estimates

In our financial reporting process, we employ methods, estimates and assumptions that affect the reported amounts of assets and liabilities as of the balance sheet date of our financial statements. These methods, estimates and assumptions also affect the reported amounts of revenues and expenses, including fair value measurements and disclosure of contingencies, during the reporting period. Our actual results could differ from these estimates if the underlying assumptions prove to be incorrect. The following describes the accounting policies currently underlying our most significant financial statement items:

Recent Accounting Pronouncements

Accounting standard-setting organizations frequently issue new or revised accounting rules and pronouncements. We regularly review new accounting rules and pronouncements to determine their impact, if any, on our consolidated financial statements.

In May 2014, the Financial Accounting Standards Board (“FASB”) and International Accounting Standards Board (“IASB”) jointly issued a comprehensive new revenue recognition standard that will supersede nearly all existing revenue recognition guidance under GAAP and International Financial Reporting Standards (“IFRS”). The standard’s core principle is that a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. We are required to adopt this standard beginning in the first quarter of 2017. The adoption could have a significant impact on our consolidated financial statements, however we are currently unable to quantify the impact.

There are currently no other recent pronouncements that have been issued that we believe will materially affect our consolidated financial statements.

Contingencies

Our consolidated financial results may be affected by judgments and estimates related to loss contingencies. Accruals for loss contingencies are recorded when management determines that it is probable that an asset has been impaired or a liability has been incurred and that such economic loss can be reasonably estimated. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events, and estimates of the financial impacts of such events.

Depreciation

Depreciation of property, plant, and equipment is recorded on a straight-line basis over the estimated useful lives of our assets. We assign asset lives based on reasonable estimates when an asset is placed into service. We periodically re-evaluate the estimated useful lives of our property, plant and equipment and revise our estimates. These estimates are based on various factors including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning the useful lives of similar assets. If any of these assumptions subsequently change, the estimated useful life of the asset could change and result in an increase or decrease in depreciation expense. Subsequent events could cause us to change our estimates, which would impact the future calculation of depreciation expense.

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Property, Plant and Equipment

Property, plant, and equipment is recorded at the historical cost of construction or, upon acquisition, the fair value of the assets acquired. Expenditures for maintenance and repairs that do not add capacity or extend the useful life of an asset are expensed as incurred. Expenditures that extend the useful lives of the assets or enhance their productivity or efficiency from their original design are capitalized and expensed over the expected remaining period of use. The carrying value of the assets is based on estimates, assumptions and judgments relative to useful lives and salvage values. Sales or retirement of assets, along with the related accumulated depreciation, are removed from the accounts and any gain or loss on disposition is included in the statement of operations. Costs related to projects during construction, including interest on funds borrowed to finance the construction of facilities, are capitalized as construction in progress. Amounts reimbursed by producers for well connection costs reduce the amount of capital expenditures associated with the project.

Impairment of Long-Lived Assets

Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written down to estimated fair value. Assets are tested for impairment when events or circumstances indicate that the carrying value of a long-lived asset may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposal of the long-lived asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized. Fair value is determined using an income approach whereby the expected future cash flows are discounted using a rate management believes a market participant would assume is reflective of the risk associated with achieving the underlying cash flows.

Goodwill

Goodwill represents consideration paid in excess of the fair value of the identifiable assets acquired in a business combination. We evaluate goodwill for impairment annually on October 1st, and whenever events or changes indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, we will perform a qualitative assessment to determine whether it is more likely than not that the fair value of the reporting unit is impaired. Management will use all available information to make these determinations, including a qualitative assessment evaluating the macroeconomic environment, industry specific conditions, cost factors, and the overall financial performance at the assessment date of October 1. If determined to be necessary, goodwill is then tested for impairment using a two-step quantitative test. The first step compares the fair value of the reporting unit to its carrying value, including goodwill. If the fair value exceeds the carrying amount, goodwill of the reporting unit is not considered impaired. If the fair value does not exceed the carrying amount, the second step compares the impaired fair value to the carrying value of the reporting unit. If the carrying amount of a reporting unit’s goodwill exceeds the implied fair value of that goodwill, the excess of the carrying value over the implied value is recognized as an impairment loss.

We estimate fair value using valuation analyses based on values of comparable companies and comparable transactions. In comparable company’s analysis, we review the public stock market trading multiples for selected publicly-traded midstream companies with comparable financial and operating characteristics. These characteristics are market capitalization, location of midstream operations and the characterization of such operations that are deemed to be similar to ours. In a comparable transactions analysis, we review certain acquisition multiples for selected recent midstream company or asset package transactions.

We have one reporting unit for goodwill purposes. We are in the process of performing our annual goodwill impairment test as of October 1, 2014. We performed the qualitative assessment and concluded that the first step of the goodwill impairment test was required. There are currently no indications that a goodwill impairment exists as of October 1, 2014; however, we have not completed the first step of the goodwill impairment test as of the date these financial statements were available.

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Revenue Recognition

In general, we recognize revenue from customers when all of the following criteria are met:

•

persuasive evidence of an exchange arrangement exists;

•

delivery has occurred or services have been rendered;

•

the price is fixed or determinable; and

•

collectability is reasonably assured.

We record revenue for natural gas gathering services over the period in which they are earned (i.e., either physical delivery of product has taken place or the services designated in the contract have been performed). While we make every effort to record actual volume and price data, there may be times where we need to make use of estimates for certain revenues and expenses. If the assumptions underlying our estimates prove to be substantially incorrect, it could result in material adjustments in results of operation.

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INDUSTRY OVERVIEW

Natural gas is a critical and growing component of energy consumption in the United States. The U.S. natural gas pipeline grid is the link between upstream exploration and production activities and downstream end-use markets. This network is a highly integrated transmission and distribution grid that transports natural gas from producing regions to customers such as local distribution companies (“LDCs”), industrial users and electric generation facilities. Companies generate revenues at various stages within this value chain by gathering, processing, treating, fractionating, transporting, storing and marketing natural gas and natural gas liquids (“NGLs”).

The following diagram illustrates various components of the natural gas value chain:

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Source: EIA, Annual Energy Outlook 2014

The range of services offered is generally classified according to the categories described below. As indicated above, we do not currently provide all of these services.

Gathering. At the initial stages of the midstream value chain, a network of pipes known as gathering systems directly connect to wellheads in the production area. These gathering systems transport natural gas from the wellhead to downstream pipelines or a central location for treating and processing. A large gathering system may involve thousands of miles of gathering lines connected to thousands of wells. Gathering systems are typically designed to be highly flexible to allow gathering of natural gas at different pressures and scalable to allow for additional production and well connections without significant incremental capital expenditures.

Compression. Natural gas compression is a mechanical process in which a volume of natural gas at a given pressure is compressed to a desired higher pressure, which enables more efficient gathering and delivery into a higher pressure system, processing plant or pipeline. Field compression is typically used to allow a gathering system to operate at a lower pressure or provide sufficient discharge pressure to deliver natural gas into a higher pressure system. Compression is also used in the transportation of natural gas to support the movement of gas across pipeline systems and in storage to enhance withdrawal and injection capability.

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Treating and Dehydration. Treating and dehydration involves the removal of impurities such as water, carbon dioxide, nitrogen and hydrogen sulfide that may be present when natural gas is produced at the wellhead. These impurities must be removed for the natural gas to meet the specifications for transportation on long-haul intrastate and interstate pipelines.

Processing. The principal components of natural gas are methane and ethane, but some natural gas also contains varying amounts of other NGLs, which are heavier hydrocarbons that are found in some natural gas streams. Even after treating and dehydration, some natural gas is not suitable for long-haul intrastate and interstate pipeline transportation or commercial use because it contains NGLs, which increase Btu levels beyond transport specifications. This natural gas, referred to as liquids-rich natural gas, must be processed to remove these heavier hydrocarbon components. However, NGLs are also valuable commodities once removed from the natural gas stream and utilized in the refining and petrochemical industries. The removal and separation of NGLs usually takes place in a processing plant using industrial processes that exploit differences in the weights, boiling points, vapor pressures and other physical characteristics of NGL components.

Fractionation. Fractionation is the separation of the mixture of extracted NGLs into individual components for end-user sale. Fractionation is accomplished by controlling the temperature of the stream of mixed liquids in order to take advantage of the difference in boiling points of separate products.

Transportation. The U.S. natural gas pipeline grid transports natural gas from producing regions to customers, such as LDCs, industrial users and electric generation facilities. The concentration of natural gas production in a few regions of the United States generally requires transportation pipelines to cross state borders to meet national demand. These pipelines are referred to as interstate pipelines and are primarily regulated by federal agencies or commissions, including the Federal Energy Regulatory Commission (“FERC”). Pipelines that transport natural gas within one state are generally referred to as intrastate pipelines. Intrastate pipelines are primarily regulated by state agencies or commissions.

Storage. Natural gas storage plays a vital role in maintaining the reliability of natural gas supplies needed to meet the demands of consumers. Natural gas is typically stored in underground storage facilities, including salt dome caverns and depleted reservoirs. Storage facilities are generally utilized by (1) pipelines, to manage imbalances in operations, (2) natural gas end-users, such as LDCs, to manage the seasonality and variability of demand and to satisfy future natural gas needs and (3) independent natural gas marketing and trading companies in connection with the execution of their trading strategies.

Contractual Arrangements

Midstream natural gas services, other than transportation and storage, are usually provided under contractual arrangements that vary in the amount of associated commodity price risk. Standard contract types include fee-based arrangements, percent-of-proceeds and percent-of-liquids arrangements, and keep-whole arrangements. During the nine months ended September 30, 2014, we generated over 90% of our revenues under long-term, fixed-fee and fixed-spread natural gas gathering and sales agreements that are intended to mitigate our direct commodity price exposure and enhance the stability of our cash flows. Under fixed-fee arrangements, the service provider typically receives a fee for each unit of natural gas gathered and compressed at the wellhead and an additional fee per unit of natural gas treated or processed at its facility. This fee is directly related to the volume of natural gas that flows through the gatherer’s or processor’s systems and is not directly dependent on commodity prices. Some fee-based contracts have minimum volume commitments, which obligate a customer to pay an agreed upon fee regardless of the actual volume of gas gathered or processed. We also generate revenues under fixed-spread natural gas sales arrangements, whereby we purchase natural gas volumes that have been processed by our third-party processing facilities or treated by our own facilities at an index price less a fixed price, and we then sell these volumes at the same index price, plus or minus a fixed price differential, or a fixed-spread. By entering into such natural gas purchase and sales activities, we are able to lock in a fixed-spread and do not incur commodity price exposure on these transactions.

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Transportation and Storage Services Contractual Arrangements

Level of Service Provisions

There are two basic forms of service provided in the transportation and storage of natural gas: firm and interruptible service. Each level of service governs the availability of capacity on the service provider’s system for a specific customer and the priority of movement of a specific customer’s products relative to other customers, especially in the event that total customer demand for services exceeds available system capacity.

•

Firm. Firm service obligates customers to pay a reservation charge for reserving an agreed upon amount of pipeline throughput or storage capacity, regardless of the actual capacity used, and a usage charge when a customer uses the capacity it has reserved under these firm service contracts. In addition, firm service customers are typically charged an overrun usage charge when the level of natural gas they deliver exceeds their reserved capacity.

•

Interruptible. Interruptible transportation and storage service is generally used by customers that either do not need firm service or have been unable to contract for firm service. These customers are assessed a usage fee for the volume of natural gas actually transported or stored. The obligation to provide this service is limited to available capacity not otherwise used by firm service customers. Unlike customers receiving firm services, customers receiving services under interruptible contracts are not guaranteed capacity on the pipeline or at the storage facility.

Dedication Provisions

Both firm and interruptible service contracts may contain dedication provisions. Dedication provisions effectively dedicate any and all production from specified leases or existing and future wells on dedicated lands for a specified term. Dedication provision may alternatively continue in effect for as long there is commercial production from the identified wells or leases, which are often referred to as “life-of-reserves” or “life-of-lease” dedications. Dedication provisions typically remain in effect even if ownership of the subject acreage or well changes in the future.

U.S. Natural Gas Market Fundamentals

As indicated in the charts shown below, U.S. natural gas production and overall U.S. energy demand are expected to grow in the coming decades. Population is a large determinant of energy consumption through its influence on demand for travel, housing, consumer goods and services. The EIA anticipates the total U.S. population will increase by approximately 21% from 2012 to 2040. Another important contributor to energy consumption is the industrial sector, with total consumption in this sector expected to grow to approximately 38.3 quadrillion Btu in 2040 compared to 30.5 quadrillion Btu in 2012, according to the EIA. According to the EIA, energy use is projected to grow by approximately 12% from 2012 to 2040, while energy use per capita is expected to decline by approximately 8% over the same period. A review of other supply and demand elements follows.

Natural gas is a key component of energy consumption within the United States. According to the EIA, annual consumption of natural gas in the United States increased from approximately 24.9 quadrillion Btu in 2011 to approximately 26.2 quadrillion Btu in 2012. According to the EIA, natural gas consumption represented approximately 27% of total energy consumption in 2012, and the EIA projects that this percentage will increase to approximately 30% by 2040. The charts shown below illustrate energy consumption by fuel source in 2012 and expected energy consumption by fuel source in 2040.

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Energy Consumption by Fuel Source


2012		2040

95 Quadrillion Btu		106 Quadrillion Btu

Source: EIA, Annual Energy Outlook 2014

The EIA expects that the growth of natural gas consumption relative to other fuel sources will be primarily driven by the use of natural gas in electricity generation. According to the EIA, annual demand for natural gas in the electric power sector is projected to increase from approximately 9.3 Tcf in 2012 to approximately 11.2 Tcf in 2040, with a portion of the growth attributable to the retirement of 50 gigawatts of coal-fired capacity by 2021. The EIA also projects that natural gas consumption in the industrial sector will be higher due to the rejuvenation of the industrial sector as it benefits from surging shale gas production that is accompanied by slow price growth, particularly from 2011 through 2019, when the price of natural gas is expected to remain below 2010 levels. However, the EIA expects growth in natural gas consumption for power generation and in the industrial sector to be partially offset by decreased usage in the residential sector.

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U.S. Primary Energy Consumption by Fuel, 1980-2040

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Source: EIA, Annual Energy Outlook 2014

Over the past several years, there has been a fundamental shift in U.S. natural gas production towards unconventional resources, which according to the EIA include natural gas produced from shale formations, tight gas and coal beds. The emergence of unconventional natural gas plays and advancements in technology have been crucial factors that have allowed producers to efficiently extract significant volumes of natural gas from these plays. According to the EIA, the dual application of horizontal drilling and hydraulic fracturing has been the primary driver of increases in shale gas production. As indicated by the diagram below, the development of these unconventional sources has offset declines in other, more traditional U.S. natural gas supply sources, which has helped meet growing consumption and lowered the need for imported natural gas. The EIA predicts that the United States will become a net exporter of natural gas starting in 2018.

As indicated by EIA forecasts shown in the diagram below, as the depletion of conventional onshore and offshore resources continues, natural gas from unconventional resource plays is forecasted to fill the void and continue to gain market share from higher-cost sources of natural gas. In fact, the EIA estimates that natural gas production from the major shale formations will provide the majority of the growth in domestically produced natural gas supply in coming years, increasing to over 50% in 2040 as compared with 40% in 2012.

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U.S. Dry Natural Gas Production by Source, 1990-2040

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NGLs Market Opportunity

The Partnership’s principal area of operations in North Louisiana and East Texas, where it gathers, treats and processes NGLs from the liquids-rich Cotton Valley formation, strategically positions the Partnership to benefit from substantial NGLs demand due to increasing U.S. olefins production. The Gulf Coast region is the hub for U.S. olefins production and exportation.

Overview

Olefins, predominantly comprised of ethylene and propylene, are a class of unsaturated hydrocarbons derived from NGLs (such as ethane, propane and butane) or petroleum liquids (naphtha and gas oils).

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Ethylene is the world’s most widely used petrochemical in terms of volume and is a key building block to produce a number of key derivatives such as polyethylene (“PE”) and PVC, which are used in a wide variety of key end markets including packaging, construction and transportation. PE production accounts for approximately 60% of global ethylene consumption, while PVC production accounts for approximately 10% of ethylene production. The chart below shows estimated global ethylene demand for 2013 by product.

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The principal feedstocks for ethylene production are NGLs and naphtha. NGLs, such as ethane, propane and butane, are used primarily by ethylene producers in the U.S. and the Middle East.

The cost chart below illustrates the ethylene feedstock cost position of production facilities in different regions globally based on feedstock used.

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In the U.S., technological advances in horizontal drilling and fracturing techniques in shale formations have dramatically increased the supply of low-cost ethane feedstock. The spread between U.S. ethane and global oil prices has provided a significant margin advantage for U.S. ethane-based ethylene producers. Throughout 2012 and 2013, production costs for U.S. ethylene production facilities utilizing ethane feedstock were significantly lower than global ethylene production facilities utilizing naphtha and other feedstocks. This significant cost advantage resulted in a positive cash cost differential that has ranged from $0.23 per pound to $0.48 per pound, and averaged $0.38 per pound, since 2012 for U.S. ethane-based ethylene producers as compared to Asia naphtha-based ethylene producers. Supply and demand dynamics in the U.S. ethane market are expected to keep U.S. ethane prices at relatively low levels, which should continue to support a U.S. ethylene cost advantage compared to high-cost ethylene producers in Europe and Asia.

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Current and projected lower feedstock costs have resulted in, and are anticipated to continue to result in, high profitability for U.S. ethane-based ethylene production facilities.

Locations of Ethylene Production Assets Utilizing Advantaged Ethane Feedstock in the U.S.

U.S. ethane-based ethylene producers are primarily located in the Gulf Coast region, with ready access to Mont Belvieu, Texas, the largest NGLs hub in the U.S. Mt. Belvieu includes over 100 million barrels of NGLs and petroleum liquid storage capacity, more than 750,000 barrels per day of fractionation capacity and an extensive NGL distribution system. Ethane is transported to Mont Belvieu from almost all of the major shale plays and basins in the U.S., including the Haynesville, Eagle Ford, Barnett and Woodford shales and the Permian, Anadarko, Denver and Piceance basins.

Ethylene Supply and Demand

Global ethylene production capacity is estimated to have been approximately 341.2 billion pounds in 2013. U.S. ethylene production capacity is estimated to have accounted for approximately 17.9% of global ethylene production capacity and Europe is estimated to have accounted for approximately 20.4%. Combined with Asia at 34.1%, these three regions accounted for approximately 72.3% of global ethylene production capacity in 2013. During the next five years, as projected by Wood Mackenzie, global average annual ethylene production capacity net additions are projected to be approximately 3.8% per year, lagging the projected compound annual growth rate (CAGR) for ethylene demand of 4.4% per year. The global ethylene production operating rates are expected to improve from 86.4% in 2013 to an estimated 89.2% in 2018.

U.S. ethylene demand as measured by production was approximately 55.0 billion pounds in 2013. Demand for ethylene in the U.S. is projected by Wood Mackenzie to grow at a CAGR of 4.8% from 2013 to approximately 69.5 billion pounds in 2018. Key downstream ethylene demand drivers include ethylene’s use in PE and PVC production, with U.S. PE demand (including net exports) expected to grow at a CAGR of 5.0% from approximately 31.0 billion pounds in 2013 to approximately 39.7 billion pounds in 2018 and U.S. PVC demand (including net exports) expected to grow at a CAGR of 4.7% from approximately 14.9 billion pounds in 2013 to approximately 18.7 billion pounds in 2018. As ethylene and ethylene derivative production grows, we expect a larger percentage of ethylene derivatives will be exported.

The following chart depicts historical and forecast ethylene production operating rates in the U.S. and globally. U.S. ethylene production operating rates are currently above the global average and this is expected to continue through 2018, driven by the strong profitability associated with U.S. ethylene operations and the ability to profitably export ethylene derivative products into higher cost regions.

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LNG Market Opportunity

We believe that the emerging liquefied natural gas (“LNG”) export industry in the United States presents an opportunity. The majority of the approved and proposed LNG export facilities in the United States are situated on the Southeast Texas and Southwest Louisiana gulf coast. We are positioned to take advantage of this opportunity due to the close proximity of our assets to these export facilities and the potential for us to provide crucial distribution and interconnection services between the areas of feedstock production and the export terminals. Additionally, we believe that growth in LNG demand could favorably impact domestic natural gas prices and increase production in the region where we operate.

International natural gas reserves and production are spread over a wide array of geographic areas and the disparity between areas of production and areas of consumption has been the principal stimulus of international trade in gas. LNG is natural gas that has been converted into its liquid state through a cooling process, which allows for efficient transportation by sea. Over the past decade, global LNG demand has risen, on average, 7.9% per year.

With the increased U.S. production of natural gas, U.S. domestic gas production now exceeds domestic gas consumption for a large part of the year, which may reduce future gas imports. As a result, the North American gas market is moving in a different cycle from the rest of the world and has larger differentials in pricing than other markets (see the following chart). Regional price differentials create the opportunity for arbitrage and also act as a catalyst for the extraction of new reserves. Given these conditions, interest in exporting LNG from the U.S. has grown and a number of new liquefaction plants are now planned.

Natural Gas Prices, January 2009—October 2014 (U.S. $ per Mcf)

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Source: Bloomberg

During the period between 2002 and 2012, worldwide natural gas demand is estimated to have increased at a pace of 2.8% per year. Comparatively, global LNG demand grew at a much faster rate, averaging 7.9% per year during the same period. The strong demand growth was the combined result of a number of factors including the need to replace declining gas production in certain regions of the world, efforts to displace coal and nuclear fired power generation, national energy policies targeting supply diversity, and the realization of latent demand from industrial and residential sectors.

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Worldwide demand for natural gas as well as for LNG is forecasted to continue their upward trajectories into the future. The EIA projects that global natural gas demand will grow at a rate of 1.7% per year from 2010 to 2030 with the industrial and power generation sectors accounting for nearly three-fourths of the increase. LNG demand is expected to grow at an even faster overall rate. Based on data from Wood Mackenzie, LNG demand is forecast to grow by 4.5% per year from a base of 218.9 Mtpa in 2010, reaching 351.7 Mtpa in 2020 and 532.8 Mtpa in 2030.

LNG Demand by Region

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Source: Wood Mackenzie.

Overview of Areas of Operation

We operate natural gas gathering, processing, transportation, and treating assets located in North Louisiana / East Texas focused on the Haynesville-Bossier and Cotton Valley formations. The Texas-Louisiana basin is a mature, long-lived and prolific hydrocarbon producing province that produces oil and gas from several reservoirs and a variety of trap types. The basin has been a long-time target of conventional oil producers, but as a result of technological advances, operators have recently begun exploring the more shale-like rock, which is contiguous across the basin. There are multiple oil-bearing targets within the basin.

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Haynesville-Bossier Shale: The Haynesville-Bossier Shale is located in east Texas and western Louisiana and is found at intervals greater than 10,000 feet below the surface. The shale interval in east Texas is known as the Lower Bossier, and the shale interval in western Louisiana is referred to as the Haynesville. These formations are of a type once considered too costly to explore. However, in 2008, newer technology and processes led to increased activity as energy exploration companies began to lease property in preparation for possible drilling and production.

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Cotton Valley: The Cotton Valley formation is a tight gas play in northeast Texas and northwest Louisiana located just above the Haynesville/Bossier Shale with a depth of 7,800 to 10,000 feet that consists of sandstone, limestone and shale. It has historically been a natural gas play, although improvements in technology have increased production of oil and NGLs in the area. The formation is characterized by thick, multi-zone natural gas and oil reservoirs with well-known geologic features and long-lived, predictable production profiles. Over 21,000 vertical wells have been completed throughout the play establishing reasonably low geologic risk. In 2005, operators started redeveloping the Cotton Valley using horizontal drilling and advanced hydraulic fracturing techniques. The Cotton Valley formation is productive when accessed through horizontal drilling and fracture stimulation technologies. We believe these qualities, when combined with the liquids-rich nature of the natural gas, concentrated oil content, high initial rates of production and competitive well costs, make the formation attractive for producers in the area.

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Within the Haynesville-Bossier and Cotton Valley formations, drilling activity – as measured by drilling permit application counts and rig counts – has remained stable over recent periods. According to Baker Hughes, rig counts have averaged 42 rigs per month over the 12 month period between October 2013 and October 2014, with 38 rigs operating in October 2013 and 41 rigs operating in October 2014. Drilling permit applications have also been steady, with an average of over 60 permitting applications per month year-to-date in our counties and parishes of operation according to the Texas Railroad Commission and Louisiana Department of Natural Resources. We believe permitting activity is an indicator of future drilling activity.

Rig Count in Azure Operating Area

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Source: Baker Hughes.

Permitting Applications in Azure Operating Area

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Source: Texas Railroad Commission, Louisiana Dept. of Natural Resources. Shows permit applications for Harrison, Panola, San Augustine, Rusk, Nacogdoches, Sabine and Shelby counties and for Caddo, DeSoto and Red River parishes. Excludes amended applications.

Natural Gas Price Impact on Production Levels

Natural gas prices have a direct impact on dry natural gas drilling. Consequently, volatility in natural gas prices can affect producers’ capital programs, drilling activity and production levels. Recent trends in drilling and production levels in the Haynesville shale exemplify this direct relationship with natural gas prices. Natural gas production in the Haynesville shale steadily trended upward through 2011 peaking in 2012 at over 10 Bcf/d. However, as natural gas prices fell during 2012, producers reduced their drilling programs and natural gas production in the Haynesville shale steadily declined to approximately 7 Bcf/d by 2013. Over the same period, the average number of active rigs running in the Haynesville shale declined from 57 in 2012 to 40 in 2013. Natural gas prices again trended upward in 2013 into early 2014, and natural gas production levels stabilized at approximately 7 Bcf/d. We believe production has stabilized at this level, and production is likely to increase with a commensurate increase in natural gas prices.

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Natural Gas Prices (Henry Hub), December 2010—September 2014 (U.S. $ per Mcf)

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Source: EIA

Natural Gas Forward Strip Prices(Henry Hub), Calendar 2014—Calendar 2018 (U.S. $ per Mcf)

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Source: Factset

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BUSINESS

Overview

We are a fee-based, growth-oriented Delaware limited partnership focused on owning, operating, developing and acquiring midstream energy infrastructure that is strategically located in core producing areas of unconventional resource basins in North America. We currently provide natural gas gathering, compression, treating and processing services in North Louisiana and East Texas in the prolific Haynesville and Bossier shale formations, the liquids-rich Cotton Valley formation and the shallower producing sands in the Travis Peak formation. According to the EIA, these formations comprise the third largest natural gas basin in the United States in terms of natural gas production.


	Nine Months Ended September 30, 2014		Year Ended December 31, 2013
Pro forma net income (loss) (100%)	$	16,182	$	(180,021	)
Pro forma Adjusted EBITDA attributable to Azure Midstream Operating (100%)	$	78,250	$	130,590
Pro forma Adjusted EBITDA attributable to us (40%)	$	31,300	$	52,236

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Business Strategies

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Increase capacity utilization and throughput volumes on our existing systems. Our systems are designed to benefit from incremental volumes arising from high-density, infill drilling on existing pad sites already connected to our systems and do not require significant additional capital expenditures to handle such volumes. We intend to continue to focus on the stability of cash flows that we generate by optimizing returns from our existing asset portfolio and maximizing the utilization of our assets by increasing throughput volumes from existing customers and connecting new customers to our systems. We continually monitor field development activity by our customers, and we work closely with customers to tailor and enhance our service offerings to maximize the efficiency and economics of their production. For example, we recently procured a contract to gather up to an additional 40 MMcf/d of throughput volumes on the Legacy system and are in discussions with potential customers regarding additional volumes on our systems. Further, we are implementing a gas allocation process, often referred to as component balancing, which will ensure our producer customers receive an accurate portion of value for natural gas liquids. Other midstream providers may blend a producer’s NGL-rich gas with another producer’s lean gas thereby diluting value to the NGL-rich gas stream and accreting value to the leaner gas stream. Implementing component balancing will enable us to more effectively compete for third-party gas services, particularly those that require processing. As such, we expect to attract additional volumes of gas that may require processing to our systems.

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Acquisitions from Azure Midstream Holdings. We believe that Azure Midstream Holdings’ economic interest in us incentivizes it to offer us acquisition opportunities, including additional interests in Azure Midstream Operating, although it is under no obligation to do so. We will have a right of first offer to acquire the remaining 60% limited partner interest in Azure Midstream Operating from Azure Midstream Holdings prior to that interest being sold to a third party. We

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believe that Azure Midstream Holdings is strongly positioned to continue pursuing and developing integrated midstream solutions projects, which may involve the development, construction and operation of pipelines, processing plants and associated infrastructure, which would allow customers to deliver crude oil and natural gas to transmission pipelines. Furthermore, we believe that the ability of Azure Midstream Holdings to pursue and develop integrated energy infrastructure projects will create potential acquisition opportunities for us in the future.

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Acquisitions from third parties. In the near term, we intend to pursue acquisition opportunities from third parties that we can finance on an accretive basis. Such acquisitions could be pursued independently by us or jointly with Azure Midstream Holdings.

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Diversify our assets through acquisitions of midstream assets with exposure to other basins and hydrocarbons. While our current operations represent our core business, we intend to diversify our basin exposure into new, high-growth regions, as well as expand our operational capabilities into natural gas processing and crude oil services, primarily through acquisitions. We expect to continue to pursue opportunities to acquire crude oil, NGL and natural gas assets that (i) complement our existing business, (ii) allow us to integrate additional midstream services, (iii) balance our commodity profile and (iv) enhance our basin diversity. We anticipate that our highly qualified management team and energy-focused sponsors will provide us with an advantage in pursuing these acquisitions as compared to other competitors. We and our sponsors are frequently involved in discussions with third parties regarding the purchase of natural gas and crude oil midstream energy infrastructure assets. We intend to continue to evaluate opportunities to acquire or develop other midstream energy infrastructure assets that complement our existing business and allow us to leverage our management team’s development and industry expertise throughout the midstream value chain.

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Generate stable and predictable fee-based cash flows. We intend to continue pursuing accretive opportunities to provide fixed-fee and fixed-spread services to existing and new customers, limiting our direct exposure to commodity price volatility when possible. We plan to focus on obtaining additional long-term commitments from customers, which may include minimum volume and revenue commitments, acreage dedications or life of lease arrangements. The long-term, fixed-fee and fixed-spread nature of our contracts reduces direct commodity exposure and provides relatively predictable revenue streams.

Competitive Strengths

We believe that we will be able to successfully execute our business strategies because of the following competitive strengths:

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able to achieve a high level of EURs on wells completed. We believe that producers will continue their drilling and completion activities in our areas of operation in a variety of commodity price environments because the return economics associated with core-area wells remain favorable in lower pricing environments compared to less economic areas of production. We believe our core producers can earn acceptable rates of return above their cost of capital when natural gas prices are slightly above $3.00 per Mcf. Additionally, continued drilling activity in these formations positions us to pursue attractive growth opportunities by further developing and optimizing our systems and by developing or acquiring complementary systems within our geographic areas of operation. Our highly efficient, modern infrastructure provides us the ability to deliver throughput volumes with a lower amount of compression while reducing gas losses and to add additional throughput volumes with marginal incremental costs and capital expenditures.

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Our Assets

Our assets currently consist of three natural gas gathering systems, one natural gas processing facility, seven owned treating plants, three leased treating plants, five owned compressors and two leased compressors located in North Louisiana and East Texas. Our gathering and transmission network consists of approximately 1,365 miles of pipelines that, in aggregate, collects wellhead natural gas from approximately 1,380 receipt points stemming from acreage dedications covering 12 counties and parishes. Our gathering, compression, treating and processing assets are shown on the following map.

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We acquired a significant portion of our midstream assets through our November 15, 2013 acquisition of TGGT, a joint venture formed in 2009 by two of our largest customers, BG and EXCO. At that time, TGGT operated approximately 1,060 miles of gathering pipelines that transported natural gas from supply basins to major intrastate and interstate pipelines in the region. Prior to our acquisition of TGGT, these gathering systems and treating facilities were operated primarily to provide midstream services to BG and EXCO to support their drilling and development programs. At the same time, we acquired ETG, which comprises the remainder of our initial assets, from Tenaska Capital Management. These assets comprise all of the assets of Azure Midstream Operating, and we classify them into three main systems: Holly, Center and Legacy. The following table provides information regarding the assets of Azure Midstream Operating. Unless otherwise noted, all information is as of or for the nine-month period ended September 30, 2014.


System	Formations Served	Approximate Length (Miles)		Approximate Number of Receipt Points(1)		Approximate Acreage Dedication (Acres)		Average Remaining Term of MVC/MRC (Years)		Average Daily Throughput (MMcf/d) (2)		Daily Throughput Capacity (MMcf/d)
Holly	Haynesville/ Bossier/Cotton Valley		335		716		69,000		4.2		625		2,100
Center	Haynesville/ Bossier/Cotton Valley		372		144		370,000		5.2		132		900
Legacy	Cotton Valley/ Haynesville/ Travis Peak		658		518		100,000		—		234		500

(1)

(2)

The EXCO and BG contracts include an aggregate minimum volume commitment of 600,000 MMbtu/d (584 MMcf/d) for the Holly and Center system. EXCO and BG have the right to ship any or all of this commitment on either or both of these systems in accordance with the contracts. Please read “—Gas Gathering Agreements.”

Holly System

The Holly system is primarily located within the DeSoto, Red River and Caddo parishes of North Louisiana and currently serves the Haynesville and Bossier shale formations and the liquids-rich Cotton Valley formation. We believe this area is the “core of the core” of the Haynesville shale because of the quality of the geology and the high production profile of the wells drilled to date, with EUR approaching ten billion cubic feet per well, as estimated by Wood Mackenzie. During the first ten months of 2014, 344 drilling permits were issued in the area. As of September 30, 2014, the Holly system consisted of approximately 335 miles of high- and low-pressure pipeline serving approximately 69,000 dedicated gross acres, with a throughput of approximately 625 MMcf/d. All of the high pressure pipeline is less than five years old, reducing required maintenance capital expenditures in the near term. The system also includes four amine treating plants with combined capacity of 920 MMcf/d and two 1,340 horsepower compressors.

Customers and Contracts. The Holly system has life of lease acreage dedications with BG and EXCO, including a minimum volume commitment from BG and EXCO through December 2018. The Holly system also has additional long term primary producer contracts with Chesapeake Energy Corporation, Encana Corporation and EP Energy Corporation with a weighted average remaining term of five years. For the nine months ended September 30, 2014, natural gas gathered from BG and EXCO represented approximately 95% of the throughput on the Holly system, with third-party operated gas representing the remaining 5%. Approximately 99% of BG and EXCO’s acreage is held by production, which supports continual production.

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Delivery Points and Utilization. As of September 30, 2014, the Holly system connected to eight downstream access points, providing shippers with access to over 3,030 MMcf/d of off-take capacity. As of September 30, 2014, the utilization for the treating plants was approximately 50%, while pipeline capacity utilization on the Holly system was approximately 14%.

Center System

The Center system is primarily located within the San Augustine, Nacogdoches, Sabine, Panola and Shelby counties in East Texas and currently serves multiple formations, including the Haynesville, Bossier and the liquids-rich James-Lime formation. During the first ten months of 2014, 149 drilling permits were issued in the area. As of September 30, 2014, the system consisted of approximately 372 miles of high pressure pipeline serving approximately 370,000 dedicated gross acres, with a throughput of 132 MMcf/d. The Center system is designed to efficiently access large acreage positions held by major producers within the East Texas region. There are over 20 producers contracted on the Center system, with estimated ultimate recovery potential from five to twelve billion cubic feet per well, as estimated by Wood Mackenzie. The Center system covers a wide range of undedicated and undeveloped acreage and the system’s capacity is able to support incremental growth without deploying large amounts of additional capital. Approximately 98% of the natural gas transported on this system requires treating for CO2, which we treat for an additional fee. As of September 30, 2014, the system included six amine treating plants with combined capacity of 952 MMcf/d, two 1,340 horsepower compressors and access to five major interconnect access points that offer our customers superior deliverability.

Customers and Contracts. Similar to our Holly system, the Center system has life of lease acreage dedications with BG and EXCO, including a minimum volume commitment from BG and EXCO through December 2018. In addition, our contract with another producer includes an annual and cumulative minimum revenue commitment with respect to volumes gathered by the Center system for an initial term of ten years expiring in 2020. Other major producers contracted on the Center system include Chesapeake Energy Corporation, Newfield Exploration Company, Devon Energy Corporation, Goodrich Petroleum Corp., Samson Resources Corporation and SM Energy Company. Our contracts with these other major producers have a weighted average remaining term of seven years.

Delivery Points and Utilization. As of September 30, 2014, the Center system connected to eight downstream access points, providing shippers with access to almost 1,940 MMcf/d of off-take capacity. For the nine months ended September 30, 2014, the utilization for the treating plants was approximately 15%, while pipeline capacity utilization on the Center system was approximately 7%.

Fairway Processing Plant. The Center system includes the new Fairway processing plant with a processing capacity of 10 MMcf/d, which is designed to extract NGL content from natural gas ranging between 2.7 and 6.4 GPM, from the James Lime formation for liquids processing. Portions of the James Lime formation in the Haynesville Shale area in East Texas has rich associated natural gas that requires processing to remove the heavy end of the produced gas stream. Volume growth for the central portion of our gathering system, where many of our customers are actively drilling, has resulted in the need for additional gas gathering infrastructure in the area.

The Fairway plant had an in-service date of March 17, 2014 and recovers natural gas liquids from natural gas produced from the James Lime formation and returns the dry residue natural gas into the Center system for delivery into our interconnections with Gulf South’s 42-inch pipeline, CenterPoint Energy Gas Transmission’s 42-inch Line near Carthage, Gulf South’s 30-inch pipeline at Milam, and our interconnection with the facilities of Natural Gas Pipeline Company of America in Nacogdoches County, Texas. NGLs recovered by the Fairway plant are trucked to fractionation facilities located in East Texas, South Louisiana, or Mont Belvieu, Texas, for separation into purity products.

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Legacy System

The Legacy system is primarily located within Harrison, Panola and Rusk counties in Texas and Caddo parish in Louisiana and currently serves the Cotton Valley formation, the Haynesville shale formation and the shallower producing sands in the Travis Peak formation. The Cotton Valley formation has historically been a natural gas play, although improvements in technology have increased production of oil and NGLs in the area. The Cotton Valley formation is productive when accessed through horizontal drilling and fracture stimulation technologies. We believe these qualities, when combined with the liquids-rich nature of the natural gas, concentrated oil content, high initial rates of production and competitive well costs, make the formation attractive for producers in the area. During the first ten months of 2014, 431 drilling permits were issued in the area. As of September 30, 2014, the Legacy system consisted of approximately 658 miles of high- and low-pressure gathering lines and served approximately 100,000 dedicated acres, with a throughput of 234 MMcf/d and access to seven major downstream markets, which we believe provides superior delivery capability compared to our competitors. As of September 30, 2014, the Legacy system had ten 1,340 horsepower compressors and two additional compressors comprising 870 horsepower, for a total of 14,270 horsepower of compression. Our Legacy system gathers high-Btu natural gas with an NGL content between 2.0 and 5.2 GPM.

Customers and Contracts. Our major customers contracted on the Legacy system are BG, BP plc, Devon Energy Corporation, Endeavor Energy Resources, L.P., EXCO, Sabine Oil & Gas LLC and Samson Resources Corporation. These contracts have a remaining life varying from one year to life of lease.

Delivery Points. The Legacy system has access to seven major downstream markets and four third-party processing plants, including the Carthage Hub, providing shippers with access to 693 MMcf/d of processing capacity. In addition, the Legacy system affords multiple opportunities to access high-NGL content horizontal gas from Cotton Valley, where we believe future production is likely to outpace existing processing capacity.

Gas Gathering Agreements

We derive revenue primarily from long-term, fee-based gas gathering agreements (“GGAs”) with some of the largest and most active producers in our areas of operation. The following describes the material provisions included in certain of our significant gas gathering agreements, including our natural gas gathering agreement with BG and EXCO and our minimum revenue commitment gas gathering agreement.

BG and EXCO Minimum Volume Commitment

We have entered into gas gathering agreements with BG and EXCO (collectively, the “BG/EXCO GGA”) pursuant to which BG and EXCO have jointly agreed to a minimum volume commitment (“MVC”) with respect to their collective production gathered by our Holly and Center systems, the material terms of which are discussed below. The minimum volume of natural gas required to be delivered to these systems is calculated on an annual basis based upon the daily average of such volumes delivered during the applicable contract year. While the MVC feature of the contract is set to terminate on December 1, 2018, the BG/EXCO GGA is a life of lease contract. Accordingly, BG and EXCO will not be obligated to deliver a minimum volume of natural gas from their production gathered by our Holly and Center systems after such date, although the production from BG and EXCO’s dedicated acreage in these fields will still be required to be delivered to our gathering systems.

The collective MVC is 600,000 MMbtu/d (584 MMcf/d) and the BG/EXCO GGA includes the following provisions:

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Under certain circumstances, some or all of these provisions can apply in combination with one another. For instance, if BG and EXCO were to ship a significantly larger volume of gas during any contract year, the MVC in the following year could be significantly reduced. If volumes delivered during this subsequent year are not in excess of this reduced MVC, we could receive a significantly reduced amount of revenues or cash flows from BG and/or EXCO in a given period, which would have a material adverse effect on our results of operations, financial condition and cash flows and our ability to make distributions to our unitholders. Additionally, the MVC is subject to suspension in the event of a force majeure or a breach by us of the BG/EXCO GGA.

Minimum Revenue Commitment

We have also entered into a gas gathering agreement with a customer on our Center system that includes an annual minimum revenue commitment and a cumulative minimum revenue commitment (collectively, the “MRC”) through 2020. Pursuant to the terms of the contract, the MRC is calculated on an annual and cumulative basis based on volumes of gas transported at agreed upon rates, subject to certain adjustments. The contract has a ten-year term expiring December 31, 2020, and continues year-to-year thereafter. Volumes supplied by the customer are currently less than the annual MRC requirement, and we are therefore entitled to a deficiency payment. As a result, the customer’s deficiency payments may be credited against future volumes supplied by the customer in excess of the annual MRC. We record the deficiency payments received as deferred revenue because the customer is entitled to utilize the deficiency payment to offset future volumes supplied in excess of the annual MRC over the term of the contract. We recognize the deferred revenue under this arrangement in revenue once all contingencies or potential performance obligations associated with the related deficiency volumes have either (i) been satisfied through the gathering of future excess volumes or (ii) expired (or lapsed) through the passage of time.

Our Sponsors

Competition

The natural gas gathering, compression, treating and processing businesses are highly competitive, and we face strong competition in acquiring new natural gas supplies. Our competition in obtaining additional natural gas supplies include interstate and intrastate pipelines and other midstream companies that gather, compress, process and market natural gas in the vicinity of our facilities. The ability to secure the dedication of natural gas supplies is primarily based on the reputation, efficiency, flexibility and reliability of the processor and the pricing of services. When commodity prices are high, producers generally desire to retain the full benefits of such increased commodity prices. Accordingly, in a high NGL pricing environment, fee-based arrangements are preferred by most producers. The primary competitors of our Holly system are Access Midstream Partners, L.P., Enable Midstream Partners, L.P. and Kinder Morgan Energy Partners, L.P. The primary competitors of our Center system are Midcoast Energy Partners, L.P. and Energy Transfer Partners, L.P. The primary competitors of our Legacy system are DCP Midstream Partners, L.P., MarkWest Energy Partners, L.P., Enable Midstream Partners, L.P., Enbridge Energy Partners, L.P. and Marlin Midstream Partners, L.P.

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We believe the primary advantages of our assets are their proximity to established and/or new production, the service flexibility they provide to producers and the operating efficiency and cost savings associated with our midstream assets. We believe that we can provide the services that producers and other customers require to connect, gather and process their natural gas efficiently, at competitive and flexible contract terms. Our ability to tailor processing agreements to meet the specific needs of our customers, our ability to offer lower-priced services due to our relatively lower capital investments as compared to the rest of the industry and higher recovery efficiencies and lower fuel consumption at our facilities factor positively in our ability to compete in the markets we serve.

Seasonality

Demand for natural gas generally decreases during the spring and fall months and increases during the summer and winter months. However, seasonal anomalies such as mild winters or mild summers sometimes lessen this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations. These seasonal anomalies can increase demand for natural gas during the summer and winter months and decrease demand for natural gas during the spring and fall months. We do not expect seasonal conditions to have a material impact on our throughput volumes.

Insurance

We maintain insurance policies with insurers in amounts and with coverage and deductibles that we, with the advice of our insurance advisors and brokers, believe are reasonable and prudent. We cannot, however, provide assurance that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices.

Safety and Maintenance Regulation

Our pipelines are subject to regulation by the Pipeline and Hazardous Materials Safety Administration, or PHMSA, of the Department of Transportation, or DOT, under the Natural Gas Pipeline Safety Act of 1968, or NGPSA. The NGPSA has been amended from time to time, including by the Pipeline Safety Improvement Act of 2002, or PSI Act, and the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, or the PIPES Act. Pursuant to these acts, PHMSA has promulgated regulations governing pipeline wall thickness, design pressures, maximum operating pressures, pipeline patrols and leak surveys, minimum depth requirements, and emergency procedures, as well as other matters intended to ensure adequate protection for the public and to prevent accidents and failures. We believe that our pipeline operations are in substantial compliance with applicable NGPSA requirements; however, due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, future compliance with the NGPSA could result in increased costs.

Additionally, PHMSA has established a series of rules requiring pipeline operators to develop and implement integrity management programs for gas transmission pipelines that, in the event of a pipeline leak or rupture, could affect high consequence areas, or HCAs, where a release could have the most significant adverse consequences, including high population areas, certain drinking water sources and ecological areas that are unusually sensitive to environmental damage from a pipeline release. The PHMSA has developed regulations that require 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:

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perform ongoing assessments of pipeline integrity;

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identify and characterize applicable threats to pipeline segments that could impact a HCA;

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improve data collection, integration and analysis;

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repair and remediate pipelines as necessary; and

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implement preventive and mitigating actions.

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Although many of our pipeline facilities fall within a class that is currently not subject to these requirements, it may incur significant costs and liabilities associated with repair, remediation, preventative or mitigation measures associated with its non-exempt pipelines. Such costs and liabilities might relate to repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, as well as lost cash flows resulting from shutting down our pipelines during the prudency of such repairs. Additionally, should we fail to comply with PHMSA or comparable state regulations, we could be subject to penalties and fines. If future PHMSA pipeline integrity management regulations were to require that we expand our integrity managements program to currently unregulated pipelines, including gathering lines, costs associated with compliance may have a material effect on our operations.

Most recently, these pipeline safety laws were amended in January 2012, when President Obama signed the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011, or the 2011 Pipeline Safety Act, which 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. Among other things, the 2011 Pipeline Safety Act directed 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, pipeline material strength testing, and verification of the maximum allowable pressure of certain pipelines. The 2011 Pipeline Safety Act also increases the maximum penalty for violation of pipeline safety regulations from $100,000 to $200,000 per violation per day of violation and from $1.0 million to $2.0 million for a related series of violations. In addition, the PHMSA recently 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. The PHMSA has also published advanced notice of proposed rulemakings to solicit comments on the need for changes to its natural gas and liquid pipeline safety regulations, including gathering lines, and also recently published an advisory bulletin providing guidance on verification of records related to pipeline maximum allowable operating pressure. We have completed the verification process and, in some cases, performed hydrostatic tests on pipelines to confirm and document the maximum allowable operating pressures. The safety enhancement requirements and other provisions of the 2011 Pipeline Safety Act as well as any implementation of PHMSA rules thereunder, or otherwise, could require us to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could be significant and have a material adverse effect on our results of operations or financial position.

The National Transportation Safety Board has recommended that the PHMSA make a number of changes to its rules, including removing an exemption from most safety inspections for natural gas pipelines installed before 1970. 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 by extending more stringent and comprehensive safety regulations (such as integrity management requirements) to pipelines and gathering lines not previously subjected to these requirements. While we expect any legislative or regulatory changes to allow us time to become compliant with new requirements, costs associated with compliance may have a material effect on our operations.

States are largely preempted by federal law from regulating pipeline safety but may assume responsibility for enforcement of federal intrastate pipeline regulations and inspection of intrastate pipelines. States may adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines; however, states vary considerably in their authority and capacity to address pipeline safety. State standards may include requirements for facility design and management in addition to requirements for pipelines. We do not anticipate any significant problems in complying with state laws and regulations applicable to our operations. Our natural gas pipelines have continuous inspection and compliance programs designed to maintain compliance with federal and state pipeline maintenance, safety and pollution control requirements.

We may be subject to the Chemical Facility Anti-Terrorism Standards Act, or the CFATS, which is administered by the U.S. Department of Homeland Security, or DHS. The CFATS requires that certain facilities

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register with the DHS to determine if their facilities are exempt from regulation or if they present a high level of security risk. A facility determined to have a high level of security risk will be placed by the DHS into a tier level based on a risk-based tier system. All facilities placed into a tier will be required to provide additional information to help determine final security measures. Covered facilities that are determined by DHS to pose a high level of security risk will be 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. We have complied with the requirements of CFATS by registering certain of our facilities with the DHS.

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 are currently implementing our own cyber-security programs and protocols; however, we cannot guarantee their effectiveness. A significant cyber-attack could have a material effect on operations and those of our customers.

In addition, we are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, referred to as OSHA, and comparable state statutes, whose purpose is to protect the health and safety of workers, both generally and within the pipeline industry. The applicable laws and regulations include the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act, the EPA Accidental Release Prevention regulations under the Clean Air Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations, that this information be provided to employees, state and local government authorities and citizens and that we prepare a risk management plan which is submitted to the EPA. 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 specified thresholds, or any process which involves 10,000 pounds or more of a flammable liquid or gas in one location. Flammable liquids stored in atmospheric tanks below their normal boiling point without the benefit of chilling or refrigeration are exempt. We have an internal program of inspection designed to monitor and enforce compliance with worker safety requirements. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety. However, compliance with these laws and regulations requires facilities to be shut down for internal inspections, which can have a significant impact on processing unit availability.

Regulation of Operations

Regulation of pipeline gathering and transportation services, natural gas sales and transportation of NGLs may affect certain aspects of our business and the market for its products and services.

Gathering Pipeline Regulation. Section 1(b) of the Natural Gas Act of 1938, or NGA, exempts natural gas gathering facilities from regulation by FERC under the NGA. In a declaratory order dated May 4, 2007, FERC declared our subsidiary, TGG Pipeline, Ltd., to be gathering and therefore it is not subject to FERC regulation. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish whether a pipeline is a gathering pipeline 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 some of our natural gas gathering facilities and intrastate transportation pipelines may be subject to change based on future determinations by FERC, the courts, or Congress. If FERC were to consider the status of an individual facility and determine that the facility 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

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regulation by FERC under the NGA or the Natural Gas Policy Act of 1978, or NGPA. Such regulation could decrease or increase revenue, increase or decrease operating costs, and, depending upon the facility in question, could adversely or positively affect our results of operations and cash flows. In addition, if any of our other 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 FERC.

State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. Our natural gas gathering operations are subject to ratable take and common purchaser statutes in the states in which we operate. These statutes generally require our gathering pipelines to take natural gas without undue discrimination in favor of one producer over another producer or one source of supply over another similarly situated source of supply. The regulations under these statutes can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. States in which we operate have adopted a complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to gathering access and rate discrimination. We cannot predict whether such a complaint will be filed against us in the future. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal remedies. To date, there has been no adverse effect to our system due to these regulations.

Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels. Our gathering operations could be adversely affected should they be subject in the future to more stringent application of state or federal regulation of rates and services. Our gathering operations also may be or become subject to additional safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management 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 our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Intrastate Natural Gas Pipeline Regulation. We are subject to rate regulation under the Texas Utilities Code, as implemented by the Texas Railroad Commission, or the TRRC, and we have tariffs on file with the TRRC. Generally, the TRRC is vested with the authority to ensure that rates, operations and services of natural gas utilities, including intrastate pipelines and gatherers who have exercised eminent domain authority under the Texas Utilities Code, are just and reasonable, and not discriminatory. The rates we charge for intrastate services are deemed just and reasonable under Texas law unless challenged in a complaint. We cannot predict whether such a complaint will be filed against us or whether the TRRC will change its regulation of these rates. Failure to comply with the Texas Utilities Code can result in the imposition of administrative, civil and criminal remedies. To date, there has been no adverse effect to our system due to this regulation.

The TRRC’s current code of conduct applies the common purchaser act to gathering and transportation activities. The common purchaser statutes generally require pipelines to purchase or take 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. The regulations under these statutes can have the effect of imposing some restrictions on our ability as an owner of pipeline facilities to decide with whom we contract to purchase natural gas. Texas has adopted a complaint-based regulation of natural gas purchasing, gathering and transportation activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas purchases, gathering and transportation access, and rate discrimination.

In Texas, natural gas gathering and transmission pipelines are subject to laws regarding rates, competition and confidentiality (“Competition Statute”) and are subject to complaint procedures for challenging determinations of lost and unaccounted for gas by gas gatherers, processors and transporters (“LUG Statute”). The Competition Statute allows the TRRC the ability to use either a cost-of-service method or a market-based

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method for setting rates for natural gas gathering and/or transmission in formal rate proceedings. It also gives the TRRC specific authority to enforce its statutory duty to prevent discrimination in natural gas gathering and transportation, to enforce the requirement that parties participate in an informal complaint process, and to punish purchaser, transporters, and gatherers for taking discriminatory actions against shippers and sellers. The LUG Statute modifies the informal complaint process at the TRRC with procedures unique to lost and unaccounted for gas issues. We cannot predict what effect, if any, these statutes might have on our operations, but they have had no adverse effect since they were enacted in 2007.

Natural Gas Storage Regulation. Saltwater disposal wells within our Legacy system are under the jurisdiction of the TRRC. Regulatory requirements for these wells involve monthly and annual reporting of the natural gas and water disposal volumes associated with the operation of these wells, respectively. Results of periodic mechanical integrity tests run on these wells must also be reported to the TRRC. We believe that we are in material compliance with all applicable rules and regulations related to these wells.

Environmental Matters

General. Our natural gas gathering, processing, transportation and fractionation activities are subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to the protection of the environment. As an owner or operator of these facilities, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:

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requiring the acquisition of permits to conduct regulated activities;

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requiring the installation of pollution-control equipment, imposing emission or discharge limits or otherwise restricting the way we operate, resulting in additional costs to our operations;

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limiting or prohibiting construction activities in areas, such as air quality nonattainment areas, wetlands, coastal regions or areas inhabited by endangered or threatened species;

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delaying system modification or upgrades during review of permit applications and revisions;

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requiring investigatory and remedial actions to mitigate discharges, releases or pollution conditions associated with our operations or attributable to former operations; and

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enjoining the operations of facilities deemed to be in non-compliance with permits issued pursuant to or regulatory requirements imposed by such environmental laws and regulations.

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties and natural resource damages. Certain environmental statutes impose strict joint and several liability for costs required to clean up and restore sites where hazardous substances, petroleum hydrocarbons or wastes have been disposed or otherwise released. Moreover, neighboring landowners and other third parties may file common law claims for personal injury and property damage allegedly caused by the release of hazardous substances, petroleum hydrocarbons or wastes into the environment.

The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment and thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation and actual future expenditures may be different from the amounts we currently anticipate. As with the midstream industry in general, complying with current and anticipated environmental laws and regulations can increase our capital costs to construct, maintain and operate equipment and facilities. While these existing laws and regulations affect our maintenance capital expenditures and net income, we do not believe they will have a material adverse effect on our business, financial position or results of operations or cash flows, nor do we believe that they will affect our competitive position since the operations of our competitors are generally similarly affected. In addition, we believe that the various environmental activities in which we are presently engaged are not expected to materially interrupt or diminish our operational ability to

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gather natural gas. We cannot, however, provide assurance that future events, such as changes in existing laws or enforcement policies, the promulgation of new laws or regulations, or the development or discovery of new facts or conditions will not cause us to incur significant costs.

Below is a discussion of the more significant environmental laws and regulations, as amended from time to time, that relate to our business. We believe that we are in substantial compliance with these environmental laws and regulations.

Hazardous Waste Management. Our operations generate solid wastes, including some hazardous wastes, that are subject to the federal Resource Conservation and Recovery Act, or RCRA, and comparable state laws, which impose requirements for solid waste, including stringent standards 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. Specifically, RCRA excludes from regulation hazardous waste, certain produced waters and other wastes intrinsically associated with the exploration, development, or production of crude oil and natural gas. However, these oil and gas exploration and production wastes may still be regulated under state solid waste laws and regulations that are generally less stringent than the requirements imposed under the RCRA. However, common industrial wastes such as paint wastes, waste solvents, laboratory wastes, and waste compressor oils may be regulated as special or hazardous waste. The transportation of natural gas and NGLs in pipelines may also generate some hazardous wastes subject to RCRA or comparable state law requirements.

Site Remediation. The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the Superfund law, and comparable state laws impose liability without regard to fault or the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. Such classes of persons include the current and past owners or operators of sites where a hazardous substance was released, and companies that transported or disposed or arranged for transportation or disposal of hazardous substances at offsite locations, such as landfills. Although crude oil and natural gas are excluded from CERCLA’s regulation as a “hazardous substance,” in the course of our ordinary operations, we generate wastes that may be designated as hazardous substances. CERCLA authorizes the U.S. Environmental Protection Agency, or EPA, states, and in some cases, third parties to take actions in response to releases or threatened releases of hazardous substances into the environment and to seek to recover from the classes of responsible persons the costs they incur. Under CERCLA, we could be subject to strict joint and several liability for the costs of cleaning up and restoring sites where hazardous substances have been released into the environment and for damages to natural resources.

We currently own or lease, and may have in the past owned or leased, properties that for many years have been used for the measurement, gathering, compression, treating and processing of natural gas. Although we typically used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes may have been disposed of or released on or under the properties we owned or leased or on or under other locations where such substances have been taken for reclamation or disposal. Such petroleum hydrocarbons or wastes may have migrated to property adjacent to our owned and leased sites or the disposal sites. In addition, some of the properties may have been operated by third parties or by previous owners whose treatment and disposal or release of petroleum hydrocarbons or wastes was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed wastes, including waste disposed of by prior owners or operators; remediate contaminated property, including groundwater contamination, whether from prior owners or operators or other historic activities or spills; or perform remedial operations to prevent future contamination. We are not currently a potentially responsible party in any federal or state Superfund site remediation and there are no current, pending or anticipated Superfund response or remedial activities at or implicating our facilities or operations.

Air Emissions. The Clean Air Act, and comparable state laws, regulate emissions of air pollutants from various industrial sources, including natural gas processing plants and compressor stations, and also impose

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various emission limits, operational limits and monitoring, reporting and record keeping requirements on air emission sources. Failure to comply with these requirements could result in monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. Such laws and regulations require pre- construction permits for the construction or modification of certain projects or facilities with the potential to emit air emissions above certain thresholds. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining permits and approvals for air emissions. For example, in August 2012, the EPA published final rules establishing new air emission control requirements for natural gas and natural gas liquid production, processing, storage and transportation activities, including New Source Performance Standards, or NSPS, to address emissions of sulfur dioxide and volatile organic compounds, and a separate set of emission standards, referred to as National Emission Standards for Hazardous Air Pollutants, or NESHAP, to address hazardous air pollutants frequently associated with production and processing activities. In addition, these rules establish emission standards for certain wet seal and reciprocating compressors, pneumatic controllers and storage vessels. Compliance with these requirements may require modifications to certain of our operations, including the installation of new equipment to control emissions from our processing facilities, which could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.

Water Discharges. The Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and hazardous substances, into waters of the United States. The discharge of pollutants into jurisdictional waters is prohibited, except in accordance with the terms of a permit issued by the EPA or a delegated state agency. Spill prevention, control and countermeasure requirements under federal laws require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarbon spill, rupture or leak. In addition, the 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. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance including spills and other non-authorized discharges.

Endangered Species. The Endangered Species Act, or ESA, restricts activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. While some of our processing facilities and pipelines are located in areas that are or may be designated as habitats for endangered or threatened species, we believe that we are in substantial compliance with the ESA. If endangered species are located in areas of the underlying properties where we wish to conduct growth activities, such work could be prohibited or delayed or expensive mitigation may be required. 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, or FWS, is required to make a determination on listing of numerous species as endangered or threatened under the ESA before the completion of the agency’s 2017 fiscal year. The designation of previously unidentified endangered or threatened species could cause us to incur additional costs from species protection measures or become subject to delays or limits on future development activity in the affected areas. Moreover, such designations in areas where our natural gas exploration and production customers operate could cause our customers to incur increased costs arising from species protection measures and could result in delays or limitations in our customers’ performance of operations, which could reduce demand for our midstream services.

Climate Change. In December 2009, the EPA determined that emissions of greenhouse gases, or GHGs, present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. Based on these findings, EPA has adopted regulations under existing provisions of the federal Clean Air Act, that, among other things, establish construction and operating permit for GHG emissions from certain large stationary sources that are potential major sources of certain principal, or criteria, pollutant emissions. Under these regulations, facilities required to obtain permits for their GHG emissions will be required to meet “best available control technology” standards for their GHG emissions established by the states or, in some cases, by the EPA on a case-by-case

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basis. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain all permits for new or modified sources that exceed GHG emission thresholds. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States, including, among others, certain onshore oil and natural gas processing and fractionating facilities. We are monitoring GHG emissions from certain of our facilities as required by the GHG emissions reporting rule. While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce emissions of GHGs in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations that limit emissions of GHGs could adversely affect demand for the oil and natural gas that exploration and production operators produce, some of whom are our customers, which could thereby reduce demand for our midstream services. Finally, it should be noted that 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, droughts and floods and other climatic events; if any such effects were to occur, it is uncertain if they would have an adverse effect on our financial condition and operations.

Title to Properties and Rights of Way

As of September 30, 2014, approximately 12% of our real property is land we own in fee, while in the remaining 88%, our interest is derived from easements, rights-of-way, leases, permits or licenses from land owners or governmental authorities permitting the use of the real property for our operations. The surface of the land on which our processing facilities and many of our compressors and other facilities are located is owned in fee title, and we believe that we have satisfactory title to such land. We have no knowledge of any challenge to the underlying title of any material easement, right-of-way, lease, permit or license held by us or to our title to any material easement, right-of-way, permit or lease, and we believe that we have satisfactory title to all of our material easements, rights-of-way, permits and licenses.

Some of the easements, rights-of-way, permits and licenses to be transferred to us may require the consent of the grantor of such rights, which in certain instances is a governmental entity. Our general partner expects to obtain, prior to the closing of this offering, sufficient third-party consents, permits and authorizations for the transfer of the assets necessary to enable us to operate our business in all material respects as described in this prospectus. With respect to any material consents, permits or authorizations that have not been obtained prior to closing of this offering, the closing of this offering will not occur unless reasonable bases exist that permit our general partner to conclude that such consents, permits or authorizations will be obtained within a reasonable period following the closing, or the failure to obtain such consents, permits or authorizations will have no material adverse effect on the operation of our business.

Employees

We are managed and operated by the board of directors and executive officers of our general partner. We do not have any employees. As of September 1, 2014, Azure Midstream Holdings and its subsidiaries employed approximately 117 people who will provide direct, full-time support to our operations. All of the employees required to conduct and support our operations will be employed by Azure Midstream Holdings and its subsidiaries and all of our direct, full-time personnel are subject to the omnibus agreement between our general partner and Azure Midstream Holdings. None of these employees are covered by collective bargaining agreements, and Azure Midstream Holdings considers its employee relations to be good.

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Legal Proceedings

Our operations are subject to a variety of risks and disputes normally incident to its business. As a result, we are and may, at any given time, be a defendant in various legal proceedings and litigation arising in the ordinary course of business. However, the assets that will be contributed to Azure Midstream Operating are not currently subject to any material litigation.

With respect to Azure Midstream Operating’s properties, we maintain insurance policies with insurers in amounts and with coverage and deductibles that we, with the advice of our insurance advisors and brokers, believe are reasonable and prudent. We cannot, however, provide assurance that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices.

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MANAGEMENT

Management of Azure Midstream Partners, LP

We are managed by the directors and executive officers of our general partner, Azure Midstream Partners GP, LLC. Our general partner is not elected by our unitholders and will not be subject to re-election by our unitholders in the future. Azure Midstream Holdings owns all of the membership interests in our general partner and has the right to appoint the entire board of directors of our general partner, including our independent directors. Our unitholders are not entitled to elect the directors of our general partner’s board of directors or to directly or indirectly participate in our management or operations. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, we intend to incur indebtedness that is nonrecourse to our general partner.

At the completion of this offering, we expect that our general partner will have seven directors, including two director nominees who will become members of our board of directors prior to or in connection with the listing of our common units on the NYSE. In accordance with the NYSE’s phase-in rules, we will have at least three independent directors within one year following the effective date of the registration statement of which this prospectus forms a part. We expect that our board will determine that each of Messrs. Fuller and , our director nominees who will become members of our board of directors prior to or in connection with the listing of our common units on the NYSE, is independent under the independence standards of the NYSE.

In evaluating director candidates, Azure Midstream Holdings will assess whether a candidate possesses the integrity, judgment, knowledge, experience, skill and expertise that are likely to enhance the ability of our board of directors to manage and direct our affairs and business, including, when applicable, to enhance the ability of committees of the board of directors of our general partner to fulfill their duties.

Neither we nor our subsidiaries have any employees. Our general partner has the sole responsibility for providing the employees and other personnel necessary to conduct our operations. All of the employees that conduct our business are employed by our general partner or its affiliates, but we sometimes refer to these individuals in this prospectus as our employees.

Director Independence

As a publicly traded partnership, we qualify for, and are relying on, certain exemptions from the NYSE’s corporate governance requirements, including:

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the requirement that a majority of the board of directors of our general partner consist of independent directors;

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the requirement that the board of directors of our general partner have a nominating/corporate governance committee that is composed entirely of independent directors; and

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the requirement that the board of directors of our general partner have a compensation committee that is composed entirely of independent directors.

As a result of these exemptions, we do not expect that our general partner’s board of directors will be comprised of a majority of independent directors. Our board of directors does not currently intend to establish a nominating/corporate governance committee or a compensation committee. Accordingly, unitholders will not have the same protections afforded to equityholders of companies that are subject to all of the corporate governance requirements of the NYSE.

We are, however, required to have an audit committee of at least three members, and all of its members are required to meet the independence and experience standards established by the NYSE and the Exchange Act, subject to certain transitional relief during the one-year period following the effective date of the registration statement of which this prospectus forms a part. In accordance with the NYSE’s corporate governance standards,

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we must have at least one independent member on our audit committee who satisfies the independence and experience requirements by the date our common units are listed on the NYSE, at least a majority of independent members within 90 days of the effective date of the registration statement of which this prospectus forms a part and a fully independent audit committee within one year of such effective date.

Committees of the Board of Directors

The board of directors of our general partner will have an audit committee, and may have such other committees as the board of directors shall determine from time to time. Each of the standing committees of the board of directors will have the composition and responsibilities described below.

Audit Committee

At least three independent members of the board of directors of our general partner will serve as our audit committee. Our general partner initially may rely on the phase-in rules of the SEC and the NYSE with respect to the independence of our audit committee. Those rules permit our general partner to have an audit committee that has one independent member by the date our common units are first listed on the NYSE, a majority of independent members within 90 days thereafter and all independent members within one year thereafter. Our audit committee will assist the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. Our audit committee will have the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. Our audit committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to our audit committee.

Directors and Executive Officers of Azure Midstream Partners GP, LLC

Directors are appointed by Azure Midstream Holdings, the sole member of our general partner, and hold office until their successors have been appointed or qualified or until their earlier death, resignation, removal or disqualification. Executive officers are appointed by, and serve at the discretion of, the board of directors. The following table presents information for the directors, director nominees and executive officers of Azure Midstream Partners GP, LLC as of October 1, 2014.


Name	Age	Position with Azure Midstream Partners GP, LLC
I.J. “Chip” Berthelot, II	55	President; Director
Eric T. Kalamaras	41	Chief Financial Officer
John E. O’Shea, Jr.	52	Director
Paul G. Smith	56	Director
Thomas O. Whitener, Jr.	67	Director
James P. Benson	54	Director
Thomas R. Fuller	66	Director Nominee

I.J. (“Chip”) Berthelot has been the President and a director of our general partner since September 2014. Mr. Berthelot has been the President of Azure Midstream Holdings LLC since July 2014. Mr. Berthelot previously founded Laser Northeast Gathering Company (Laser II) in January 2009, which developed a 1.4 Bcf/d gathering system in northeastern Pennsylvania. Laser II was sold to Delphi Midstream Partners in 2010, where Mr. Berthelot remained as president prior to its sale to Williams Partners, L.P. (NYSE: WPZ) in March 2012. Prior to Laser II, Mr. Berthelot founded Laser Midstream Company LLC (Laser I) in 2005, which focused on natural gas gathering and processing in Texas and Louisiana and was subsequently sold to Eagle Rock Energy Partners, L.P. (NASDAQ: EROC) in 2007. Prior to Laser I, Mr. Berthelot was the president of Loco Energy Company, a privately owned midstream company engaged in natural gas gathering in Texas, from 2002 to 2004. Prior to Loco Energy Company, Mr. Berthelot served as Chief Operating Officer, Executive Vice President and a member of the Board of Directors

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at the gathering and processing business MidCoast Energy Resources, Inc., which was sold to Enbridge Energy Partners, L.P. (NYSE: EEP) in 2001. Mr. Berthelot has a B.S. in Natural Gas Engineering from Texas A&I University and is a registered Professional Engineer in the State of Texas. We believe that Mr. Berthelot’s role as President of our general partner as well as his executive experience and knowledge of the gathering industry bring important and necessary skills to the board of directors.

Eric T. Kalamaras has been the Chief Financial Officer of our general partner since September 2014. Mr. Kalamaras has been Chief Financial Officer of Azure Midstream Holdings LLC since July 2014. Mr. Kalamaras previously served as Senior Vice President and Chief Financial Officer for Valerus Energy Holdings, L.P., a multi-billion dollar field service company from 2012 to 2013. Prior to January 2012, Mr. Kalamaras served as Executive Vice President and Chief Financial Officer for Delphi Midstream Partners beginning in 2011 until it was sold to Williams Partners, L.P. (NYSE: WPZ) in March 2012. Mr. Kalamaras served as Executive Vice President and Chief Financial Officer of Atlas Pipeline Partners, L.P. (NYSE: APL) from 2009 to 2011. Mr. Kalamaras’ prior experience includes working in the energy investment banking groups of Wells Fargo Investment Bank and Bank of America Investment Bank with extensive transaction and capital raising experience primarily focused on master limited partnerships. Mr. Kalamaras has a B.B.A. from Central Michigan University and a M.B.A. from Wake Forest University. He currently serves on the Advisory Board of the Children’s Museum of Houston.

John E. O’Shea, Jr. is a managing director of Tenaska Capital Management and has been a director of our general partner since September 2014. Mr. O’Shea has 30 years of experience developing, acquiring and operating growth businesses in the oil and natural gas midstream sectors. Mr. O’Shea leads Tenaska Capital Management’s midstream team, where he is responsible for the origination of midstream investments and the management and optimization of Tenaska Capital Management’s midstream portfolio assets. Prior to joining Tenaska Capital Management in May 2013, Mr. O’Shea was an advisor and subsequently an operating partner with Denham Capital Management LP from February 2011 to July 2011 and from September 2012 to February 2013, respectively, and served as Chief Executive Officer of Tradition Midstream, LLC, a midstream development company from July 2011 to August 2012. He was also president and co-founder of Millennium Midstream Partners, L.P, which was acquired by Eagle Rock Energy Partners, L.P. (NASDAQ: EROC) in 2008. Mr. O’Shea held several business development, acquisitions and operations positions over 12 years with Dynegy, Inc. in its domestic and international pipeline and processing businesses. Mr. O’Shea has a B.S. in petroleum engineering from Louisiana Tech University and a M.B.A. from the University of Texas. Mr. O’Shea sits on the board of directors of various privately held companies. We believe Mr. O’Shea’s extensive experience in the midstream industry and his role with Tenaska Capital Management bring valuable attributes to the board of directors.

Paul G. Smith is a founding member and senior managing director of Tenaska Capital Management and has been a director of our general partner since September 2014. Mr. Smith is Chairman of the Tenaska Capital Management Investment Committee and is Vice Chairman of Tenaska Energy Inc. Mr. Smith has over 30 years of experience in the energy and power industries, including more than 20 years with Tenaska Energy Inc. His broad experience includes business development, project development, power company management, natural gas production management, marketing company management, commercial contract negotiations, engineering, mergers and acquisitions, corporate strategy, and equity placements. Mr. Smith was previously Tenaska Energy Inc.’s Vice President of Corporate Development. Prior to that, Mr. Smith served as Chief Executive Officer of Tenaska International with responsibility for its international power generation development and operating activities. Mr. Smith also served as Vice President and General Manager of Tenaska Canada, where he was responsible for all of Tenaska Energy Inc.’s business activities in the Canadian energy markets. Mr. Smith has a B.S. in mechanical engineering from Iowa State University and a M.B.A. from the University of Nebraska at Omaha. Mr. Smith sits on the board of directors of various privately held companies. We believe Mr. Smith’s extensive experience in the energy industry and his roles with Tenaska Capital Management bring valuable attributes to the board of directors.

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Thomas O. Whitener, Jr. is President and founding partner of Energy Spectrum Partners and has been a director of our general partner since September 2014. Mr. Whitener leads Energy Spectrum Partners’ midstream private equity business with responsibilities including leading negotiations, structuring and executing investment transactions, actively monitoring existing investments and working closely as a board member with the management teams of portfolio companies. Mr. Whitener has approximately 40 years of experience financing and advising companies and managing private equity investments in the energy industry. Prior to Energy Spectrum Partners, Mr. Whitener served as a Managing Director at R. Reid Investments Inc. and as a Senior Vice President of Dean Witter Reynolds’ Energy Corporate Finance Group. Through these positions, he gained significant experience with mergers and acquisitions, institutional equity and debt placements and energy asset divestitures. Following college, Mr. Whitener served three years as an officer in the U.S. Navy and began his professional career as an energy lender with InterFirst Bank Dallas. Later, as a senior manager, he was responsible for managing and overseeing commitments in excess of $1.5 billion to the upstream, midstream and oil field service sectors of the energy industry. Mr. Whitener has a B.B.A. with highest honors and a M.B.A. from the University of Texas. Mr. Whitener sits on the board of directors of various privately held companies. We believe Mr. Whitener’s extensive experience in the energy industry and his roles with Energy Spectrum Partners bring important skills to the board of directors.

James P. Benson is a founding partner of Energy Spectrum Partners and has been a director of our general partner since September 2014. Mr. Benson has extensive relationships and networks within the energy industry. Historically, Mr. Benson has been instrumental in and responsible for originating many of Energy Spectrum Partners’ most successful investments. Mr. Benson primarily focuses on business development activities and the sourcing and financing of new transactions for Energy Spectrum Partners’ midstream private equity business. Through his extensive industry relationships and active marketing efforts, Mr. Benson participates in the evaluation and negotiation of potential investments and assists portfolio companies in arranging and structuring debt financing. Mr. Benson has approximately 30 years of private equity, investment banking, financial advisory and commercial banking experience in the energy industry. Prior to co-founding Energy Spectrum Partners in 1996, Mr. Benson served for ten years as a Managing Director at R. Reid Investments Inc., where his experience included energy-related private placements of debt and equity, acquisitions and divestitures. Mr. Benson began his career at InterFirst Bank Dallas, where he served for four years and was responsible for various energy financings and financial recapitalizations. Mr. Benson has a B.S. from the University of Kansas and a M.B.A. with high honors from Texas Christian University. Mr. Benson sits on the board of directors of various privately held companies. We believe Mr. Benson’s extensive experience in the energy industry and his role with Energy Spectrum Partners bring valuable skills to the board of directors.

Thomas R. Fuller will be appointed to our board of directors in connection with the closing of the offering. Mr. Fuller is a founding and active partner, and has been a principal since 1988, of Diverse Energy Management Co., a 27 year old private upstream acquisition, exploitation drilling and production company which also invests in other energy-related companies. Mr. Fuller has been involved in all facets of the company, from management to reservoir, drilling deal and private equity analysis. Mr. Fuller has approximately 44 years of experience as a petroleum engineer, specializing in economic and reserves evaluation, in the energy industry. Prior to Diverse Energy Management Co., Mr. Fuller served as Executive and Director of Hillin Oil Company and Senior Vice President and Energy Group Manager of First City Banks. In the past 20 years, he has sat on the Boards of various public and private upstream energy companies. Mr. Fuller began his career as a petroleum engineer at Exxon Co. USA. Mr. Fuller has earned degrees from the University of Wyoming and the Louisiana State University School of Banking of the South and is a Registered Professional Engineer in Texas. Mr. Fuller sits on the board of directors of Halcon Resources Corp (NYSE) and various privately held companies, and is an executive committee member of Azure Midstream Holdings. Mr. Fuller previously served as a director of Petrohawk Energy Corporation. We believe Mr. Fuller’s extensive experience in the energy industry and his roles with Diverse Energy Management Co. bring important skills to the board of directors.

Board Leadership Structure

We expect that Mr. Whitener will serve as the chairman of the board of directors. The board of directors of our general partner has no policy with respect to the separation of the offices of chairman of the board of directors and chief executive officer. Instead, that relationship is defined and governed by the amended and

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restated limited liability company agreement of our general partner, which permits the same person to hold both offices. Directors of the board of directors of our general partner are designated or appointed by Azure Midstream Holdings. Accordingly, unlike holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business or governance, subject in all cases to any specific unitholder rights contained in our partnership agreement.

Board Role in Risk Oversight

Our corporate governance guidelines will provide that the board of directors of our general partner is responsible for reviewing the process for assessing the major risks facing us and the options for their mitigation. This responsibility will be largely satisfied by our audit committee, which is responsible for reviewing and discussing with management and our independent registered public accounting firm our major risk exposures and the policies management has implemented to monitor such exposures, including our financial risk exposures and risk management policies.

Reimbursement of Expenses of Our General Partner

Our general partner will not receive any management fee or other compensation for its management of our partnership. Our general partner and its affiliates will, however, be reimbursed for all expenses incurred on our behalf. Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. The partnership agreement provides that our general partner will determine the expenses that are allocable to us. There is no limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. Please read “The Partnership Agreement—Reimbursement of Expenses” and “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—Omnibus Agreement—Reimbursement of General and Administrative Expenses.”

Compensation of Our Directors

Our general partner did not have any, and paid no compensation to, members of its board of directors in 2013. Following the consummation of this offering, any employees of Azure Midstream Holdings or its affiliates who also serve as directors of our general partner will not receive additional compensation for their service as a director of our general partner. Directors of our general partner who are not officers of our general partner or any of their affiliates or employees of Azure Midstream Holdings or any of its affiliates will receive both cash and equity compensation as “non-employee directors.” Additional information regarding our anticipated non-director compensation program will be included in a subsequent amendment to this registration statement.

Executive Compensation

Compensation Discussion and Analysis

Since our general partner was formed in September 2014, it did not participate in the design or implementation of, nor accrue any obligations with respect to, compensation for the fiscal year ending December 31, 2013. Accordingly, we are not presenting any compensation for historical periods. Compensation paid to the executive officers of Azure Midstream Holdings that also provide services to us will be reimbursed by us in an amount allocated to us pursuant to Azure Midstream Holdings’ allocation methodology and subject to the terms of the omnibus agreement that we intend to enter into with Azure Midstream Holdings prior to the close of this offering, as described below.

We are currently considered an emerging growth company for purposes of the SEC’s executive compensation disclosure rules. In accordance with such rules, our reporting obligations extend only to the

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individual serving as our chief executive officer, and our two other most highly compensated executive officers. We will not directly employ any of the persons responsible for managing our business. All of the initial executive officers that will be responsible for managing our day to day affairs are also current officers of our general partner, Azure Midstream Holdings or its affiliates, and therefore will have responsibilities for us, our general partner and Azure Midstream Holdings and its subsidiaries after this offering.

The Azure Midstream Holdings individuals that we consider to be our “named executive officers” for purposes of this filing are as follows:

•

I.J. “Chip” Berthelot, II—President

•

Eric T. Kalamaras—Chief Financial Officer

The objectives of Azure Midstream Holdings’ compensation policies are to attract, motivate and retain qualified management and personnel who are highly talented while ensuring that executive officers and other employees are compensated in a manner that advances both the short- and long-term interests of shareholders. In pursuing these objectives, Azure Midstream Holdings’ compensation committee believes that compensation should reward executive officers and other employees for both their personal performance and the performance of Azure Midstream Holdings and its subsidiaries.

Prior to the completion of this offering, we and our general partner will enter into an omnibus agreement with Azure Midstream Holdings pursuant to which, among other matters:

•

Azure Midstream Holdings will make available to our general partner the services of the Azure Midstream Holdings employees who serve as the executive officers of our general partner; and

•

our general partner will be obligated to reimburse Azure Midstream Holdings for any allocated portion of the costs that Azure Midstream Holdings incurs in providing compensation and benefits to such Azure Midstream Holdings employees.

Under the applicable provisions of our partnership agreement, we are required to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. These expenses include compensation expenses for individuals who perform services for us or on our behalf and expenses allocated to us by Azure Midstream Holdings or its affiliates. We intend to enter into an omnibus agreement with Azure Midstream Holdings in connection with this offering, which will govern the manner in which expenses will be allocated to us. Consistent with our Predecessor, we expect expenses will be allocated to us based on our proportionate share of Azure Midstream Holdings’ revenues, employee compensation, distributable cash flow, Adjusted EBITDA or gross property, plant and equipment. For more information on the partnership agreement and the omnibus agreement, please read “The Partnership Agreement—Reimbursement of Expenses” and “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—Omnibus Agreement.”

The executive officers of our general partner currently receive all of their compensation and benefits for employment related to our business from Azure Midstream Holdings. Although we bear an allocated portion of Azure Midstream Holdings’ costs of providing compensation and benefits to the Azure Midstream Holdings employees who serve as the executive officers of our general partner, we will have no control over such costs and do not establish or direct the compensation policies or practices of Azure Midstream Holdings. We are required to pay all compensation amounts allocated to us by Azure Midstream Holdings although we may object to amounts that we deem unreasonable. The executive officers of our general partner, as well as the employees of Azure Midstream Holdings who may provide services to us, may participate in employee benefit plans and arrangements sponsored by Azure Midstream Holdings, including plans that may be established in the future.

In the future, the executive officers and directors of our general partner may receive equity-based compensation in connection with the long-term incentive plan that we intend to adopt (described below), and we

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will be responsible for all costs associated with the grant of awards under such long-term incentive plan. All determinations with respect to awards to be made under our long-term incentive plan to executive officers and other employees of our general partner and of Azure Midstream Holdings will be made by the board of directors of our general partner, although our general partner’s board of directors may consult with Azure Midstream Holdings when making such decisions. Responsibility and authority for compensation-related decisions for executive officers and other personnel employed directly by our general partner, if any, will reside with our general partner.

To the extent awards are made under our long-term incentive plan to the executive officers of our general partner, such awards will be approved by the board of directors of our general partner. All other compensation decisions regarding our named executive officers will be made by the board of directors of Azure Midstream Holdings and the compensation committee of the board of directors of Azure Midstream Holdings and will not be subject to approvals by the board of directors of our general partner or the audit committee or conflicts committee of the board of directors of our general partner.

Effective as of January 1, 2014, Azure Midstream Holdings LLC entered into an employment agreement with Eric T. Kalamaras (the “Employment Agreement”), the chief financial officer of our general partner. Pursuant to the Employment Agreement, Mr. Kalamaras receives an annual base salary of $225,000 as well as an annual bonus, which, for 2014, will be targeted at 50-100% of his base salary. The Employment Agreement is for an initial two year term, with automatic one year renewals if neither party gives notice of nonrenewal. It is expected that costs incurred pursuant to the Employment Agreement will be reimbursable by us pursuant to the Omnibus Agreement.

Pursuant to the Employment Agreement, Mr. Kalamaras also received a grant of profits interests in Azure Midstream Company, LLC and, upon completion of this offering, will be entitled to receive additional profits interests.

The terms of the Employment Agreement also provide that if Mr. Kalamaras is terminated without “cause” or resigns for “good reason” (each, as defined in the Employment Agreement), Mr. Kalamaras will be entitled to receive, subject to his execution of a release of claims: (i) a lump sum severance payment equal to the greater of two times his base salary or his base salary due through the end of the initial term of the agreement or the then-current renewal term; (ii) an amount up to two times the greater of his target annual bonus or his most recent annual bonus and (iii) 24 months’ reimbursement of the employer-portion of Mr. Kalamaras’ premiums under COBRA. Mr. Kalamaras is the only named executive officer with an employment agreement.

Long-Term Incentive Plan

Our general partner intends to adopt the Azure Midstream Partners, LP 2014 Long-Term Incentive Plan (our “LTIP”) under which our general partner may issue long-term equity based awards to directors, officers and employees of Azure Midstream Holdings, our general partner or its affiliates, and to any consultants, affiliates of our general partner or other individuals who perform services for us. These awards will be intended to compensate the recipients thereof based on the performance of our common units and their continued service during the vesting period, as well as to align their long-term interests with those of our unitholders. We will be responsible for our portion of the cost of awards granted under our LTIP and all determinations with respect to awards to be made under our LTIP will be made by the board of directors of our general partner or any committee thereof that may be established for such purpose or by any delegate of the board of directors or such committee, subject to applicable law, which we refer to as the plan administrator. We currently expect that the board of directors of our general partner or a committee thereof will be designated as the plan administrator. The following description reflects the terms that are currently expected to be included in the LTIP.

General

The LTIP will provide for the grant, from time to time at the discretion of the board of directors of our general partner or any delegate thereof, subject to applicable law, of unit awards, restricted units, phantom units,

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unit options, unit appreciation rights, distribution equivalent rights, and other unit-based awards. The purpose of awards under the LTIP is to provide additional incentive compensation to individuals providing services to us, and to align the economic interests of such individuals with the interests of our unitholders. The LTIP will limit the number of units that may be delivered pursuant to vested awards to common units, subject to proportionate adjustment in the event of unit splits and similar events. Common units subject to awards that are cancelled, forfeited, withheld to satisfy exercise prices or tax withholding obligations or otherwise terminated without delivery of the common units will be available for delivery pursuant to other awards.

Restricted Units and Phantom Units

A restricted unit is a common unit that is subject to forfeiture. Upon vesting, the forfeiture restrictions lapse and the recipient holds a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or on a deferred basis upon specified future dates or events or, in the discretion of the plan administrator, cash equal to the fair market value of a common unit. The plan administrator may make grants of restricted units and phantom units under the LTIP that contain such terms, consistent with the LTIP, as the plan administrator may determine are appropriate, including the period over which restricted units or phantom units will vest. The plan administrator may, in its discretion, base vesting on the grantee’s completion of a period of service or other criteria or upon a change of control (as defined in the LTIP) or as otherwise described in an award agreement.

Distributions made by us with respect to awards of restricted units may be subject to the same vesting requirements as the restricted units.

Distribution Equivalent Rights

The plan administrator, in its discretion, may also grant distribution equivalent rights, either as standalone awards or in tandem with other awards. Distribution equivalent rights are rights to receive an amount in cash, restricted units or phantom units equal to all or a portion of the cash distributions made on units during the period an award remains outstanding.

Unit Options and Unit Appreciation Rights

The LTIP may also permit the grant of options covering common units. Unit options represent the right to purchase a number of common units at a specified exercise price. Unit appreciation rights represent the right to receive the appreciation in the value of a number of common units over a specified exercise price, either in cash or in common units. Unit options and unit appreciation rights may be granted to such eligible individuals and with such terms as the plan administrator may determine, consistent with the LTIP; however, a unit option or unit appreciation right must have an exercise price equal to at least the fair market value of a common unit on the date of grant.

Unit Awards

Awards covering common units may be granted under the LTIP with such terms and conditions, including restrictions on transferability, as the plan administrator of the LTIP may establish.

Other Unit-Based Awards

The LTIP may also permit the grant of “other unit-based awards,” which are awards that, in whole or in part, are valued or based on or related to the value of a common unit. The vesting of another unit-based award may be based on a participant’s continued service, the achievement of performance criteria or other measures. On vesting or on a deferred basis upon specified future dates or events, another unit-based award may be paid in cash and/or in units (including restricted units) or any combination thereof as the plan administrator of the LTIP may determine.

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Source of Common Units

Common units to be delivered with respect to awards may be newly-issued units, common units acquired by us or our general partner in the open market, common units already owned by our general partner or us, common units acquired by our general partner directly from us or any other person or any combination of the foregoing.

Anti-Dilution Adjustments and Change in Control

If an “equity restructuring” event occurs that could result in an additional compensation expense under applicable accounting standards if adjustments to awards under the LTIP with respect to such event were discretionary, the plan administrator will equitably adjust the number and type of units covered by each outstanding award and the terms and conditions of such award to equitably reflect the restructuring event, and the plan administrator will adjust the number and type of units with respect to which future awards may be granted under the LTIP. With respect to other similar events, including, for example, a combination or exchange of units, a merger or consolidation or an extraordinary distribution of our assets to unitholders, that would not result in an accounting charge if adjustment to awards were discretionary, the plan administrator shall have discretion to adjust awards in the manner it deems appropriate and to make equitable adjustments, if any, with respect to the number of units available under the LTIP and the kind of units or other securities available for grant under the LTIP. Furthermore, upon any such event, including a change in control of us or our general partner, or a change in any law or regulation affecting the LTIP or outstanding awards or any relevant change in accounting principles, the plan administrator of the LTIP will generally have discretion to (i) accelerate the time of exercisability or vesting or payment of an award, (ii) require awards to be surrendered in exchange for a cash payment or substitute other rights or property for the award, (iii) provide for the award to assumed by a successor or one of its affiliates, with appropriate adjustments thereto, (iv) cancel unvested awards without payment or (v) make other adjustments to awards as the plan administrator deems appropriate to reflect the applicable transaction or event.

Termination of Service

The consequences of the termination of a grantee’s membership on the board of directors of our general partner or other service arrangement will generally be determined by the plan administrator in the terms of the relevant award agreement.

Amendment or Termination of Long-Term Incentive Plan

The plan administrator, at its discretion, may terminate the LTIP at any time with respect to the common units for which a grant has not previously been made. The plan administrator also has the right to alter or amend the LTIP or any part of it from time to time or to amend any outstanding award made under the LTIP, provided that no change in any outstanding award may be made that would materially impair the vested rights of the participant without the consent of the affected participant or result in taxation to the participant under Section 409A of the Code.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of our units that will be issued upon the consummation of this offering and the related transactions and held by:

•

each person who then will beneficially own 5% or more of the then outstanding units;

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each director, director nominee and named executive officer of our general partner; and

•

all directors and officers of our general partner as a group.

The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. In computing the number of common units beneficially owned by a person and the percentage ownership of that person, common units subject to options or warrants held by that person that are currently exercisable or exercisable within 60 days of , if any, are deemed outstanding, but are not deemed outstanding for computing the percentage ownership of any other person. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable. The percentage of units beneficially owned is based on a total of common units and subordinated units outstanding immediately following this offering.

The following table does not include any common units that officers, directors, director nominees, employees and certain other persons associated with us purchase in this offering through the directed unit program described under “Underwriting.”


Name of Beneficial Owner(1)	Common Units to be Beneficially Owned	Percentage of Common Units to be Beneficially Owned		Subordinated Units to be Beneficially Owned		Percentage of Subordinated Units to be Beneficially Owned			Percentage of Total Common and Subordinated Units to be Beneficially Owned
Azure Midstream Holdings			%				100	%			%
I.J. “Chip” Berthelot, II			%		—		—	%			%
John E. O’Shea, Jr.			%		—		—	%			%
Paul G. Smith			%		—		—	%			%
Thomas O. Whitener, Jr.			%		—		—	%			%
James P. Benson			%		—		—	%			%
Thomas R. Fuller			%		—		—	%			%
Eric T. Kalamaras			%		—		—	%			%
All directors, director nominees and executive officers as a group ( persons)			%		—		—	%		—	%

Less than 1%.

(1)

Unless otherwise indicated, the address for all beneficial owners in this table is 12377 Merit Drive, Suite 300, Dallas, TX 75251.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

After the consummation of this offering, Azure Midstream Holdings will directly own common units and subordinated units representing an aggregate % limited partner interest in us as well as a 60% interest in Azure Midstream Operating and will own and control our general partner. Azure Midstream Holdings will appoint all of the directors of our general partner, which will maintain the managing member interest in us, and Azure Midstream Holdings will indirectly own the incentive distribution rights.

Distributions and Payments to Our General Partner and its Affiliates

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the formation, ongoing operation and any liquidation of Azure Midstream Partners, LP These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s length negotiations.

Formation Stage

The consideration received by Azure Midstream Holdings and its affiliates for the contribution of the assets and liabilities to us

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common units;

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subordinated units;

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a non-economic general partner interest;

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the incentive distribution rights through its ownership of our general partner; and

•

the repayment of certain indebtedness of Azure Energy.

Operational Stage

Distributions of available cash to our general partner and its affiliates

We will generally make cash distributions to our unitholders, including affiliates of our general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, Azure Midstream Holdings will be entitled to increasing percentages of the distributions, up to 50% of the distributions above the highest target distribution level.

Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, Azure Midstream Holdings and its affiliates would receive an annual distribution of approximately $ million on their common and subordinated units.

Payments to our general partner and its affiliates

Our general partner and its affiliates will be entitled to reimbursement for all expenses they incur on our behalf, including salaries and employee benefit costs for employees who provide services to us, and all other necessary or appropriate expenses allocable to us or reasonably incurred by our general partner and its affiliates in connection with operating our business. The partnership agreement provides that our general partner will determine the expenses that are

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allocable to us. We expect to incur approximately $16.0 million for the twelve months ending December 31, 2015 to reimburse our general partner and its affiliates, including Azure Midstream Holdings, for expenses under the omnibus agreement.

Withdrawal or removal of our general partner

If our general partner withdraws or is removed, its non-economic general partner interest and its affiliates’ incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. Please read “The Partnership Agreement—Withdrawal or Removal of Our General Partner.”

Liquidation Stage

Liquidation

If we are ever liquidated, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

Agreements Governing the Transactions

We and other parties have entered into or will enter into the various documents and agreements that will affect the offering transactions, including our acquisition of interests in Azure Midstream Operating, the vesting of assets in, and the assumption of liabilities by, us and our subsidiaries, and the application of the proceeds of this offering. These agreements will not be the result of arm’s length negotiations, and they, or any of the transactions that they provide for, may not be effected on terms at least as favorable to the parties to these agreements as they could have been obtained from nonaffiliated third-parties. All of the transaction expenses incurred in connection with these transactions, including the expenses associated with transferring assets into our subsidiaries, will be paid from the proceeds of this offering.

Limited Partnership Agreement of Azure Midstream Operating

As a result of the transactions described in “Summary—Formation Transactions and Partnership Structure,” our sole assets will consist of a 40% limited partner interest in Azure Midstream Operating, over which we have operating control through our ownership of Azure Midstream Operating Company GP, LLC, the general partner of Azure Midstream Operating.

Upon the closing of this offering, we and Azure Midstream Holdings will enter into an amended and restated limited partnership agreement of Azure Midstream Operating. Based on our sole ownership of the general partner of Azure Midstream Operating, we will have the sole responsibility for managing the operations of Azure Operating. However, we expect that certain actions of Azure Midstream Operating will require the unanimous approval of both us and Azure Midstream Holdings. The amended and restated partnership agreement will provide that Azure Midstream Operating will distribute all distributable cash of Azure Midstream Operating to us and Azure Midstream Holdings on a pro rata basis within days of the end of each quarter.

Omnibus Agreement

Upon the closing of this offering, we will enter into an omnibus agreement with Azure Midstream Holdings, our general partner and others. The following discussion describes provisions of the omnibus agreement. Any or all of the provisions of the omnibus agreement will be terminable by Azure Midstream Holdings at its option if our general partner is removed without cause and units held by our general partner and its affiliates are not voted in favor of that removal. The omnibus agreement will also generally terminate in the event of a change of control of us or our general partner.

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Administrative Services

Our general partner and its affiliates, including Azure Midstream Holdings, will provide certain management and other services to us including, but not limited to:

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bookkeeping, audit and accounting services: assistance with the maintenance of our corporate books and records, assistance with the preparation of our tax returns and arranging for the provision of audit and accounting services;

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legal and insurance services: arranging for the provision of legal, insurance and other professional services and maintaining our existence and good standing in necessary jurisdictions;

•

administrative and clerical services: assistance with office space, arranging meetings for our common unitholders pursuant to the partnership agreement, arranging the provision of IT services, providing administrative services required for subsequent debt and equity financings and attending to all other administrative matters necessary to ensure the professional management of our business;

•

banking and financial services: providing cash management including assistance with preparation of budgets, overseeing banking services and bank accounts, arranging for the deposit of funds and monitoring and maintaining compliance therewith;

•

advisory services: assistance in complying with United States and other relevant securities laws;

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client and investor relations: arranging for the provision of, advisory, clerical and investor relations services to assist and support us in our communications with our common unitholders; and

•

other services: assistance with the integration of any acquired businesses.

Our general partner or its applicable affiliate may temporarily or permanently exclude any particular service from the scope of the omnibus agreement upon 180 days’ notice. Our general partner also has the right to delegate the performance of some or all of the services to be provided pursuant to the omnibus agreement to any other person or entity, though such delegation does not relieve our general partner from its obligations under the omnibus agreement.

In order to facilitate the provision of services under the omnibus agreement, we, on the one hand, and Azure Midstream Holdings, on the other, have granted one another certain royalty-free, non-exclusive and non-transferable rights to use one another’s intellectual property under certain circumstances.

The agreement also contains a provision stating that each of our general partner and its affiliates, including Azure Midstream Holdings, is an independent contractor under the agreement and nothing in the agreement may be construed to impose an implied or express fiduciary duty owed by Azure Midstream Holdings or its affiliates, on the one hand, to the recipients of services under the agreement, on the other hand. The agreement prohibits recovery of lost profits or revenue, or special, incidental, exemplary, punitive or consequential damages from Azure Midstream Holdings or its affiliates, except in cases of gross negligence, willful misconduct, bad faith, reckless disregard in performance of services under the agreement or fraudulent or dishonest acts on their part.

Reimbursement of Expenses

For services provided under the omnibus agreement, we must pay Azure Midstream Holdings, our general partner or the affiliate of Azure Midstream Holdings providing services to us: (i) all costs incurred in connection with the employment of employees who provide us services under the omnibus agreement on a full-time basis; (ii) a prorated share of costs incurred in connection with the employment of employees, including administrative personnel, who provide us services under the omnibus agreement on a part-time basis, and such prorated share shall be determined by our general partner in good faith; (iii) a prorated share of certain administrative costs, including office costs, services by outside vendors, other sales, general and administrative costs and depreciation and amortization; (iv) various other administrative costs in accordance with the terms of the omnibus agreement,

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including travel, insurance, legal and audit services, government and public relations and bank charges; and (v) for certain costs and expenses incurred on our behalf for managing and controlling our business and operations.

The omnibus agreement does not set a limit on the amount of expenses for which our general partner and its affiliates, including Azure Midstream Holdings, may be reimbursed. Our general partner is entitled to determine in good faith the expenses that are allocable to us. We expect to incur approximately $16.0 million for the twelve months ending December 31, 2015 to reimburse our general partner and its affiliates, including Azure Midstream Holdings, for expenses under the omnibus agreement.

Our Right of First Offer for Azure Midstream Holdings’ Interest in Azure Midstream Operating

Under the omnibus agreement, Azure Midstream Holdings will be required to offer us the right to purchase its remaining 60% limited partner interest in Azure Midstream Operating before it can sell that interest to anyone else. We refer to our purchase right as a right of first offer. The consummation and timing of any future purchases by us of any part of Azure Midstream Holdings’ interest in Azure Midstream Operating will depend upon, among other things, Azure Midstream Holdings’ decision to sell its interest in Azure Midstream Operating, our ability to reach an agreement with Azure Midstream Holdings regarding the price and other terms of such purchase, compliance with our debt agreements, and our ability to obtain financing on acceptable terms. Although we will have the right of first offer to purchase Azure Midstream Holdings’ interest in Azure Midstream Operating, we are not obligated to purchase any additional interest in Azure Midstream Operating from Azure Midstream Holdings and Azure Midstream Holdings is under no obligation to sell any such interest.

Pursuant to the omnibus agreement, Azure Midstream Holdings must give us written notice of its intent to sell all or a portion of its 60% interest in Azure Midstream Operating specifying the fundamental terms of the proposed sale, other than the sale price. Within 45 days of receiving such notification from Azure Midstream Holdings, the conflicts committee of our general partner must notify Azure Midstream Holdings in writing whether we wish to make an offer to purchase the interest to be sold, and, if so, provide the price we are willing to pay for the interest. Thereafter, our conflicts committee and Azure Midstream Holdings will enter into good faith negotiations for a 45-day period to reach an agreement for us to purchase the interest offered for sale. If our conflicts committee and Azure Midstream Holdings cannot agree on the terms of purchase for the interest offered for sale after negotiating in good faith for the 45-day period, Azure Midstream Holdings may give us notice that it rejects our offer and will thereafter seek an alternative purchase. In the event Azure Midstream Holdings is thereafter able to obtain a good faith, binding offer to pay at least % of the highest purchase price (on a present value basis) we proposed or as contained in any greater written offer made by us during the 45-day negotiation period, then Azure Midstream Holdings will be free to sell the interest at such greater price. If an alternative transaction complying with the provisions set out immediately above has not been consummated by Azure Midstream Holdings within 270 days after the end of our 45-day negotiation period, the right of first offer would be reinstated and would apply to any future sale or future offer by Azure Midstream Holdings to sell all or a portion of its interest.

Historical Transactions

During the quarter ended September 30, 2014, we purchased the residence of Eric T. Kalamaras, our Chief Financial Officer, as part of a relocation package for $1.1 million. To effectuate the purchase, we engaged a third-party relocation company, who executed the purchase for $1.1 million and will subsequently sell the officer’s residence. We entered into a loan agreement with a third party for $1.0 million of the purchase price, and, as of September 30, 2014, the asset is included within assets held for sale, and the loan amount is included within the current portion of long-term debt on our balance sheet. We have entered into a sales contract for the residence, and we expect that we will receive the fair market value of the residence that we recorded at the time of the purchase.

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Competition

Under our partnership agreement, Azure Midstream Holdings and its affiliates are expressly permitted to compete with us. Azure Midstream Holdings and any of its affiliates may acquire, construct or dispose of assets in the future without any obligation to offer us the opportunity to purchase or construct those assets, other than our right of first offer on Azure Midstream Holdings’ 60% limited partner interest in Azure Midstream Operating.

Procedures for Review, Approval and Ratification of Transactions with Related Persons

The board of directors of our general partner will adopt a related party transactions policy in connection with the closing of this offering that will provide that the board of directors of our general partner or its authorized committee will review on at least a quarterly basis all related person transactions that are required to be disclosed under SEC rules and, when appropriate, initially authorize or ratify all such transactions. In the event that the board of directors of our general partner or its authorized committee considers ratification of a related person transaction and determines not to so ratify, the code of business conduct and ethics will provide that our management will make all reasonable efforts to cancel or annul the transaction.

The related party transactions policy will provide that, in determining whether or not to recommend the initial approval or ratification of a related person transaction, the board of directors of our general partner or its authorized committee should consider all of the relevant facts and circumstances available, including (if applicable) but not limited to: (i) whether there is an appropriate business justification for the transaction; (ii) the benefits that accrue to us as a result of the transaction; (iii) the terms available to unrelated third parties entering into similar transactions; (iv) the impact of the transaction on a director’s independence (in the event the related person is a director, an immediate family member of a director or an entity in which a director or an immediate family member of a director is a partner, shareholder, member or executive officer); (v) the availability of other sources for comparable products or services; (vi) whether it is a single transaction or a series of ongoing, related transactions; and (vii) whether entering into the transaction would be consistent with the code of business conduct and ethics.

The related party transactions policy described above will be adopted in connection with the closing of this offering, and as a result the transactions described above were not reviewed under such policy.

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CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates, including Azure Midstream Holdings, on the one hand, and us and our unaffiliated limited partners, on the other hand. The directors and officers of our general partner have duties to manage our general partner in a manner that is beneficial to its owners. At the same time, our general partner has a duty to manage our partnership in a manner it believes is not adverse to our interests. Our partnership agreement specifically defines the remedies available to unitholders for actions taken that, without these defined liability standards, might constitute breaches of fiduciary duty under applicable Delaware law. The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to the limited partners and the partnership.

Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or our limited partners, on the other hand, the resolution or course of action in respect of such conflict of interest shall be permitted and deemed approved by all our limited partners and shall not constitute a breach of our partnership agreement, of any agreement contemplated thereby or of any duty, if the resolution or course of action in respect of such conflict of interest is:

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approved by the conflicts committee of our general partner, although our general partner is not obligated to seek such approval; or

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approved by the holders of a majority of the outstanding common units, excluding any such units owned by our general partner or any of its affiliates.

Our general partner may, but is not required to, seek the approval of such resolutions or courses of action from the conflicts committee of its board of directors or from the holders of a majority of the outstanding common units as described above. If our general partner does not seek approval from the conflicts committee or from holders of common units as described above and the board of directors of our general partner approves the resolution or course of action taken with respect to the conflict of interest, then it will be presumed that, in making its decision, the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of us or any of our unitholders, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption and proving that such decision was not in good faith. Unless the resolution of a conflict is specifically provided for in our partnership agreement, the board of directors of our general partner or the conflicts committee of the board of directors of our general partner may consider any factors they determine in good faith to consider when resolving a conflict. An independent third party is not required to evaluate the resolution. When our partnership agreement requires someone to act in good faith, it requires that person to not have acted with the belief that such action was adverse to the interests of the partnership or meets the standard otherwise specified in our partnership agreement.

Conflicts of interest could arise in the situations described below, among others:

The directors and officers of our general partner have duties to make decisions in a manner that is beneficial to the owners of our general partner, which may be contrary to our interests.

Because the officers and certain directors of our general partner are also directors or officers of affiliates of our general partner, including our general partner, they have duties to our general partner that may cause them to pursue business strategies that disproportionately benefit our general partner or which otherwise are not in our best interests.

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Our general partner is allowed to take into account the interests of parties other than us in exercising certain rights under our partnership agreement.

Our partnership agreement contains provisions that permissibly reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. 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. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its call right, its voting rights with respect to any units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation.

Our general partner and its affiliates compete with us, and will have the ability to compete with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to us.

Affiliates of our general partner are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us, and our general partner or its affiliates may acquire, construct or dispose of assets in the future without any obligation to offer us the opportunity to acquire those assets, other than our right of first offer on Azure Midstream Holdings’ 60% limited partner interest in Azure Midstream Operating. We share our management team with our general partner, and the shared management team is under no obligation to offer new business opportunities to us before offering them to our general partner, which could have a material adverse impact on our ability to maintain or grow our business.

Under our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to our general partner and its affiliates. As a result, neither our general partner nor any of its affiliates have any obligation to present business opportunities to us.

Our partnership agreement limits the liability of, and replaces the duties owed by, our general partner and also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty.

In addition to the provisions described above, our partnership agreement contains provisions that restrict the remedies available to our unitholders for actions that might otherwise constitute breaches of fiduciary duty. For example, our partnership agreement provides that:

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our general partner shall not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed that the decision was not adverse to the interest of the partnership and, with respect to criminal conduct, did not act with the knowledge that the conduct was unlawful;

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our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or those other persons acted in bad faith or, in the case of a criminal matter, acted with knowledge that its conduct was unlawful; and

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in resolving conflicts of interest, it will be presumed that in making its decision the general partner, the board of directors of the general partner or the conflicts committee of the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption and proving that such decision was not in good faith.

By purchasing a common unit, a common unitholder will agree to become bound by the provisions in our partnership agreement, including the provisions discussed above. Please read “—Fiduciary Duties.”

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Common unitholders have no right to enforce obligations of our general partner and its affiliates under agreements with us.

Any agreements between us, on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

Contracts between us, on the one hand, and our general partner and its affiliates, on the other, are not and will not be the result of arm’s-length negotiations.

Neither our partnership agreement nor any of the other agreements, contracts and arrangements between us and our general partner and its affiliates are or will be the result of arm’s-length negotiations. Our general partner will determine, in good faith, the terms of any of such future transactions.

Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval, necessary or appropriate to conduct our business including, but not limited to, the following actions:

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expending, lending, or borrowing money, assuming, guaranteeing, or otherwise contracting for, indebtedness and other liabilities, issuing evidences of indebtedness, including indebtedness that is convertible into our securities, and incurring any other obligations;

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preparing and transmitting tax, regulatory and other filings, periodic or other reports to governmental or other agencies having jurisdiction over our business or assets;

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acquiring, disposing, mortgaging, pledging, encumbering, hypothecating, or exchanging our assets or merging or otherwise combining us with or into another person;

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negotiating, executing and performing contracts, conveyance or other instruments;

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distributing cash;

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selecting or dismissing employees and agents, outside attorneys, accountants, consultants and contractors and determining their compensation and other terms of employment or hiring;

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maintaining insurance for our benefit;

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forming, acquiring an interest in, and contributing property and loaning money to, any further limited partnerships, joint ventures, corporations, limited liability companies or other relationships;

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controlling all matters affecting our rights and obligations, including bringing and defending actions at law or in equity or otherwise litigating, arbitrating or mediating, and incurring legal expense and settling claims and litigation;

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indemnifying any person against liabilities and contingencies to the extent permitted by law;

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purchasing, selling or otherwise acquiring or disposing of our partnership interests, or issuing additional options, rights, warrants, appreciation rights, phantom or tracking interests relating to our partnership interests; and

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entering into agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.

Please read “The Partnership Agreement” for information regarding the voting rights of unitholders.

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Actions taken by our general partner may affect the amount of cash available to pay distributions to unitholders or accelerate the right to convert subordinated units.

The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:

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amount and timing of asset purchases and sales;

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cash expenditures;

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borrowings;

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entry into and repayment of current and future indebtedness;

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issuance of additional units; and

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the creation, reduction or increase of reserves in any quarter.

In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to our unitholders, including borrowings that have the purpose or effect of:

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enabling affiliates of our general partner to receive distributions on any subordinated units held by them or the incentive distribution rights; or

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hastening the expiration of the subordination period.

In addition, our general partner may use an amount, initially equal to $ million, which would not otherwise constitute operating surplus, in order to permit the payment of distributions on subordinated units and the incentive distribution rights. All of these actions may affect the amount of cash or equity distributed to our unitholders and our general partner and may facilitate the conversion of subordinated units into common units. Please read “How We Make Distributions to Our Partners.”

For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and our subordinated units, our partnership agreement permits us to borrow funds, which would enable us to make such distribution on all outstanding units. Please read “How We Make Distributions to Our Partners—Operating Surplus and Capital Surplus—Operating Surplus.”

We will reimburse our general partner and its affiliates for expenses.

We will reimburse our general partner and its affiliates, including Azure Midstream Holdings, for costs incurred in managing and operating us. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us, and it will charge on a fully allocated cost basis for services provided to us. Our omnibus agreement and services agreement with Azure Midstream Holdings also address our payment of annual amounts to, and our reimbursement of, our general partner and its affiliates for these costs and services. Please read “Certain Relationships and Related Party Transactions.”

Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit its liability under contractual arrangements so that counterparties to such agreements have recourse only against our assets and not against our general partner or its assets or any affiliate of our general partner or its assets. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s duties, even if we could have obtained terms that are more favorable without the limitation on liability.

Common units are subject to our general partner’s call right.

If at any time our general partner and its affiliates own more than 80% of the 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 the market price calculated in

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accordance with the terms of our partnership agreement. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and exercising its call right. Our general partner may use its own discretion, free of fiduciary duty restrictions, in determining whether to exercise this right. As a result, a common unitholder may have his common units purchased from him at an undesirable time or price. Please read “The Partnership Agreement—Limited Call Right.”

We may choose not to retain separate counsel for ourselves or for the holders of common units.

The attorneys, independent accountants and others who perform services for us have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the conflicts committee of the board of directors of our general partner and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the conflict committee in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict, although we may choose not to do so.

The holder or holders of our incentive distribution rights may elect to cause us to issue common units to it in connection with a resetting of target distribution levels without the approval of our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

The holder or holders of a majority of our incentive distribution rights (initially Azure Midstream Holdings through its ownership of our general partner) have the right, at any time when there are no subordinated units outstanding and they have received incentive distributions at the highest level to which they are entitled (50.0%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distribution levels at the time of the exercise of the reset election. Following a reset election, a baseline distribution amount will be calculated equal to an amount equal to the prior cash distribution per common unit for the fiscal quarter 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.

We anticipate that Azure Midstream Holdings would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per unit without such conversion. However, Azure Midstream Holdings may transfer the incentive distribution rights at any time. It is possible that Azure Midstream Holdings or a transferee could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when the holders of the incentive distribution rights expect that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, the holders of the incentive distribution rights may be experiencing, or may expect to experience, declines in the cash distributions it receives related to the 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 them to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved. 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 the holders of the incentive distribution rights in connection with resetting the target distribution levels. Please read “How We Make Distributions to Our Partners—Azure Midstream Holdings’ Right to Reset Incentive Distribution Levels.”

Duties

Duties owed to unitholders by our general partner are prescribed by law and in our partnership agreement. The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to the limited partners and the partnership.

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Our partnership agreement contains various provisions that eliminate and replace the fiduciary duties that might otherwise be owed by our general partner and its directors and officers with contractual standards governing the duties of our general partner and contractual methods of resolving conflicts of interest. We have adopted these provisions to allow our general partner or its affiliates to engage in transactions with us that otherwise might be prohibited by state law fiduciary standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because the board of directors of our general partner has a duty to manage our partnership in good faith and a duty to manage our general partner in a manner beneficial to its owner. Without these modifications, our general partner’s ability to make decisions involving conflicts of interest would be restricted. Replacing the fiduciary duty standards in this manner benefits our general partner by enabling it to take into consideration all parties involved in the proposed action. Replacing the fiduciary duty standards also strengthens the ability of our general partner to attract and retain experienced and capable directors. Replacing the fiduciary duty standards represents a detriment to our public unitholders because it restricts the remedies available to our public unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permits our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interests.

The following is a summary of the material restrictions of the fiduciary duties owed by our general partner to the limited partners:

State law fiduciary duty standards

Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally require that any action taken or transaction engaged in be entirely fair to the partnership.

Partnership agreement modified standards

Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues as to compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith,” meaning that it believed that its actions or omissions were not adverse to the interests of the partnership, and will not be subject to any higher standard under applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These standards replace the obligations to which our general partner would otherwise be held.

If our general partner does not obtain approval from the conflicts committee of the board of directors of our general partner or our common unitholders, excluding any such units owned by our general partner or its affiliates, and the board of directors of our general partner approves the resolution or course of action taken with respect to the conflict of interest, then it will be presumed that, in making its

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decision, its board, which may include board members affected by the conflict of interest, acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. These standards replace the obligations to which our general partner would otherwise be held.

Rights and remedies of unitholders

The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These actions include actions against a general partner for breach of its duties or of our partnership agreement. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.

By purchasing our common units, each common unitholder automatically agrees to be bound by the provisions in our partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner to sign a partnership agreement does not render the partnership agreement unenforceable against that person.

Under our partnership agreement, we must indemnify our general partner and its officers, directors, managers and certain other specified persons, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith. We must also provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent these provisions purport to include indemnification for liabilities arising under the Securities Act in the opinion of the SEC, such indemnification is contrary to public policy and, therefore, unenforceable. Please read “The Partnership Agreement—Indemnification.”

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DESCRIPTION OF THE COMMON UNITS

The Units

The common units and the subordinated units are separate classes of limited partner interests in us. The holders of units are entitled to participate in partnership distributions and exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and subordinated units in and to partnership distributions, please read this section and “How We Make Distributions to Our Partners.” For a description of other rights and privileges of limited partners under our partnership agreement, including voting rights, please read “The Partnership Agreement.”

Transfer Agent and Registrar

Duties

will serve as the registrar and transfer agent for the common units. We will pay all fees charged by the transfer agent for transfers of common units except the following, which must be paid by unitholders:

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surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

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special charges for services requested by a holder of a common unit; and

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other similar fees or charges.

There will be no charge to unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

Resignation or Removal

The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor is appointed or has not accepted its appointment within 30 days of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

Upon the transfer of a common unit in accordance with our partnership agreement, the transferee of the common unit shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Each transferee:

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represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;

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automatically becomes bound by the terms and conditions of our partnership agreement; and

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gives the consents, waivers and approvals contained in our partnership agreement, such as the approval of all transactions and agreements that we are entering into in connection with our formation and this offering.

Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.

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We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and any transfers are subject to the laws governing the transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a substituted limited partner in our partnership for the transferred common units.

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the common unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

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THE PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement, which we will adopt in connection with the closing of this offering. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of our partnership agreement, when available, upon request at no charge.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

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with regard to distributions of available cash, please read “How We Make Distributions to Our Partners”;

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with regard to the duties of, and standard of care applicable to, our general partner, please read “Conflicts of Interest and Fiduciary Duties”;

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with regard to the transfer of common units, please read “Description of the Common Units—Transfer of Common Units”; and

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with regard to allocations of taxable income and taxable loss, please read “Material U.S. Federal Income Tax Consequences.”

Organization and Duration

Azure Midstream Partners, LP was organized in September 2014 and will have a perpetual existence unless terminated pursuant to the terms of our partnership agreement.

Purpose

Our purpose, as set forth in our partnership agreement, is limited to any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law; provided that our general partner shall not cause us to take any action that the general partner determines would be reasonably likely to cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than the business of buying, gathering, compressing, treating, processing and selling natural gas and NGLs, our general partner may decline to do so in its sole discretion. Our general partner is generally authorized to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Cash Distributions

Our partnership agreement specifies the manner in which we will make cash distributions to holders of our common units and other partnership securities as well as to Azure Midstream Holdings in respect of its incentive distribution rights. For a description of these cash distribution provisions, please read “How We Make Distributions to Our Partners.”

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under “—Limited Liability.”

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Voting Rights

The following is a summary of the unitholder vote required for approval of the matters specified below. Matters that require the approval of a “unit majority” require:

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during the subordination period, the approval of a majority of the common units, excluding those common units whose vote is controlled by our general partner and its affiliates, and a majority of the subordinated units, voting as separate classes; and

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after the subordination period, the approval of a majority of the common units, voting as a single class.

In voting their common and subordinated units, affiliates of our general partner will have no duty or obligation whatsoever to us or the limited partners, including any duty to act in a manner beneficial to us or the limited partners.

The incentive distribution rights may be entitled to vote in certain circumstances.

Issuance of additional units

No approval right.

Amendment of the partnership agreement

Certain amendments may be made by our general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read “—Amendment of the Partnership Agreement.”

Merger of our partnership or the sale of all or substantially all of our assets

Unit majority in certain circumstances. Please read “—Merger, Consolidation, Conversion, Sale or Other Disposition of Assets.”

Dissolution of our partnership

Unit majority. Please read “—Dissolution.”

Continuation of our business upon dissolution

Unit majority. Please read “—Dissolution.”

Withdrawal of our general partner

Under most circumstances, the approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of our general partner prior to , 2025 in a manner that would cause a dissolution of our partnership. Please read “—Withdrawal or Removal of Our General Partner.”

Removal of our general partner

Not less than 66²/₃% of the outstanding units, voting as a single class, including units held by our general partner and its affiliates. In addition, any vote to remove our general partner during the subordination period must provide for the election of a successor general partner by the holders of a majority of the common units and a majority of the subordinated units, voting as separate classes. Please read “—Withdrawal or Removal of Our General Partner.”

Transfer of our general partner interest

No approval right. Please read “—Transfer of General Partner Interest.”

Transfer of incentive distribution rights

No approval right. Please read “—Transfer of Subordinated Units and Incentive Distribution Rights.”

Transfer of ownership interests in our general partner

No approval right. Please read “—Transfer of Ownership Interests in the General Partner.”

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If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the specific prior approval of our general partner.

Applicable Law; Forum, Venue and Exclusive Jurisdiction

Our partnership agreement is governed by Delaware law. Our partnership agreement requires that any claims, suits, actions or proceedings:

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arising out of or relating in any way to the partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of the partnership agreement or the duties, obligations or liabilities among limited partners or of limited partners to us, or the rights or powers of, or restrictions on, the limited partners or us);

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brought in a derivative manner on our behalf;

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asserting a claim of breach of a fiduciary duty owed by any director, officer or other employee of us or our general partner, or owed by our general partner, to us or the limited partners;

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asserting a claim arising pursuant to any provision of the Delaware Act; or

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asserting a claim governed by the internal affairs doctrine

shall be exclusively brought in the Court of Chancery of the State of Delaware (or, if such court does not have subject matter jurisdiction thereof, any other court located in the State of Delaware with subject matter jurisdiction), regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims. By purchasing a common unit, a limited partner is irrevocably consenting to these limitations and provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or such other Delaware courts) in connection with any such claims, suits, actions or proceedings.

Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of the partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. However, if it were determined that the right, or exercise of the right, by the limited partners as a group:

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to remove or replace our general partner;

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to approve some amendments to our partnership agreement; or

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to take other action under our partnership agreement;

constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us under the reasonable belief that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

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Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years.

Following the completion of this offering, we expect that our subsidiaries will conduct business in two states and we may have subsidiaries that conduct business in other states or countries in the future. Maintenance of our limited liability as owner of our operating subsidiaries may require compliance with legal requirements in the jurisdictions in which the operating subsidiaries conduct business, including qualifying our subsidiaries to do business there.

Limitations on the liability of members or limited partners for the obligations of a limited liability company or limited partnership have not been clearly established in many jurisdictions. If, by virtue of our ownership interest in our subsidiaries or otherwise, it were determined that we were conducting business in any jurisdiction without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

Issuance of Additional Interests

Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders.

It is possible that we will fund acquisitions through the issuance of additional common units, subordinated units or other partnership interests. Holders of any additional common units we issue will be entitled to share equally with the then-existing common unitholders in our distributions of available cash. In addition, the issuance of additional common units or other partnership interests may dilute the value of the interests of the then-existing common unitholders in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership interests that, as determined by our general partner, may have rights to distributions or special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit our subsidiaries from issuing equity interests, which may effectively rank senior to the common units.

Our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other partnership interests whenever, and on the same terms that, we issue partnership interests to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of our general partner and its affiliates, including such interest represented by common and subordinated units, that existed immediately prior to each issuance. The common unitholders will not have preemptive rights under our partnership agreement to acquire additional common units or other partnership interests.

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Amendment of the Partnership Agreement

General

Amendments to our partnership agreement may be proposed only by our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in a manner beneficial to us or the limited partners. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or to call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

Prohibited Amendments

No amendment may be made that would:

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enlarge the obligations of any limited partner without his consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or

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enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld in its sole discretion.

The provision of our partnership agreement preventing the amendments having the effects described in the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding units, voting as a single class (including units owned by our general partner and its affiliates). Upon completion of the offering, an affiliate of our general partner will own approximately % of our outstanding common and subordinated units.

No Unitholder Approval

Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:

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a change in our name, the location of our principal place of business, our registered agent or our registered office;

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the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;

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a change that our general partner determines to be necessary or appropriate to qualify or continue our qualification as a limited partnership or other entity in which the limited partners have limited liability under the laws of any state or to ensure that neither we nor any of our subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed);

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an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisers Act of 1940 or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed;

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an amendment that our general partner determines to be necessary or appropriate in connection with the creation, authorization or issuance of additional partnership interests or the right to acquire partnership interests;

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any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

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an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;

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any amendment that our general partner determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership or other entity, as otherwise permitted by our partnership agreement;

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a change in our fiscal year or taxable year and related changes;

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conversions into, mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the conversion, merger or conveyance other than those it receives by way of the conversion, merger or conveyance; or

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any other amendments substantially similar to any of the matters described in the clauses above.

In addition, our general partner may make amendments to our partnership agreement, without the approval of any limited partner, if our general partner determines that those amendments:

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do not adversely affect the limited partners, considered as a whole, or any particular class of limited partners, in any material respect;

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are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

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are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed for trading;

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are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or

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are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

Opinion of Counsel and Unitholder Approval

Any amendment that our general partner determines adversely affects in any material respect one or more particular classes of limited partners, and is not permitted to be adopted by our general partner without limited partner approval, will require the approval of at least a majority of the class or classes so affected, but no vote will be required by any class or classes of limited partners that our general partner determines are not adversely affected in any material respect. Any such amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any such amendment that would reduce the voting percentage required to take any action other than to remove the general partner or call a meeting of unitholders is required to be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced. Any such amendment that would increase the percentage of units required to remove the general partner or call a meeting of unitholders must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the percentage sought to be increased. For amendments of the type not requiring unitholder approval, our general partner will not be required to obtain an opinion of counsel that an amendment will neither result in a loss of limited liability to the limited partners nor result in our being treated as a taxable entity for federal income tax purposes in connection with any of the amendments. No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units, voting as a single class, unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners.

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Merger, Consolidation, Conversion, Sale or Other Disposition of Assets

A merger, consolidation or conversion of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger, consolidation or conversion and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in a manner beneficial to us or the limited partners.

In addition, our partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us to sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without such approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without such approval. Finally, our general partner may consummate any merger without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in a material amendment to the partnership agreement (other than an amendment that the general partner could adopt without the consent of other partners), each of our units will be an identical unit of our partnership following the transaction and the partnership securities to be issued do not exceed 20% of our outstanding partnership interests (other than incentive distribution rights) immediately prior to the transaction.

If the conditions specified in our partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity, if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, we have received an opinion of counsel regarding limited liability and tax matters and the governing instruments of the new entity provide the limited partners and our general partner with the same rights and obligations as contained in our partnership agreement. Our unitholders are not entitled to dissenters’ rights of appraisal under our partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.

Dissolution

We will continue as a limited partnership until dissolved under our partnership agreement. We will dissolve upon:

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the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;

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there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law;

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the entry of a decree of judicial dissolution of our partnership; or

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the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or its withdrawal or removal following the approval and admission of a successor.

Upon a dissolution under the last clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing as a successor general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:

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the action would not result in the loss of limited liability under Delaware law of any limited partner; and

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•

neither our partnership nor any of our subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue (to the extent not already so treated or taxed).

Liquidation and Distribution of Proceeds

Upon our dissolution, unless our business is continued, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as described in “How We Make Distributions to Our Partners—Distributions of Cash Upon Liquidation.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

Withdrawal or Removal of Our General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to , 2025 without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after , 2025, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days’ notice to the limited partners if at least 50% of the outstanding common units are held or controlled by one person and its affiliates, other than our general partner and its affiliates. In addition, our partnership agreement permits our general partner, in some instances, to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. Please read “—Transfer of General Partner Interest.”

Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a unit majority may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period after that withdrawal, the holders of a unit majority agree in writing to continue our business and to appoint a successor general partner. Please read “—Dissolution.”

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66²/₃% of the outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units, voting as a class, and the outstanding subordinated units, voting as a class. The ownership of more than 33¹/₃% of the outstanding units by our general partner and its affiliates gives them the ability to prevent our general partner’s removal. At the closing of this offering, our general partner and its affiliates will own % of our outstanding limited partner units, including all of our subordinated units.

Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist:

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all subordinated units held by any person who did not, and whose affiliates did not, vote any units in favor of the removal of the general partner, will immediately and automatically convert into common units on a one-for-one basis; and

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if all of the subordinated units convert pursuant to the foregoing, all cumulative common unit arrearages on the common units will be extinguished and the subordination period will end.

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In the event of the removal of our general partner under circumstances where cause exists or withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest and incentive distribution rights of the departing general partner and its affiliates for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest and the incentive distribution rights of the departing general partner and its affiliates for fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. If the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partner interest and all its and its affiliates’ incentive distribution rights will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred as a result of the termination of any employees employed for our benefit by the departing general partner or its affiliates.

Transfer of General Partner Interest

At any time, our general partner may transfer all or any of its non-economic general partner interest to another person without the approval of any other partner. As a condition of this transfer, the transferee must, among other things, assume the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement and furnish an opinion of counsel regarding limited liability and tax matters.

Transfer of Ownership Interests in the General Partner

At any time, the owners of our general partner may sell or transfer all or part of its ownership interests in our general partner to an affiliate or third party without the approval of our unitholders.

Transfer of Subordinated Units and Incentive Distribution Rights

By transfer of subordinated units or incentive distribution rights in accordance with our partnership agreement, each transferee of subordinated units or incentive distribution rights will be admitted as a limited partner with respect to the subordinated units or incentive distribution rights transferred when such transfer and admission is reflected in our books and records. Each transferee:

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represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;

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automatically becomes bound by the terms and conditions of our partnership agreement; and

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gives the consents, waivers and approvals contained in our partnership agreement, such as the approval of all transactions and agreements we are entering into in connection with our formation and this offering.

Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.

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We may, at our discretion, treat the nominee holder of subordinated units or incentive distribution rights as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Subordinated units and incentive distribution rights are securities and any transfers are subject to the laws governing transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a limited partner for the transferred subordinated units or incentive distribution rights.

Until a subordinated unit or incentive distribution right has been transferred on our books, we and the transfer agent may treat the record holder of the unit or right as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove our general partner or from otherwise changing our management. Please read “—Withdrawal or Removal of Our General Partner” for a discussion of certain consequences of the removal of our general partner. If any person or group, other than our general partner and its affiliates, acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply in certain circumstances. Please read “—Meetings; Voting.”

Limited Call Right

If at any time our general partner and its affiliates own more than 80% of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or beneficial owners or to us, to acquire all, but not less than all, of the limited partner interests of the class held by unaffiliated persons, as of a record date to be selected by our general partner, on at least 10, but not more than 60, days notice. The purchase price in the event of this purchase is the greater of:

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the highest price paid by our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and

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the average of the daily closing prices of the partnership securities of such class over the 20 trading days preceding the date that is three days before the date the notice is mailed.

As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at an undesirable time or at a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Units.”

Non-Taxpaying Holders; Redemption

To avoid any adverse effect on the maximum applicable rates chargeable to customers by us or any of our future subsidiaries, or in order to reverse an adverse determination that has occurred regarding such maximum rate, our partnership agreement provides our general partner the power to amend the agreement. If our general partner, with the advice of counsel, determines that our not being treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes, coupled with the tax status (or lack of proof thereof) of one or more of our limited partners (or their owners, to the extent relevant), has, or is reasonably likely to have, a material adverse effect on the maximum applicable rates chargeable to customers by

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our subsidiaries, then our general partner may adopt such amendments to our partnership agreement as it determines necessary or advisable to:

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obtain proof of the federal income tax status of our limited partners (and their owners, to the extent relevant); and

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permit us to redeem the units held by any person whose tax status has or is reasonably likely to have a material adverse effect on the maximum applicable rates or who fails to comply with the procedures instituted by our general partner to obtain proof of the federal income tax status. The redemption price in the case of such a redemption will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption.

Non-Citizen Assignees; Redemption

If our general partner, with the advice of counsel, determines we are subject to federal, state or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner (or its owners, to the extent relevant), then our general partner may adopt such amendments to our partnership agreement as it determines necessary or advisable to:

•

obtain proof of the nationality, citizenship or other related status of our limited partners (and their owners, to the extent relevant); and

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permit us to redeem the units held by any person whose nationality, citizenship or other related status creates substantial risk of cancellation or forfeiture of any property or who fails to comply with the procedures instituted by the general partner to obtain proof of the nationality, citizenship or other related status. The redemption price in the case of such a redemption will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption.

Meetings; Voting

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited.

Our general partner does not anticipate that any meeting of our unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum, unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage. Our general partner may postpone any meeting of the unitholders one or more times for any reason by giving notice to the unitholders entitled to vote at such meeting. Our general partner may also adjourn any meeting of unitholders one or more times for any reason, including the absence of a quorum, without a vote of the unitholders.

Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “—Issuance of Additional Interests.” However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates and purchasers specifically approved by our general partner, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any

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matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise. Except as our partnership agreement otherwise provides, subordinated units will vote together with common units, as a single class.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record common unitholders under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Voting Rights of Incentive Distribution Rights

If a majority of the incentive distribution rights are held by our general partner and its affiliates, the holders of the incentive distribution rights will have no right to vote in respect of such rights on any matter, unless otherwise required by law, and the holders of the incentive distribution rights shall be deemed to have approved any matter approved by our general partner.

If less than a majority of the incentive distribution rights are held by our general partner and its affiliates, the incentive distribution rights will be entitled to vote on all matters submitted to a vote of unitholders, other than amendments and other matters that our general partner determines do not adversely affect the holders of the incentive distribution rights in any material respect. On any matter in which the holders of incentive distribution rights are entitled to vote, such holders will vote together with the subordinated units, prior to the end of the subordination period, or together with the common units, thereafter, in either case as a single class, and such incentive distribution rights shall be treated in all respects as subordinated units or common units, as applicable, when sending notices of a meeting of our limited partners to vote on any matter (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under our partnership agreement. The relative voting power of the holders of the incentive distribution rights and the subordinated units or common units, depending on which class the holders of incentive distribution rights are voting with, will be set in the same proportion as cumulative cash distributions, if any, in respect of the incentive distribution rights for the four consecutive quarters prior to the record date for the vote bears to the cumulative cash distributions in respect of such class of units for such four quarters.

Status as Limited Partner

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Except as described under “—Limited Liability,” the common units will be fully paid, and unitholders will not be required to make additional contributions.

Indemnification

Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:

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our general partner;

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any departing general partner;

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any person who is or was an affiliate of our general partner or any departing general partner;

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any person who is or was a director, officer, managing member, manager, general partner, fiduciary or trustee of us or our subsidiaries, an affiliate of us or our subsidiaries or any entity set forth in the preceding three bullet points;

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any person who is or was serving as director, officer, managing member, manager, general partner, fiduciary or trustee of another person owing a fiduciary duty to us or any of our subsidiaries;

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any person who controls our general partner or any departing general partner; and

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any person designated by our general partner.

Any indemnification under these provisions will only be out of our assets. Unless our general partner otherwise agrees, it will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

Reimbursement of Expenses

Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine the expenses that are allocable to us.

Books and Reports

Our general partner is required to keep appropriate books of our business at our principal offices. These books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.

We will furnish or make available to record holders of our common units, within 105 days after the close of each fiscal year, an annual report containing audited consolidated financial statements and a report on those consolidated financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 50 days after the close of each quarter. We will be deemed to have made any such report available if we file such report with the SEC on EDGAR or make the report available on a publicly available website which we maintain.

We will furnish each record holder with information reasonably required for federal and state tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to our unitholders will depend on their cooperation in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and in filing his federal and state income tax returns, regardless of whether he supplies us with the necessary information.

Right to Inspect Our Books and Records

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at his own expense, have furnished to him:

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a current list of the name and last known address of each record holder;

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copies of our partnership agreement, our certificate of limited partnership, and all amendments thereto, together with copies of the executed copies of all powers of attorney pursuant to which our partnership agreement, our certificate of limited partnership and all amendments thereto have been executed; and

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•

information regarding the status of our business and financial condition (provided that obligation shall be satisfied to the extent the limited partner is furnished our most recent annual report and any subsequent quarterly or periodic reports required to be filed (or which would be required to be filed) with the SEC pursuant to Section 13(a) of the Exchange Act).

Under our partnership agreement, however, each of our limited partners and other persons who acquire interests in our partnership interests, do not have rights to receive information from us or any of the persons we indemnify as described above under “—Indemnification” for the purpose of determining whether to pursue litigation or assist in pending litigation against us or those indemnified persons relating to our affairs, except pursuant to the applicable rules of discovery relating to the litigation commenced by the person seeking information.

Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interests or that we are required by law or by agreements with third parties to keep confidential. Our partnership agreement limits the rights to information that a limited partner would otherwise have under Delaware law.

Registration Rights

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units or other limited partner interests proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of our general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts.

In addition, in connection with this offering, we expect to enter into a registration rights agreement with our general partner and certain of its affiliates. Pursuant to the registration rights agreement, we will be required to file a registration statement to register the common units and subordinated units issued to our general partner or its affiliates and the common units issuable upon the conversion of the subordinated units upon request of our general partner. In addition, the registration rights agreement gives our general partner and certain of its affiliates piggyback registration rights under certain circumstances. The registration rights agreement also includes provisions dealing with holdback agreements, indemnification and contribution and allocation of expenses. These registration rights are transferable to affiliates of our general partner and, in certain circumstances, to third parties. Please read “Units Eligible for Future Sale.”

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UNITS ELIGIBLE FOR FUTURE SALE

After the sale of the common units offered by this prospectus, our general partner and its affiliates will hold an aggregate of common units and subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and some may convert earlier. For information regarding the conversion of subordinated units into common units prior to the end of the subordination period, please read “The Partnership Agreement—Withdrawal or Removal of Our General Partner.” The sale of these common and subordinated units could have an adverse impact on the price of the common units or on any trading market that may develop.

Our common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units held by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

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1% of the total number of the securities outstanding; or

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the average weekly reported trading volume of our common units for the four weeks prior to the sale.

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned our common units for at least six months (provided we are in compliance with the current public information requirement), or one year (regardless of whether we are in compliance with the current public information requirement), would be entitled to sell those common units under Rule 144, subject only to the current public information requirement. After beneficially owning Rule 144 restricted units for at least one year, a person who is not deemed to have been an affiliate of ours at any time during the 90 days preceding a sale would be entitled to freely sell those common units without regard to the public information requirements, volume limitations, manner of sale provisions and notice requirements of Rule 144.

Issuance of Additional Interests

Our partnership agreement provides that we may issue an unlimited number of limited partner interests of any type at any time without a vote of the unitholders. Any issuance of additional common units or other equity securities would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. Please read “The Partnership Agreement—Issuance of Additional Interests.”

Partnership Agreement and Registration Rights Agreement

Under our partnership agreement and the registration rights agreement that we expect to enter into, our general partner and its affiliates will have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any units that they hold. Subject to the terms and conditions of the partnership agreement and the registration rights agreement, these registration rights allow our general partner and its affiliates or their assignees holding any units to require registration of any of these units and to include any of these units in a registration by us of other units, including units offered by us or by any unitholder. Our general partner and its affiliates will continue to have these registration rights for two years following its withdrawal or removal as our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors, and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discount. Except as described below, our general partner and its affiliates may sell their units in private transactions at any time, subject to compliance with applicable laws.

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Lock-up Agreement

We, Azure Midstream Holdings, our general partner and the directors and executive officers of our general partner have agreed not to sell any common units they beneficially own for a period of 180 days from the date of this prospectus. Participants in our directed unit program will be subject to similar restrictions. Please read “Underwriting” for a description of these lock-up provisions. Please read “Underwriting” for a description of these lock-up provisions.

Registration Statement on Form S-8

Prior to the completion of this offering, we expect to adopt a new long-term incentive plan (the “Long-Term Incentive Plan”). If such plan is adopted, we intend to file a registration statement on Form S-8 under the Securities Act to register common units issuable under the Long-Term Incentive Plan. This registration statement on Form S-8 is expected to be filed following the effective date of the registration statement of which this prospectus is a part and will be effective upon filing. Accordingly, common units issued under the Long-Term Incentive Plan will be eligible for resale in the public market without restriction after the effective date of the Form S-8 registration statement, subject to applicable vesting requirements, Rule 144 limitations applicable to affiliates and the lock-up restrictions described above.

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MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES

This section summarizes the material federal income tax consequences that may be relevant to prospective unitholders and is based upon current provisions of the Internal Revenue Code of 1986, as amended (the “Code”), existing and proposed Treasury regulations thereunder (the “Treasury Regulations”), and current administrative rulings and court decisions, all of which are subject to change, possibly with retroactive effect. Changes in these authorities may cause the federal income tax consequences to a prospective unitholder to vary substantially from those described below, possibly on a retroactive basis. Unless the context otherwise requires, references in this section to “we” or “us” are references to Azure Midstream Partners, LP and its subsidiaries.

Legal conclusions contained in this section, unless otherwise noted, are the opinion of Vinson & Elkins L.L.P. and are based on the accuracy of representations made by us to them for this purpose. However, this section does not address all U.S. federal income tax matters that affect us or our unitholders and does not describe the application of the alternative minimum tax that may be applicable to certain unitholders. Furthermore, this section focuses on unitholders who are individual citizens or residents of the United States (for federal income tax purposes), who have the U.S. dollar as their functional currency, who use the calendar year as their taxable year, who purchase units subject to this registration statement, who do not materially participate in the conduct of our business activities, and who hold units as capital assets (generally, property that is held for investment). This section has limited applicability to corporations, partnerships, (including entities treated as partnerships for federal income tax purposes), estates, trusts, non-resident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, non-U.S. persons, IRAs, employee benefit plans, real estate investment trusts or mutual funds. Accordingly, we encourage each unitholder to consult the unitholder’s own tax advisor in analyzing the federal, state, local and non-U.S. tax consequences particular to that unitholder resulting from ownership or disposition of units and potential changes in applicable tax laws.

We are relying on opinions and advice of Vinson & Elkins L.L.P. with respect to the matters described herein. An opinion of counsel represents only that counsel’s best legal judgment and does not bind the Internal Revenue Service (the “IRS”) or a court. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any such contest of the matters described herein may materially and adversely impact the market for units and the prices at which our units trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders because the costs will reduce our distributable cash flow. Furthermore, the tax consequences of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions, which may be retroactively applied.

For the reasons described below, Vinson & Elkins L.L.P. has not rendered an opinion with respect to the following U.S. federal income tax issues: (i) the treatment of a unitholder whose units are the subject of a securities loan (e.g., a loan to a short seller to cover a short sale of units) (please read “—Tax Consequences of Unit Ownership—Treatment of Securities Loans”); (ii) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “—Disposition of Units—Allocations Between Transferors and Transferees”); and (iii) whether our method for taking into account Section 743 adjustments is sustainable in certain cases (please read “—Tax Consequences of Unit Ownership—Section 754 Election” and “—Uniformity of Units”).

Taxation of the Partnership

Partnership Status

We expect to be treated as a partnership for U.S. federal income tax purposes and, therefore, generally will not be liable for entity-level federal income taxes. Instead, as described below, each of our unitholders will take into account its respective share of our items of income, gain, loss and deduction in computing its federal income tax liability as if the unitholder had earned such income directly, even if we make no cash distributions to the unitholder.

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Section 7704 of the Code generally provides that publicly-traded partnerships will be treated as corporations for U.S. federal income tax purposes. However, if 90% or more of a partnership’s gross income for every taxable year it is publicly-traded consists of “qualifying income,” the partnership may continue to be treated as a partnership for federal income tax purposes (the “Qualifying Income Exception”). Qualifying income includes income and gains derived from the transportation, storage, processing and marketing of certain natural resources, including crude oil, natural gas and products thereof, as well as other types of income such as interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than % of our current gross income is not qualifying income; however, this estimate could change from time to time.

Based upon factual representations made by us and our general partner, Vinson & Elkins L.L.P. is of the opinion that we will be treated as a partnership and our partnership and limited liability company subsidiaries will be disregarded as entities separate from us for federal income tax purposes. The representations made by us and our general partner upon which Vinson & Elkins L.L.P. has relied in rendering its opinion include, without limitation:

(a) Neither we nor any of our partnership or limited liability company subsidiaries has elected or will elect to be treated as a corporation for federal income tax purposes;

(b) For each taxable year since and including the year of our initial public offering, more than 90% of our gross income has been and will be income of a character that Vinson & Elkins L.L.P. has opined is “qualifying income” within the meaning of Section 7704(d) of the Code; and

(c) Each hedging transaction that we treat as resulting in qualifying income has been and will be appropriately identified as a hedging transaction pursuant to applicable Treasury Regulations, and has been and will be associated with oil, natural gas, or products thereof that are held or to be held by us in activities that Vinson & Elkins L.L.P. has opined or will opine result in qualifying income.

We believe that these representations are true and will be true in the future.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as transferring all of our assets, subject to all of our liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation and then as distributing that stock to our unitholders in liquidation. This deemed contribution and liquidation should not result in the recognition of taxable income by our unitholders or us so long as the aggregate amount of our liabilities does not exceed the adjusted tax basis of our assets. Thereafter, we would be treated as an association taxable as a corporation for U.S. federal income tax purposes.

The present U.S. federal income tax treatment of publicly-traded partnerships, including us, or an investment in our common units may be modified by administrative or legislative action or judicial interpretation at any time. For example, from time to time, members of the U.S. Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly-traded partnerships. One such legislative proposal would have eliminated the Qualifying Income Exception upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any such changes will ultimately be enacted. However, it is possible that a change in law could affect us and may be applied retroactively. Any such changes could negatively impact the value of an investment in our units.

If for any reason we are taxable as a corporation in any taxable year, our items of income, gain, loss and deduction would be taken into account by us in determining the amount of our liability for U.S. federal income tax, rather than being passed through to our unitholders. Our taxation as a corporation would materially reduce our distributable cash flow and thus would likely substantially reduce the value of our units. Any distribution

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made to a unitholder at a time we are treated as a corporation would be (i) a taxable dividend to the extent of our current or accumulated earnings and profits, then (ii) a nontaxable return of capital to the extent of the unitholder’s adjusted tax basis in its units, and thereafter (iii) taxable capital gain.

The remainder of this discussion is based on the opinion of Vinson & Elkins L.L.P. that we will be treated as a partnership for U.S. federal income tax purposes.

Tax Consequences of Unit Ownership

Limited Partner Status

Unitholders who are admitted as limited partners of the partnership, as well as unitholders whose units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of units, will be treated as partners of the partnership for federal income tax purposes. For a discussion related to the risks of losing partner status as a result of securities loans, please read “—Treatment of Securities Loans.” Unitholders who are not treated as partners in us as described above are urged to consult their own tax advisors with respect to the tax consequences applicable to them under their particular circumstances.

Flow-Through of Taxable Income

Subject to the discussion below under “—Entity-Level Collections of Unitholder Taxes” with respect to payments we may be required to make on behalf of our unitholders, we will not pay any federal income tax. Rather, each unitholder will be required to report on its federal income tax return each year its share of our income, gains, losses and deductions for our taxable year or years ending with or within its taxable year. Consequently, we may allocate income to a unitholder even if that unitholder has not received a cash distribution.

Basis of Units

A unitholder’s tax basis in its units initially will be the amount paid for those units increased by the unitholder’s initial allocable share (as measured for federal income tax purposes) of our “nonrecourse” liabilities (liabilities for which no partner bears the economic risk of loss). That basis generally will be (i) increased by the unitholder’s share of our income and any increases in such unitholder’s share of our nonrecourse liabilities, and (ii) decreased, but not below zero, by the amount of all distributions to the unitholder, the unitholder’s share of our losses, and any decreases in the unitholder’s share of our nonrecourse liabilities and its share of our expenditures that are neither deductible nor required to be capitalized. The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all of those interests.

Ratio of Taxable Income to Distributions

We estimate that a purchaser of units in this offering who owns those units from the date of closing of this offering through the record date for distributions for the period ending December 31, , will be allocated, on a cumulative basis, an amount of federal taxable income that will be % or less of the cash distributed on those units with respect to that period. These estimates are based upon the assumption that earnings from operations will approximate the amount required to make the minimum quarterly distribution on all units and other assumptions with respect to capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and which could be changed or with which the IRS could disagree. Accordingly, we cannot assure that these estimates will prove to be correct, and our counsel has not opined on the accuracy of such estimates. The actual ratio of taxable income to cash

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distributions could be higher or lower than expected, and any differences could be material and could affect the value of units. For example, the ratio of taxable income to cash distributions to a purchaser of units in this offering would be higher, and perhaps substantially higher, than our estimate with respect to the period described above if:

We distribute less cash than we have assumed in making this projection; or we make a future offering of units and use the proceeds of the offering in a manner that does not produce additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes during such period or that is depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering.

Treatment of Distributions

Distributions by us to a unitholder generally will not be taxable to the unitholder, unless such distributions exceed the unitholder’s tax basis in its units, in which case the unitholder generally will recognize gain taxable in the manner described below under “—Disposition of Units.”

Any reduction in a unitholder’s share of our “nonrecourse liabilities” (liabilities for which no partner bears the economic risk of loss) will be treated as a distribution by us of cash to that unitholder. A decrease in a unitholder’s percentage interest in us because of our issuance of additional units may decrease the unitholder’s share of our nonrecourse liabilities. For purposes of the foregoing, a unitholder’s share of our nonrecourse liabilities generally will be based upon that unitholder’s share of the unrealized appreciation (or depreciation) in our assets, to the extent thereof, with any excess liabilities allocated based on the unitholder’s share of our profits. Please read “—Disposition of Units.”

A non-pro rata distribution of money or property (including a deemed distribution as a result of a reallocation of our nonrecourse liabilities described above) may cause a unitholder to recognize ordinary income, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture and substantially appreciated “inventory items,” both as defined in Section 751 of the Code (“Section 751 Assets”). To the extent of such reduction, the unitholder would be deemed to receive its proportionate share of the Section 751 Assets and exchange such assets with us in return for a portion of the non-pro rata distribution. This deemed exchange generally will result in the unitholder’s recognition of ordinary income in an amount equal to the excess of (i) the non-pro rata portion of that distribution over (ii) the unitholder’s tax basis (generally zero) in the Section 751 Assets deemed to be relinquished in the exchange.

Limitations on Deductibility of Losses

A unitholder may not be entitled to deduct the full amount of loss we allocate to it because its share of our losses will be limited to the lesser of (i) the unitholder’s adjusted tax basis in its units, and (ii) in the case of a unitholder that is an individual, estate, trust or certain types of closely-held corporations, the amount for which the unitholder is considered to be “at risk” with respect to our activities. In general, a unitholder will be at risk to the extent of its adjusted tax basis in its units, reduced by (x) any portion of that basis attributable to the unitholder’s share of our nonrecourse liabilities, (y) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or similar arrangement and (z) any amount of money the unitholder borrows to acquire or hold its units, if the lender of those borrowed funds owns an interest in us, is related to another unitholder or can look only to the units for repayment. A unitholder subject to the at risk limitation must recapture losses deducted in previous years to the extent that distributions (including distributions deemed to result from a reduction in a unitholder’s share of nonrecourse liabilities) cause the unitholder’s at risk amount to be less than zero at the end of any taxable year.

Losses disallowed to a unitholder or recaptured as a result of the basis or at risk limitations will carry forward and will be allowable as a deduction in a later year to the extent that the unitholder’s adjusted tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon a taxable disposition of units,

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any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but not losses suspended by the basis limitation. Any loss previously suspended by the at risk limitation in excess of that gain can no longer be used, and will not be available to offset a unitholder’s salary or active business income.

In addition to the basis and at risk limitations, a passive activity loss limitation generally limits the deductibility of losses incurred by individuals, estates, trusts, some closely-held corporations and personal service corporations from “passive activities” (generally, trade or business activities in which the taxpayer does not materially participate). The passive loss limitations are applied separately with respect to each publicly-traded partnership. Consequently, any passive losses we generate will be available to offset only passive income generated by us. Passive losses that exceed a unitholder’s share of passive income we generate may be deducted in full when the unitholder disposes of all of its units in a fully taxable transaction with an unrelated party. The passive loss rules generally are applied after other applicable limitations on deductions, including the at risk and basis limitations.

Limitations on Interest Deductions

The deductibility of a non-corporate taxpayer’s “investment interest expense” generally is limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:

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interest on indebtedness allocable to property held for investment;

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interest expense allocated against portfolio income; and

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the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent allocable against portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses other than interest directly connected with the production of investment income. Net investment income generally does not include qualified dividend income or gains attributable to the disposition of property held for investment. A unitholder’s share of a publicly-traded partnership’s portfolio income and, according to the IRS, net passive income will be treated as investment income for purposes of the investment interest expense limitation.

Entity-Level Collections of Unitholder Taxes

If we are required or elect under applicable law to pay any U.S. federal, state, local or non-U.S. tax on behalf of any current or former unitholder or our general partner, we are authorized to treat the payment as a distribution of cash to the relevant unitholder or our general partner. Where the tax is payable on behalf of all the unitholders or we cannot determine the specific unitholder on whose behalf the tax is payable, we are authorized to treat the payment as a distribution to all current unitholders. Payments by us as described above could give rise to an overpayment of tax on behalf of a unitholder, in which event the unitholder may be entitled to claim a refund of the overpayment amount. Unitholders are urged to consult their own tax advisors to determine the consequences to them of any tax payment we make on their behalf.

Allocation of Income, Gain, Loss and Deduction

Our items of income, gain, loss and deduction generally will be allocated among our unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or we make incentive distributions, gross income will be allocated to the recipients to the extent of these distributions.

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Specified items of our income, gain, loss and deduction will be allocated under Section 704(c) of the Code (or the principles of Section 704(c) of the Code) to account for any difference between the adjusted tax basis and fair market value of our assets at the time such assets are contributed to us and at the time of any subsequent offering of our units (a “Book-Tax Disparity”). As a result, the U.S. federal income tax burden associated with any Book-Tax Disparity immediately prior to an offering generally will be borne by our partners holding interests in us prior to such offering. In addition, items of recapture income will be specially allocated to the extent possible (subject to the limitations described above) to the unitholder who was allocated the deduction giving rise to that recapture income in order to minimize the recognition of ordinary income by other unitholders.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Code to eliminate a Book-Tax Disparity, will generally be given effect for U.S. federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has “substantial economic effect.” In any other case, a partner’s share of an item will be determined on the basis of the partner’s interest in us, which will be determined by taking into account all the facts and circumstances, including (i) the partner’s relative contributions to us, (ii) the interests of all the partners in profits and losses, (iii) the interest of all the partners in cash flow and (iv) the rights of all the partners to distributions of capital upon liquidation. Vinson & Elkins L.L.P. is of the opinion that, with the exception of the issues described in “—Section 754 Election” and “—Disposition of Units—Allocations Between Transferors and Transferees,” allocations of income, gain, loss or deduction under our partnership agreement will be given effect for U.S. federal income tax purposes.

Treatment of Securities Loans

A unitholder whose units are loaned (for example, a loan to a “short seller” to cover a short sale of units) may be treated as having disposed of those units. If so, such unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period (i) any of our income, gain, loss or deduction allocated to those units would not be reportable by the lending unitholder, and (ii) any cash distributions received by the unitholder as to those units may be treated as ordinary taxable income.

Due to a lack of controlling authority, Vinson & Elkins L.L.P. has not rendered an opinion regarding the tax treatment of a unitholder that enters into a securities loan with respect to its units. Unitholders desiring to assure their status as partners and avoid the risk of income recognition from a loan of their units are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and lending their units. The IRS has announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please read “—Disposition of Units—Recognition of Gain or Loss.”

Tax Rates

Under current law, the highest marginal federal income tax rates for individuals applicable to ordinary income and long-term capital gains (generally, gains from the sale or exchange of certain investment assets held for more than one year) are 39.6% and 20%, respectively. These rates are subject to change by new legislation at any time.

In addition, a 3.8% net investment income tax (“NIIT”) applies to certain net investment income earned by individuals, estates, and trusts. For these purposes, net investment income generally includes a unitholder’s allocable share of our income and gain realized by a unitholder from a sale of units. In the case of an individual, the tax will be imposed on the lesser of (i) the unitholder’s net investment income from all investments, or (ii) the amount by which the unitholder’s modified adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or a surviving spouse), $125,000 (if married filing separately) or $200,000 (if the unitholder is unmarried or in any other case). In the case of an estate or trust, the tax will be imposed on the lesser of (i) undistributed net investment income, or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

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Section 754 Election

We will make the election permitted by Section 754 of the Code that permits us to adjust the tax bases in our assets as to specific purchasers of our units under Section 743(b) of the Code. That election is irrevocable without the consent of the IRS. The Section 743(b) adjustment separately applies to each purchaser of units based upon the values and adjusted tax bases of our assets at the time of the relevant purchase, and the adjustment will reflect the purchase price paid. The Section 743(b) adjustment does not apply to a person who purchases units directly from us.

Under our partnership agreement, we are authorized to take a position to preserve the uniformity of units even if that position is not consistent with applicable Treasury Regulations. A literal application of Treasury Regulations governing a Section 743(b) adjustment attributable to properties depreciable under Section 167 of the Code may give rise to differences in the taxation of unitholders purchasing units from us and unitholders purchasing from other unitholders. If we have any such properties, we intend to adopt methods employed by other publicly-traded partnerships to preserve the uniformity of units, even if inconsistent with existing Treasury Regulations, and Vinson & Elkins L.L.P. has not opined on the validity of this approach. Please read “—Uniformity of Units.”

The IRS may challenge the positions we adopt with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of units due to lack of controlling authority. Because a unitholder’s adjusted tax basis for its units is reduced by its share of our items of deduction or loss, any position we take that understates deductions will overstate a unitholder’s adjusted tax basis in its units, and may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “—Disposition of Units—Recognition of Gain or Loss.” If a challenge to such treatment were sustained, the gain from the sale of units may be increased without the benefit of additional deductions.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. The IRS could seek to reallocate some or all of any Section 743(b) adjustment we allocated to our assets subject to depreciation to goodwill or nondepreciable assets. Goodwill, as an intangible asset, is generally amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure any unitholder that the determinations we make will not be successfully challenged by the IRS or that the resulting deductions will not be reduced or disallowed altogether. Should the IRS require a different tax basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than it would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year

We will use the year ending December 31 as our taxable year and the accrual method of accounting for U.S. federal income tax purposes. Each unitholder will be required to include in its tax return its share of our income, gain, loss and deduction for each taxable year ending within or with its taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of its units following the close of our taxable year but before the close of its taxable year must include its share of our income, gain, loss and deduction in income for its taxable year, with the result that it will be required to include in income for its taxable year its share of more than twelve months of our income, gain, loss and deduction. Please read “—Disposition of Units—Allocations Between Transferors and Transferees.”

Tax Basis, Depreciation and Amortization

The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of those assets. If we dispose of depreciable property by sale,

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foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation deductions previously taken, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of its interest in us. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction.”

The costs we incur in offering and selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. While there are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us, the underwriting discounts and commissions we incur will be treated as syndication expenses.

Valuation and Tax Basis of Our Properties

The U.S. federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values and the tax bases of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of tax basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deduction previously reported by unitholders could change, and unitholders could be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Units

Recognition of Gain or Loss

A unitholder will be required to recognize gain or loss on a sale of units equal to the difference, if any, between the unitholder’s amount realized and tax basis in the units sold. A unitholder’s amount realized generally will equal the sum of the cash and the fair market value of other property it receives plus its share of our nonrecourse liabilities with respect to the units sold. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Except as noted below, gain or loss recognized by a unitholder on the sale or exchange of a unit held for more than one year generally will be taxable as long-term capital gain or loss. However, gain or loss recognized on the disposition of units will be separately computed and taxed as ordinary income or loss under Section 751 of the Code to the extent attributable to Section 751 Assets, such as depreciation recapture and our “inventory items,” regardless of whether such inventory item is substantially appreciated in value. Ordinary income attributable to Section 751 Assets may exceed net taxable gain realized on the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and capital gain or loss upon a sale of units. Net capital loss may offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year.

For purposes of calculating gain or loss on the sale of units, the unitholder’s adjusted tax basis will be adjusted by its allocable share of our income or loss in respect of its units for the year of the sale. Furthermore, as described above, the IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all of those interests. Upon a sale or other disposition of less than all of those interests, a portion of that adjusted tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s adjusted tax basis in its entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership.

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Treasury Regulations under Section 1223 of the Code allow a selling unitholder who can identify units transferred with an ascertainable holding period to elect to use the actual holding period of the units transferred. Thus, according to the ruling discussed in the paragraph above, a unitholder will be unable to select high or low basis units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, it may designate specific units sold for purposes of determining the holding period of the units transferred. A unitholder electing to use the actual holding period of units transferred must consistently use that identification method for all subsequent sales or exchanges of our units. A unitholder considering the purchase of additional units or a sale of units purchased in separate transactions is urged to consult its tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

Specific provisions of the Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” financial position, including a partnership interest with respect to which gain would be recognized if it were sold, assigned or terminated at its fair market value, in the event the taxpayer or a related person enters into:

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a short sale;

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an offsetting notional principal contract; or

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a futures or forward contract with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is authorized to issue Treasury Regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees

In general, our taxable income or loss will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month (the “Allocation Date”). However, gain or loss realized on a sale or other disposition of our assets or, in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction will be allocated among the unitholders on the Allocation Date in the month in which such income, gain, loss or deduction is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although simplifying conventions are contemplated by the Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations. Recently, however, the Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly-traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis. Nonetheless, the proposed regulations will not be effective until they are issued in their final form, and the proposed regulations do not specifically authorize the use of the proration method we have adopted. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the validity of this method of allocating income and deductions between transferee and transferor unitholders. If this method is not allowed under the final Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses could be reallocated among our unitholders. We are authorized to revise our method of allocation between transferee and transferor unitholders, as well as among unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

A unitholder who disposes of units prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deduction attributable to the month of disposition but will not be entitled to receive a cash distribution for that period.

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Notification Requirements

A unitholder who sells or purchases any of its units is generally required to notify us in writing of that transaction within 30 days after the transaction (or, if earlier, January 15 of the year following the transaction in the case of a seller). Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a transfer of units may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale through a broker who will satisfy such requirements.

Constructive Termination

We will be considered to have “constructively” terminated as a partnership for federal income tax purposes upon the sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of measuring whether the 50% threshold is reached, multiple sales of the same unit are counted only once. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than the calendar year, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in such unitholder’s taxable income for the year of termination.

A constructive termination occurring on a date other than December 31 generally would require that we file two tax returns for one fiscal year thereby increasing our administration and tax preparation costs. However, pursuant to an IRS relief procedure the IRS may allow a constructively terminated partnership to provide a single Schedule K-1 for the calendar year in which a termination occurs. Following a constructive termination, we would be required to make new tax elections, including a new election under Section 754 of the Code, and the termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination may either accelerate the application of, or subject us to, any tax legislation enacted before the termination that would not otherwise have been applied to us as a continuing as opposed to a terminating partnership.

Uniformity of Units

Because we cannot match transferors and transferees of units and other reasons, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. As a result of the need to preserve uniformity, we may be unable to completely comply with a number of U.S. federal income tax requirements. Any non-uniformity could have a negative impact on the value of the units. Please read “—Tax Consequences of Unit Ownership—Section 754 Election.”

Our partnership agreement permits our general partner to take positions in filing our tax returns that preserve the uniformity of our units. These positions may include reducing the depreciation, amortization or loss deductions to which a unitholder would otherwise be entitled or reporting a slower amortization of Section 743(b) adjustments for some unitholders than that to which they would otherwise be entitled. Vinson & Elkins L.L.P. is unable to opine as to the validity of such filing positions.

A unitholder’s adjusted tax basis in units is reduced by its share of our deductions (whether or not such deductions were claimed on an individual income tax return) so that any position that we take that understates deductions will overstate the unitholder’s basis in its units, and may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “—Disposition of Units—Recognition of Gain or Loss” above and “—Tax Consequences of Unit Ownership—Section 754 Election” above. The IRS may challenge one or more of any positions we take to preserve the uniformity of units. If such a challenge were sustained, the uniformity of units might be affected, and, under some circumstances, the gain from the sale of units might be increased without the benefit of additional deductions.

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Tax-Exempt Entities and Other Investors

Ownership of units by employee benefit plans and other tax-exempt entities as well as by non-resident alien individuals, non-U.S. corporations and other non-U.S. persons (collectively, “Non-U.S. Unitholders”) raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them. Prospective unitholders that are tax-exempt entities or Non-U.S. Unitholders should consult their tax advisors before investing in our units. Employee benefit plans and most other tax-exempt entities, including IRAs and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income will be unrelated business taxable income and will be taxable to a tax-exempt unitholder.

Non-U.S. Unitholders are taxed by the United States on income effectively connected with the conduct of a U.S. trade or business (“effectively connected income”) and on certain types of U.S.-source non-effectively connected income (such as dividends), unless exempted or further limited by an income tax treaty. Non-U.S. Unitholders will be considered to be engaged in business in the United States because of their ownership of our units. Furthermore, is it probable that they will be deemed to conduct such activities through permanent establishments in the United States within the meaning of applicable tax treaties. Consequently, they will be required to file U.S. federal tax returns to report their share of our income, gain, loss or deduction and pay U.S. federal income tax on their share of our net income or gain in a manner similar to a taxable U.S. unitholder. Moreover, under rules applicable to publicly-traded partnerships, distributions to Non-U.S. Unitholders are subject to withholding at the highest applicable U.S. federal effective tax rate. Each Non-U.S. Unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes.

In addition, because a Non-U.S. Unitholder classified as a corporation will be treated as engaged in a United States trade or business, that corporation may be subject to the U.S. branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain as adjusted for changes in the foreign corporation’s “U.S. net equity” to the extent reflected in the corporation’s effectively connected earnings and profits. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Code.

A Non-U.S. Unitholder who sells or otherwise disposes of a unit will be subject to U.S. federal income tax on any gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the Non-U.S. Unitholder. Under a ruling published by the IRS interpreting the scope of “effectively connected income,” gain recognized by a non-U.S. person from the sale of its interest in a partnership that is engaged in a trade or business in the United States will be considered to be effectively connected with a U.S. trade or business. Thus, part or all of a Non-U.S. Unitholder’s gain from the sale or other disposition of its units may be treated as effectively connected with a unitholder’s indirect U.S. trade or business constituted by its investment in us. Moreover, under the Foreign Investment in Real Property Tax Act, a Non-U.S. Unitholder generally will be subject to federal income tax upon the sale or disposition of a unit if (i) it owned (directly or constructively applying certain attribution rules) more than 5% of our units at any time during the five-year period ending on the date of such disposition and (ii) 50% or more of the fair market value of our worldwide real property interests and our other assets used or held for use in a trade or business consisted of U.S. real property interests (which include U.S. real estate (including land, improvements, and certain associated personal property) and interests in certain entities holding U.S. real estate) at any time during the shorter of the period during which such unitholder held the units or the five-year period ending on the date of disposition. More than 50% of our assets may consist of U.S. real property interests. Therefore, Non-U.S. Unitholders may be subject to U.S. federal income tax (and in the case of a foreign corporation, possible branch profits tax) on gain from the sale or disposition of their units.

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Administrative Matters

Information Returns and Audit Procedures

We intend to furnish to each unitholder, within 90 days after the close of each taxable year, specific tax information, including a Schedule K-1, which describes its share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure our unitholders that those positions will yield a result that conforms to all of the requirements of the Code, Treasury Regulations or administrative interpretations of the IRS.

The IRS may audit our U.S. federal income tax information returns. Neither we nor Vinson & Elkins L.L.P. can assure prospective unitholders that the IRS will not successfully challenge the positions we adopt, and such a challenge could adversely affect the value of the units. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability and may result in an audit of the unitholder’s own return. Any audit of a unitholder’s return could result in adjustments unrelated to our returns.

Publicly-traded partnerships generally are treated as entities separate from their owners for purposes of U.S. federal income tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings of the partners. The Code requires that one partner be designated as the “Tax Matters Partner” for these purposes, and our partnership agreement designates our general partner.

The Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review may go forward, and each unitholder with an interest in the outcome may participate in that action.

A unitholder must file a statement with the IRS identifying the treatment of any item on its federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Nominee Reporting

Persons who hold an interest in us as a nominee for another person are required to furnish to us:

(1) the name, address and taxpayer identification number of the beneficial owner and the nominee;

(2) a statement regarding whether the beneficial owner is:

(a) a non-U.S. person;

(b) a non-U.S. government, an international organization or any wholly-owned agency or instrumentality of either of the foregoing; or

(3) the amount and description of units held, acquired or transferred for the beneficial owner; and

(4) specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

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Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $100 per failure, up to a maximum of $1.5 million per calendar year, is imposed by the Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Accuracy-Related Penalties

Certain penalties may be imposed as a result of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for the underpayment of that portion and that the taxpayer acted in good faith regarding the underpayment of that portion. We do not anticipate that any accuracy related penalties will be assessed against us.

State, Local and Other Tax Considerations

In addition to federal income taxes, unitholders may be subject to other taxes, including state and local income taxes, unincorporated business taxes, and estate, inheritance or intangibles taxes that may be imposed by the various jurisdictions in which we conduct business or own property now or in the future or in which the unitholder is a resident. We currently conduct business or own property in Texas. Texas does not impose a personal income tax on individuals, but does impose an income tax on corporations and other entities. In addition, we may also own property or do business in other states in the future that impose income or similar taxes on nonresident individuals. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on its investment in us.

Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. Some of the jurisdictions 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 jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of the unitholder’s investment in us. We strongly recommend that each prospective unitholder consult, and depend upon, its own tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and non-U.S., as well as U.S. federal tax returns that may be required of it. Vinson & Elkins L.L.P. has not rendered an opinion on the state, local, alternative minimum tax or non-U.S. tax consequences of an investment in us.

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INVESTMENT BY EMPLOYEE BENEFIT PLANS

An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and restrictions imposed by Section 4975 of the Internal Revenue Code. For these purposes the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs established or maintained by an employer or employee organization. Among other things, consideration should be given to:

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whether the investment is prudent under Section 404(a)(1)(B) of ERISA;

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whether in making the investment, that plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA; and

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whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return. Please read “Material U.S. Federal Income Tax Consequences—Tax-Exempt Entities and Other Investors.”

The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.

Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit employee benefit plans from engaging in specified transactions involving “plan assets” with parties that are “parties in interest” under ERISA or “disqualified persons” under the Internal Revenue Code with respect to the plan.

In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code.

The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets” under some circumstances. Under these regulations, an entity’s assets would not be considered to be “plan assets” if, among other things:

(i) the equity interests acquired by employee benefit plans are publicly offered securities—i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, freely transferable and registered under some provisions of the federal securities laws;

(ii) the entity is an “operating company”—i.e., it is primarily engaged in the production or sale of a product or service other than the investment of capital either directly or through a majority-owned subsidiary or subsidiaries; or

(iii) there is no significant investment by benefit plan investors, which is defined to mean that less than 20% of the value of each class of equity interest is held by the employee benefit plans referred to above.

Plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA and the Internal Revenue Code in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.

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UNDERWRITING

Citigroup Global Markets Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated are acting as joint book-running managers of the offering and as representatives of the underwriters named below. Subject to the terms and conditions stated in the underwriting agreement dated the date of this prospectus, each underwriter named below has severally agreed to purchase, and we have agreed to sell to that underwriter, the number of common units set forth opposite the underwriter’s name.


Underwriters		Number of Common Units
Citigroup Global Markets Inc.
Merrill Lynch, Pierce, Fenner & Smith Incorporated

Total

The underwriting agreement provides that the obligations of the underwriters to purchase the common units included in this offering are subject to approval of legal matters by counsel, including the validity of the common units, and to other conditions contained in the underwriting agreement, such as the receipt by the underwriters of officer’s certificates and legal opinions. The underwriters are obligated to purchase all the common units (other than those covered by the underwriters’ option to purchase additional common units described below) if they purchase any of the common units. If any underwriter defaults, the underwriting agreement provides that the purchase commitments of the non-defaulting underwriters may be increased or the underwriting agreement may be terminated. The underwriters reserve the right to withdraw, cancel or modify offers to the public and to reject orders in whole or in part.

Common units sold by the underwriters to the public will initially be offered at the initial public offering price set forth on the cover of this prospectus. Any common units sold by the underwriters to securities dealers may be sold at a discount from the initial public offering price not to exceed $ per common unit. After the common units are released for sale to the public, if all the common units are not sold at the initial offering price, the underwriters may change the offering price and the other selling terms. The offering of the common units by the underwriters is subject to receipt and acceptance and subject to the underwriters’ right to reject any order in whole or in part.

Option to Purchase Additional Common Units

If the underwriters sell more common units than the total number set forth in the table above, we have granted to the underwriters an option, exercisable for 30 days from the date of this prospectus, to purchase up to additional common units at the public offering price less the underwriting discount. To the extent the option is exercised, each underwriter must purchase a number of additional common units approximately proportionate to that underwriter’s initial purchase commitment. Any common units issued or sold under the option will be issued and sold on the same terms and conditions as the other common units that are the subject of this offering.

No Sales of Similar Securities

We, our general partner, our general partner’s officers, directors and equity holders, our affiliates and their officers and directors, have agreed that, for a period of 180 days from the date of this prospectus, we and they will not, without the prior written consent of each of Citigroup Global Markets Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated, offer, pledge, sell, contract to sell, sell any option or contract to purchase, purchase any option or contract to sell, grant any option, right or warrant to purchase, lend or otherwise transfer or dispose of, directly or indirectly, any common units or any securities convertible into or exercisable or exchangeable for our common units, or enter into any swap or other arrangement that transfers to another, in whole or in part, any of the economic consequences of ownership of the common units, whether any such transaction described above

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is to be settled by delivery of common units or such other securities, in cash or otherwise, subject to certain exceptions. Neither Citigroup Global Markets Inc. nor Merrill Lynch, Pierce, Fenner & Smith Incorporated has any present intention or any understanding, implicit or explicit, to release any of the common units or other securities subject to the look-up agreement prior to the expiration of the 180-day restricted period described above.

Directed Unit Program

At our request, the underwriters have reserved up to % of the common units for sale at the initial public offering price to persons who are directors, officers or employees, or who are otherwise associated with us through a directed unit program. The number of units available for sale to the general public will be reduced by the number of directed units purchased by participants in the program. Except for certain of our officers, directors and employees who have entered into lock-up agreements as contemplated in the immediately preceding paragraph, each person buying common units through the directed unit program has agreed that, for a period of 180 days from the date of this prospectus, he or she will not, without the prior written consent of Citigroup Global Markets Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated, dispose of or hedge any common units or any securities convertible into or exchangeable for our common units with respect to common units purchased in the program. For certain officers, directors and employees purchasing common units through the directed unit program, the lock-up agreements contemplated in the immediately preceding paragraph shall govern with respect to their purchases. Citigroup Global Markets Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated, in their sole discretion, may release any of the securities subject to these lock-up agreements at any time, which, in the case of officers and directors, shall be with notice. Any directed units not purchased will be offered by the underwriters to the general public on the same basis as all other common units offered. We have agreed to indemnify the underwriters against certain liabilities and expenses, including liabilities under the Securities Act, in connection with the sales of the directed units.

Listing

We intend to apply to have our common units approved for listing on the NYSE, subject to official notice of issuance, under the symbol “AZUR.” The underwriters have undertaken to sell common units to a minimum of 400 beneficial owners in lots of 100 or more common units to meet the NYSE’s distribution requirements for trading.

Prior to this offering, there has been no public market for our common units. Consequently, the initial public offering price for the common units was determined by negotiations among us and the representatives. Among the factors considered in determining the initial public offering price were our results of operations, our current financial condition, our future prospects, our markets, the economic conditions in and future prospects for the industry in which we compete, our management and currently prevailing general conditions in the equity securities markets, including current market valuations of publicly traded companies considered comparable to our company. We cannot, however, provide assurance that the price at which the common units will sell in the public market after this offering will not be lower than the initial public offering price or that an active trading market in our common units will develop and continue after this offering.

The representatives have advised us that the underwriters do not intend to confirm sales to discretionary accounts that exceed 5% of the total number of our common units offered by them.

Commissions and Discounts

The representatives have advised us that the underwriters propose initially to offer the common units to the public at the public offering price set forth on the cover page of this prospectus and to dealers at that price less a concession not in excess of $ per common unit. After the initial offering, the public offering price, concession or any other term of the offering may be changed.

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The following table shows the underwriting discounts and commissions that we are to pay to the underwriters in connection with this offering. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional common units.


	No exercise	Full exercise
Per Common Unit	$	$
Total	$	$

We will pay a structuring fee equal to an aggregate of % of the gross proceeds from this offering to Citigroup Global Markets Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated for the evaluation, analysis and structuring of our partnership.

We also have agreed to reimburse the underwriters for up to $ of the reasonable fees and expenses of counsel related to the review by the Financial Industry Regulatory Authority, Inc., or FINRA, of the terms of sale of the common units offered by this prospectus.

We estimate that the total expenses of this offering, not including the underwriting discount and structuring fee, will be approximately $ million, all of which will be paid by us.

Price Stabilization, Short Positions and Penalty Bids

In connection with this offering, the underwriters may purchase and sell common units in the open market. Purchases and sales in the open market may include short sales, purchases to cover short positions, which may include purchases pursuant to the underwriters’ option to purchase additional common units, and stabilizing purchases.

•

Short sales involve secondary market sales by the underwriters of a greater number of common units than they are required to purchase in this offering.

•

“Covered” short sales are sales of common units in an amount up to the number of common units represented by the underwriters’ option to purchase additional common units.

•

“Naked” short sales are sales of common units in an amount in excess of the number of common units represented by the underwriters’ option to purchase additional common units.

•

Covering transactions involve purchases of common units either pursuant to the underwriters’ option to purchase additional common units or in the open market after the distribution has been completed in order to cover short positions.

•

To close a naked short position, the underwriters must purchase common units in the open market after the distribution has been completed. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in this offering.

•

To close a covered short position, the underwriters must purchase common units in the open market after the distribution has been completed or must exercise the option to purchase additional common units. In determining the source of common units to close the covered short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through the option to purchase additional common units.

•

Stabilizing transactions involve bids to purchase common units so long as the stabilizing bids do not exceed a specified maximum.

The underwriters also may impose a penalty bid. Penalty bids permit the underwriters to reclaim a selling concession from a syndicate member when the underwriters, in covering short positions or making stabilizing purchases, repurchase common units originally sold by that syndicate member.

198

Purchases to cover short positions and stabilizing purchases, as well as other purchases by the underwriters for their own accounts, may have the effect of preventing or retarding a decline in the market price of the common units. They may also cause the price of the common units to be higher than the price that would otherwise exist in the open market in the absence of these transactions. The underwriters may conduct these transactions on the NYSE, in the over-the-counter market or otherwise. If the underwriters commence any of these transactions, they may discontinue them at any time.

Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of our common units. In addition, neither we nor any of the underwriters make any representation that the representatives will engage in these transactions or that these transactions, once commenced, will not be discontinued without notice.

Electronic Distribution

A prospectus in electronic format may be made available on the web sites maintained by one or more of the underwriters. The representatives may agree to allocate a number of common units to underwriters for sale to their online brokerage account holders. The representatives will allocate common units to underwriters that may make Internet distributions on the same basis as other allocations. In addition, common units may be sold by the underwriters to securities dealers who resell common units to online brokerage account holders.

Underwriter Relationships

Certain of the underwriters and their affiliates have engaged, and may in the future engage, in commercial banking, investment banking and advisory services for us, our general partner and our respective affiliates from time to time in the ordinary course of their business for which they have received customary fees and reimbursement of expenses.

The underwriters and their respective affiliates are full service financial institutions engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, principal investment, hedging, financing and brokerage activities. In the ordinary course of their various business activities, the underwriters and their respective affiliates may make or hold a broad array of investments, including serving as counterparties to certain derivative hedging arrangements, and actively trade debt and equity securities (or related derivative securities) and financial instruments (which may include bank loans and/or credit default swaps) for their own account and for the accounts of their customers and may at any time hold long and short positions in such securities and instruments. Such investment and securities activities may involve securities and instruments of the issuer.

We, our general partner and certain of our affiliates have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments the underwriters may be required to make because of any of those liabilities.

Because FINRA views our common units offered hereby as interests in a direct participation program, this offering is being made in compliance with Rule 2310 of the FINRA rules. Investor suitability with respect to the common units will be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

Selling Legends

Notice to Prospective Investors in Australia

No placement document, prospectus, product disclosure statement or other disclosure document has been lodged with the Australian Securities and Investments Commission (“ASIC”), in relation to the offering. This prospectus does not constitute a prospectus, product disclosure statement or other disclosure document under the Corporations Act 2001 (the “Corporations Act”), and does not purport to include the information required for a prospectus, product disclosure statement or other disclosure document under the Corporations Act.

199

Any offer in Australia of the common units may only be made to persons (the “Exempt Investors”), who are:

•

“sophisticated investors” (within the meaning of section 708(8) of the Corporations Act), “professional investors” (within the meaning of section 708(11) of the Corporations Act) or otherwise pursuant to one or more exemptions contained in section 708 of the Corporations Act; and

•

“wholesale clients” (within the meaning of section 761G of the Corporations Act),

so that it is lawful to offer the common units without disclosure to investors under Chapters 6D and 7 of the Corporations Act.

The common units applied for by Exempt Investors in Australia must not be offered for sale in Australia in the period of 12 months after the date of allotment under the offering, except in circumstances where disclosure to investors under Chapters 6D and 7 of the Corporations Act would not be required pursuant to an exemption under both section 708 and Subdivision B of Division 2 of Part 7.9 of the Corporations Act or otherwise or where the offer is pursuant to a disclosure document which complies with Chapters 6D and 7 of the Corporations Act. Any person acquiring common units must observe such Australian on-sale restrictions.

This prospectus contains general information only and does not take account of the investment objectives, financial situation or particular needs of any particular person. It does not contain any securities recommendations or financial product advice. Before making an investment decision, investors need to consider whether the information in this prospectus is appropriate to their needs, objectives and circumstances, and, if necessary, seek expert advice on those matters.

Notice to Prospective Investors in the European Economic Area

In relation to each member state of the European Economic Area that has implemented the Prospectus Directive (each, a relevant member state), other than Germany, with effect from and including the date on which the Prospectus Directive is implemented in that relevant member state (the relevant implementation date), an offer of securities described in this prospectus may not be made to the public in that relevant member state other than:

•

to any legal entity which is a qualified investor as defined in the Prospectus Directive;

•

to fewer than 100 or, if the relevant member state has implemented the relevant provision of the 2010 PD Amending Directive, 150, natural or legal persons (other than qualified investors as defined in the Prospectus Directive), as permitted under the Prospectus Directive, subject to obtaining the prior consent of the relevant Dealer or Dealers nominated by the Issuer for any such offer; or

•

in any other circumstances falling within Article 3(2) of the Prospectus Directive;

provided that no such offer of securities shall require us or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Directive.

For purposes of this provision, the expression an “offer of securities to the public” in any relevant member state means the communication in any form and by any means of sufficient information on the terms of the offer and the securities to be offered so as to enable an investor to decide to purchase or subscribe for the securities, as the expression may be varied in that member state by any measure implementing the Prospectus Directive in that member state, and the expression “Prospectus Directive” means Directive 2003/71/EC (and amendments thereto, including the 2010 PD Amending Directive, to the extent implemented in the relevant member state), and includes any relevant implementing measure in each relevant member state. The expression 2010 PD Amending Directive means Directive 2010/73/EU.

200

We have not authorized and do not authorize the making of any offer of securities through any financial intermediary on their behalf, other than offers made by the underwriters with a view to the final placement of the securities as contemplated in this prospectus. Accordingly, no purchaser of the securities, other than the underwriters, is authorized to make any further offer of the securities on behalf of us or the underwriters.

Notice to Prospective Investors in Germany

This prospectus has not been prepared in accordance with the requirements for a securities or sales prospectus under the German Securities Prospectus Act (Wertpapierprospektgesetz), the German Sales Prospectus Act (Verkaufsprospektgesetz) or the German Investment Act (Investmentgesetz). Neither the German Federal Financial Services Supervisory Authority (Bundesanstalt für Finanzdienstleistungsaufsicht—BaFin) nor any other German authority has been notified of the intention to distribute our common units in Germany. Consequently, our common units may not be distributed in Germany by way of public offering, public advertisement or in any similar manner, and this prospectus and any other document relating to this offering, as well as information or statements contained therein, may not be supplied to the public in Germany or used in connection with any offer for subscription of the common units to the public in Germany or any other means of public marketing. Our common units are being offered and sold in Germany only to qualified investors which are referred to in Section 3, paragraph 2 no. 1 in connection with Section 2 no. 6 of the German Securities Prospectus Act, Section 8f paragraph 2 no. 4 of the German Sales Prospectus Act, and in Section 2 paragraph 11 sentence 2 no.1 of the German Investment Act. This prospectus is strictly for use of the person who has received it. It may not be forwarded to other persons or published in Germany.

This offering does not constitute an offer to sell or the solicitation of an offer to buy the common units in any circumstances in which such offer or solicitation is unlawful.

Notice to Prospective Investors in Hong Kong

No advertisement, invitation or document relating to the common units has been or may be issued or has been or may be in the possession of any person for the purposes of issue, whether in Hong Kong or elsewhere, which is directed at, or the contents of which are likely to be accessed or read by, the public of Hong Kong (except if permitted to do so under the securities laws of Hong Kong) other than with respect to common units which are or are intended to be disposed of only to persons outside Hong Kong or only to “professional investors” as defined in the Securities and Futures Ordinance and any rules made under that Ordinance.

Notice to Prospective Investors in the Netherlands

Our common units may not be offered or sold, directly or indirectly, in the Netherlands, other than to qualified investors (gekwalificeerde beleggers) within the meaning of Article 1:1 of the Dutch Financial Supervision Act (Wet op het financieel toezicht).

Notice to Prospective Investors in Switzerland

This prospectus is being communicated in Switzerland to a small number of selected investors only. Each copy of this prospectus is addressed to a specifically named recipient and may not be copied, reproduced, distributed or passed on to third parties. Our common units are not being offered to the public in Switzerland, and neither this prospectus, nor any other offering materials relating to our common units, may be distributed in connection with any such public offering.

We have not been registered with the Swiss Financial Market Supervisory Authority FINMA as a foreign collective investment scheme pursuant to Article 120 of the Collective Investment Schemes Act of June 23, 2006 (“CISA”). Accordingly, our common units may not be offered to the public in or from Switzerland, and neither this prospectus, nor any other offering materials relating to our common units, may be made available through a

201

public offering in or from Switzerland. Our common units may only be offered, and this prospectus may only be distributed, in or from Switzerland by way of private placement exclusively to qualified investors (as this term is defined in the CISA and its implementing ordinance).

Notice to Prospective Investors in the United Kingdom

We may constitute a “collective investment scheme” as defined by section 235 of the Financial Services and Markets Act 2000 (“FSMA”) that is not a “recognised collective investment scheme” for the purposes of FSMA (“CIS”) and that has not been authorised or otherwise approved. As an unregulated scheme, it cannot be marketed in the United Kingdom to the general public, except in accordance with FSMA. This prospectus is only being distributed in the United Kingdom to, and is only directed at:

•

if we are a CIS and are marketed by a person who is an authorised person under FSMA, (a) investment professionals falling within Article 14(5) of the Financial Services and Markets Act 2000 (Promotion of Collective Investment Schemes) Order 2001, as amended (the “CIS Promotion Order”) or (b) high net worth companies and other persons falling within Article 22(2)(a) to (d) of the CIS Promotion Order; or

•

otherwise, if marketed by a person who is not an authorised person under FSMA, (a) persons who fall within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005, as amended (the “Financial Promotion Order”) or (b) Article 49(2)(a) to (d) of the Financial Promotion Order; and

•

in both cases (i) and (ii) to any other person to whom it may otherwise lawfully be made, (all such persons together being referred to as “relevant persons”). The common units are only available to, and any invitation, offer or agreement to subscribe, purchase or otherwise acquire such common units will be engaged in only with, relevant persons. Any person who is not a relevant person should not act or rely on this prospectus or any of its contents.

Each joint book-running manager has represented, warranted and agreed that:

(a)

it has only communicated or caused to be communicated and will only communicate or cause to be communicated an invitation or inducement to engage in investment activity (within the meaning of Section 21 of FSMA received by it in connection with the issue or sale of common units which are the subject of the offering contemplated by this prospectus (the “Securities”) in circumstances in which Section 21(1) of FSMA does not apply to us; and

(b)

it has complied and will comply with all applicable provisions of FSMA with respect to anything done by it in relation to the Securities in, from or otherwise involving the United Kingdom.

202

LEGAL MATTERS

The validity of our common units will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. Certain legal matters in connection with our common units offered hereby will be passed upon for the underwriters by Baker Botts L.L.P., Houston, Texas.

EXPERTS

The consolidated financial statements of Azure Midstream Holdings LLC and subsidiaries as of December 31, 2013 and for the period from November 15, 2013 to December 31, 2013 have been included herein in reliance upon the report of KPMG LLP, independent registered public accounting firm, included herein, and upon the authority of said firm as experts in accounting and auditing.

The consolidated financial statements of Azure Midstream Predecessor and subsidiaries as of and for the year ended December 31, 2012 and for the period from January 1, 2013 to November 14, 2013 have been included herein in reliance upon the report of KPMG LLP, independent registered public accounting firm, included herein, and upon the authority of said firm as experts in accounting and auditing.

The financial statements of TPF II East Texas Gathering, LLC as of November 14, 2013 and December 31, 2012 and for the period from January 1, 2013 to November 14, 2013 and the year ended December 31, 2012 have been included herein in reliance upon the report of KPMG LLP, independent auditors, included herein, and upon the authority of said firm as experts in accounting and auditing.

The balance sheet of Azure Midstream Partners, LP as of November 7, 2014 has been included herein in reliance upon the report of KPMG LLP, independent registered public accounting firm, included herein, and upon the authority of said firm as experts in accounting and auditing.

203

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 regarding our common units. This prospectus, which constitutes part of the registration statement, does not contain all of the information set forth in the registration statement. For further information regarding us and our common units offered in this prospectus, we refer you to the registration statement and the exhibits and schedule filed as part of the registration statement. The registration statement, including the exhibits, may be inspected and copied at the public reference facilities maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of this material can also be obtained upon written request from the Public Reference Section of the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549, at prescribed rates or from the SEC’s web site on the Internet at http://www.sec.gov. Please call the SEC at 1-800-SEC-0330 for further information on public reference rooms.

As a result of the offering, we will file with or furnish to the SEC periodic reports and other information. These reports and other information may be inspected and copied at the public reference facilities maintained by the SEC or obtained from the SEC’s website as provided above. Our website will be located at and we intend to make our periodic reports and other information filed with or furnished to the SEC available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

We intend to furnish or make available to our unitholders annual reports containing our audited financial statements prepared in accordance with GAAP. We also intend to furnish or make available to our unitholders quarterly reports containing our unaudited interim financial information, including the information required by Form 10-Q, for the first three fiscal quarters of each fiscal year.

204

FORWARD-LOOKING STATEMENTS

Some of the information in this prospectus may contain forward-looking statements. Forward-looking statements give our current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as “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. They can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. No assurance can be given as to our value, the price at which our securities will trade after this offering or whether a liquid market for those securities will develop or be maintained. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus. Actual results may vary materially. 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 third-party operators, processors and transporters;

•

changes in the availability and cost of capital;

•

operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control;

•

the effects of existing and future laws and governmental regulations;

•

the effects of future litigation; and

•

certain factors discussed elsewhere in this prospectus.

All forward-looking statements are expressly qualified in their entirety by the foregoing cautionary statements.

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INDEX TO FINANCIAL STATEMENTS


Azure Midstream Partners, LP and Subsidiaries
Unaudited Pro Forma Consolidated Financial Information			F-2
Introduction			F-2
Pro Forma Consolidated Balance Sheet as of September 30, 2014			F-4
Pro Forma Consolidated Statement of Operations for the Nine-Month Period Ended September 30, 2014			F-5
Pro Forma Consolidated Statement of Operations for the Year Ended December 31, 2013			F-6
Notes to Pro Forma Consolidated Financial Statements			F-7
Audited Balance Sheet
Report of Independent Registered Public Accounting Firm			F-11
Balance Sheet as of November 7, 2014			F-12
Notes to Balance Sheet			F-13

Azure Midstream Holdings LLC and Subsidiaries and Azure Midstream Predecessor and Subsidiaries
Audited Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm (Azure Midstream Holdings LLC)			F-14
Report of Independent Registered Public Accounting Firm (Azure Midstream Predecessor)			F-15
Consolidated Balance Sheets as of December 31, 2013 and 2012			F-16
Consolidated Statements of Operations for the Period from November 15, 2013 to December 31, 2013, the Period from January 1, 2013 to November 14, 2013 and the Year Ended December 31, 2012			F-17
Consolidated Statements of Cash Flows for the Period from November 15, 2013 to December 31, 2013, the Period from January 1, 2013 to November 14, 2013 and the Year Ended December 31, 2012			F-18
Consolidated Statements of Members’ Equity for the Period from November 15, 2013 to December 31, 2013, the Period from January 1, 2013 to November 14, 2013 and the Year Ended December 31, 2012			F-19
Notes to the Consolidated Financial Statements			F-20
Unaudited Condensed Consolidated Financial Statements
Condensed Consolidated Balance Sheets as of September 30, 2014 and December 31, 2013 (unaudited)			F-39
Condensed Consolidated Statements of Operations for the Nine-Month Periods Ended September 30, 2014 and 2013 (unaudited)			F-40
Condensed Consolidated Statements of Cash Flows for the Nine-Month Periods Ended September 30, 2014 and 2013 (unaudited)			F-41
Condensed Consolidated Statements of Members’ Equity for the Nine-Month Periods Ended September 30, 2014 and 2013 (unaudited)			F-42
Notes to the Condensed Consolidated Financial Statements			F-43

TPF II East Texas Gathering, LLC
Audited Financial Statements
Independent Auditors’ Report			F-56
Balance Sheets as of November 14, 2013 and December 31, 2012			F-57
Statements of Operations for the Period from January 1, 2013 to November 14, 2013 and the Year Ended December 31, 2012			F-58
Statements of Cash Flows for the Period from January 1, 2013 to November 14, 2013 and the Year Ended December 31, 2012			F-59
Statements of Members’ Equity for the Period from January 1, 2013 to November 14, 2013 and the Year Ended December 31, 2012			F-60
Notes to the Financial Statements			F-61

F-1

AZURE MIDSTREAM PARTNERS, LP

UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL INFORMATION

AS OF SEPTEMBER 30, 2014 AND FOR THE NINE-MONTH PERIOD ENDED SEPTEMBER 30, 2014

AND THE YEAR ENDED DECEMBER 31, 2013

Introduction

Azure Midstream Partners, LP (the “Partnership”) is a Delaware limited partnership that was formed in September 2014 by Azure Midstream Holdings LLC (“Azure Midstream Holdings”) in connection with the initial public offering of common units representing limited partner interest in the Partnership (the “Offering”).

The unaudited pro forma consolidated financial statements of the Partnership are based on the historical financial statements of Azure Midstream Holdings and the Azure Midstream Predecessor (the “Predecessor”). Azure Midstream Holdings is comprised of the midstream assets of TGGT Holdings, LLC (“TGGT”) and TPF II East Texas Gathering, LLC (“ETG”), which were acquired from EXCO Resources, Inc. (“EXCO”), BG Group plc. (“BG”) and TPF II, LP (“Tenaska Capital Management”) on November 15, 2013 (the “Acquisition), respectively. Azure Midstream Holdings indirectly owns and operates TGGT and ETG through its wholly owned subsidiary, Azure Midstream Energy LLC (“Azure Energy”). These midstream assets are primarily located in the North Louisiana and East Texas areas of the Haynesville, Bossier and Cotton Valley formations. The Azure Midstream Predecessor is comprised of the midstream assets of TGGT, as TGGT and is the predecessor of Azure Midstream Holdings for accounting purposes. In connection with the Offering, Azure Midstream Holdings will contribute Azure Energy to Azure Midstream Operating Company LP (“Azure Midstream Operating”), a newly formed Delaware limited partnership.

At the completion of the Offering, Azure Midstream Holdings will own (i) the non-economic general partner interest in the Partnership and an indirect ownership of the incentive distribution rights in the Partnership through its direct 100% ownership of Azure Midstream Partners GP, LLC (the “Azure GP”), a Delaware limited liability company and the general partner of the Partnership and (ii) a % limited partner interest in the Partnership, represented by common units and subordinated units and (iii) a 60% limited partner interest in Azure Midstream Operating. The Partnership will own a 40% limited partner interest in Azure Midstream Operating and the general partner interest in Azure Midstream Operating.

Unless the context requires otherwise, for purposes of this pro forma presentation, all references to “we,” “our,” “us” and the “Partnership” refer to Azure Midstream Partners, LP and its subsidiaries, including Azure Midstream Operating. The Azure Midstream Operating financial information is consolidated with the Partnership because the Partnership, through its ownership of Azure Midstream Operating’s general partner, will control Azure Midstream Operating upon the completion of the Offering. The Partnership controls Azure Midstream Operating through its ownership of the general partner because the limited partners of Azure Midstream Operating do not have the ability to remove the general partner, liquidate Azure Midstream Operating, or have any rights to manage or control Azure Midstream Operating. As the owner of 100% of the general partner interests in Azure Midstream Operating, the Partnership has all powers to control and manage the business and affairs of Azure Midstream Operating.

The unaudited pro forma consolidated statements of operations for the nine-month period ended September 30, 2014 and the year ended December 31, 2013 assume the Acquisition and the Offering and related transactions occurred on January 1, 2013. The unaudited pro forma consolidated balance sheet as of September 30, 2014 assumes the Offering and related transactions occurred on September 30, 2014. The unaudited pro forma consolidated financial statements do not present the Partnership’s actual results of operations had the Acquisition and the Offering and related transactions been completed at the dates indicated. In addition, they do not project the Partnership’s results of operations for any future period.

F-2

The unaudited pro forma consolidated financial statements reflect the following significant assumptions and transactions:

•

Azure Midstream Holdings will contribute a 40% limited partner interest in Azure Midstream Operating to us;

•

We will acquire the general partner interest in Azure Midstream Operating through our direct 100% ownership of Azure Midstream Operating GP, LLC;

•

We will issue common units and subordinated units to Azure Midstream Holdings, representing a limited partner interest in us;

•

We will issue our general partner a non-economic general partner interest in us and all of our incentive distribution rights, which will entitle our general partner to increasing percentages of the cash that we distribute in excess of $ per unit per quarter;

•

We will issue common units to the public, representing a % limited partner interest in us;

•

We will enter into a new $150 million revolving credit facility; and

•

We will use the net proceeds from this Offering (including any new proceeds from the exercise of the underwriters’ options to purchase additional common units from us) as described in “Use of Proceeds”

The unaudited pro forma consolidated financial statements and accompanying notes have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”). These accounting principles are consistent with those used in, and should be read together with, the historical consolidated financial statements and related notes, which are included elsewhere in this prospectus.

The adjustments reflected in the unaudited pro forma consolidated financial statements are based on currently available information and certain estimates and assumptions. Therefore, actual results may differ from the pro forma adjustments. However, management believes that the estimates and assumptions used provide a reasonable basis for presenting the significant effects of the Offering and the related transactions. Management also believes the pro forma adjustments give appropriate effect to the estimates and assumptions and are applied in conformity with GAAP.

F-3

AZURE MIDSTREAM PARTNERS, LP

UNAUDITED PRO FORMA CONSOLIDATED BALANCE SHEET

September 30, 2014


	Azure Midstream Holdings LLC					Azure Midstream Partners, LP
	September 30, 2014 Historical		Offering Related Pro Forma Adjustments			September 30, 2014 Pro Forma
	(in thousands)
Current Assets
Cash and cash equivalents	$	26,034			(f)	$	26,034
Restricted cash		79					79
Accounts receivable—affiliates		14,553					14,553
Accounts receivable—nonaffiliates, net of allowances for bad debt of $41		11,663					11,663
Assets held for sale		4,190					4,190
Other current assets		1,187					1,187

Total current assets		57,706		—			57,706

Property and equipment—net		823,068					823,068
Goodwill		100,896					100,896
Intangible assets, net		74,726					74,726
Other non-current assets		18,167			(g)

Total assets	$	1,074,563	$	—		$

Current Liabilities
Accounts payable and accrued liabilities		19,959					19,959
Current portion of long-term debt		28,649			(g)

Total current liabilities		48,608		—
Long-term liabilities
Long-term debt		505,364			(g)
Other long-term liabilities		5,351					5,351

Total liabilities		559,323		—
Commitments and contingencies (see Note 4)		—					—
Members’ equity		515,240			(h)
Azure Midstream Partners, LP—common units		—			(i)		—
Azure Midstream Partners, LP—subordinated units		—			(i)		—
Non-controlling interest in Azure Midstream Operating		—			(j)		—

Total liabilities and members’ equity	$	1,074,563	$	—		$

See accompanying notes to the unaudited pro forma consolidated financial statements

F-4

AZURE MIDSTREAM PARTNERS, LP

UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS

Nine-Month Period Ended September 30, 2014


	Azure Midstream Holdings LLC		Pro Forma Adjustments			Azure Midstream Partners, LP
	September 30, 2014 Historical		Offering Related			September 30, 2014 Pro Forma
	(in thousands, except per unit data)
Revenues:
Operating revenues—affiliates	$	77,827	$	—		$	78,741
Operating revenues—non-affiliates		57,006		—			56,092

Total operating revenues		134,833		—			134,833

Operating expenses:
Cost of purchased gas and NGLs sold		30,095		—			30,095
Operating expense		23,685		—			23,685
General and administrative		10,760		—			10,760
Asset impairments		228		—			228
Depreciation and amortization		21,989		—			21,989

Total expenses		86,757		—			86,757
Income from operations		48,076		—			48,076
Interest expense		31,145		—			31,145
Other expense		326		—			326

Net income before income taxes		16,605		—			16,605
Income tax expense		423		—			423

Net income from continuing operations	$	16,182		—			16,182

Net income attributable to non-controlling interest			$	9,709	(e)		9,709

Net income attributable to Azure Midstream Partners, LP						$	6,473

Net income attributable to Azure Midstream Partners, LP:
Limited partner interest:
Common units						$	—
Subordinated units						$	—
Net income per limited partner unit (basic and diluted):
Common units						$	—
Subordinated units						$	—
Weighted average number of limited partner units outstanding (basic and diluted):
Common units							—
Subordinated units							—

See accompanying notes to the unaudited pro forma consolidated financial statements

F-5

AZURE MIDSTREAM PARTNERS, LP

UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS

For the year ended December 31, 2013


	Azure Midstream Holdings LLC			Predecessor		TPF II East Texas Gathering LLC			Azure Midstream Holdings LLC						Azure Midstream Partners, LP
	Period from November 15, 2013 to December 31, 2013			Period from January 1, 2013 to November 14, 2013		Period from January 1, 2013 to November 14, 2013			Historical Pro Forma Adjustments			Pro Forma, as Adjusted, December 31, 2013			Offering Related Pro Forma Adjustments			Pro Forma, as Adjusted December 31, 2013
	(in thousands, except per unit data)
Revenues:
Operating revenues—affiliate	$	16,389		$	135,665	$	2,754			—		$	154,808			—		$	154,808
Operating revenues—non-affiliates		8,430			44,667		11,799			—			64,896			—			64,896

Total operating revenues		24,819			180,332		14,553			—			219,704			—			219,704

Operating expenses:
Cost of purchased gas and NGLs sold		4,505			21,054		253			—			25,812			—			25,812
Operating expense		5,455			33,850		9,388			—			48,693			—			48,693
General and administrative		458			11,166		3,095			—			14,719			—			14,719
Transaction cost		6,135			—		—			(6,135	)(c)		—			—			—
Asset impairments		—			583		237,478			—			238,061			—			238,061
Depreciation and amortization		3,480			31,143		15,021			(20,907	)(a)		28,737			—			28,737

Total expenses		20,033			97,796		265,235			(27,042	)		356,022			—			356,022
Income from operations		4,786			82,536		(250,682	)		27,042			(136,318	)		—			(136,318	)
Interest expense		5,046			10,321		1,083			23,854	(b)		40,304			—			40,304
Other expense (income)		576			2,316		(2	)		—			2,890			—			2,890

Net income (loss) before income taxes		(836	)		69,899		(251,763	)		3,188			(179,512	)		—			(179,512	)
Income tax expense		106			361		—			42	(d)		509			—			509

Net (loss) income	$	(942	)	$	69,538	$	(251,763	)	$	3,146		$	(180,021	)		—			(180,021	)

Net loss attributable to non-controlling interests															$	(108,013	)(e)		(108,013	)

Net loss attributable to Azure Midstream Partners, LP:																		$	(72,008	)

Net loss attributable to Azure Midstream Partners, LP:
Limited partner interest:
Common units																		$	—
Subordinated units																		$	—
Net loss per limited partner unit (basic and diluted):
Common units																		$	—
Subordinated units																		$	—
Weighted average number of limited partner units outstanding (basic and diluted):
Common units																			—
Subordinated units																			—

See accompanying notes to the unaudited pro forma consolidated financial statements

F-6

AZURE MIDSTREAM PARTNERS, LP

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

(1) Basis of Presentation

The historical financial information for the year ended December 31, 2013 is derived from and should be read in conjunction with the audited historical consolidated financial statements of Azure Midstream Holdings and the Azure Midstream Predecessor. The historical financial information for the nine-month period ended September 30, 2014 and balance sheet information at September 30, 2014 is derived from and should be read in conjunction with the unaudited historical financial statements of Azure Midstream Holdings. In each case, the historical financial information reflects 100% of the Azure Midstream Holdings and Azure Midstream Predecessor’s operations. As part of the offering, Azure Midstream Holdings will cause Azure Energy to be contributed to Azure Midstream Operating in exchange for all of the limited partner interests of Azure Midstream Operating. Azure Midstream Holdings will then contribute an approximate 40% limited partner interest in Azure Midstream Operating to the Partnership.

The pro forma adjustments have been prepared as if certain transactions to be completed in conjunction with the Offering had taken place on January 1, 2013 in the case of the pro forma statement of operations for the year ended December 31, 2013 and the nine-month period ended September 30, 2014, or on September 30, 2014 in the case of the pro forma balance sheet. These transactions and adjustments are described in Note 3 to these unaudited pro forma consolidated financial statements.

The unaudited pro forma adjustments do not give effect to incremental general and administrative expenses of approximately $3.0 million per year that we expect to incur as a result of being a publicly-traded partnership. These general and administrative expenses include fees associated with annual and quarterly reporting, tax returns, schedule K-1 preparation and distribution, investor relations, registrar and transfer agents, incremental insurance costs, executive compensation, accounting, auditing, legal and independent director compensation. The unaudited pro forma adjustments do not give effect to any cost savings or other operating efficiencies from the integration of the TGGT and ETG businesses within our operations. Specifically, we terminated the ETG management service agreement with Tenaska Capital Management in connection with the Acquisition resulting in approximately $2.5 million in cost reductions. The unaudited pro forma adjustments do include an adjustment of $6.1 million associated with acquisition related costs incurred in connection with the Acquisition, which were previously included within transaction costs during the period from November 15, 2013 to December 31, 2013. The unaudited pro forma statement of operations for the year ended December 31, 2013 includes an impairment charge of $238.1 million, of which $237.0 million was an impairment charge that was recognized by ETG prior to the Acquisition, and is the result of adjusting the carrying value of the ETG assets to their net realizable fair value immediately prior to the Acquisition by us.

(2) Summary of Significant Accounting Policies

The accounting policies used in preparing the unaudited pro forma consolidated financial statements are those used by Azure Midstream Holdings as set forth in its audited historical combined financial statements contained elsewhere in this prospectus.

(3) Pro Forma Adjustments and Assumptions

The accompanying unaudited pro forma financial statements give pro forma effect to the following:

Historical Pro Forma Adjustments and Assumptions

(a)

This adjustment reflects the acquisition of TGGT and ETG on November 15, 2013. As a result of applying purchase accounting to the assets acquired and liabilities assumed, Azure Midstream Holdings

F-7

AZURE MIDSTREAM PARTNERS, LP

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

recognized adjustments to the historical net book value of the Predecessor’s assets and liabilities. These adjustments are expected to have a continuing effect on the amount of depreciation and amortization expense. As a result of applying purchase accounting, property, plant and equipment and identifiable intangible assets were recorded at their fair values. The fair values assigned to property, plant and equipment were less than the historical carrying values assigned by the Predecessor. The assigned useful lives of the property, plant and equipment acquired, which are estimates based on various factors including age, manufacturing specifications, technological advances and historical data concerning useful lives of similar assets, are also greater than the useful lives assigned by the Predecessor. Additionally, we recognized an intangible asset associated with customer relationships that is being amortized over a 12 year recovery period. The Predecessor had no such intangible assets. These factors resulted in a net decrease in depreciation and amortization expense. The net impact to depreciation and amortization expense is $20.9 million during the year ended December 31, 2013.

(b)

This adjustment reflects the entrance into the Azure Energy $550 million Senior Secured Term Loan B (“TLB”) and the $50 million Senior Secured Revolving Credit Facility (the “Revolver” and, collectively with the TLB, the “Credit Agreement”). In connection with the Acquisition, we borrowed $550 million under the TLB and borrowings bear interest at approximately 6.5%. We did not borrow under the Revolver in connection with the Acquisition. The borrowings result in an increase in interest expense of $23.9 million during the year ended December 31, 2013, including amortization of deferred financing costs incurred in connection with the execution of the Credit Agreement and annual commitment fees on the Revolver.

The incremental interest expense on the TLB is calculated as 1% plus the applicable margin for Eurodollar loans of 5.5%. A change in the borrowing rate of 1/8 percent would have an impact of approximately $0.7 million on the pro forma annual interest expense on the TLB for the year ended December 31, 2013.

(c)

This adjustment removes the direct, incremental costs of $6.1 million associated with the Acquisition from the pro forma statement of operations for the year ended December 31, 2013. These non-recurring acquisition-related costs were previously included in transaction costs within the historical financial statements of Azure Midstream Holdings for the period from November 15, 2013 to December 31, 2013.

(d)

This adjustment reflects the inclusion of income tax expense associated with ETG as ETG historically did not recognize expense associated with the gross margin tax enacted by the state of Texas because such gross margin tax was not allocated to ETG. An adjustment to recognize gross margin tax for the period from January 1, 2013 to November 14, 2013 has been included as we will incur gross margin tax on the ETG operations in the future.

F-8

AZURE MIDSTREAM PARTNERS, LP

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

Offering Related Pro Forma Adjustments and Assumptions

(e)

Income attributable to non-controlling interests of $9.7 million for the nine-month period ended September 30, 2014 and loss attributable to non-controlling interests of $108.0 million for the year ended December 31, 2013, which represents Azure Midstream Holdings’ 60% interest in Azure Midstream Operating’s net income.


	Nine-Month Period Ended September 30, 2014			Year Ended December 31, 2013
	(in thousands)
Pro forma net income (loss)	$	16,182		$	(180,021	)
Non-controlling interest %		60	%		60	%

Pro forma non-controlling interest in net income (loss)	$	9,709		$	(108,013	)

(f)

The sale of common units, representing a % limited partner interest in us, at an assumed price of $ per unit and resulting in gross proceeds of $ million and underwriting discounts and other costs totaling $ million. If the underwriters were to exercise in full their option to purchase an additional common units, gross proceeds would equal $ million.


		($ in millions)
Gross proceeds from initial public offering
Underwriting discount
Expenses and costs of initial public offering
Structuring fee
Net proceeds

(g)

The adjustment reflects the entrance into the Partnership’s new $150 million revolving credit facility, which will initially have no outstanding borrowings, and the repayment of a portion of the outstanding indebtedness associated with the Azure Energy credit agreement. The adjustment also reflects estimated debt issuance costs of $ million associated with the new $150 million revolving credit facility and the write-off of previously deferred debt issuance costs of $ million as a result of entering into the new revolving credit facility in accordance with relevant accounting guidance.

(h)

The elimination of the Azure Midstream Holdings capital accounts of $ million following Azure Midstream Holdings’ contribution to us of a 40% interest in Azure Midstream Operating and a 100% interest in Azure Midstream Operating’s general partner in exchange for common units and subordinated units, representing a % limited partner interest in us.

(i)

The issuance of common units and subordinated units, representing a % limited partner interest in us, for $ million and the issuance of all of our incentive distribution rights. Additionally, the issuance to our general partner of a non-economic general partner interest in us.

F-9

AZURE MIDSTREAM PARTNERS, LP

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

(j)

Azure Midstream Holdings’ 60% limited partner interest in Azure Midstream Operating of $ million.

Included below is a reconciliation between the Azure Midstream Holdings historical equity and the pro forma partners’ equity:

Azure Midstream Predecessor equity

Adjustment(b)

Adjustment(c)

Adjustment(e)

Adjustment(f)

Pro forma partners’ equity

(4) Commitments and Contingencies

Commitments and contingencies of Azure Midstream Holdings and the Predecessor are described in the unaudited condensed consolidated financial statements for the nine-month period ended September 30, 2014 contained elsewhere in this prospectus.

(5) Income per Unit

Pro forma net income per limited partner unit is determined by dividing the pro forma net income that would have been allocated, in accordance with the net income allocation provisions of the limited partnership agreement, to the holders of common and subordinated units under the two-class method by the number of common and subordinated units expected to be outstanding at the closing of this Offering. For purposes of this calculation, we assumed that (i) the Minimum Quarterly Distribution was made to all unitholders for each quarter during the periods presented, (ii) the number of units outstanding was common units and subordinated units and (iii) no incentive distributions were made to Azure Midstream Holdings. The common and subordinated unitholders each represent 50% limited partner interests. All units were assumed to have been outstanding since January 1, 2013.

Pro forma basic and diluted net income per unit are equivalent since it is expected here will be no dilutive units outstanding at the date of closing of the Offering.

Pursuant to the partnership agreement, to the extent quarterly distributions exceed certain earnings targets, Azure Midstream Holdings is entitled to receive certain incentive distributions that will result in more net income proportionally being allocated to the general partner than the holders of common and subordinated units.

F-10

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors

Azure Midstream Partners GP, LLC:

We have audited the accompanying balance sheet of Azure Midstream Partners, LP (the Partnership) as of November 7, 2014. This financial statement is the responsibility of the Partnership’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. An audit of a balance sheet also includes examining, on a test basis, evidence supporting the amounts and disclosures in that balance sheet, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall balance sheet presentation. We believe that our audit of the balance sheet provides a reasonable basis for our opinion.

In our opinion, the balance sheet referred to above presents fairly, in all material respects, the financial position of Azure Midstream Partners, LP as of November 7, 2014, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Dallas, Texas

November 12, 2014

F-11

AZURE MIDSTREAM PARTNERS, LP

BALANCE SHEET

November 7, 2014


	November 7, 2014
Assets
Current Assets
Cash	$	1,000

Total Assets	$	1,000


Liabilities and Partners’ Equity
Commitments and contingencies
Partners’ Equity
Limited partner’s interest	$	1,000

Total Liabilities and Partners’ Equity	$	1,000

F-12

AZURE MIDSTREAM PARTNERS, LP

NOTES TO BALANCE SHEET

(1) Organization and Nature of Operations

Azure Midstream Partners, LP (the “Partnership”) is a Delaware limited partnership that was formed on September 26, 2014 by Azure Midstream Holdings LLC (“Azure Midstream Holdings”) and Azure Midstream Partners GP, LLC (“Azure GP”). The Partnership was formed in connection with the initial public offering of common units representing limited partner interest in the Partnership (the “Offering”).

We are a fee-based, growth-oriented Delaware limited partnership focused on owning, operating, developing and acquiring midstream energy infrastructure that is strategically located in core producing areas of unconventional resource basins in North America. We currently provide natural gas gathering, compression, treating and processing services in North Louisiana and East Texas in the prolific Haynesville and Bossier shale formations, the liquids-rich Cotton Valley formation and shallower producing sands in the Travis Peak formation. Historically, Azure Midstream Holdings has owned and operated these midstream assets through Azure Midstream Energy, LLC (“Azure Energy”). In connection with the Offering, Azure Midstream Holdings will contribute Azure Energy to Azure Midstream Operating Company LP (“Azure Midstream Operating”), a newly formed Delaware limited partnership.

At the consummation of the Offering, the Partnership’s assets will consist of a 40% limited partner interest in Azure Midstream Operating, as well as the general partner interest in Azure Midstream Operating. Through the Partnership’s ownership of Azure Midstream Operating’s general partner, we will control all of Azure Midstream Operating’s assets and operations. Azure Midstream Holdings will own (i) the non-economic general partner interest in the Partnership and an indirect ownership of the incentive distribution rights in the Partnership through its direct 100% ownership of Azure Midstream Partners GP, LLC (the “Azure GP”), a Delaware limited liability company and the general partner of the Partnership and (ii) a limited partner interest in the Partnership and (iii) a 60% limited partner interest in Azure Midstream Operating.

On November 5, 2014, Azure Midstream Holdings contributed $1,000 to the Partnership in exchange for a non-economic general partner interest and 100% limited partner interest in the Partnership. There have been no other transactions involving the Partnership as of November 7, 2014.

(2) Subsequent Events

Management of the Partnership has evaluated subsequent events through November 12, 2014, which is the date the balance sheet was available to be issued.

F-13

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors

Azure Midstream Holdings LLC:

We have audited the accompanying consolidated balance sheet of Azure Midstream Holdings LLC and subsidiaries as of December 31, 2013 and the related consolidated statements of operations, cash flows, and members’ equity for the period from November 15, 2013 to December 31, 2013. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Azure Midstream Holdings LLC and subsidiaries as of December 31, 2013 and the results of their operations and their cash flows for the period from November 15, 2013 to December 31, 2013 in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Dallas, Texas

October 2, 2014

F-14

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors

Azure Midstream Holdings LLC:

We have audited the accompanying consolidated balance sheet of Azure Midstream Predecessor and subsidiaries as of December 31, 2012 and the related consolidated statements of operations, cash flows, and members’ equity for the period from January 1, 2013 to November 14, 2013 and for the year ended December 31, 2012. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Azure Midstream Predecessor and subsidiaries as of December 31, 2012 and the results of their operations and their cash flows for the period from January 1, 2013 to November 14, 2013 and the year ended December 31, 2012 in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Dallas, Texas

October 2, 2014

F-15

AZURE MIDSTREAM HOLDINGS LLC AND SUBSIDIARIES AND

AZURE MIDSTREAM PREDECESSOR AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

As of December 31, 2013 and 2012


	Azure Midstream Holdings LLC		Predecessor
	December 31, 2013		December 31, 2012
	(in thousands)
Current Assets
Cash and cash equivalents	$	15,576	$	8,050
Accounts receivable—affiliates		20,834		28,622
Accounts receivable—nonaffiliates, net of allowances for bad debt of $94 in 2013 and $1,055 in 2012		13,678		6,610
Assets held for sale		4,065		9,065
Other current assets		955		1,744

Total current assets		55,108		54,091

Property and equipment, net		823,102		1,142,208
Goodwill		100,896		—
Intangible assets, net		79,433		—
Other non-current assets		21,801		5,335

Total assets	$	1,080,340	$	1,201,634

Current liabilities
Accounts payable and accrued liabilities		30,151		29,172
Current portion of long-term debt		27,500		2,029

Total current liabilities		57,651		31,201
Long-term liabilities
Long-term debt		522,500		491,642
Other long-term liabilities		1,131		183

Total liabilities		581,282		523,026
Commitments and contingencies (see Note 8)
Members’ equity		499,058		678,608

Total liabilities and members’ equity	$	1,080,340	$	1,201,634

See accompanying notes to the consolidated financial statements.

F-16

AZURE MIDSTREAM HOLDINGS LLC AND SUBSIDIARIES AND

AZURE MIDSTREAM PREDECESSOR AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

For the period from November 15, 2013 to December 31, 2013, the period from January 1, 2013 to

November 14, 2013 and the year ended December 31, 2012


	Azure Midstream Holdings LLC			Predecessor
	Period from November 15, 2013 to December 31, 2013			Period from January 1, 2013 to November 14, 2013		Year ended December 31, 2012
	(in thousands, except per unit data)
Revenues:
Operating revenues—affiliates	$	16,389		$	135,665	$	198,243
Operating revenues—non-affiliates		8,430			44,667		48,208

Total operating revenues		24,819			180,332		246,451

Operating expenses:
Cost of purchased gas sold		4,505			21,054		22,794
Operating expense		5,455			33,850		48,586
General and administrative		458			11,166		17,514
Transaction cost		6,135			—		—
Asset impairments		—			583		50,771
Depreciation and amortization		3,480			31,143		32,132

Total expenses		20,033			97,796		171,797

Income from operations		4,786			82,536		74,654
Interest expense		5,046			10,321		16,145
Other expense		576			2,316		3,441
Net income (loss) before income taxes		(836	)		69,899		55,068
Income tax expense		106			361		425

Net income (loss)	$	(942	)	$	69,538	$	54,643

See accompanying notes to the consolidated financial statements.

F-17

AZURE MIDSTREAM HOLDINGS LLC AND SUBSIDIARIES AND

AZURE MIDSTREAM PREDECESSOR AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Period from November 15, 2013 to December 31, 2013, the Period from January 1, 2013 to November 14, 2013 and the Year Ended December 31, 2012


	Azure Midstream Holdings LLC			Predecessor
	Period from November 15, 2013 to December 31, 2013			Period from January 1, 2013 to November 14, 2013			Year ended December 31, 2012
	(in thousands)
Operating activities:
Net (loss) income	$	(942	)	$	69,538		$	54,643
Adjustments to reconcile net (loss) income to net cash provided
Depreciation and amortization		3,480			31,143			32,132
Amortization of deferred financing costs		550			872			2,375
Impairment of assets		—			583			50,771
Loss on sale of assets		—			198			1,636
Other, net		—			2,407			1,109
Changes in operating assets and liabilities:
Accounts receivable		(8,531	)		11,277			9,736
Other current assets		(268	)		1,385			3,841
Accounts payable and other current liabilities		7,595			(3,819	)		(27,188	)

Net cash provided by operating activities		1,884			113,584			129,055
Investing activities:
Acquisition of TGGT, net of cash acquired		(916,242	)
Acquisition of ETG—cash portion		(3,178	)
Capital expenditures		(5,326	)		(29,208	)		(191,001	)
Proceeds from sale of property and equipment		—			1,573			11,936
Insurance recoveries on property and equipment		—			32			500

Net cash used in investing activities		(924,746	)		(27,603	)		(178,565	)
Financing activities:
Borrowings under credit agreements		550,000			—			29,500
Repayments under credit agreements		—			(86,642	)		—
Members’ contributions for members interest		410,000			—			—
Payments of deferred financing costs		(21,562	)		—			(2,811	)
Payments on capital lease obligations		—			(2,029	)		(5,164	)

Net cash provided by (used in) financing activities		938,438			(88,671	)		21,525
Increase (decrease) in cash and cash equivalents		15,576			(2,690	)		(27,985	)
Cash and cash equivalents—Beginning of period		—			8,050			36,035

Cash and cash equivalents—End of period	$	15,576		$	5,360		$	8,050

See accompanying notes to the consolidated financial statements.

F-18

AZURE MIDSTREAM HOLDINGS LLC AND SUBSIDIARIES AND

AZURE MIDSTREAM PREDECESSOR AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY

For the Period from November 15, 2013 to December 31, 2013, the Period from January 1, 2013 to November 14, 2013 and the Year Ended December 31, 2012


	Members’ Equity
	(in thousands)
Beginning Azure Midstream Predecessor Members’ Equity—December 31, 2011	$	622,679
Azure Midstream Predecessor Members’ contributions for Wallace Lake acquisition		1,286
Azure Midstream Predecessor Members’ share of period net income		54,643

Azure Midstream Predecessor Members’ equity—December 31, 2012		678,608
Azure Midstream Predecessor Members’ share of period net income		69,538

Ending Azure Midstream Predecessor Members’ Equity—November 14, 2013	$	748,146
Elimination of Azure Midstream Predecessor Members’ Equity		(748,146	)
Beginning Azure Midstream Holdings Members’ Equity
Azure Midstream Holdings Members’ cash contribution—November 15, 2013		410,000
Azure Midstream Holdings Members’ equity issued in connection with the Acquisition		90,000

Total Beginning Azure Midstream Holdings Members’ Equity Contribution		500,000

Azure Midstream Holdings Members’ Share of period net loss		(942	)

Ending Azure Midstream Predecessor Members’ Equity—December 31, 2013	$	499,058

See accompanying notes to the consolidated financial statements.

F-19

AZURE MIDSTREAM HOLDINGS LLC AND SUBSIDIARIES AND

AZURE MIDSTREAM PREDECESSOR AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) Organization and Nature of Business

Organization

Azure Midstream Holdings

The accompanying historical financial statements of Azure Midstream Holdings LLC (“Azure Midstream Holdings” or the “Company”) and Azure Midstream Predecessor (the “Predecessor”) have been prepared in connection with the proposed initial public offering of limited partner units in Azure Midstream Partners, LP (the “Partnership”). The Partnership is an indirect subsidiary of Azure Midstream Holdings and was formed as a limited partnership in Delaware in September 2014 by Azure Midstream Holdings and Azure Midstream Partners GP, LLC (“Azure GP”), a Delaware limited liability company and general partner of the Partnership. Azure Midstream Holdings is a Delaware limited liability company.

On November 15, 2013, Azure Midstream Holdings acquired 100% of the equity interests in TGGT Holdings, LLC (“TGGT”) for an aggregate sales price of $910 million, plus customary working capital adjustments, from EXCO Resources, Inc. (“EXCO”) and BG Group plc (“BG”). As part of the Acquisition, members of Azure Midstream Holdings management, Energy Spectrum Partners VI LP, and its parallel and co-investment funds (“Energy Spectrum Partners”), a group of co-investors affiliated with Energy Spectrum Partners (the “Co-Investors”) and an affiliate of Tenaska Capital Management, LLC (“Tenaska Capital Management” and collectively with the members of management, Energy Spectrum Partners and the Co-Investors, the “Members”) contributed a combined $410 million in cash for an ownership interest in Azure Midstream Holdings. In a related transaction, TPF II East Texas Gathering, LLC (“ETG”), a business managed by Tenaska Capital Management, was contributed to Azure Midstream Holdings in exchange for a $90 million additional ownership interest in Azure Midstream Holdings valued at $90 million (the “ETG Contribution”). We refer to our acquisition of TGGT and the ETG Contribution as the “Acquisition.” As partial consideration to the Acquisition, EXCO and BG collectively retained a 7% ownership in Azure Midstream Holdings (the “EXCO and BG Contribution”). As of December 31, 2013, members of management, Energy Spectrum Partners, the Co-Investors and Tenaska Capital Management each owned 2%, 29%, 33% and 29% of Azure Midstream Holdings, respectively. As of December 31, 2013, EXCO and BG, collectively, owned 7% of Azure Midstream Holdings.

Subsequent to the Acquisition and contribution of ETG, TGGT and ETG are indirectly owned and operated by Azure Midstream Holdings through its wholly owned subsidiary, Azure Midstream Energy LLC (“Azure Energy”). Azure Energy is a Delaware limited liability company that was formed in November 2013.

As part of the offering, Azure Midstream Holdings will cause Azure Energy to be contributed to Azure Midstream Operating in exchange for all of the limited partner interests of Azure Midstream Operating. Azure Midstream Holdings will then contribute an approximate 40% limited partner interest in Azure Midstream Operating to the Partnership. The Partnership will also own all of the ownership interest in Azure Midstream Operating Company GP, LLC (“Azure Midstream Operating GP”), a newly formed Delaware limited liability company and the general partner of Azure Midstream Operating. The Partnership will consolidate Azure Midstream Operating as a result of its ownership of Azure Midstream Operating GP. Azure Midstream Holdings will retain the remaining 60% limited partner interest in Azure Midstream Operating and will own all of the ownership interest in Azure GP.

Azure Midstream Predecessor

The Predecessor was formed on August 14, 2009, arising from a transaction between EXCO and BG. EXCO contributed two midstream companies, TGG Pipeline, Ltd. (“TGG”), and Talco Midstream Assets, Ltd., with a combined net book value of $316.3 million, to the Predecessor, in exchange for membership interest in the

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Predecessor. EXCO then sold 50% of its membership interest in the Predecessor to BG for cash consideration of approximately $269.2 million, including closing adjustments. Upon formation, EXCO and BG (the “Predecessor Members”) contributed $20.0 million each to fund initial operations of the Predecessor. The Predecessor Member’s capital was equalized at the opening balance sheet date, per the terms of the Predecessor formation agreement.

The Predecessor’s operations were overseen by a management board with equal membership from both Predecessor Members. Neither EXCO nor BG had control over the management of, or a controlling beneficial economic interest in, the operations of the Predecessor. Each Predecessor Member had no liability in excess of: (i) the amount of its contributions to the Predecessor; (ii) its share of any assets and undistributed profits of the Predecessor; (iii) its obligation to make other payments expressly provided for in the Predecessor formation agreement; and (iv) the amount of any distributions wrongfully distributed to it.

The Predecessor had no employees and was staffed by the Predecessor Members’ employees who were seconded (100% duty assigned by the respective member) to the Predecessor. The Predecessor employed the services of contractors as needed and had the ability to purchase services from either EXCO or BG under the terms of service agreements executed with each Predecessor Member at the inception of the Predecessor.

Unless the context requires otherwise, all references to “we,” “our,” “us” and the “Company” refers to Azure Midstream Holdings, including Azure Energy. All references to the Predecessor refer to the Azure Midstream Predecessor. All references to the “Partnership” refers to Azure Midstream Partners, LP.

Nature of Business

Azure Midstream Holdings and the Predecessor are engaged in natural gas gathering, compression, treating, transportation, and related services primarily in North Louisiana and East Texas focused on the Haynesville, Bossier and Cotton Valley formations. Azure Midstream Holdings and the Predecessor operate 1,365 miles of pipeline that move natural gas from these North Louisiana and East Texas supply basins to 20 existing major intrastate and interstate pipelines in the region.

Basis of Presentation

The consolidated financial statements include the assets, liabilities and results of operations of Azure Midstream Holdings as of December 31, 2013 and for the period from November 15, 2013 to December 31, 2013, and of the Predecessor as of December 31, 2012 and for the period from January 1, 2013 to November 14, 2013 and the year ended December 31, 2012. The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The Azure Midstream Holdings consolidated financial statements are comprised of the TGGT and ETG assets, liabilities and results of operations as of December 31, 2013, and for all periods subsequent to the Acquisition. The Predecessor consolidated financial statements are comprised of the TGGT assets, liabilities and results of operations as of and for all periods prior to the Acquisition as TGGT is the Predecessor of Azure Midstream Holdings for accounting purposes. The Azure Midstream Holdings consolidated financial statements reflect the application of purchase accounting related to the acquisition of a controlling interest in TGGT and ETG effective as of November 15, 2013. All intercompany accounts and transactions have been eliminated in the preparation of the accompanying consolidated financial statements.

We evaluate events that occur after the balance sheet date, but before the financial statements are issued, for potential recognition or disclosure. Based on the evaluation, we have determined that there were no material subsequent events that require recognition or disclosure other than those disclosed herein.

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Segments

Our chief operating decision-maker is our President. The chief operating decision-maker reviews financial information presented on a consolidated basis in order to make decisions about resource allocations and to assess our performance. There are no segment managers who are held accountable by the chief operating decision-maker, or anyone else, for operations, operating results and planning for levels or components below the consolidated unit level. Accordingly, we have determined that we have one reportable segment.

(2) Summary of Significant Accounting Policies

Use of Estimates

The consolidated financial statements have been prepared in conformity with GAAP, which require management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the balance sheet dates, the reported amounts of revenue and expense, including fair value measurements, and disclosure of contingencies. Although management believes these estimates are reasonable, actual results could differ from its estimates.

Cash and Cash Equivalents

The Company considers all highly liquid investments with an original maturity of three months or less when purchased to be cash equivalents.

Accounts Receivable

The majority of our accounts receivable are due from customers to whom we provided transportation, gathering, compression or treating services or to whom we sold purchased natural gas or condensate. A significant portion of our accounts receivable and our Predecessor’s accounts receivable are due from EXCO and BG (See Note 9).

Assets Held For Sale

Assets held for sale consist of various long-lived assets (disposal groups) that our Predecessor committed and initiated a plan to sell. These long-lived assets consist of equipment, such as compressors, treating and dehydration units, generators, vehicles and an office building that our Predecessor concluded would not be used in its business. Azure Midstream Holdings has continued to evaluate the plan to sell these assets, and we continue to believe the sale of these assets is probable. Azure Midstream Holdings and the Predecessor have recorded the assets at their fair market value as of December 31, 2013 and 2012. See Note 5 for further discussion of the impairments recognized by the Predecessor.

Property, Plant and Equipment

Property, plant, and equipment are recorded at historical cost of construction or, upon acquisition, the fair value of the assets acquired. Expenditures for maintenance and repairs that do not add capacity or extend the useful life of an asset are expensed as incurred. Expenditures to extend the useful lives of the assets or enhance their productivity or efficiency from their original design are capitalized over the expected remaining period of use. The carrying value of the assets is based on estimates, assumptions and judgments relative to useful lives and salvage values. Sales or retirements of assets, along with the related accumulated depreciation, are removed from the accounts and any gain or loss on disposition is included in the statement of operations. Costs related to

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projects during construction, including interest on funds borrowed to finance the construction of facilities, are capitalized as construction in progress. Azure Midstream Holdings and the Predecessor’s gas gathering asset capital expenditures for 2013 and 2012 have been reduced by amounts reimbursed by producers for well connections.

Depreciation of property, plant, and equipment is recorded on a straight-line basis over the estimated useful lives of the assets. These estimates are based on various factors including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning the useful lives of similar assets. In connection with the Acquisition, the Company applied purchase accounting to the assets acquired and liabilities assumed and determined an appropriate estimate for the useful lives of the assets acquired. Our estimate of useful lives was different than the useful lives assigned to these assets by the Predecessor (See Note 5).

Impairment of Long-Lived Assets

Relevant accounting guidance requires long lived assets to be reviewed whenever events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. In order to determine whether an impairment has occurred, the Company compares the net book value of the asset to the estimated undiscounted future net cash flows related to the asset. The Company’s estimate of undiscounted cash flows is based on assumptions regarding the purchase and resale margins on natural gas, volume of gas available to the asset, markets available to the asset, operating expenses, and prices of natural gas liquids. The amount of availability of natural gas to an asset is sometimes based on assumptions regarding a producer’s future drilling activity, which may be dependent in part on natural gas prices. Projections of gas volumes and future commodity prices are inherently subjective and contingent upon a number of variable factors. Any significant variance in any of the above assumptions or factors could materially affect our cash flows, which could require us to record an impairment of an asset.

If an impairment has occurred, the amount of the impairment is determined based on the expected future net cash flows discounted using a rate management believes a market participant would assume is reflective of the risk associated with achieving the underlying cash flows.

Intangible Assets

Intangible assets with finite useful lives are reviewed for impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Intangible assets that have finite useful lives are amortized over their useful lives. Our intangible assets include customer relationships and assembled workforce intangible assets. The fair values of these intangibles are based on the present value of cash flows attributable to the assets, which includes management’s estimates of revenue and operating expenses and costs relating to the utilization of other assets to fulfill such relationships. For the customer relationships, we determine the recovery period based on historical customer attrition rates and management’s assumptions about future events, including customer demand, contract renewal, useful lives of related assets and market conditions. When necessary, intangible assets’ useful lives are revised and the impact on amortization is reflected on a prospective basis.

Goodwill

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changes indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. Goodwill is tested for impairment using a two-step quantitative test. The first step compares the fair value of the Company to its carrying value, including goodwill. If the fair value exceeds the carrying amount, the goodwill is not considered impaired. If the fair value does not exceed the carrying amount the second step compares the implied fair value to the carrying value of the Company. If the carrying amount of goodwill exceeds the implied fair value of that goodwill, the excess of the carrying value over the implied value is recognized as an impairment in the statement of operations.

Other Noncurrent Assets

Other noncurrent assets primarily consist of external costs incurred in connection with the closing of the Azure Midstream Holdings and the Predecessor Credit Agreements. Deferred loan costs are capitalized and amortized over the life of the related agreement. Amortization of deferred loan costs is included in interest expense in the statement of operations.

Asset Retirement Obligations

Accounting standards related to asset retirement obligations requires us to evaluate whether any future asset retirement obligations exist as of December 31, 2013 and 2012, and whether the expected retirement date of the related costs of retirement can be estimated. We have concluded that our natural gas gathering system assets, which include pipelines, compression facilities and treating facilities, have an indeterminate life because they are owned and will operate for an indeterminate future period when properly maintained. A liability for these asset retirement obligations will be recorded only if and when a future retirement obligation with a determinable life is identified. The Company and the Predecessor did not provide any asset retirement obligations as of December 31, 2013 and December 31, 2012 because the Company and the Predecessor did not have sufficient information to reasonably estimate such obligations, and the Company and the Predecessor had no current intention of discontinuing use of any significant assets.

Gas Imbalances

Quantities of natural gas over delivered or under delivered related to imbalance agreements are recorded monthly as accounts receivable or accounts payable using an estimated price based on current market prices, an index to current market prices or the weighted average prices of natural gas at the plant or system pursuant to imbalance agreements for which settlement prices have yet to be finalized. Dependent on imbalance contract terms within certain volumetric limits, imbalances may be settled by deliveries of natural gas. At December 31, 2013, the Azure Midstream Holdings imbalance receivables were $0.2 million, and imbalance payables were $0.8 million. At December 31, 2012, the Predecessor imbalance receivables were $0.8 million, and imbalance payables were $0.8 million.

Revenue Recognition

Primarily, the Company earns service fee revenue from the transportation, gathering, compression and treating of natural gas. Transportation, gathering, compression and treating services are generally provided on a fixed fee basis per unit based on the volumes (Mcf) or heating content (MMbtu) of natural gas.

Secondary revenue producing activities, which are reported as a component of revenues, are the sales of natural gas purchased from third parties, for which the Company takes title, and the sale of condensate liquids. Natural gas revenues arise from transactions that are completed under contracts with limited commodity price

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exposure, and we elect the normal purchases and normal sales exemption on all such transactions for accounting purposes. The Company receives a market price per barrel on our revenue from natural gas condensate liquids. We report the natural gas and condensate revenues and the associated purchases and expenses on a gross basis within our statement of operations. The cost of natural gas purchased from third parties is reported as a component of operating costs and expenses.

Revenue from all services and activities are recognized when all of the following criteria are met: (i) persuasive evidence of an exchange arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the price is fixed or determinable, and (iv) collectability is reasonably assured.

The Company has a natural gas gathering agreement with a customer that provides for a minimum revenue commitment (“MRC”). Under the MRC, our customer agrees to pay a minimum monetary amount over certain periods during the term of the MRC. The customer must make a deficiency payment to us at the end of the contract year if its actual revenues are less than its MRC for that year. The customer is entitled to utilize the deficiency payments to offset gathering fees in the following periods to the extent that such customer’s revenues in the following periods exceed its MRC for that period. This contract provision ranges for the entire duration of the gas gathering agreement, which is ten years. We record customer billings for obligations under the MRC (solely with respect to this natural gas gathering agreement) as deferred revenue when the customer has the right to utilize deficiency payments to offset gathering fees in subsequent periods. We recognize deferred revenue under this arrangement as revenue once all contingencies or potential performance obligations associated with the related revenues have either (i) been satisfied through the gathering of future excess volumes of natural gas, or (ii) expired (or lapsed) through the passage of time pursuant to the terms of the natural gas gathering agreement. We classify deferred revenue as noncurrent where the expiration of the customer’s right to utilize deficiency payments is greater than one year. As of December 31, 2013, deferred revenue under the MRC agreement was $1.1 million and is included within other long term liabilities. No deferred revenue amounts under these arrangements were recognized as revenue during the period from November 15, 2013 to December 31, 2013. We also have a gas gathering agreement with BG and EXCO that includes an annual minimum volume commitment (“MVC”) that could result in the receipt of a deficiency payment if the volumes of gas gathered are less than the MVC of 600,000 MMbtu/d for the annual period. We do not defer revenue associated with the MVC agreement because BG and EXCO are not entitled to utilize the deficiency payments to offset gathering fees in the following periods.

The Predecessor had no such MRC gas gathering agreements with its customers.

Income Taxes and Uncertain Tax Positions

No provision for federal income taxes is included within Azure Midstream Holdings or the Predecessor statements of operations as such income is taxable directly to Azure Midstream Holdings and Predecessor members. Each member is responsible for its share of federal and state income tax. Net earnings for financial statement purposes may differ significantly from taxable income reportable to each member as a result of differences between the tax basis and financial reporting basis of assets and liabilities.

Azure Midstream Holdings and the Predecessor is responsible for its portion of the Revised Texas Franchise Tax (the Texas margin tax). The tax is assessed on the Texas-sourced taxable margin, which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits. Although the bill states that the Texas margin tax is not an income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers both revenues and expenses. For the period from November 15, 2013 to December 31, 2013 Azure Midstream Holdings recorded $0.1 million of Texas

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margin tax expense. For the period from January 1, 2013 to November 14, 2013 and the year ended December 31, 2012, the Predecessor recorded $0.4 million and $0.4 million of Texas margin tax, respectively.

Azure Midstream Holdings and the Predecessor evaluate the uncertainty in tax positions taken or expected to be taken in the course of preparing the consolidated financial statements to determine whether the tax positions are more likely than not of being sustained by the applicable tax authority. Tax positions deemed not to meet the more likely than not threshold would be recorded as a tax benefit or expense in the current year. We believe that there are no uncertain tax positions and that no provision for income tax is required for these consolidated financial statements.

Environmental Costs

The operations of Azure Midstream Holdings and the Predecessor are subject to various federal, state and local laws and regulations relating to the protection of the environment. Although the Company believes that it is in compliance with applicable environmental regulations, the risk of costs and liabilities are inherent in pipeline ownership and operation, and there can be no assurances that significant costs and liabilities will not be incurred by the Company. Management is not aware of any contingent liabilities that currently exist with respect to environmental matters.

Commitments and Contingencies

The consolidated financial results of Azure Midstream Holdings and the Predecessor may be affected by judgments and estimates related to loss contingencies. Accruals for loss contingencies are recorded when management determines that it is probable that an asset has been impaired or a liability has been incurred and that such economic loss can be reasonably estimated. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events, and estimates of the financial impacts of such events. See Note 8 for a discussion of commitments and contingencies as of December 31, 2013 and 2012.

Earnings Per Unit

Earnings per unit has not been presented because Azure Midstream Holdings and the Predecessor’s members hold interests and not units.

Fair Value Measurements

The Company and the Predecessor utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible. The Company and the Predecessor determines fair value based on assumptions that market participants would use in pricing an asset or liability in the principal or most advantageous market. When considering market participant assumptions in fair value measurements, the following fair value hierarchy distinguishes between observable and unobservable inputs, which are categorized in one of the following levels:

•

Level 1 Inputs: Unadjusted quoted prices in active markets for identical assets or liabilities accessible to the reporting entity at the measurement date.

•

Level 2 Inputs: Other than quoted prices included in Level 1 inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the asset or liability.

•

Level 3 Inputs: Unobservable inputs for the asset or liability used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at measurement date.

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In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, an investment’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company and Predecessor’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment, and the Company and the Predecessor considers various factors specific to the investment. A review of the fair value hierarchy classification is conducted at each fiscal year end reporting date.

The fair value of a financial instrument is the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. As of December 31, 2013 and 2012, the carrying amount approximates fair value for cash and cash equivalents, accounts receivable, accounts payable and accrued expenses, and notes payable. The Company used Level 3 inputs in connection with establishing the fair values of assets and liabilities in connection with the Acquisition (See Note 3). The carrying value of the Azure Midstream Holdings and Predecessor debt obligation as of December 31, 2013 and 2012 approximates fair value and is a Level 2 valuation based on the observable inputs used for similar liabilities and the floating rate nature of the applicable interest rates.

Recent Accounting Pronouncements

There are currently no other recent pronouncements that have been issued that the Company believes will materially affect its consolidated financial statements.

(3) Acquisitions

Azure Midstream Holdings

On November 15, 2013, the Company purchased TGGT from EXCO and BG, and purchased ETG from Tenaska Capital Management, for a total purchase price of $1.0 billion, plus customary working capital adjustments. Both TGGT and ETG are engaged in natural gas gathering, processing, compression, treating, transportation and related services in North Louisiana and East Texas.

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information. We utilized a mix of the cost, income and market approaches to determine the estimated fair values of such assets and liabilities. The fair value measurements and models have been classified as non-recurring Level 3 measurements.

We recognized $6.1 million of acquisition-related costs within transaction costs during the period November 15, 2013 to December 31, 2013.

The following table summarizes the consideration paid for in the acquisition and the amounts of estimated fair value of the assets acquired and liabilities assumed at the acquisition date.


Purchase price allocation (in thousands):
Cash paid to EXCO, BG and Tenaska Capital Management	$	919,420
Equity issued to Tenaska Capital Management		90,000

Total purchase price	$	1,009,420

Assets acquired:
Current assets	$	27,146
Total tangible assets		824,043
Goodwill		100,896
Intangibles		80,100
Liabilities assumed:
Current liabilities		19,716
Remaining construction costs		1,981
Other long term liabilities		1,068

Total purchase price	$	1,009,420

We received $5.4 million of cash in connection with the acquisition of TGGT, and the table above does not reflect the cash received. See Note 5 for further discussion of the goodwill and intangible assets recognized as a result of the Acquisition.

Unaudited Pro Forma Financial Information

The following unaudited pro forma financial information for the period January 1, 2013 to November 14, 2013 and the year ended December 31, 2012 assumes the TGGT and ETG acquisition occurred on January 1, 2012. For the period January 1, 2013 to November 14, 2013 and the year ended December 31, 2012, ETG recognized $14.6 million and $31.2 million in revenues, respectively, and a loss from operations of $250.7 million and $3.7 million, respectively. ETG recognized an asset impairment of $237.0 million during the period January 1, 2013 to November 14, 2013, which was included in the net loss from operations and the pro forma net loss included below. The asset impairment was a result of adjusting the carrying value of the ETG property and equipment to its net realizable fair value prior to the ETG Contribution.

The pro forma adjustments for the period from January 1, 2013 to November 14, 2013 consist of a reduction in depreciation and amortization expense of $20.9 million, an increase in interest expense associated with the Azure Energy credit agreement (including amortization expense associated with deferred financing costs and commitments fees associated with the Revolver, see Note 6) of $22.7 million and an increase in income tax expense of $0.1 million because ETG was not allocated income tax expense associated with the Texas gross margin tax. The pro forma adjustments for the year ended December 31, 2012 consist of a reduction in

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depreciation and amortization expense of $20.1 million, an increase in interest expense associated with the Azure Energy credit agreement (including amortization expense associated with deferred financing costs and commitment fees associated with the Revolver, see Note 6) of $22.4 million and an increase in income tax expense of $0.1 million because ETG was not allocated income tax expense associated with the Texas gross margin tax.


	Period from January 1, 2013 to November 14, 2013			Year ended December 31, 2012
	(in thousands)
Revenues	$	194,885		$	277,673
Net (Loss) Income	$	(184,084	)	$	46,217

Pro forma information for the period from November 15, 2013 to December 31, 2013 is not presented because TGGT and ETG were included within the Azure Midstream Holdings results of operations for the period. The unaudited pro forma information is not necessarily indicative of what our statements of operations would have been if the transaction occurred on January 1, 2012, or what the financial position and results from operations will be for any future periods. For the period from November 15, 2013 to December 31, 2013, TGGT contributed $21.7 million in revenue and $6.0 million in income from operations to the Azure Midstream Holdings statement of operations. For the period from November 15, 2013 to December 31, 2013, ETG contributed $3.1 million in revenues and $0.4 million in loss from operations to the Azure Midstream Holdings statement of operations.

Predecessor

During 2012, the Predecessor received an offer to purchase the Danville gathering system. Danville was operated solely to gather natural gas produced from EXCO operated wells in the Danville field near Kilgore in Gregg County, Texas. In December 2012, the Predecessor sold the Danville gathering system to Gas Solutions II, Ltd. (subsidiary of Costar Midstream) for $7.5 million. The net book value of the Danville assets was $13.0 million, resulting in an impairment charge of $5.5 million. The proceeds received under the terms of the sale were used as a mandatory repayment of the amount outstanding under the Predecessor Credit Agreement, see Note 6.

(4) Accounts Receivable and Concentration of Credit Risk

Our primary markets are in the North Louisiana and East Texas natural gas supply basins, and we deliver natural gas to 20 existing major intrastate and interstate pipelines in these regions. We have a concentration of revenues and trade accounts receivable due from customers, including EXCO and BG, engaged in the production, trading, distribution and marking of natural gas and condensate. These concentrations may affect overall credit risk in that these customers, including EXCO and BG, may be affected similarly by changes in the economic, regulatory, environmental or other factors. We analyze our customers’ historical financial and operational information before extending credit. The Predecessor’s concentration of credit risk is not materially different than that of the Company.

Our top two customers, EXCO and BG, for the period from November 15, 2013 to December 31, 2013 each represented 33%, respectively, of our consolidated total revenue. The Predecessor’s top two customers, also EXCO and BG, for the period from January 1, 2013 to November 14, 2013 and the year ended December 31, 2012 each represented 37% and 40%, respectively, of consolidated total revenue. EXCO and BG are both considered related parties, see Note 9 for further discussion of related party transactions.

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Allowance for doubtful accounts is determined based on a specific identification of accounts reviewed by management and deemed doubtful as to collectability. As of December 31, 2013 and 2012, the Company and the Predecessor recorded a $0.1 million and $1.1 million reserve for amounts deemed to be uncollectable, respectively.

(5) Property and Equipment, Identifiable Intangible Assets and Goodwill

Property and Equipment

Property and Equipment consisted of the following:


	Estimated Useful Life (yrs)	Azure Midstream Holdings December 31, 2013			Estimated Useful Life (yrs)	Azure Midstream Predecessor December 31, 2012
	(in thousands)
Pipelines	45	$	697,450		30 – 40	$	1,014,823
Buildings	30		6,432		20 – 25		5,644
Gas processing and compression facilities	20		114,004		4 – 20		177,288
Other depreciable assets	5 – 15		5,842		4 – 20		8,312

Total property and equipment			823,728				1,206,067
Accumulated depreciation			(2,797	)			(76,274	)

Total			820,931				1,129,793
Construction in progress			1,681				12,343
Land and other			490				72

Property and Equipment, net		$	823,102			$	1,142,208

Depreciation is provided using the straight-line method based on the estimated useful life of each asset. Our estimated useful lives were different than the estimated useful lives assigned by the Predecessor. Depreciation expense recognized by Azure Midstream Holdings for the period from November 15, 2013 to December 31, 2013 was $2.8 million. Depreciation expense recognized by the Predecessor for the period from January 1, 2013 to November 14, 2013 and the year ended December 31, 2012 was $31.1 million and $32.1 million, respectively.

We completed our new Fairway processing plant in March 2014. The Fairway processing plant will recover natural gas liquids (“NGL”) from natural gas produced from the James Lime formation and return dry residue gas into the Center system for delivery into third party and affiliated interconnections. NGLs recovered will be trucked to third party fractionation facilities. The Fairway processing plant asset is included within gas processing and compression facilities in the table above, and we will recognize revenues associated with residue gas sales, NGL sales and processing fees within natural gas and NGL sales.

We capitalize interest on qualified projects during their construction period. Once a project is placed into service, capitalized interest, as a component of the total cost of construction, is depreciated over the useful life of the asset constructed. The Predecessor’s accounting policy associated with capitalized interest was not materially different than ours. Azure Midstream Holdings did not recognize any capitalized interest during the period from November 15, 2013 to December 31, 2013 as there were no qualified projects under construction during the period. The Predecessor recognized capitalized interest on qualified projects for the period from January 1, 2013 to November 14, 2013 and the year ended December 31, 2012 in the amounts of $0.03 million and $2.0 million, respectively.

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Long Lived Asset Impairments

Azure Midstream Holdings

Azure Midstream Holdings had no long lived asset impairments during the period from November 15, 2013 to December 31, 2013.

Predecessor

A summary of the impairment expense for the period January 1, 2013 to November 14, 2013 and for the year ended December 31, 2012 is reflected below:


	2013			2012
	(in thousands)
Decommissioning temporary treating facility	$	(664	)	$	34,886
Danville gathering system		—			5,470
Canceled capital projects		—			9,247
Assets held for sale		1,247			1,168

	$	583		$	50,771

In the first quarter of 2012, the Predecessor recorded an impairment of approximately $34.9 million for certain assets associated with the installation of temporary treating facilities in response to an explosion at the Holly 6 amine treating facility in May 2011. After completion of an independent engineering study, the decision was made to reactivate the undamaged permanent facility at the location since the facility had not sustained as much damage as was initially contemplated. The impairment resulted from costs incurred to install and provision temporary treating facilities that were not utilized or were determined to have a shorter utilization period than originally anticipated. The credit recorded in 2013 was a result of cost savings on the removal of the equipment as compared to the project removal budget.

The Predecessor also recorded a $9.2 million impairment during 2012 related to canceled projects, comprised of expired right of way, surveying costs, and outsourced engineering services. The projects were canceled as a result of decreased natural gas prices and reduced producer development drilling projections.

The Predecessor recorded certain assets as held for sale. During the period from January 1, 2013 to November 14, 2013 and the year ended December 31, 2012, the Predecessor recognized an impairment of $1.2 million and $1.2 million, respectively, as a result of adjusting the carrying value of these held for sale assets to their net realizable fair value.

Identifiable Intangible Assets

The fair value of the acquired intangible assets is associated with customer relationships and was determined based on the present value of cash flows attributed to these customers, which includes management’s estimate of revenue and operating expenses and costs relating to utilization of other assets to fulfill such relationships. We determined the recovery period based on historical customer attrition rates and management’s assumptions on future events. The customer relationships intangible asset is being amortized over the estimated recovery period of 12 years. Amortization expense associated with this intangible asset was $0.7 million for the period from November 15, 2013 to December 31, 2013 and is included within depreciation and amortization expense.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Identifiable intangible assets reported within the balance sheet as of December 31, 2013 are comprised of the following:


	Gross Carrying Amount		Accumulated Amortization		Net
	(in thousands)
Identifiable Intangible Assets:
Customer relationship	$	80,100	$	667	$	79,433

The estimated amortization expense of intangible assets for each of the next five fiscal years is $6.7 million.

There was no amortization expense associated with intangible assets recognized during the period from January 1, 2013 to November 14, 2013 and the year ended December 31, 2012 because the Predecessor had no such intangible assets.

Goodwill

We evaluate goodwill for impairment annually on October 1st. We also evaluate goodwill whenever events or circumstances indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. There were no impairments of goodwill during the period from November 15, 2013 to December 31, 2013. The Predecessor consolidated financial statements do not include goodwill.

(6) Long Term Debt

Azure Energy Credit Agreement

On November 15, 2013, Azure Midstream Holdings and Azure Midstream Energy closed on a $550 million Senior Secured Term Loan B (“TLB”) maturing November 15, 2018, and a $50 million Senior Secured Revolving Credit Facility (“Revolver” and collectively with the TLB, the “Credit Agreement”) with a maturity of November 15, 2017. The financing, which was led by JPMorgan Chase Bank, N.A., as administrative agent, includes a syndicate of five external banks. Borrowings under the Credit Agreement are unconditionally guaranteed, jointly and severally, by all of our subsidiaries and are collateralized by first priority liens on substantially all of existing and subsequently acquired assets and equity.

Under the TLB, borrowings bear interest at our option of either the (i) monthly Eurodollar Rate, which is the British Bankers Association London Inter Bank Offered Rate and cannot be less than 1% per year or (ii) the Alternative Base Rate (“ABR”), which is the greatest of (a) the Prime Rate in effect on such day, (b) the Federal Funds Rate; plus 0.50% or (c) the 30-day Eurodollar Rate; plus 1.0%; plus the applicable Eurodollar margin or the ABR margin which is 5.5% and 4.5%, respectively. We have elected the Eurodollar Rate and Eurodollar margin for the TLB for the period November 15, 2013 to December 31, 2013.

For the Revolver, borrowings bear interest under the same terms as the TLB and the applicable Eurodollar margin and ABR margin vary quarterly based on the Company’s consolidated leverage ratio, as defined in the Credit Agreement, being generally computed as the ratio of (a) total funded indebtedness to (b) the sum of

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consolidated earnings before interest, taxes, depreciation, amortization before certain other noncash charges, or Adjusted EBITDA. The Eurodollar margin and ABR margin for the Revolver is as follows:


Consolidated Leverage Ratio	Applicable Margin for Eurodollar Loans			Applicable Margin for ABR Loans
Less than or equal to 2.00 to 1.00		2.75	%		1.75	%
Less than or equal to 3.00 to 1.00 but greater than 2.00 to 1.00		3.00	%		2.00	%
Less than or equal to 3.50 to 1.00 but greater than 3.00 to 1.00		3.25	%		2.25	%
Less than or equal to 4.00 to 1.00 but greater than 3.50 to 1.00		3.50	%		2.50	%
Greater than 4.00 to 1.00		3.75	%		2.75	%

The weighted average interest rate for the period from November 15, 2013 to December 31, 2013 was 6.50%. Outstanding borrowings associated with our Credit Agreement were $550.0 million as of December 31, 2013, of which $27.5 million has been classified as current because the principal payments are due within one year. As of December 31, 2013, all outstanding borrowings were associated with the TLB and we had no outstanding borrowings under the Revolver.

We may prepay all loans under the Credit Agreement at any time subject to certain notice requirements. The Credit Agreement requires repayment of the TLB in consecutive quarterly installments on the last day of each fiscal quarter commencing on March 31, 2014. Each of the installments shall be in an aggregate principal amount equal to 1.25% of the original aggregate principal amount of the TLB. During the period from November 15, 2013 to December 31, 2013 we were not required to make principal payments on the TLB. We will have remaining principal payments associated with the TLB of $27.5 million in 2014, 2015, 2016 and 2017 and the remaining principal amount is due upon maturity in 2018.

The Credit Agreement requires mandatory prepayments of amounts outstanding under the TLB and Revolver with the net proceeds from any asset sales (or recovery events) yielding greater than $7.5 million (excluding routine sales conducted in the normal course of business).

Our Credit Agreement contains, among other things, covenants defining our and our subsidiaries’ ability to dispose of assets, merge, make distributions, repurchase, or redeem equity interest and indebtedness, incur indebtedness and guarantees, create liens, enter into agreements with negative pledge clauses, make certain investments or acquisitions, enter into transactions with affiliates or engage in any business activity other than our existing business. Our Credit Agreement also contains covenants requiring us to deliver to the Lenders our leverage and interest coverage financial covenant certificates of compliance, as well as an annual excess cash flow covenant.

The maximum permitted leverage ratio is 5.00 times debt to total consolidated adjusted EBITDA for the period from December 31, 2013 to December 31, 2014, 4.75 times debt to total consolidated adjusted EBITDA for the period from March 31, 2015 to December 31, 2015, and 4.50 times debt to total consolidated adjusted EBITDA thereafter. The minimum interest coverage is 2.50 times consolidated adjusted EBITDA to total interest expense.

Our Credit Agreement also includes customary events of default, including nonpayment of principal or interest, violation of covenants, incorrectness of representations and warranties, cross defaults and cross acceleration, bankruptcy, material judgments, Employee Retirement Income Security Act of 1974, as amended (ERISA) events, actual or asserted invalidity of the guarantees or the security documents, and certain changes of control of the Company. Compliance with these financial covenants under our Credit Agreement is tested

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

quarterly. As of December 31, 2013, we are in compliance with the covenants associated with our Credit Agreement.

We incurred $21.6 million in fees related to the Credit Agreement that were capitalized as deferred financing costs. These costs are amortized under the effective interest method over the term of the Credit Agreement and are recorded in interest expense. The unamortized balance of deferred financing costs is included within other noncurrent assets and as of December 31, 2013 the unamortized balance was $21.0 million. Amortization expense associated with these deferred financing costs was $0.6 million for the period from November 15, 2013 to December 31, 2013, and such amount has been included within interest expense.

The carrying value of our debt obligations as of December 31, 2013 approximates fair value due to the floating rate nature of our applicable interest rates and is a Level 2 valuation based on the observable inputs used for similar liabilities.

Predecessor Credit Agreement

In January 2011, the Predecessor entered into a $500.0 million senior secured credit facility (the “Predecessor Credit Agreement”) with a maturity of five years. The Predecessor Credit Agreement, which was led by JPMorgan Chase Bank, N.A., as administrative agent, included a syndicate of four external banks and an affiliate of BG, BG Atlantic Finance Limited. Borrowings under the Predecessor Credit Agreement were unconditionally guaranteed, jointly and severally, by all of the Predecessor’s subsidiaries and were collateralized by first priority liens on substantially all of the existing and subsequently acquired assets and equity. On January 25, 2012, the Predecessor closed an amendment to the Predecessor Credit Agreement increasing the aggregate commitment to $600.0 million with the same maturity, pricing and financial covenants as the Predecessor Credit Agreement. The amendment included seven new lenders and removed the related-party lender, BG Atlantic Finance Limited. In connection with the Acquisition, EXCO and BG proportionally paid the remaining $405.0 million outstanding borrowings under the Predecessor Credit Agreement with proceeds received from the Acquisition.

Under the Predecessor Credit Agreement, outstanding borrowings bore interest at the Predecessor’s option of either the monthly Eurodollar Rate (the British Bankers Association London Inter-Bank Offered Rate Libor) plus the applicable Eurodollar spread or the Alternate Base Rate “ABR” (the highest of the (a) Prime Rate in effect on such day, (b) Federal Funds Rate plus 0.50%, or (c) the 30-day Eurodollar Rate plus 1.0%) plus an applicable ABR spread.

The applicable Eurodollar Spread and ABR Spread for the interest rate varied quarterly based on the Predecessor’s consolidated leverage ratio (as defined in the Predecessor Credit Agreement, generally computed as the ratio of (a) total funded indebtedness to (b) the sum of consolidated earnings before interest, taxes, depreciation, amortization before certain other noncash charges, or adjusted EBITDA).

The weighted average interest rate associated with the Predecessor Credit Agreement for the period from January 1, 2013 to November 14, 2013 and the year ended December 31, 2012 was 2.42% and 2.72%, respectively. Outstanding borrowings associated with the Predecessor Credit Agreement averaged $446.6 million for the period from January 1, 2013 to November 14, 2013 and were $491.6 million as of December 31, 2012. The outstanding borrowings have been reflected as long-term liabilities because there were no amounts due within one year.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Agreement and were recorded in interest expense. Amortization expense associated with these deferred financing costs was $0.9 million and $2.4 million for the period from January 1, 2013 to November 14, 2013 and the year ended December 31, 2012, respectively, and such amount has been included within interest expense.

(7) Lease Obligations

Azure Midstream Holdings Lease Obligations

Azure Midstream Holdings leases compression and treating equipment and we account for these leases as operating leases. Total rent expense for operating leases, including those with terms of less than one year, was $0.7 million for the period from November 15, 2013 to December 31, 2013.

The following table is a schedule of future minimum lease payments for leases that had initial or noncancelable lease terms in excess of one year as of December 31, 2013.


Year	Operating leases
	(in thousands)
2014	$	3,567
2015		2,690
2016		1,140
2017		168
2018		162
2019		764

Total lease payments	$	8,491

Predecessor Lease Obligations

The Predecessor leased compression and treating equipment and these leases were accounted for as operating leases. Total rent expense for operating leases, including those with terms of less than one year, was $1.8 million and $11.8 million for the period from January 1, 2013 to November 14, 2013 and the year ended December 31, 2012, respectively.

(8) Commitments and Contingencies

Legal Matters

Azure Midstream Holdings

Liabilities for loss contingencies arising from claims, assessments, litigation, fines, penalties, or from other sources are recorded when it is probable that a liability has been incurred and the amount of the assessment can be reasonably estimated. Legal costs related to any such contingencies are expensed as incurred. Accruals for estimated losses are adjusted as further information develops or as circumstances change. At December 31, 2013, the Company did not have an accrual related to contractual disputes.

During 2013, the Company has been a party to litigation arising from events occurring during the normal course of business. While we are unable to estimate the range of exposure, we believe that there is no significant exposure to the Company arising out of these matters. At December 31, 2013, the Company had no active litigation matters the Company believes will have a material adverse impact on its consolidated results of operations, financial condition or cash flows.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Predecessor

Liabilities for loss contingencies arising from claims, assessments, litigation, fines, penalties, or from other sources were recorded by the Predecessor when it is probable that a liability has been incurred and the amount of the assessment can be reasonably estimated. Legal costs related to any such contingencies were expensed as incurred. Accruals for estimated losses are adjusted as further information develops or as circumstances change. At December 31, 2012, the Predecessor recorded contingencies of $1.2 million related to contractual disputes within accounts payable and accrued liabilities. During 2012, the Predecessor settled one claim resulting in an additional loss of $0.6 million, which has been included within other expense.

Regulatory Compliance

In the ordinary course of our business, we are subject to various laws and regulations. In the opinion of our management, compliance with current laws and regulations will not have a material effect on our results of operations, cash flows or financial condition. The Predecessor had no such regulatory compliance matters impacting its consolidated financial statements.

(9) Related Party Transactions

Azure Midstream Holdings Related Party Transactions

Subsequent to the Acquisition, the respective employees of BG and EXCO (previous secondees to the Predecessor, see further discussion below) continued as employees through December 31, 2013 under transition services agreements with Azure Midstream Holdings. BG and EXCO invoiced Azure Midstream Holdings and subsidiaries for the payroll and benefits cost of the relevant employees, as well as for information technology, and treasury support services under the respective transition service agreements. Additionally, Azure Midstream Holdings entered into a transition services agreement with member Tenaska Capital Management to assist with the transition of accounting services, natural gas flow management and other administrative functions related to the contributed ETG business through December 31, 2013.

For the period from November 15, 2013 through December 31, 2013 under these agreements, Azure Midstream Holdings recorded operating expenses of $1.6 million and general and administrative expenses of $1.9 million payable to its members.

Furthermore, for the period from November 15, 2013 to December 31, 2013, Azure Midstream Holdings recorded revenues from its Members of $16.4 million. As of December 31, 2013, Members accounts receivable were $20.8 million.

Accounts payable and accrued liabilities owed to Members as of December 31, 2013 were $6.5 million.

Predecessor Related Party Transactions

For the period from January 1, 2013 to November 14, 2013 and the year ended December 31, 2012, the Predecessor had significant transactions with the Predecessor Members.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

which enabled the Predecessor to purchase services from either EXCO or BG. EXCO and BG invoiced the Predecessor for actual documented costs attributable or fairly allocated to the employment and secondment of the EXCO and BG secondees. Services provided by EXCO and BG employees who were not seconded to the alliance were billed to the Predecessor pursuant to the respective service agreement.

For the period from January 1, 2013 to November 14, 2013 and the year ended December 31, 2012 under these agreements with the Predecessor Members, the Predecessor recorded operating expenses of $8.6 million and $7.5 million, respectively, and general and administrative expenses of $6.0 million and $12.6 million, respectively.

Furthermore, for the period from January 1, 2013 to November 14, 2013 and the year ended December 31, 2012, the Predecessor recorded revenues from the Predecessor Members of $135.7 million and $198.2 million, respectively. As of December 31, 2012, Predecessor Members accounts receivable were $28.6 million.

Accounts payable and accrued liabilities owed to the Predecessor Members as of December 31, 2012 were $3.2 million.

(10) Supplemental Footnote Information

Supplemental Cash Flow Information


	Azure Midstream Holdings
	Period from November 15, 2013 to December 31, 2013
	(in thousands)
Supplemental Disclosures:
Cash paid for Interest	$	3,082

Supplemental schedule of non-cash investing and financing activities:
Noncash capital expenditures included in accounts payable and accrued liabilities	$	3,346
Members’ equity issued for property and equipment	$	90,000


	Predecessor
	Period from January 1, 2013 to November 14, 2013		Year ended December 31, 2012
	(in thousands)
Supplemental Disclosures:
Cash paid for interest, net of amounts capitalized	$	9,203	$	14,762
Cash paid for income taxes	$	460	$	494

Supplemental schedule of non-cash investing and financing activities:
Noncash capital expenditures included in accounts payable and accrued liabilities	$	2,282	$	9,277
Noncash capital contribution	$	—	$	1,286
Net impact of noncash exchange of property and equipment with third party	$	6,084	$	—

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Operating Revenues


	Azure Midstream Holdings		Predecessor
	Period from November 15, 2013 to December 31, 2013		Period from January 1, 2013 to November 14, 2013		Year ended December 31, 2012
	(in thousands)
Operating revenues
Transportation, gathering, compression and treating—affiliates	$	15,736	$	134,664	$	192,155
Transportation, gathering, compression and treating—non-affiliates		3,842		16,331		19,350
Natural gas and NGL sales—affiliates		653		1,001		6,088
Natural gas and NGL sales—non-affiliates		4,588		28,336		28,858

Total operating revenues	$	24,819	$	180,332	$	246,451

F-38

AZURE MIDSTREAM HOLDINGS LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

As of September 30, 2014 and December 31, 2013

(Unaudited)


	September 30, 2014		December 31, 2013
	(in thousands)
Current Assets
Cash and cash equivalents	$	26,034	$	15,576
Restricted cash		79		—
Accounts receivable—affiliates		14,553		20,834
Accounts receivable—nonaffiliates, net of allowances for bad debt of $41 in 2014 and $94 in 2013		11,663		13,678
Assets held for sale		4,190		4,065
Other Current Assets		1,187		955

Total current assets		57,706		55,108

Property and Equipment, net		823,068		823,102
Goodwill		100,896		100,896
Intangible Assets, net		74,726		79,433
Other Non-Current Assets		18,167		21,801

Total assets	$	1,074,563	$	1,080,340

Current Liabilities
Accounts payable and accrued liabilities		19,959		30,151
Current portion of long-term debt		28,649		27,500

Total current liabilities		48,608		57,651
Long-term liabilities
Long-term debt		505,364		522,500
Other long-term liabilities		5,351		1,131

Total liabilities		559,323		581,282
Commitments and contingencies (see Note 8)
Members’ equity		515,240		499,058

Total liabilities and members’ equity	$	1,074,563	$	1,080,340

See accompanying notes to the condensed consolidated financial statements.

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AZURE MIDSTREAM HOLDINGS LLC AND SUBSIDIARIES AND

AZURE MIDSTREAM PREDECESSOR AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

For the Nine-Month Periods Ended September 30, 2014 and 2013

(Unaudited)


	Azure Midstream Holdings LLC		Predecessor
	For the Nine-Month Period Ended September 30, 2014		For the Nine-Month Period Ended September 30, 2013
	(in thousands)
Revenues:
Operating revenues—affiliates	$	77,827	$	125,014
Operating revenues—nonaffiliates		57,006		33,546

Total operating revenues		134,833		158,560

Operating expenses:
Cost of purchased gas and NGLs sold		30,095		18,239
Operating expense		23,685		28,993
General and administrative		10,760		9,820
Asset impairments		228		583
Depreciation and amortization		21,989		26,713

Total expenses		86,757		84,348

Income from operations		48,076		74,212
Interest expense		31,145		9,331
Other expense		326		1,695

Net income before income taxes		16,605		63,186
Income tax expense		423		317

Net income	$	16,182	$	62,869

See accompanying notes to the condensed consolidated financial statements.

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AZURE MIDSTREAM HOLDINGS LLC AND SUBSIDIARIES AND

AZURE MIDSTREAM PREDECESSOR

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Nine-Month Periods Ended September 30, 2014 and 2013

(Unaudited)


	Azure Midstream Holdings LLC			Predecessor
	September 30, 2014			September 30, 2013
	(in thousands)
Operating activities:
Net income	$	16,182		$	62,869
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		21,989			26,713
Amortization of deferred financing costs		3,684			784
Impairment of assets		228			583
Loss on extinguishment of debt		303			—
Loss on sale of assets		110			198
Other, net		1,829			2,397
Changes in operating assets and liabilities:
Accounts receivable, net		8,714			4,603
Other current assets		(232	)		1,457
Accounts payable and other current liabilities		(9,709	)		(2,772	)
Other long term liabilities		4,282			—

Net cash provided by operating activities		47,380			96,832

Investing activities:
Capital expenditures		(16,363	)		(27,604	)
Proceeds from sale of property and equipment		676			1,551
Restricted cash		(79	)		—
Other		(1,138	)		32

Net cash used in investing activities		(16,904	)		(26,021	)

Financing activities:
Repayments under credit agreements		(20,625	)		(71,642	)
Payments of deferred financing costs		(335	)		—
Payments on capital lease obligations		(15	)		(2,029	)
Other		957			—

Net cash used in financing activities		(20,018	)		(73,671	)

Increase in cash and cash equivalents		10,458			(2,860	)
Cash and cash equivalents—Beginning of period		15,576			8,050

Cash and cash equivalents—End of period	$	26,034		$	5,190

See accompanying notes to the condensed consolidated financial statements.

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AZURE MIDSTREAM HOLDINGS LLC AND SUBSIDIARIES AND

AZURE MIDSTREAM PREDECESSOR

CONDENSED CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY

For the Nine-Month Periods Ended September 30, 2014 and 2013

(Unaudited)


	Members’ Equity
	(in thousands)
Azure Midstream Holdings LLC
Beginning Members’ Equity—December 31, 2013	$	499,058
Members’ share of period net income		16,182

Ending Members’ Equity—September 30, 2014	$	515,240


	Members’ Equity
	(in thousands)
Azure Midstream Predecessor
Beginning Members’ Equity—December 31, 2012	$	678,608
Members’ share of period net income		62,869

Ending Members’ Equity—September 30, 2013	$	741,477

See accompanying notes to the condensed consolidated financial statements.

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AZURE MIDSTREAM PREDECESSOR

NOTES TO CONDENSED CONSOLIDATED STATEMENTS

(1) Organization and Nature of Business

Organization

Azure Midstream Holdings

On November 15, 2013, Azure Midstream Holdings acquired 100% of the equity interests in TGGT Holdings, LLC (“TGGT”) for an aggregate sales price of $910 million, plus customary working capital adjustments, from EXCO Resources, Inc. (“EXCO”) and BG Group plc (“BG”). As part of the Acquisition, members of Azure Midstream Holdings management, Energy Spectrum Partners VI LP, and its parallel and co-investment funds (“Energy Spectrum Partners”), a group of co-investors affiliated with Energy Spectrum Partners (the “Co-Investors”) and an affiliate of TPF II, LP (“Tenaska Capital Management” and collectively with the members of management, Energy Spectrum Partners and the Co-Investors, the “Members”) contributed a combined $410 million in cash for an ownership interest in Azure Midstream Holdings. In a related transaction, TPF II East Texas Gathering, LLC (“ETG”), a business managed by Tenaska Capital Management, was contributed to Azure Midstream Holdings in exchange for a $90 million additional ownership interest in Azure Midstream Holdings valued at $90 million (the “ETG Contribution”). We refer to our acquisition of TGGT and the ETG Contribution as the “Acquisition.” As partial consideration to the Acquisition, EXCO and BG collectively retained a 7% ownership in Azure Midstream Holdings (the “EXCO and BG Contribution”). As of September 30, 2014 and December 31, 2013, members of management, Energy Spectrum Partners, the Co-Investors and Tenaska Capital Management each owned 2%, 29%, 33% and 29% of Azure Midstream Holdings, respectively. As of September 30, 2014 and December 31, 2013, EXCO and BG, collectively, owned 7% of Azure Midstream Holdings.

As part of the initial public offering of limited partner units in the Partnership (the “Offering”), Azure Midstream Holdings will cause Azure Energy to be contributed to a newly formed limited partnership, Azure Midstream Operating Company, LP (“Azure Midstream Operating”). Azure Midstream Holdings will then contribute an approximate 40% limited partner interest in Azure Midstream Operating to the Partnership in exchange for common units, subordinated units and incentive distribution rights of the Partnership. The Partnership will also own all of the ownership interest in Azure Midstream Operating Company GP, LLC (the “Azure Midstream Operating GP”), a newly formed Delaware limited liability company and the general partner of Azure Midstream Operating. The Partnership will consolidate Azure Midstream Operating as a result of its ownership of Azure Midstream Operating GP. Azure Midstream Holdings will retain the remaining 60% limited partner interest in Azure Midstream Operating and will own all of the ownership interest in Azure GP.

Azure Midstream Predecessor

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NOTES TO CONDENSED CONSOLIDATED STATEMENTS

combined net book value of $316.3 million, to the Predecessor, in exchange for membership interest in the Predecessor. EXCO then sold 50% of its membership interest in the Predecessor to BG for cash consideration of approximately $269.2 million, including closing adjustments. Upon formation, EXCO and BG (the “Predecessor Members”) contributed $20.0 million each to fund initial operations of the Predecessor. The Predecessor Member’s capital was equalized at the opening balance sheet date, per the terms of the Predecessor formation agreement.

The Predecessor’s operations were overseen by a management board with equal membership from both of the Predecessor Members. Neither EXCO nor BG had control over the management of, or a controlling beneficial economic interest in, the operations of the Predecessor. Each Predecessor Member had no liability in excess of: (i) the amount of its contributions to the Predecessor; (ii) its share of any assets and undistributed profits of the Predecessor; (iii) its obligation to make other payments expressly provided for in the Predecessor formation agreement; and (iv) the amount of any distributions wrongfully distributed to it.

Unless the context requires otherwise, all references to “we,” “our,” “us” and the “Company” refers to Azure Midstream Holdings, including Azure Energy. All references to the Predecessor refers to the Azure Midstream Predecessor. All references to the “Partnership” refers to Azure Midstream Partners, LP.

Nature of Business

Azure Midstream Holdings and the Predecessor are engaged in natural gas gathering, compression, treating, transportation, and related services primarily in North Louisiana and East Texas focused on the Haynesville, Bossier and Cotton Valley formations. Azure Midstream Holdings and the Predecessor operate more than 1,365 miles of pipeline that move natural gas from these North Louisiana and East Texas supply basins to 20 existing major intrastate and interstate pipelines in the region.

(2) Basis of Presentation

The accompanying condensed consolidated financial statements of Azure Midstream Holdings and the Predecessor have been prepared pursuant to the rules and regulations of the United States Securities and Exchange Commission. Pursuant to such rules and regulations, certain disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been omitted. The accompanying condensed consolidated financial statements and notes should be read in conjunction with the Azure Midstream Holdings and Predecessor audited consolidated financial statements and notes as of December 31, 2013 and 2012, and the period from November 15, 2013 to December 31, 2013, the period from January 1, 2013 to November 14, 2013 and the year ended December 31, 2012, included elsewhere within this offering prospectus (the “Prospectus”).

The accompanying condensed consolidated financial statements reflect all adjustments that are, in the opinion of management, necessary to a fair statement of the Azure Midstream Holdings financial position as of September 30, 2014 and December 31, 2013 and the nine-month period ended September 30, 2014, and the Predecessor financial position for the nine-month period ended September 30, 2013. The condensed consolidated financial statements as of September 30, 2014 and December 31, 2013 and for the nine-month periods ended

F-44

AZURE MIDSTREAM HOLDINGS LLC AND SUBSIDIARIES AND

AZURE MIDSTREAM PREDECESSOR

NOTES TO CONDENSED CONSOLIDATED STATEMENTS

September 30, 2014 and 2013, are unaudited and have been prepared on the same basis as the audited consolidated financial statements of Azure Midstream Holdings and the Predecessor. All intercompany accounts and transactions have been eliminated in the preparation of the accompanying condensed consolidated financial statements. The Azure Midstream Holdings condensed consolidated financial statements are comprised of the TGGT and ETG assets and operations as of September 30, 2014 and December 31, 2013, and for all periods subsequent to the Acquisition. The Predecessor condensed consolidated financial statements are comprised of the TGGT assets and operations as of and for all periods prior to the Acquisition as TGGT is the Predecessor of Azure Midstream Holdings for accounting purposes. Adjustments (consisting of normal recurring accruals) necessary for a fair presentation of the results of operations and financial position have been included herein. Due to estimates inherent in preparing interim condensed consolidated financial statements, the operating results for the nine-month period ended September 30, 2014 are not necessarily indicative of the results that may be expected for the year ending December 31, 2014 or for any future quarterly period.

Segments

Significant Accounting Policies

During the nine-month period ended September 30, 2014, there were no material changes to our significant accounting policies described in Note 2 of our audited consolidated financial statements included elsewhere in the Prospectus.

Recent Accounting Pronouncements

F-45

AZURE MIDSTREAM HOLDINGS LLC AND SUBSIDIARIES AND

AZURE MIDSTREAM PREDECESSOR

NOTES TO CONDENSED CONSOLIDATED STATEMENTS

(3) Acquisitions

Azure Midstream Holdings

We allocated the total purchase price to the assets acquired and the liabilities assumed based on their estimated fair values at the acquisition date, with the excess purchase price recorded as goodwill. The goodwill of $100.9 million arising from the acquisition consists largely of the synergies and ability to connect the systems to allow customers more flexibility on delivery of gas. The fair values of the assets and liabilities are based on assumptions related to expected future cash flows, discount rates and asset lives using currently available information. We utilized a mix of the cost, income and market approaches to determine the estimated fair values of such assets and liabilities. The fair value measurements and models have been classified as non-recurring Level 3 measurements.

We recognized $6.1 million of acquisition-related costs within transaction costs during the period November 15, 2013 to December 31, 2013. There were no acquisition-related costs recognized during the nine-month periods ended September 30, 2014 and 2013.

The following table summarizes the consideration paid for in the acquisition and the amounts of estimated fair value of the assets acquired and liabilities assumed at the acquisition date.


Purchase price allocation (in thousands):
Cash paid to EXCO, BG and Tenaska Capital Management	$	919,420
Equity issued to Tenaska Capital Management		90,000

Total purchase price	$	1,009,420

Assets acquired:
Current assets	$	27,146
Total tangible assets		824,043
Goodwill		100,896
Intangibles		80,100
Liabilities assumed:
Current liabilities		19,716
Remaining construction costs		1,981
Other long term liabilities		1,068

Total purchase price	$	1,009,420

The following unaudited pro forma financial information for the nine-month period ended September 30, 2013 assumes the TGGT and ETG acquisitions occurred on January 1, 2012. During the nine-month period ended September 30, 2013, ETG recognized $13.0 million in revenues and a loss from operations of $10.4 million.

F-46

AZURE MIDSTREAM HOLDINGS LLC AND SUBSIDIARIES AND

AZURE MIDSTREAM PREDECESSOR

NOTES TO CONDENSED CONSOLIDATED STATEMENTS

The pro forma adjustments for the nine-month period ended September 30, 2013 consist of a reduction in depreciation and amortization expense of $18.0 million, an increase in interest expense associated with the Azure Energy credit agreement (including amortization of deferred financing costs and commitment fees associated with the Revolver, see Note 6) of $18.4 million and an increase in income tax expense of $0.1 million because ETG was not allocated income tax expense associated with the Texas gross margin tax.


	Nine-Month Period Ended September 30, 2013
	(in thousands)
Revenues	$	171,512
Net income	$	50,867

Pro forma information for the nine-month period ended September 30, 2014 is not presented because TGGT and ETG were included within the Azure Midstream Holdings results of operations for the period. The unaudited pro forma information is not necessarily indicative of what our statements of operations would have been if the transaction occurred on January 1, 2012, or what the financial position and results from operations will be for any future periods.

For the nine-month period ended September 30, 2014, TGGT contributed $120.8 million in revenues and $50.4 million in income from operations to our statement of operations. For the nine-month period ended September 30, 2014, ETG contributed $14.0 million in revenues and $2.5 million in income from operations to our statement of operations.

Predecessor

During the nine-month period ended September 30, 2013, the Predecessor had no acquisitions.

(4) Accounts Receivable and Concentration of Credit Risk

Our primary markets are in the North Louisiana and East Texas natural gas supply basins, and we deliver natural gas to 20 existing major intrastate and interstate pipelines in these regions. We have a concentration of revenues and trade accounts receivable due from customers, including EXCO and BG, engaged in the production, trading, distribution and marking of natural gas and condensate. These concentrations may affect overall credit risk in that these customers, including EXCO and BG, may be affected similarly by changes in economic, regulatory or other factors. We analyze our customers’ historical financial and operational information before extending credit. The Predecessor’s concentration of credit risk is not materially different than that of the Company.

Our top two customers, EXCO and BG, for the nine-month period ended September 30, 2014 each individually represented 29% of our consolidated total revenue. The Predecessor’s top two customers, also EXCO and BG, for the nine-month period ended September 30, 2013 each individually represented 39% of consolidated total revenue. EXCO and BG are both considered related parties, see Note 9 for further discussion of related party transactions.

Allowance for doubtful accounts is determined based on a specific identification of accounts reviewed by management and deemed doubtful as to collectability. As of September 30, 2014 and December 31, 2013, the Company recorded a $0.1 million reserve for amounts deemed to be uncollectable.

F-47

AZURE MIDSTREAM HOLDINGS LLC AND SUBSIDIARIES AND

AZURE MIDSTREAM PREDECESSOR

NOTES TO CONDENSED CONSOLIDATED STATEMENTS

(5) Property, Plant and Equipment, Identifiable Intangible Assets and Goodwill

Property, Plant and Equipment

Property, Plant and Equipment consisted of the following as of each period presented:


	Estimated Useful Life (yrs)	September 30, 2014			December 31, 2013
		(in thousands)
Pipelines	45	$	699,816		$	697,450
Buildings	30		6,432			6,432
Gas processing and compression facilities	20		122,020			114,004
Other depreciable assets	5 – 15		10,303			5,842

Total property and equipment			838,571			823,728
Accumulated depreciation			(20,080	)		(2,797	)

Total			818,491			820,931
Construction in progress			3,324			1,681
Land and other			1,253			490

Property and Equipment, net		$	823,068		$	823,102

Depreciation is provided using the straight-line method based on the estimated useful life of each asset. Our estimated useful lives were different than the estimated useful lives assigned by the Predecessor. Depreciation expense for the nine-month periods ended September 30, 2014 and 2013 was $17.3 million and $26.7 million, respectively.

We capitalize interest on qualified projects during their construction period. Once a project is placed into service, capitalized interest, as a component of the total cost of construction, is depreciated over the useful life of the asset constructed. The Predecessor’s accounting policy associated with capitalized interest was not materially different than ours. During the nine-month period ended September 30, 2014, we did not capitalize any interest on qualified projects. During the nine-month period ended September 30, 2013, the Predecessor’s capitalized interest on qualified projects was $0.03 million.

Asset Impairments

During the nine-month periods ended September 30, 2014 and 2013, the Company and the Predecessor recognized $0.2 million and $0.6 million in impairments, respectively. The impairments resulted from adjusting the book value of assets held for sale to fair value during the period.

Identifiable Intangible Assets

The fair value of the acquired intangible assets is primarily associated with customer relationships and was determined based on the present value of cash flows attributed to these customers, which includes management’s estimate of revenue and operating expenses and costs relating to utilization of other assets to fulfill such relationships. We determined the recovery period based on historical customer attrition rates and management’s assumptions on future events. The customer relationship intangible asset is being amortized over the estimated recovery period of 12 years. Amortization expense associated with this intangible asset was $4.7 million during the nine-month period ended September 30, 2014, and is included within depreciation and amortization expense.

F-48

AZURE MIDSTREAM HOLDINGS LLC AND SUBSIDIARIES AND

AZURE MIDSTREAM PREDECESSOR

NOTES TO CONDENSED CONSOLIDATED STATEMENTS

Identifiable intangible assets reported within the balance sheet as of September 30, 2014 and December 31, 2013 are comprised of the following:


	As of September 30, 2014						As of December 31, 2013
Identifiable Intangible Assets:	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
	(in thousands)						(in thousands)
Customer relationship	$	80,100	$	5,375	$	74,726	$	80,100	$	667	$	79,433

The estimated amortization expense of intangible assets for each of the next five fiscal years is $6.7 million.

There was no amortization expense associated with intangible assets recognized during the nine-month period ended September 30, 2013 because the Predecessor had no such intangible assets.

Goodwill

We evaluate goodwill for impairment annually on October 1. We also evaluate goodwill whenever events or circumstances indicate that it is more likely than not that the fair value of our reporting unit is less than its carrying amount. We have one reporting unit for goodwill purposes. We are in the process of performing our annual goodwill impairment test as of October 1, 2014. We performed the qualitative assessment and concluded that the first step of the goodwill impairment test was required. There are currently no indications that a goodwill impairment exists as of October 1, 2014; however, we have not completed the first step of the goodwill impairment test as of the date these financial statements were available.

(6) Long Term Debt

Azure Energy Credit Agreement

F-49

AZURE MIDSTREAM HOLDINGS LLC AND SUBSIDIARIES AND

AZURE MIDSTREAM PREDECESSOR

NOTES TO CONDENSED CONSOLIDATED STATEMENTS

For the Revolver, borrowings bear interest under the same terms as the TLB and the applicable Eurodollar margin and ABR margin vary quarterly based on our consolidated leverage ratio, as defined in the Credit Agreement, being generally computed as the ratio of (a) total funded indebtedness to (b) the sum of consolidated earnings before interest, taxes, depreciation, amortization before certain other noncash charges, or Adjusted EBITDA. The Eurodollar margin and ABR margin for the Revolver is as follows:


Consolidated Leverage Ratio	Applicable Margin for Eurodollar Loans			Applicable Margin for ABR Loans
Less than or equal to 2.00 to 1.00		2.75	%		1.75	%
Less than or equal to 3.00 to 1.00 but greater than 2.00 to 1.00		3.00	%		2.00	%
Less than or equal to 3.50 to 1.00 but greater than 3.00 to 1.00		3.25	%		2.25	%
Less than or equal to 4.00 to 1.00 but greater than 3.50 to 1.00		3.50	%		2.50	%
Greater than 4.00 to 1.00		3.75	%		2.75	%

The weighted average interest rate for the nine-month period ended September 30, 2014 was 6.50%. Outstanding borrowings associated with our Credit Agreement were $529.4 million and $550.0 million as of September 30, 2014 and December 31, 2013, respectively, of which $27.5 million and $27.5 million has been classified as current because the principal payments are due within one year.

We may prepay all loans under the Credit Agreement at any time subject to certain notice requirements. The Credit Agreement requires repayment of the TLB in consecutive quarterly installments on the last day of each fiscal quarter commencing on March 31, 2014. Each of the installments shall be in an aggregate principal amount equal to 1.25% of the original aggregate principal amount of the TLB. During the nine-month period ended September 30, 2014, we made principal payments of $20.6 million on the TLB. We have remaining principal payments associated with the TLB of $6.9 million in 2014, $27.5 million in 2015, 2016 and 2017 and the remaining outstanding principal amount is due upon maturity in 2018.

F-50

AZURE MIDSTREAM HOLDINGS LLC AND SUBSIDIARIES AND

AZURE MIDSTREAM PREDECESSOR

NOTES TO CONDENSED CONSOLIDATED STATEMENTS

Agreement and are recorded in interest expense. The unamortized balance of deferred financing costs is included in other noncurrent assets and as of September 30, 2014 and December 31, 2013 the unamortized balance was $17.4 million and $21.0 million, respectively. Amortization expense associated with these deferred financing costs was $3.7 million for the nine-month period ended September 30, 2014.

The carrying value of our debt obligations as of September 30, 2014 and December 31, 2013 approximates fair value due to the floating rate nature of our applicable interest rates and is a Level 2 valuation based on the observable inputs used for similar liabilities.

First Amendment to Azure Energy Credit Agreement

In September 2014, we entered into the first amendment to the Credit Agreement (the “First Amendment”). Among other things, the First Amendment reduced borrowing capacity under the Revolver from $50 million to $40 million and provided for more favorable financial condition covenants, including amending our maximum permitted consolidated leverage ratio and consolidated interest coverage ratio.

Our maximum permitted consolidated leverage ratio as a result of the First Amendment is 5.50 times debt to consolidated adjusted EBITDA until June 30, 2015, 5.25 for the quarterly period ended September 30, 2015, 5.00 for the quarterly period ended December 31, 2015 and 4.50 for the quarterly period ended March 31, 2016 and thereafter. The First Amendment also amended our required consolidated interest coverage ratio to 2.25 times consolidated EBITDA to consolidated interest expense until June 30, 2015 and 2.50 thereafter.

We have recognized a loss on the extinguishment of debt, which is included within interest expense, of $0.3 million during the nine-month period ended September 30, 2014 as a result of the First Amendment. The loss on extinguishment of debt is in accordance with applicable accounting guidance and results from the write-off of previously deferred financing costs associated with the Credit Agreement. We incurred $0.2 million in fees associated with the First Amendment. These fees have been deferred and included within deferred financing costs as of September 30, 2014.

Predecessor Credit Agreement

In January 2011, the Predecessor entered into a $500 million senior secured credit facility (the “Predecessor Credit Agreement”) with a maturity of five years. The Predecessor Credit Agreement, which was led by JPMorgan Chase Bank, N.A., as administrative agent, included a syndicate of four external banks and an affiliate of BG, BG Atlantic Finance Limited. Borrowings under the Predecessor Credit Agreement were unconditionally guaranteed, jointly and severally, by all of the Predecessor’s subsidiaries and were collateralized by first priority liens on substantially all of the existing and subsequently acquired assets and equity. On January 25, 2012, the Predecessor closed an amendment to the Predecessor Credit Agreement increasing the aggregate commitment to $600 million with the same maturity, pricing and financial covenants as the Predecessor Credit Agreement. The amendment included seven new lenders and removed the related-party lender, BG Atlantic Finance Limited. In connection with the Acquisition, EXCO and BG proportionally paid the remaining $405.0 million outstanding borrowings under the Predecessor Credit Agreement with proceeds received from the Acquisition.

F-51

AZURE MIDSTREAM HOLDINGS LLC AND SUBSIDIARIES AND

AZURE MIDSTREAM PREDECESSOR

NOTES TO CONDENSED CONSOLIDATED STATEMENTS

The weighted average interest rate associated with the Predecessor’s Credit Agreement for the nine-month period ended September 30, 2013 was 2.5%, and average outstanding borrowings during the nine-month period ended September 30, 2013 were $454.2 million.

The Predecessor incurred $4.8 million in fees associated with the Predecessor Credit Agreement that were capitalized as deferred financing costs. These costs were amortized over the term of the Predecessor Credit Agreement and were recorded in interest expense. Amortization expense associated with these deferred financing costs was $0.8 million for the nine-month period ended September 30, 2013.

(7) Lease Obligations

Azure Midstream Holdings Lease Obligations

Azure Midstream Holdings and subsidiaries amended its Dallas, Texas office lease agreement in September 2014. The office lease agreement is a ten year agreement expiring in May 2025. The office lease agreement will be accounted for as a capital lease. As a result, at the inception of the office lease agreement we recognized a capital lease asset, included within property, plant and equipment in the amount of $3.6 million, and capital lease liability, of which $0.2 million is included within current portion of long-term debt and $3.4 million is included within long-term debt.

Azure Midstream Holdings leases compression and treating equipment and we account for these leases as operating leases. Total rent expense for operating leases, including those with terms of less than one year, was $3.3 million for the nine-month period ended September 30, 2014.

Predecessor Lease Obligations

The Predecessor leased compression and treating equipment and these leases were accounted for as operating leases. Total rent expense for operating leases, including those with terms of less than one year, was $2.2 million for the nine-month period ended September 30, 2013.

(8) Commitments and Contingencies

Legal Matters

Liabilities for loss contingencies arising from claims, assessments, litigation, fines, penalties, or from other sources are recorded when it is probable that a liability has been incurred and the amount of the assessment can be reasonably estimated. Legal costs related to any such contingencies are expensed as incurred. Accruals for estimated losses are adjusted as further information develops or as circumstances change. At September 30, 2014 and December 31, 2013, the Company did not have an accrual related to contractual disputes.

During 2013, the Company has been a party to litigation arising from events occurring during the normal course of business. While we are unable to estimate the range of exposure, we believe that there is no significant exposure to the Company arising out of these matters. At September 30, 2014 and December 31, 2013, the Company had no active litigation matters the Company believes will have a material adverse impact on its consolidated results of operations or financial condition.

F-52

AZURE MIDSTREAM HOLDINGS LLC AND SUBSIDIARIES AND

AZURE MIDSTREAM PREDECESSOR

NOTES TO CONDENSED CONSOLIDATED STATEMENTS

Regulatory Compliance

(9) Related Party Transactions

Azure Midstream Holdings Related Party Transactions

EXCO and BG are considered related parties for financial reporting purposes as a result of their combined 7% ownership interest in us. We also provide services to an affiliate of Tenaska Capital Management, which we consider to be a related party. For the nine-month period ended September 30, 2014, Azure Midstream Holdings recorded revenues from these affliates in the amount of $78.7 million. As of September 30, 2014 and December 31, 2013, Members’ accounts receivable were $15.5 million and $20.8 million, respectively.

Accounts payable and accrued liabilities owed to EXCO at September 30, 2014 and December 31, 2013 were $1.6 million and $6.5 million, respectively.

Purchase of Residence Upon Relocation – During the quarter ended September 30, 2014, the Company purchased the residence of an officer of the Company. To effectuate the purchase, the Company engaged a third-party relocation company, who executed the purchase for $1.1 million and will subsequently sell the officer’s residence. The Company entered into a loan agreement with a third party for $1.0 million of the purchase price, and, as of September 30, 2014, the asset is included within assets held for sale, and the loan amount is included within current portion of long-term debt on our balance sheet. We have entered into a sales agreement for the residence and we expect that we will receive the fair market value of the residence that we recorded at the time of the purchase.

Predecessor Related Party Transactions

The Predecessor had significant transactions with EXCO and BG.

The Predecessor’s operations were governed by its limited liability company agreement, which included a secondment agreement whereby certain EXCO and BG employees were seconded (100% duty assigned) to the Predecessor to serve in various managerial or operational roles. In addition to the secondment agreement, the limited liability company agreement included a BG Services Agreement and an EXCO Services Agreement, which enabled the Predecessor to purchase services from either EXCO or BG. EXCO and BG invoiced the Predecessor for actual documented costs attributable or fairly allocated to the employment and secondment of the EXCO and BG secondees. Services provided by EXCO and BG employees who were not seconded to the alliance were billed to the Predecessor pursuant to the respective service agreement.

For the nine-month period ended September 30, 2013, the Predecessor incurred charges for secondees and services from EXCO and BG in the amount of $13.2 million, of which $7.7 million has been included within operating expenses and $5.5 million has been included within general and administrative expenses. For the nine-month period ended September 30, 2013, the Predecessor recorded revenues from EXCO and BG in the amount of $125.0 million.

F-53

AZURE MIDSTREAM HOLDINGS LLC AND SUBSIDIARIES AND

AZURE MIDSTREAM PREDECESSOR

NOTES TO CONDENSED CONSOLIDATED STATEMENTS

(10) Supplemental Footnote Information

Supplemental Cash Flow Information


	Azure Midstream Holdings
	Nine-Month Period Ended September 30, 2014
	(in thousands)
Supplemental Disclosures:
Cash paid for interest	$	27,181
Cash paid for income taxes	$	339
Supplemental schedule of non-cash investing and financing activities:
Non-cash capital expenditures included in accounts payable and accrued liabilities	$	854
Capital lease assets	$	3,608


	Predecessor
	Nine-Month Period Ended September 30, 2013
	(in thousands)
Supplemental Disclosure:
Cash paid for interest, net of amounts capitalized	$	8,431
Cash paid for income taxes	$	460
Supplemental schedule of non-cash investing and financing activities:
Non-cash capital expenditures included in accounts payable and accrued liabilities	$	2,577
Net impact of noncash exchange of property and equipment with third party	$	6,084

Operating Revenues


	Azure Midstream Holdings		Predecessor
	Nine-Month Period Ended September 30, 2014		Nine-Month Period Ended September 30, 2013
	(in thousands)
Operating revenues
Transportation, gathering, compression and treating—affiliates	$	74,809	$	124,012
Transportation, gathering, compression and treating—non-affiliates		20,371		9,096
Natural gas and NGL sales—affiliates		3,018		1,002
Natural gas and NGL sales—non-affiliates		36,635		24,450

Total operating revenues	$	134,833	$	158,560

Deferred Revenue Associated with our Minimum Revenue Commitments

F-54

AZURE MIDSTREAM HOLDINGS LLC AND SUBSIDIARIES AND

AZURE MIDSTREAM PREDECESSOR

NOTES TO CONDENSED CONSOLIDATED STATEMENTS

in the following periods exceed its MRC for that period. This contract provision ranges for the entire duration of the gas gathering agreement, which is ten years. We record customer billings for obligations under the MRC (solely with respect to this natural gas gathering agreement) as deferred revenue when the customer has the right to utilize deficiency payments to offset gathering fees in subsequent periods. We recognize deferred revenue under this arrangement in revenue once all contingencies or potential performance obligations associated with the related revenues have either (i) been satisfied through the gathering of future excess volumes of natural gas, or (ii) expired (or lapsed) through the passage of time pursuant to the terms of the natural gas gathering agreement. As of September 30, 2014 and December 31, 2013, deferred revenue associated with this MRC agreement was $5.3 million and $1.1 million, respectively, and has been included within other long term liabilities. We received deficiency payments of $4.2 million during the nine-month period September 30, 2014, and no deferred revenue amounts under this MRC arrangement have been recognized as revenue during the nine-month period ended September 30, 2014. The Predecessor had no such MRC gas gathering agreements with its customers.

F-55

INDEPENDENT AUDITORS’ REPORT

The Member

TPF II East Texas Gathering, LLC:

We have audited the accompanying financial statements of TPF II East Texas Gathering, LLC (a Delaware limited liability company) (the Company), which comprise the balance sheets as of November 14, 2013 and December 31, 2012, and the related statements of operations, member’s equity, and cash flows for the period from January 1, 2013 to November 14, 2013 and the year ended December 31, 2012, and the related notes to the financial statements.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these financial statements in accordance with U.S. generally accepted accounting principles; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of TPF II East Texas Gathering, LLC as of November 14, 2013 and December 31, 2012, and the results of its operations and its cash flows for the period from January 1, 2013 to November 14, 2013 and the year ended December 31, 2012, in accordance with U.S. generally accepted accounting principles.

Emphasis of Matter

As discussed in note 1 to the financial statements, on November 15, 2013, TPF II East Texas Holdings, LLC, the parent entity to the Company, sold 100% of its ownership in the Company to Azure Midstream Holdings LLC.

/s/ KPMG LLP

Omaha, Nebraska

April 24, 2014

F-56

TPF II EAST TEXAS GATHERING, LLC

BALANCE SHEETS

As of November 14, 2013 and December 31, 2012

(in thousands)


	November 14, 2013		December 31, 2012
Assets
Current assets:
Cash and cash equivalents	$	15,204	$	7,899
Accounts receivable		3,123		3,374
Prepaid expenses and other		451		456

Total current assets		18,778		11,729

Property, plant, and equipment:
Land and right of way		12,438		47,347
Gas gathering system		72,919		323,238
Construction in progress		4,497		2,700
Other		229		215

		90,083		373,500
Less accumulated depreciation		—		(34,404	)

Total property, plant, and equipment, net		90,083		339,096

Other assets:
Contract costs, net		201		864
Deferred finance charges, net		408		537
Other assets		1,454		1,574

Total other assets		2,063		2,975

Total assets	$	110,924	$	353,800

Liabilities and Member’s Equity
Current liabilities:
Accounts payable and accrued expenses	$	5,207	$	5,291
Notes payable		15,000		—
Other liabilities		42		71

Total current liabilities		20,249		5,362
Long-term liabilities:
Notes payable		—		45,000
Other liabilities, net of current portion		411		411

Total liabilities		20,660		50,773
Commitments and contingencies (notes 5 and 7)
Member’s equity		90,264		303,027

Total liabilities and member’s equity	$	110,924	$	353,800

See accompanying notes to financial statements.

F-57

TPF II EAST TEXAS GATHERING, LLC

STATEMENTS OF OPERATIONS

Period from January 1, 2013 to November 14, 2013 and year ended December 31, 2012

(in thousands)


	2013			2012
Revenue:
Gathering	$	8,571		$	16,990
Treating		5,610			11,979
Other		372			2,252

Total revenue		14,553			31,221

Operating expenses:
Cost of sales		253			1,331
Operation and maintenance expense		7,322			10,134
Depreciation		14,923			16,897
Impairment of long-lived assets		237,478			—
Management fees and expenses		3,095			4,441
Taxes other than income taxes		2,066			2,007
Amortization		98			113

Total operating expenses		265,235			34,923

Net operating loss		(250,682	)		(3,702	)

Other income (expense):
Interest income		7			16
Interest expense		(961	)		(1,764	)
Amortization of deferred finance charges		(129	)		(151	)
Other		2			(441	)

Total other expense		(1,081	)		(2,340	)

Net loss	$	(251,763	)	$	(6,042	)

See accompanying notes to financial statements.

F-58

TPF II EAST TEXAS GATHERING, LLC

STATEMENTS OF CASH FLOWS

Period from January 1, 2013 to November 14, 2013 and year ended December 31, 2012

(in thousands)


	2013			2012
Cash flows from operating activities:
Net loss	$	(251,763	)	$	(6,042	)
Adjustments to reconcile net loss to net cash from operating activities:
Depreciation and amortization		15,021			17,010
Amortization of deferred finance charges		129			151
Impairment of long-lived assets		237,478			—
Decrease in accounts receivable		252			5,240
Decrease in prepaid expenses and other		6			13
Increase (decrease) in accounts payable and accrued expenses		1,015			(1,689	)
Increase (decrease) in other liabilities		(29	)		451

Net cash from operating activities		2,109			15,134

Cash flows from investing activities:
Capital expenditures		(3,923	)		(11,679	)
Other assets		119			(1,573	)

Net cash from investing activities		(3,804	)		(13,252	)

Cash flows from financing activities:
Equity contributions		39,000			—
Payments on notes payable		(30,000	)		(5,000	)

Net cash from financing activities		9,000			(5,000	)

Net increase (decrease) in cash and cash equivalents		7,305			(3,118	)
Cash and cash equivalents, beginning of period		7,899			11,017

Cash and cash equivalents, end of period	$	15,204		$	7,899

Supplemental disclosures of cash and noncash flow information:
Cash paid for interest	$	1,102		$	1,719
Noncash additions to property, plant, and equipment	$	518		$	1,617

See accompanying notes to financial statements.

F-59

TPF II EAST TEXAS GATHERING, LLC

STATEMENTS OF MEMBER’S EQUITY

Period from January 1, 2013 to November 14, 2013 and year ended December 31, 2012

(in thousands)


Balance, December 31, 2011	$	309,069
Net loss		(6,042	)

Balance, December 31, 2012		303,027
Equity contributions		39,000
Net loss		(251,763	)

Balance, November 14, 2013	$	90,264

See accompanying notes to financial statements.

F-60

TPF II EAST TEXAS GATHERING, LLC

NOTES TO FINANCIAL STATEMENTS

(1) Organization and Nature of the Business

Organization

TPF II East Texas Gathering, LLC (the “Company” or “ETG”) was formed to construct and own a natural gas gathering system (the “Gathering System”). The Gathering System was constructed and became operational during the year ended December 31, 2010, and is designed to transport and treat natural gas from Haynesville Shale, Bossier Shale, and James Lime production. The Company is wholly owned by TPF II East Texas Holdings, LLC (“Holdings”).

On October 16, 2013, Holdings entered into an agreement to sell 100% of its ownership in the Company to Azure Midstream Holdings LLC (“Azure Midstream Holdings”). The transaction closed on November 15, 2013. The accompanying financial statements have not been remeasured at fair value in accordance with relevant accounting guidance, as a result of this transaction.

The Company has no employees and does not anticipate having any employees in the future. Pursuant to an agreement with an affiliate (see Note 2), the affiliate will operate and maintain the Gathering System. The direct labor personnel and the operations management for the Gathering System are employees of the affiliate. Management and supervision of the Company’s operations and preparation and maintenance of the financial and other records of the Company are also the responsibility of the affiliate.

(2) Summary of Significant Accounting Policies

These financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).

Revenue Recognition

The Company earns a fee based on volumes of natural gas transported and treated through its Gathering System. The Company also buys natural gas from its gathering customers, transports and treats it, and then sells the natural gas to third parties. Natural gas sales and purchases are recorded net in the accompanying statements of operations. Revenue is recognized in the period gas is delivered and services are provided.

The Company sells natural gas to an affiliate, Tenaska Marketing Ventures (TMV). Gross natural gas sales to TMV were $2.8 million and $10.3 million for the period from January 1, 2013 to November 14, 2013 and year ended December 31, 2012, respectively. As of November 14, 2013, the Company had an account receivable from TMV of $404,000. As of December 31, 2012, the Company had no accounts receivable from TMV.

Accounts Receivable

Accounts receivable are recorded at amounts billed to customers. An allowance for doubtful accounts is recorded based on an assessment of the collectability of billed amounts. As of November 14, 2013 and December 31, 2012, the Company determined that no allowance for doubtful accounts was necessary.

Prepaid Expenses

The Company has prepaid for builders risk, property damage, and excess liability policies. These prepayments are being amortized on a straight-line basis over the term of the contracts or policies.

F-61

TPF II EAST TEXAS GATHERING, LLC

NOTES TO FINANCIAL STATEMENTS

Gas Imbalances

The Company records gas imbalances due to or from interconnecting pipelines and its customers resulting from the difference between customer nominations and actual gas receipts from, and gas deliveries to, its customers and interconnecting pipelines under various operational balancing agreements. Gas imbalances are either settled in cash or made up in kind. Gas imbalances are recorded based on current market prices or their contractually stipulated rate. As of November 14, 2013, the Company had no gas imbalance receivables, and as of December 31, 2012 the Company had $141,000 in gas imbalance receivables. The gas imbalance receivables are recorded within prepaid expenses and other current assets in the accompanying balance sheets. As of November 14, 2013 and December 31, 2012, the Company’s gas imbalance payable was $42,000 and $71,000, respectively, and is recorded within other current liabilities in the accompanying balance sheets.

Property, Plant, and Equipment

Property, plant, and equipment are recorded at historical cost of construction, net of accumulated depreciation. The costs of maintenance and repairs are expensed when incurred. Expenditures to extend the useful life or expand the capacity of the existing assets are capitalized. During the period from January 1, 2013 to November 14, 2013, the Company recorded an impairment charge of $237.0 million associated with its property, plant, and equipment (see Note 6). Depreciation on plant and equipment is recorded using the straight-line method over the following useful lives:


Gas gathering system			15-20 years
Other plant and equipment			3-20 years

Natural gas used to maintain pipeline minimum pressures, known as line pack, is capitalized and classified as property, plant, and equipment. The Company’s line pack is recoverable and as a result, not depreciated as part of the Gathering System.

As of November 14, 2013 and December 31, 2012, the construction in progress consists of costs incurred in the ongoing construction of the Gathering System.

The Company has various asset retirement obligations to remove or modify certain components of the Gathering System upon its retirement or abandonment. The Company cannot currently reasonably estimate the fair value of these obligations. An asset retirement obligation, if any, will be recognized when sufficient information exists to reasonably estimate the fair value of the obligation.

Contract Costs

The Company incurred direct costs associated with entering into contracts to transport and treat natural gas. These costs were capitalized and are being amortized to expense over the terms of the respective contracts using the straight-line method. As of November 14, 2013 and December 31, 2012, accumulated amortization was $0 and $259,000, respectively. During the period from January 1, 2013 to November 14, 2013, the Company recorded an impairment charge of $565,000 associated with its contract costs (see Note 7).

Income Taxes

The Company has no liability for federal income taxes. Income is taxed to Holdings based on the Company’s taxable income. Therefore, no provision or liability for federal income taxes has been included in the accompanying financial statements.

F-62

TPF II EAST TEXAS GATHERING, LLC

NOTES TO FINANCIAL STATEMENTS

The Company recognizes the effect of income tax positions only if these positions are more-likely than-not of being sustained. Additionally, for tax positions meeting this more-likely-than-not threshold, the amount of benefit is limited to the largest benefit that has a greater than 50% probability of being realized upon ultimate settlement. Changes in recognition or measurement are reflected in the period in which the change in judgment occurs.

Impairment of Long-Lived Assets

Long-lived assets, such as property, plant, and equipment, and contract costs, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If circumstances require a long-lived asset to be tested for impairment, the Company first compares undiscounted cash flows expected to be generated by an asset to the carrying value of the asset. If the carrying value of the long-lived asset is not recoverable on an undiscounted cash flow basis, an impairment is recognized to the extent that the carrying value exceeds its fair value. During the period from January 1, 2013 to November 14, 2013, the Company recorded an impairment charge of $237.5 million associated with its long-lived assets (see Note 7).

Fair Value Measurements

In accordance with U.S. generally accepted accounting principles (U.S. GAAP), investments measured and reported at fair value are classified and disclosed in one of the following categories:

Level 1—Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets and liabilities. This level primarily consists of financial instruments such as exchange-traded securities and listed derivatives.

Level 2—Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived principally from or corroborated by observable market data by correlation or other means.

Level 3—Pricing inputs include those that are generally less observable or unobservable and include situations where there is little, if any, market activity for the investment. Fair value for these investments is determined using valuation methodologies that consider a range of factors, including but not limited to the price at which the investment was acquired, the nature of the investment, local markets conditions, and current and projected operating performance. The inputs into the determination of fair value require significant management judgment. Due to the inherent uncertainty of these estimates, these values may differ materially from the values that would have been used had a ready market for these investments existed.

In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, an investment’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment, and the Company considers various factors specific to the investment. A review of the fair value hierarchy classification is conducted at each fiscal year end reporting date.

F-63

TPF II EAST TEXAS GATHERING, LLC

NOTES TO FINANCIAL STATEMENTS

Risks and Uncertainties

The Company is subject to several risks including, but not limited to, risks associated with the nature of and reliance on long-term contractual obligations with various third parties, the ability to operate the Gathering System in order to meet long-term contractual obligations, regulatory risks, and other uncertainties in the midstream natural gas industry.

Use of Estimates

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

(3) Transactions with Affiliates

The Company had an agreement with an affiliate, TPF Gas Services, LLC (TPF Gas Services), under which TPF Gas Services provides the day-to-day management of the affairs of the Company, services for the operation and maintenance of the Gathering System, and preparation and maintenance of the financial and other records and books of account of the Company. During the period from January 1, 2013 to November 14, 2013 and year ended December 31, 2012, billings from TPF Gas Services to the Company were $4.1 million and $5.9 million, respectively. As of November 14, 2013 and December 31, 2012, the Company had a payable to TPF Gas Services of $319,000 and $26,000, respectively.

The Company had an Operational Services Agreement with an affiliate, TPF Project Services, LLC (Project Services), which terminated effective May 1, 2013. Project Services provided operational and administrative support services to the Company such as engineering and environmental consulting and project management services. During the period from January 1, 2013 to November 14, 2013 and year ended December 31, 2012, billings from Project Services to the Company were $112,000 and $448,000, respectively. As of November 14, 2013 the Company had no amounts payable to Project Services, and as of December 31, 2012, the Company had amounts payable to Project Services in the amount of $134,000.

(4) Concentration Risk

The Company’s customers are comprised of primarily investment grade entities. As of November 14, 2013, four customers accounted for approximately 89% of total accounts receivable, and as of December 31, 2012, three customers accounted for approximately 93% of total accounts receivable. For the period from January 1, 2013 to November 14, 2013 and year ended December 31, 2012, three customers accounted for approximately 76% and 83%, respectively, of total gathering and treating revenue.

(5) Notes Payable

The Company entered into a credit agreement on August 11, 2011. The credit agreement includes a $50 million commitment for notes payable and letters of credit. As of November 14, 2013 and December 31, 2012, the Company had outstanding notes payable of $15 million and $45 million, respectively. The credit agreement terminates on August 11, 2016.

The borrowings have variable interest rates based on a LIBOR loan rate plus an applicable margin. As of November 14, 2013 and December 31, 2012, the weighted average interest rate of the borrowings was 3.23% and 3.30%, respectively. Interest expense for the period from January 1, 2013 to November 14, 2013 and year ended December 31, 2012 was $961,000 and $1.8 million, respectively.

F-64

TPF II EAST TEXAS GATHERING, LLC

NOTES TO FINANCIAL STATEMENTS

The credit agreement contains various restrictive covenants with which the Company must comply, including leverage and interest coverage ratios. As of November 14, 2013 and December 31, 2012, the Company was in compliance with all financial covenants. The credit agreement also provides for a first security interest in substantially all of the assets of the Company.

(6) Leases

The Company has operating leases for treatment and compression plant equipment that expire over the next three years. The leases contain one-month renewal period provisions. Future minimum lease payments for the leases are as follows (in thousands):


2013	$	158
2014		2,505
2015		2,392
2016		981

	$	6,036

Rent expense for the period from January 1, 2013 to November 14, 2013 and year ended December 31, 2012 related to these leases was $2.2 million and $2.6 million, respectively.

(7) Impairment Charge

Management reviews long-lived assets for indicators of impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. On October 16, 2013, Holdings entered into an agreement to sell 100% of its interests in the Company (the “Transaction”). The Transaction, along with decreases in volume and natural gas prices, triggered the performance of an impairment analysis and an undiscounted cash flow analysis indicated potential impairment. The Company developed a fair value estimate of long-lived assets and compared the carrying amounts of land, gas gathering system, and contract costs to their estimated fair value. This resulted in an impairment charge of $237.5 million on the statement of operations for the period from January 1, 2013 to November 14, 2013. The impairment was allocated to long-lived assets and reduced the gross carrying amount of long-lived assets and their related accumulated depreciation and amortization. No impairment charges were recorded during the year ended December 31, 2012.

The fair value measurement was primarily based on the value assigned to the Company in the Transaction and was supported by a discounted cash flow analysis that included the following significant inputs: discount rate, terminal multiple, and projections of revenues and expenses. These inputs are considered non-reoccurring Level 3 inputs in the fair value hierarchy.

(8) Commitments and Contingencies

The Company may be involved from time to time in certain regulatory matters, claims, and pending litigation arising in the normal course of business. The Company’s management believes the ultimate resolution of these matters, if applicable, will not have an adverse material effect on the financial condition, results of operation or cash flows of the Company.

(9) Subsequent Events

On November 15, 2013, Holdings completed the sale of the Company to Azure Midstream Holdings, repaid the outstanding balance of notes payable, and terminated the credit agreement, and changed its name to Azure ETG LLC.

The Company evaluates events that occur after the balance sheet date, but before the financial statements are issued, for potential recognition or disclosure. Based on the evaluation, we have determined that there were no material subsequent events that require recognition or disclosure other than those disclosed herein.

F-65

APPENDIX A

AMENDED AND RESTATED

AGREEMENT OF LIMITED PARTNERSHIP

AZURE MIDSTREAM PARTNERS, LP

To be filed by amendment.

A-1

APPENDIX B

GLOSSARY OF TERMS

Bbls or barrel: One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil, as NGLs or other liquid hydrocarbons.

Bcf: One billion cubic feet of natural gas.

Bcf/d: One billion cubic feet per day.

Btu: British thermal units.

CO2: Carbon dioxide.

condensate: Similar to crude oil and produced in association with natural gas gathering and processing.

dehydration: The process of removing liquids and moisture content from gas or other matter.

DOT: Department of Transportation.

EIA: Energy Information Administration.

EPA: Environmental Protection Agency.

EUR: Estimated ultimate recovery.

FERC: Federal Energy Regulatory Commission.

field: The general area encompassed by one or more oil or gas reservoirs or pools that are located on a single geologic feature, that are otherwise closely related to the same geologic feature (either structural or stratigraphic).

fractionation: The process by which a mixed stream of natural gas liquids is separated into its constituent products.

GPM: Gallons per thousand cubic feet.

hydrocarbon: An organic compound containing only carbon and hydrogen.

Mcf: One thousand cubic feet of natural gas.

MMBtu: One million British thermal units. One MMBtu is the equivalent of 0.973 Mcf.

MMBtu/d: One million British thermal units per day

MMcf: One million cubic feet of natural gas.

MMcf/d: One million cubic feet per day.

Mtpa: One million tonnes per annum.

natural gas: Hydrocarbon gas found in the earth, composed of methane, ethane, butane, propane and other gases.

B-1

NGLs: Natural gas liquids, which consist primarily of ethane, propane, isobutane, normal butane and natural gasoline.

oil: Crude oil and condensate.

residue natural gas: The pipeline quality natural gas remaining after natural gas is processed.

SEC: United States Securities and Exchange Commission.

Tcf: One trillion cubic feet of natural gas.

throughput: The volume of product transported or passing through a pipeline, plant, terminal or other facility.

wellhead: The equipment at the surface of a well used to control the pressure; the point at which the hydrocarbons and water exit the ground.

B-2

Through and including , 2015 (25 days after the date of this prospectus), all dealers that buy, sell or trade our common units, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

LOGO

Common Units

Representing Limited Partner Interests

Azure Midstream Partners, LP

PROSPECTUS

, 2015

Citigroup

BofA Merrill Lynch

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

ITEM 13. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION.

Set forth below are the expenses (other than underwriting discounts) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the Securities and Exchange Commission registration fee, the FINRA filing fee and the exchange listing fee the amounts set forth below are estimates.


SEC registration fee	$	20,335
FINRA filing fee		26,750
Printing and engraving expenses		*
Fees and expenses of legal counsel		*
Accounting fees and expenses		*
Transfer agent and registrar fees		*
NYSE listing fee		*
Miscellaneous		*

Total	$	*

To be filed by amendment.

ITEM 14. INDEMNIFICATION OF DIRECTORS AND OFFICERS.

Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other persons from and against all claims and demands whatsoever. The section of the prospectus entitled “The Partnership Agreement—Indemnification” discloses that we will generally indemnify officers, directors and affiliates of the general partner to the fullest extent permitted by the law against all losses, claims, damages or similar events and is incorporated herein by this reference.

Our general partner will purchase insurance covering its officers and directors against liabilities asserted and expenses incurred in connection with their activities as officers and directors of the general partner or any of its direct or indirect subsidiaries.

Any underwriting agreement entered into in connection with the sale of the securities offered pursuant to this registration statement will provide for indemnification of Azure Midstream Operating Company and our general partner, their officers and directors, and any person who controls Azure Midstream Operating Company and our general partner, including indemnification for liabilities under the Securities Act.

ITEM 15. RECENT SALES OF UNREGISTERED SECURITIES.

On September 26, 2014, in connection with the formation of Azure Midstream Partners, LP, we issued (i) a non-economic general partner interest in us Azure Midstream Partners GP, LLC and (ii) a 100% limited partner interest in us to Azure Midstream Holdings LLC for $1,000. The issuance was exempt from registration under Section 4(2) of the Securities Act. There have been no other sales of unregistered securities within the past three years.

II-1

ITEM 16. EXHIBITS.

The following documents are filed as exhibits to this registration statement:


Exhibit Number			Description

	1.1	*	Form of Underwriting Agreement (including form of Lock-up Agreement)

	3.1		Certificate of Limited Partnership of Azure Midstream Partners, LP

	3.2	*	Form of Amended and Restated Limited Partnership Agreement of Azure Midstream Partners, LP (included as Appendix A to the Prospectus)

	5.1	*	Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered

	8.1	*	Opinion of Vinson & Elkins L.L.P. relating to tax matters

	10.1	*	Form of Credit Agreement

	10.2	*	Form of Contribution, Conveyance and Assumption Agreement

	10.3	*	Form of Omnibus Agreement

	10.4	*	Form of Long Term Incentive Plan

	10.5	*	Executive Employment Agreement of Eric T. Kalamaras

	21.1		List of Subsidiaries of Azure Midstream Partners, LP

	23.1		Consent of KPMG LLP (Azure Midstream Holdings LLC)

	23.2		Consent of KPMG LLP (Azure Midstream Partners, LP)

	23.3		Consent of KPMG LLP (TGGT Holdings, LLC)

	23.4		Consent of KPMG LLP (TPF II East Texas Gathering, LLC)

	23.5	*	Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1)

	23.6	*	Consent of Vinson & Elkins L.L.P. (contained in Exhibit 8.1)

	24.1	*	Powers of Attorney (contained on the signature pages to this Registration Statement)

	99.1		Consent of Thomas R. Fuller, Director Nominee

To be filed by amendment.

ITEM 17. UNDERTAKINGS.

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that, for the purpose of determining liability of the registrant under the Securities Act to any purchaser in the initial distribution of the securities, in a primary offering of

II-2

securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

(1) Any preliminary prospectus or prospectus of the undersigned registrant relating to the offering required to be filed pursuant to Rule 424;

(2) Any free writing prospectus relating to the offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;

(3) The portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and

(4) Any other communication that is an offer in the offering made by the undersigned registrant to the purchaser.

The undersigned registrant hereby undertakes that:

(1) If the registrant is relying on Rule 430B:

(A) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or(4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

(B) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

(2) If the registrant is subject to Rule 430C, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

The undersigned registrant undertakes to send to each common unitholder, at least on an annual basis, a detailed statement of any transactions with Azure Midstream Partners GP, LLC or its subsidiaries, and of fees, commissions, compensation and other benefits paid, or accrued to Azure Midstream Partners GP, LLC or its subsidiaries for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.

The registrant undertakes to provide to the common unitholders the financial statements required by Form 10-K for the first full fiscal year of operations of the registrant.

II-3

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in Dallas, Texas, on November 12, 2014.


AZURE MIDSTREAM PARTNERS, LP

By:		Azure Midstream Partners GP, LLC,
		its general partner

By:		/s/ I.J. “Chip” Berthelot, II
		Name: I.J. “Chip” Berthelot, II
		Title: President

Each person whose signature appears below appoints Chip Berthelot and Eric Kalamaras, and each of them, any of whom may act without the joinder of the other, as his true and lawful attorneys-in-fact and agents, with full power of substitution and re-substitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Registration Statement and any Registration Statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he might or would do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them of their or his substitute and substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities and the dates indicated.


Signature	Title	Date

/s/ I.J. “Chip” Berthelot, II I.J. “Chip” Berthelot, II	President and Director (Principal Executive Officer)	November 12, 2014

/s/ Eric T. Kalamaras Eric T. Kalamaras	Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)	November 12, 2014

/s/ John E. O’Shea, Jr. John E. O’Shea, Jr.	Director	November 12, 2014

/s/ Paul G. Smith Paul G. Smith	Director	November 12, 2014

/s/ Thomas O. Whitener, Jr. Thomas O. Whitener, Jr.	Director	November 12, 2014

/s/ James P. Benson James P. Benson	Director	November 12, 2014

II-4

EXHIBIT INDEX


Exhibit Number			Description

	1.1	*	Form of Underwriting Agreement (including form of Lock-up Agreement)

	3.1		Certificate of Limited Partnership of Azure Midstream Partners, LP

	3.2	*	Form of Amended and Restated Limited Partnership Agreement of Azure Midstream Partners, LP (included as Appendix A to the Prospectus)

	5.1	*	Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered

	8.1	*	Opinion of Vinson & Elkins L.L.P. relating to tax matters

	10.1	*	Form of Credit Agreement

	10.2	*	Form of Contribution, Conveyance and Assumption Agreement

	10.3	*	Form of Omnibus Agreement

	10.4	*	Form of Long Term Incentive Plan

	10.5	*	Executive Employment Agreement of Eric T. Kalamaras

	21.1		List of Subsidiaries of Azure Midstream Partners, LP

	23.1		Consent of KPMG LLP (Azure Midstream Holdings LLC)

	23.2		Consent of KPMG LLP (Azure Midstream Partners, LP)

	23.3		Consent of KPMG LLP (TGGT Holdings, LLC)

	23.4		Consent of KPMG LLP (TPF II East Texas Gathering, LLC)

	23.5	*	Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1)

	23.6	*	Consent of Vinson & Elkins L.L.P. (contained in Exhibit 8.1)

	24.1	*	Powers of Attorney (contained on the signature pages to this Registration Statement)

	99.1		Consent of Thomas R. Fuller, Director Nominee

To be filed by amendment.

II-5

Azure Midstream Partners, LP - FORM S-1 - November 12, 2014

Attached files