Index to Financial Statements

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, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act:

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 7(a)(2)(B) of the Securities Act. ☐

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	$200,000,000	$23,180

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

(2)	Estimated solely for the purpose of calculating the amount of the registration fee in accordance with Rule 457(o) under the Securities Act of 1933, as amended.

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 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 prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

Subject to Completion, dated September 12, 2017

PROSPECTUS

LOGO

Howard Midstream Partners, LP

Common Units

Representing Limited Partner Interests

This is the initial public offering of common units representing limited partner interests in Howard Midstream Partners, LP. We are offering common units in this offering, and PIP5 Skyline MLP Holdings LLC (the “selling unitholder”), an affiliate of Alberta Investment Management Corporation, is offering common units in this offering. We will not receive any proceeds from the sale of the common units by the selling unitholder. We expect that the initial public offering price will be between $ and $ per common unit. Prior to this offering, there has been no public market for our common units. We have been approved to list our common units on the New York Stock Exchange under the symbol “HMP.” We are an “emerging growth company” as that term is used in the Jumpstart Our Business Startups Act of 2012 and will be subject to reduced public reporting requirements.

As a result of certain laws and regulations to which we are or may in the future become subject, we may require owners of our common units to certify that they are both U.S. citizens and subject to U.S. federal income taxation on our income. If you are not an eligible holder at the time of any requested certification in the future, your common units may be subject to redemption.

Investing in our common units involves risk. Please read “Risk Factors” beginning on page 27.

These risks include the following:

•

We may not generate sufficient distributable cash flow to support the payment of the minimum quarterly distribution to our unitholders.

•

Because of the natural decline in production from existing wells in our areas of operation, our success depends in part on producers replacing declining production and also on our ability to obtain new sources of natural gas. Any decrease in the volumes of natural gas, condensate and other products for which we provide midstream services could adversely affect our business and operating results.

•

A sustained decrease in demand for refined products in the markets served by our pipelines and terminals could materially and adversely affect our results of operations, financial position or cash flows.

•

Our natural gas gathering and processing assets are primarily located in two oil and natural gas producing regions, making us vulnerable to risks associated with operating in a limited geographic area.

•

Natural gas and NGL prices are volatile, and a change in these prices in absolute terms, or an adverse change in the prices of natural gas and NGLs relative to one another, could adversely affect our gross margin, business, financial condition, results of operations, cash flows and ability to make cash distributions.

•

The assumptions underlying our forecasted Adjusted EBITDA and distributable cash flow that we include in “Cash Distribution Policy and Restrictions on Distributions” are inherently uncertain and subject to significant business, economic, financial, regulatory and competitive risks that could cause our actual Adjusted EBITDA and distributable cash flow to differ materially from our forecast.

•

Our general partner and its affiliates, including our sponsor, have conflicts of interest with us and limited fiduciary duties to us and our unitholders, and they may favor their own interests to our detriment and that of our unitholders. Additionally, we have no control over the business decisions and operations of our sponsor, and our sponsor is under no obligation to adopt a business strategy that favors us.

•

Unitholders have very limited voting rights, and, even if they are dissatisfied, they will have limited ability to remove our general partner.

•

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, and you could lose all or part of your investment.

•

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service, or IRS, were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, or if we were otherwise subjected to a material amount of additional entity-level taxation, then our distributable cash flow would be substantially reduced.

•

Our unitholders’ share of our income will be taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.

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 price to the public	$	$
Underwriting discounts and commissions⁽¹⁾	$	$
Proceeds, before expenses, to Howard Midstream Partners, LP⁽¹⁾	$	$
Proceeds, before expenses, to the selling unitholder⁽¹⁾	$	$

(1)	Excludes a structuring fee equal to % of the gross proceeds from this offering payable to Barclays Capital Inc. and a structuring fee equal to $ payable to Tudor, Pickering, Holt & Co. Advisors, LLC. Please read “Underwriting.”

We have granted the underwriters a 30-day option to purchase up to an additional common units from us at the initial public offering price, less the underwriting discounts, commissions and the structuring fees, if the underwriters sell more than common units in this offering. The selling unitholder is an underwriter with respect to the common units that it will sell in this offering.

The underwriters expect to deliver the common units on or about , 2017.

Book-Running Managers

Co-Managers


Capital One Securities		ING		Stifel

Prospectus dated , 2017.

LOGO

TABLE OF CONTENTS


	Page
PROSPECTUS SUMMARY		1
Our Assets		1
Our ROFR Assets		3
Our Areas of Operation		5
Business Strategies		8
Competitive Strengths		9
Our Relationship with Our Sponsor and its Investors		10
Our Emerging Growth Company Status		11
Risk Factors		12
The Transactions		13
Ownership and Organizational Structure		15
Management of Howard Midstream Partners, LP		17
Principal Executive Offices and Internet Address		17
Summary of Conflicts of Interest and Duties		17
The Offering		19
Summary Historical and Pro Forma Financial Data		25
RISK FACTORS		27
Risks Related to Our Business		27
Risks Inherent in an Investment in Us		48
Tax Risks		59
USE OF PROCEEDS		64
CAPITALIZATION		65
DILUTION		67
CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS		69
General		69
Our Minimum Quarterly Distribution		71
Unaudited Pro Forma Adjusted EBITDA and Distributable Cash Flow for the Year Ended December 31, 2016 and the Twelve Months Ended June 30, 2017		73
Estimated Adjusted EBITDA and Distributable Cash Flow for the Twelve Months Ending September 30, 2018		76
Significant Forecast Assumptions		79
PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS		88
Distributions of Available Cash		88
Operating Surplus and Capital Surplus		89
Capital Expenditures		91
Subordinated Units and Subordination Period		92
Distributions of Available Cash from Operating Surplus During the Subordination Period		93
Distributions of Available Cash from Operating Surplus After the Subordination Period		94
Incentive Distribution Rights		94
Percentage Allocations of Available Cash from Operating Surplus		94
General Partner’s Right to Reset Incentive Distribution Levels		95
Distributions from Capital Surplus		97
Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels		98
Distributions of Cash Upon Liquidation		99
SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA		102
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		106
Overview		106
How We Generate Revenue		106
How We Evaluate Our Operations		107


	Page
Factors and Trends Impacting Our Business		109
Factors Impacting the Comparability of Our Financial Results		110
Results of Operations		111
Liquidity and Capital Resources		116
Internal Controls and Procedures		120
Critical Accounting Policies		121
Recently Issued Accounting Pronouncements		123
Qualitative and Quantitative Disclosures About Market Risk		125
Off Balance Sheet Arrangements		125
INDUSTRY		126
General		126
Midstream Natural Gas Industry Overview		126
Midstream Crude Oil Industry Overview		126
Midstream Services		127
Market Fundamentals		129
Natural Gas		130
Natural Gas Production		133
Natural Gas Liquids		135
Crude Oil		138
Refined Products		140
BUSINESS		143
Overview		143
Our ROFR Assets		145
Our Areas of Operation		147
Business Strategies		150
Competitive Strengths		150
Our Relationship with Our Sponsor and its Investors		152
Our Assets		153
Commercial Agreements		159
Title to Our Properties		163
Seasonality		163
Competition		164
Regulation of Operations		164
Employees		175
Insurance		175
Legal Proceedings		175
MANAGEMENT		176
Management of Howard Midstream Partners, LP		176
Director Independence		176
Committees of the Board of Directors		177
Directors and Executive Officers of Howard Midstream GP, LLC		178
Board Role in Risk Oversight		180
Reimbursement of Expenses		180
Compensation of Our Officers and Directors		180
Our Long-Term Incentive Plan		181
Compensation of Our Directors		184
PRINCIPAL AND SELLING UNITHOLDERS		185
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS		187
Distributions and Payments to Our General Partner and Its Affiliates		187
Agreements with Our Affiliates in Connection with the Transactions		189
Procedures for Review, Approval and Ratification of Related Person Transactions		191


	Page
CONFLICTS OF INTEREST AND DUTIES		192
Conflicts of Interest		192
Duties of Our General Partner		198
DESCRIPTION OF OUR COMMON UNITS		202
Our Common Units		202
Transfer Agent and Registrar		202
Transfer of Common Units		202
Exchange Listing		203
OUR PARTNERSHIP AGREEMENT		204
Organization and Duration		204
Purpose		204
Capital Contributions		204
Voting Rights		204
Limited Liability		205
Issuance of Additional Partnership Interests		207
Amendment of Our Partnership Agreement		207
Merger, Consolidation, Conversion, Sale or Other Disposition of Assets		209
Termination and Dissolution		210
Liquidation and Distribution of Proceeds		210
Withdrawal or Removal of Our General Partner		210
Transfer of General Partner Interest		211
Transfer of Ownership Interests in Our General Partner		212
Transfer of Incentive Distribution Rights		212
Election to be Treated as a Corporation		212
Change of Management Provisions		212
Limited Call Right		212
Possible Redemption of Ineligible Holders		213
Meetings; Voting		214
Status as Limited Partner		215
Indemnification		215
Reimbursement of Expenses		215
Books and Reports		216
Right to Inspect Our Books and Records		216
Registration Rights		216
Applicable Law; Exclusive Forum		217
UNITS ELIGIBLE FOR FUTURE SALE		218
Rule 144		218
Our Partnership Agreement and Registration Rights		218
Lock-Up Agreements		219
Registration Statement on Form S-8		219
MATERIAL FEDERAL INCOME TAX CONSEQUENCES		220
Partnership Status		221
Limited Partner Status		222
Tax Consequences of Unit Ownership		222
Tax Treatment of Operations		228
Disposition of Common Units		229
Uniformity of Units		231
Tax-Exempt Organizations and Other Investors		232
Administrative Matters		233
Recent Legislative Developments		236
State, Local, Foreign and Other Tax Considerations		236

iii


	Page
INVESTMENT IN HOWARD MIDSTREAM PARTNERS, LP BY EMPLOYEE BENEFIT PLANS		238
UNDERWRITING		240
Commissions and Expenses		240
Option to Purchase Additional Common Units		241
Lock-Up Agreements		241
Directed Unit Program		242
Offering Price Determination		242
Indemnification		243
Stabilization, Short Positions and Penalty Bids		243
Listing on the New York Stock Exchange		243
Stamp Taxes		244
Other Relationships		244
Direct Participation Plan Requirements		244
Selling Restrictions		244
VALIDITY OF THE COMMON UNITS		249
EXPERTS		249
WHERE YOU CAN FIND ADDITIONAL INFORMATION		250
FORWARD-LOOKING STATEMENTS		251
INDEX TO FINANCIAL STATEMENTS		F-1
APPENDIX A—FORM OF AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF HOWARD MIDSTREAM PARTNERS, LP		A-1
APPENDIX B—GLOSSARY OF TERMS		B-1

You should rely only on the information contained in this prospectus or in any free writing prospectus prepared by us or the selling unitholder or on behalf of us or the selling unitholder or to which we or the selling unitholder have referred you. We and the selling unitholder 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 such free writing prospectus. If anyone provides you with different or inconsistent information, you should not rely on it. None of us, the selling unitholder or the underwriters are making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. The information in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of our common units. Our business, financial condition, results of operations and prospects may have changed since that date.

Through and including , 2017 (the 25th day after the date of this prospectus), federal securities laws may require all dealers that effect transactions in these securities, whether or not participating in this offering, to deliver a prospectus. This requirement is in addition to a dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to an unsold allotment or subscription.

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

The data included in this prospectus regarding the midstream crude oil, natural gas and refined products industries, including descriptions of trends in the market, as well as our position within the industry, are based on a variety of sources, including independent industry publications, government publications and other published independent sources, information obtained from customers, distributors, suppliers, trade and business organizations and publicly available information, as well as good faith estimates that have been derived from management’s knowledge and experience in our industry.

In this prospectus, we rely on and refer to information regarding the midstream crude oil, natural gas and refined products industries from Wood Mackenzie Inc. (“Wood Mackenzie”). The information set forth in this prospectus derived from information provided by Wood Mackenzie is included in this prospectus in reliance upon the authority of Wood Mackenzie as experts on the midstream crude oil, natural gas and refined products industries. Wood Mackenzie is not affiliated with us and has consented to being named in this prospectus.

BASIS OF PRESENTATION

Certain monetary amounts, percentages and other figures included in this prospectus have been subject to rounding adjustments. Percentage amounts included in this prospectus have not in all cases been calculated on the basis of such rounded figures but on the basis of such amounts prior to rounding. For this reason, percentage amounts in this prospectus may vary from those obtained by performing the same calculations using the figures in our consolidated financial statements. Certain other amounts that appear in this prospectus may not sum due to rounding.

CERTAIN ASSUMPTIONS AND TERMS USED IN THIS PROSPECTUS

Except as 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 of this prospectus) and (ii) that the underwriters do not exercise their option to purchase additional common units from us. Unless the context otherwise requires, references in this prospectus to the following terms have the meanings set forth below:

•

“Howard Midstream Partners, LP,” “our partnership,” the “Partnership,” “we,” “our,” “us” or like terms, (i) when used in a historical context, refer to our Predecessor, and (ii) when used in the present tense or future tense, refer to Howard Midstream Partners, LP, a Delaware limited partnership, and its subsidiaries;

•

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

•

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

•

“OpCo” refers to Howard Midstream OpCo, LP, a Delaware limited partnership recently formed by our sponsor and OpCo GP to own a portion of our sponsor’s assets and operations;

•

“OpCo GP” refers to Howard Midstream OpCo GP, LLC, a Delaware limited liability company recently formed by our sponsor and the general partner of OpCo;

•

“Operating LLC” refers to Howard Midstream Operating, LLC, a Delaware limited liability company through which we will own OpCo GP and our interest in OpCo following the closing of this offering;

•

“our sponsor” refers to Howard Midstream Energy Partners, LLC, a Delaware limited liability company and the parent of our general partner, which will own a % limited partner interest in us following the closing of this offering;

•

“our sponsor’s preferred interests” refers to the issued and outstanding convertible, redeemable preferred interests in our sponsor;

•

“selling unitholder” refers to PIP5 Skyline MLP Holdings LLC, a Delaware limited liability company and an affiliate of Alberta Investment Management Corporation that, after giving effect to the closing of this offering (including the sale of common units by the selling unitholder in this offering) and the AIMCo exchange, will own a % limited partner interest in us;

•

“AIMCo” refers to certain investment funds, including the selling unitholder, managed by affiliates of Alberta Investment Management Corporation that own all of our sponsor’s preferred interests and a portion of its outstanding common capital interests;

•

“AIMCo exchange” refers to the selling unitholder’s exchange of a portion of our sponsor’s preferred interests for common units in us in connection with the closing of this offering;

•

“Alinda” refers to certain investment funds managed by affiliates of Alinda Capital Partners Ltd., a Cayman Islands exempted company, that own a portion of the outstanding common capital interests in our sponsor;

•

“InvestCo” refers to HEP Catalyst InvestCo, LLC, our sponsor’s joint venture with affiliates of AIMCo, Alinda and GIC Private Limited in which our sponsor will own an approximate 14% interest and which our sponsor will manage on a day to day basis pursuant to the terms of a management services agreement; and

•

“Catalyst” refers to Catalyst Midstream Partners, LLC, a joint venture between InvestCo and WPX Permian Midstream Holdings, LLC, in which InvestCo will own an approximate 50% economic and 50% voting interest.

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.

PROSPECTUS SUMMARY

This summary highlights selected information contained elsewhere in this prospectus. You should carefully read the entire prospectus, including “Risk Factors” and the historical, unaudited interim and unaudited pro forma financial statements and related notes included elsewhere in this prospectus before making an investment decision. Unless otherwise indicated, the information in this prospectus assumes (i) an initial public offering price of $ per common unit (the mid-point of the price range set forth on the cover page of this prospectus) and (ii) that the underwriters do not exercise their option to purchase additional common units. You should read “Risk Factors” beginning on page 27 for more information about important factors that you should consider before purchasing our common units. We include a glossary of some of the industry terms used in this prospectus in Appendix B.

Howard Midstream Partners, LP

We are a fee-based, growth-oriented Delaware limited partnership formed by our sponsor to own, operate, develop and acquire a diverse range of midstream energy infrastructure assets in North America. We currently provide natural gas, NGLs and refined products midstream services to third-party customers through assets strategically located in prolific hydrocarbon producing basins and attractive markets in South Texas, Northeastern Pennsylvania and along the Texas Gulf Coast. Our management team has extensive experience executing organic growth strategies and completing accretive acquisitions in the midstream industry. We intend to leverage that experience to continue growing our asset base and diversifying our operations to attract customers in growing energy markets.

We initially will own our midstream assets and conduct our business through OpCo, a limited partnership to be formed by our sponsor in which we will own a % limited partner interest and which we will control through a non-economic general partner interest. The substantial majority of our gross margin is generated under contracts that are predominantly long-term in nature and typically contain annual inflation escalators and either minimum volume commitments or demand payments.

For the year ended December 31, 2016 and the six months ended June 30, 2017, our Predecessor generated approximately $7.7 million and $(3.9) million of net income (loss), respectively. For the year ended December 31, 2016 and the six months ended June 30, 2017, our Predecessor generated approximately $102.0 million and $52.3 million of Adjusted EBITDA, respectively. Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation to its most directly comparable financial measures calculated in accordance with generally accepted accounting principles in the United States (“GAAP”), please read “Selected Historical and Pro Forma Financial Data—Non-GAAP Financial Measures.”

Our Assets

Through our interest in OpCo, we own and control natural gas gathering systems in South Texas and Northeastern Pennsylvania, a natural gas processing plant in Webb County, Texas, a deepwater marine terminal in Brownsville, Texas and a condensate and NGL stabilization facility in Live Oak County, Texas. We operate our assets through two operating segments—our Natural Gas segment and our Liquids segment.

Our Natural Gas segment includes:

•

Northeast Gathering Assets: three natural gas gathering systems, including (i) the Greenzweig system in Bradford County, Pennsylvania, which comprises approximately 89 miles of pipeline and approximately 500 MMcf/d of throughput capacity, (ii) the Lycoming system in Lycoming County, Pennsylvania, which comprises approximately 14 miles of pipeline and approximately 100 MMcf/d of throughput

capacity and (iii) the Tioga system currently under development in Tioga County, Pennsylvania, which will comprise 11 miles of pipeline and approximately 100 MMcf/d of throughput capacity. Our northeast gathering assets service lean gas production from the Marcellus Shale and other formations in Northeastern Pennsylvania under long-term, fee-based gas gathering agreements;

•

South Texas Gathering Assets: three natural gas gathering systems, including (i) the EFG system in Webb County, Texas, which comprises approximately 216 miles of pipeline and approximately 1.0 Bcf/d of throughput capacity, (ii) the CCG system in Webb County, Texas, which comprises approximately 65 miles of pipeline and approximately 200 MMcf/d of throughput capacity, and (iii) the MD-ZG system in Maverick, Dimmit, Zavala and Frio Counties, Texas, which comprises approximately 354 miles of pipeline and approximately 250 MMcf/d of throughput capacity. Our South Texas gathering assets service lean and rich natural gas production from the Eagle Ford Shale and other formations in South Texas under predominantly long-term, fee-based gas gathering agreements. Our MD-ZG system also transports lean natural gas that is delivered via third parties to residential and industrial markets along the border between the United States and Mexico; and

•

South Texas Processing Assets: our Reveille processing plant, a cryogenic natural gas processing plant commissioned in December 2013 and located in Webb County, Texas with approximately 200 MMcf/d of capacity, and related infrastructure. Our Reveille processing plant receives natural gas production from our CCG system under predominantly fee-based processing agreements from approximately 122,000 acres of dedicated leases covering multiple formations in South Texas. Our Reveille processing plant connects to Enterprise Product Partners LP’s (“Enterprise”) Eagle Ford NGL pipeline through our Falcon NGL pipeline, which spans approximately 55 miles and provides approximately 18,000 Bbl/d of takeaway capacity.

The following table provides an overview of the assets in our Natural Gas segment as of June 30, 2017:


	System Type		Approximate Miles of Pipeline		Approximate Capacity (MMcf/d)			Approximate Number of Dedicated Acres		Average Daily Throughput (MMcf/d)⁽¹⁾			Remaining Commitments			Weighted Average Contract Life Remaining (Years)⁽²⁾
Northeast Gathering Assets
Greenzweig System		Lean Gas		89		500			22,511		317		$	677.3	⁽³⁾		17.5
Lycoming System		Lean Gas		14		100			6,344		46		$	64.8	⁽³⁾		17.5
Tioga System⁽⁴⁾		Lean Gas		11		100			30,801		15		$	88.2	⁽³⁾		10.0

South Texas Gathering Assets
EFG System		Lean Gas		216		1,005			161,570		276			576	⁽⁵⁾		10.3
CCG System		Rich Gas		65		200			122,000		58			111	⁽⁵⁾		6.6
MD-ZG System		Lean and Rich Gas		354		250			101,249		41			73	⁽⁵⁾		4.9

Total				749		2,155			444,475		753						14.1

South Texas Processing Assets
Reveille Processing Plant		Cryogenic Gas Plant		—		200			122,000		58			94.1	⁽⁵⁾		11.0
Falcon NGL Pipeline		NGL Pipeline		55		18,000	⁽⁶⁾		—		2,805	⁽⁶⁾		—			—

(1)	Average daily throughput calculated over the twelve months ended June 30, 2017.

(2)	Weighted average contract life remaining is presented net of revenue and volume banks as of June 30, 2017. Please read “Business—Commercial Agreements” for a description of our revenue and volume banks.

(3)	Reflects remaining minimum revenue commitments in millions of dollars.

(4)

Reflects the first two phases of the Tioga project as if fully constructed. Phase one was placed in service in December 2016 and phase two is currently under construction. Average daily throughput calculated over the six months ended June 30, 2017 accounts for a December 2016 in-service date for phase one. Please read “Business—Our Assets—Natural Gas Segment—Northeast Gathering Assets—Tioga System” for a description of the expected buildout of the Tioga system.

(5)	Reflects remaining minimum volume commitments in Bcf.

(6)	Amounts presented in Bbl/d.

Our Liquids segment includes:

•

Brownsville Terminal: a deepwater marine terminal in Brownsville, Texas that is fully contracted under long-term contracts with minimum volume commitments. Our Brownsville terminal provides approximately 525,000 Bbls of bulk liquids storage capacity and primarily handles fuel oil, distillates, waxes and lubricants. Our Brownsville terminal also provides our customers with access to the Gulf of Mexico via dedicated dock facilities and access to growing demand markets in South Texas via rail facilities and dedicated truck loading racks.

•

Live Oak Stabilizer: a condensate and NGL stabilization facility in Live Oak County, Texas, designed to process up to approximately 10,000 Bbl/d of off-spec liquids into distinct marketable products, including NGLs, rich gas and marketable condensate. Our Live Oak stabilizer also has the ability to separately handle approximately 5,000 Bbl/d of on-spec NGL product.

•

Live Oak Rail Terminal: an approximately 260-acre industrial logistics rail terminal located in Live Oak County, Texas, which comprises approximately 28,000 linear feet of track. Our Live Oak rail terminal is capable of handling manifest and unit trains transporting multiple types of cargo, including bulk liquids, sand, pipe, aggregates and other materials used in the hydraulic fracturing process, as well as providing railcar storage services.

The following table provides an overview of the assets in our Liquids segment as of June 30, 2017:

Product Types

Approximate
Capacity (Bbls)

Access Capabilities

Aggregate
Remaining
Minimum
Volume
Commitments

Weighted
Average
Contract Life
Remaining
(Years)

Liquids Terminals

Brownsville Terminal

Fuel Oil, Distillates,
Waxes and Lubricants

525,000

Truck, Rail, Barge,
Deepwater

20,257

MBbls

3.5

Live Oak Rail Terminal

Bulk Liquids and Dry
Bulk Products

—

Truck, Rail

10,500

Railcars

17.5

Plant Type

Approximate
Throughput
Capacity (Bbl/d)

NGL Outlet

Rich Gas
Outlet

Condensate
Outlet

NGL Handling

Live Oak Stabilizer

Off-Spec and On-Spec
Condensate Stabilizer

15,000⁽¹⁾

DCP Sand Hills

DCP
Processing
Plant

Truck or Rail
to Market

(1)	Includes up to 10,000 Bbl/d off-spec throughput capacity.

Our ROFR Assets

Pursuant to the omnibus agreement we will enter into with our sponsor in connection with the closing of this offering, we will have a right of first refusal (the “ROFR”) on (i) the remaining % limited partner interest in OpCo retained by our sponsor and (ii) interests in certain additional midstream assets that are under development by our sponsor, in each case to the extent our sponsor elects to sell such interests (collectively, the “ROFR assets”) during the seven-year period following the completion of this offering. Currently, our sponsor has or expects to have five operationally and geographically diverse projects that are in various stages of development and execution that will be subject to the ROFR: the Port Arthur terminal, the Nueva Era pipeline, the EFG system expansion, the Corpus Christi terminal and the Delaware Basin gathering and processing assets.

Port Arthur Terminal. Our sponsor has a controlling ownership interest in an approximately 450-acre terminalling and marine export facility located near Port Arthur, Texas that is strategically located to serve numerous refineries, chemical plants and pipelines in the area. The facility has more than eight miles of rail track, including a unit-train loop track and railcar unloading facilities, four liquid storage tanks representing a total of approximately 220,000 barrels of capacity, two barge docks and more than 3,000 feet of deepwater frontage capable of supporting multiple docks for ocean-going vessels. Our sponsor is currently designing and plans to construct over 1,000,000 barrels of storage capacity to store refined petroleum products and blending stocks. Additionally, the pipeline infrastructure necessary to connect the Port Arthur terminal to major interstate pipelines and to our sponsor’s marine export dock facilities is under development. Infrastructure under development at the deepwater dock facilities is expected to have the ability to load and unload Aframax and Panamax class vessels with refined products bound for various export markets. The planned infrastructure is supported by an executed long-term terminal services agreement with a third-party shipper that contains minimum volume commitments. Our sponsor began construction on the Port Arthur terminal in March 2017 and expects to commence operations in mid-2018.

Nueva Era Pipeline. Our sponsor has entered into a 50-50 joint venture arrangement, which we refer to as Nueva Era, with affiliates of Grupo CLISA, S. de R.L. de C.V. (“CLISA”), a Monterrey, Mexico-based energy and services firm. The joint venture is currently constructing the Nueva Era pipeline, an approximately 200-mile natural gas pipeline from Webb County, Texas to the Monterrey, Mexico area. The Nueva Era pipeline comprises approximately 19 miles of 36-inch pipeline and approximately 181 miles of 30-inch pipeline. Once completed, the Nueva Era pipeline is expected to have the ability to deliver approximately 600 MMcf/d of natural gas, which may be expanded further with additional capital expenditures for compression. The construction of the Nueva Era pipeline is supported by a 25-year agreement with the Comisión Federal de Electricidad of Mexico (“CFE”) pursuant to which CFE, an investment grade, sovereign utility, has contracted for up to 504 MMcf/d of capacity in exchange for fixed capacity reservation fees and variable commodity payments that are based on the amount of natural gas actually transported on the Nueva Era pipeline. Our EFG system, together with the EFG system expansion being developed by our sponsor, will serve as the supply hub for the Nueva Era pipeline. Following the completion of the EFG system expansion, the EFG system will be capable of supplying and delivering to the Nueva Era pipeline natural gas gathered on the EFG system as well as natural gas received from several third party pipeline connections. As described below, in exchange for transportation services, Nueva Era will pay a portion of the capacity reservation fees and all of the commodity payments received from CFE to our sponsor pursuant to a separate 25-year agreement. The capacity reservation fees are fixed for each year of the term of the agreement with CFE and are expected to generate $1.5 billion in aggregate demand payments during the life of the agreement. Through its 50% ownership, our sponsor will receive net cash flows associated with $690.3 million of the payments, and our sponsor will receive $138.1 million of these payments directly. Construction of the Nueva Era pipeline has begun, and we expect the Nueva Era pipeline to be in service in the first quarter of 2018.

EFG System Expansion. Our sponsor is currently expanding the EFG system to increase the system’s throughput capacity and integrate it with the Nueva Era pipeline. This expansion project includes additions and modifications to existing compressor stations, transmission pipeline, meters and interconnects associated with the EFG system’s interconnection with the Nueva Era pipeline. As described above, the expanded EFG system will provide transportation service to Nueva Era pursuant to a separate 25-year capacity lease agreement that entitles our sponsor to receive a portion of the capacity reservation fees and all of the commodity payments received by Nueva Era from CFE. During the initial term of this agreement, our sponsor is expected to receive $138.1 million in payments from Nueva Era. Our sponsor will enter into a 25-year services agreement to use the existing EFG system in connection with the capacity lease agreement with Nueva Era and will reimburse the EFG system for costs incurred. We expect the EFG system expansion to be completed in late 2017.

Corpus Christi Terminal. Our sponsor is currently constructing a terminal and marine export facility at the Port of Corpus Christi, Texas. The facility will initially have 480,000 barrels of storage capacity as well as unit train loading and marine dock capabilities. Our sponsor has the capability to expand the facility by adding approximately 2,000,000 barrels of additional storage and a dedicated dock capable of handling Suez-sized vessels. The initial phase of the facility is supported by an executed terminal services agreement with a third-party shipper that contains minimum volume commitments. Our sponsor began construction on the Corpus Christi terminal in August 2017 and expects to commence operations in the second quarter of 2018.

Delaware Basin Gathering and Processing. In June 2017, our sponsor, along with affiliates of AIMCo, Alinda and GIC Private Limited, the sovereign wealth fund of Singapore (“GIC”), entered into a strategic relationship with affiliates of WPX Energy, Inc. (“WPX”) to form a joint venture, Catalyst Midstream Partners, LLC (“Catalyst”). After fulfillment of its initial capital commitment, the investment vehicle formed by our sponsor and affiliates of AIMCo, Alinda and GIC, HEP Catalyst InvestCo, LLC (“InvestCo”), will own a 50% interest in Catalyst, and our sponsor will own a 14% interest in InvestCo. Catalyst will perform crude oil and natural gas gathering and processing services for WPX in the Delaware Basin and will own, construct and operate related crude oil and natural gas gathering and processing assets, including a new cryogenic natural gas processing complex with an initial capacity of 400 MMcf/d. Catalyst will be supported by an area of mutual interest of more than 600 square miles in Reeves and Loving Counties, Texas and Lea and Eddy Counties, New Mexico, with approximately 50,000 net acres currently dedicated by WPX. Our sponsor will serve as the operator of Catalyst. Catalyst will also hold a right of first refusal on WPX’s existing and future wellhead gathering systems and water handling assets located within the area of mutual interest, as well as a right of first offer on WPX’s and its affiliates’ existing and future midstream assets located in the Delaware Basin both within and outside of the area of mutual interest. In addition, our sponsor will hold a right of first refusal on the remaining equity interests in InvestCo held by AIMCo, Alinda and GIC to the extent any such member elects to sell such interests within the six-and-a-half-year period following the closing of the Catalyst joint venture. Pursuant to the terms of the omnibus agreement, our sponsor will grant to us a right of first refusal on its interest in InvestCo, including any interest in InvestCo it may acquire in the future from AIMCo, Alinda or GIC, to the extent it elects to sell such interest.

Our right of first refusal does not ensure that we will be able to acquire interests in these ROFR assets at an attractive price or at all. We are under no obligation to purchase any ROFR assets, and our sponsor is only under an obligation to permit us to match an offer on a ROFR asset to the extent that it elects to sell such ROFR asset to a third party. We do not know when or if our sponsor will elect to sell any ROFR assets. Our ROFR will last for a period of seven years from the closing of this offering. Upon a change in control of the general partner of the Partnership, we or our sponsor may terminate the ROFR. Furthermore, our relationship with our sponsor will pose a conflict of interest in connection with any such acquisition. Any decision to exercise our right of first refusal will require the approval of the board of directors of our general partner, all of the members of which will be appointed by our sponsor as the owner of our general partner. Because our general partner is a wholly owned subsidiary of our sponsor, the officers and directors of our general partner will manage the business of our general partner in a manner that is in the best interests of our sponsor. Please read “—Our Relationship with Our Sponsor and its Investors” and “Conflicts of Interest and Duties.”

Our Areas of Operation

Our initial assets and ROFR assets are located in five key geographic areas that are prolific hydrocarbon production or demand areas, are core to the hydrocarbon value chain and have significant strategic value to us. Our geographic areas of operation are South Texas, Northeastern Pennsylvania, the Texas Gulf Coast, the Delaware Basin and Mexico and are described in more detail below:

South Texas

Our South Texas gathering and processing assets are located in the southern portion of the dry gas window of the Eagle Ford Shale, which includes portions of Webb, Maverick, Dimmit, Zavala and Frio Counties. The producers in our areas of operations in South Texas target lean natural gas, rich natural gas and crude oil and source production from a number of hydrocarbon bearing formations.

Lean Natural Gas Volumes. Our EFG system predominantly gathers production from the Eagle Ford Shale and Austin Chalk formations. These formations produce lean natural gas in our areas of operation in Webb County, Texas. This area has benefited from significant improvements in well productivity and costs over recent years as producers have focused on optimizing and enhancing completion techniques. As of June 14, 2017, Wood Mackenzie estimates that average EURs per well in this area are approximately 8.7 Bcfe.

Our MD-ZG system transports lean natural gas that is delivered via third parties to residential and industrial markets along the border between the United States and Mexico. The lean natural gas transported on our MD-ZG system is predominantly the residue gas from a third-party processing plant located in La Salle County.

Rich Natural Gas Volumes. Our CCG system gathers rich natural gas from production in Webb County, Texas and delivers these volumes to our Reveille processing plant. Operators drilling for rich natural gas in this area of Webb County, Texas have historically targeted the Olmos and Escondido formations; however, the stacked nature of natural gas resources in this area provides additional rich gas drilling inventory in other nearby formations, such as the Wilcox and San Miguel formations.

Our MD-ZG system predominantly gathers rich natural gas from production in Maverick, Dimmit, Zavala and Frio Counties, Texas. The operators in this region have historically targeted the Eagle Ford Shale and San Miguel formations. The volumes transported on our MD-ZG system are typically associated rich natural gas produced from wells drilled in this region. As of June 14, 2017, Wood Mackenzie estimates that average EURs per well in this area are approximately 720 MBoe.

Live Oak Stabilizer Volumes. Our Live Oak stabilizer processes NGL and condensate volumes delivered by truck from multiple locations across South Texas. The majority of the production processed by our Live Oak stabilizer is liquids-rich Eagle Ford production.

Downstream Natural Gas Markets. Wood Mackenzie expects capital investment in exploration and production activity to increase in South Texas as a result of improving producer economics. Natural gas produced in South Texas is ideally situated to serve this demand due to the close proximity to Mexico and LNG export facilities and the formidable size of the resource. LNG demand is expected to increase rapidly as LNG export facilities located along the Gulf Coast become operable. According to the U.S. Energy Information Administration (the “EIA”), demand for exports to Mexico is expected to increase to approximately 5 Bcf/d by 2020, with much of the growing demand to be met by pipeline exports of natural gas from South Texas.

Producers in this area also benefit from substantial natural gas infrastructure in place that provides access to multiple natural gas hubs such as Agua Dulce, Texas and the Houston Ship Channel. Our sponsor’s Nueva Era pipeline, which will be supplied from natural gas gathered and transported on our EFG system and the EFG system expansion being developed by our sponsor, will connect South Texas production to growing demand markets in Mexico. Nueva Era provides additional access to strategic demand markets that we are able to provide to our customers and will enhance our customers’ ability to achieve the highest possible net-back pricing for their production.

Northeastern Pennsylvania

Our northeast gathering assets are located in the lean natural gas area of the northeastern Marcellus Shale in Tioga, Lycoming and Bradford Counties in Northeastern Pennsylvania.

The northeastern Marcellus Shale is a lean natural gas play with significant resources in place and, due to the large average well size and robust resource potential, has some of the lowest natural gas breakeven prices in the continental United States. As of December 14, 2016, Wood Mackenzie estimates that there are approximately 132 Tcf of total natural gas-risked resource in the northeastern Marcellus Shale, and that per well EURs generally range from approximately 8 Bcf to approximately 14 Bcf. Natural gas production in this area has historically been burdened by large basis differentials due to constraints caused by a lack of infrastructure available to transport natural gas production out of the basin. However, many producers, including certain of our customers, have been actively securing firm take-away capacity out of the region and investing in new pipeline projects to improve net-back economics.

Production growth is expected to continue at a high rate in the northeastern Marcellus Shale as new pipeline takeaway options to high demand markets commence operations and realized pricing improves. Wood Mackenzie estimates that production from the northeastern Marcellus Shale will increase by approximately 3 Bcf/d to an aggregate of approximately 13 Bcf/d for the area by 2020.

Texas Gulf Coast

The assets comprising our Liquids segment, as well as the Port Arthur and Corpus Christi terminals that will be subject to our ROFR, are located along the Texas Gulf Coast and provide access to this growing market and export opportunities to various international demand centers. The strategic location of refineries in this region to the Colonial and Plantation pipeline systems, as well as export infrastructure along the Gulf Coast, allows the Gulf Coast refineries to take advantage of shifts in both domestic and international demand to balance production. For example, when production of transportation fuels in the Gulf Coast region substantially exceeds the region’s consumption, refineries located along the Gulf Coast export excess production to demand centers in Mexico and other international markets. In the event that shortages of transportation fuels arise in domestic markets, Gulf Coast refineries are able to shift production to service domestic demand.

According to the EIA, the Gulf Coast, including Texas and Louisiana, is the largest market for the import, export and processing of hydrocarbons in the United States and encompasses over 45% of total U.S. refining capacity. In addition, according to the EIA, NGL exports from the U.S. have increased from approximately 160 MBbl/d in 2010 to approximately 960 MBbl/d in 2015 and are expected to continue to increase with new export projects coming in service. These supply and demand dynamics necessitate terminalling and storage capabilities along the Gulf Coast to balance supply and demand, segregate different grades of crude to optimize refinery inputs, facilitate movements between pipelines along the Gulf Coast and to export product to foreign markets. The Gulf Coast of Texas and Louisiana has seen increasing investments to construct and expand terminals, storage and docks. Corpus Christi, Houston, Port Arthur and Nederland, Texas and Lake Charles, Louisiana have all experienced large scale build-outs of infrastructure due to their proximity to refinery markets, water access and connectivity.

Delaware Basin

Upon the closing of the Catalyst joint venture and fulfillment of its initial capital commitment, InvestCo, in which our sponsor will hold a 14% interest that will be subject to our ROFR, will own a 50% economic and 50% voting interest in Catalyst. Catalyst will perform crude oil and natural gas gathering and processing services for WPX in the Delaware Basin, which is considered one of the major producing basins in the United States and is characterized by numerous stacked reservoirs, high oil and natural gas content, extensive production history, long-lived reserves and high drilling success rates. Exploration and production activity in the Delaware Basin is primarily focused on the Wolfcamp Shale formation, the Bone Spring interval (which includes the Avalon sand and shales and the Bone Springs sands, shales and carbonates) and the shallower Delaware sand interval.

According to Wood Mackenzie, over the last several years, the Delaware Basin has been one of the most active basins in the United States in terms of exploration and production activity in part because its Wolfcamp play has a robust resource base that is estimated to represent over 30 BBoe of undrilled risked resource potential and 40,000 potential horizontal drilling locations. Wood Mackenzie forecasts an increase in wells drilled in the Delaware Basin from 2,314 in 2017 to 3,274 in 2020, resulting in increased production from 1,830 MBoe/d in 2017 to over 3,000 MBoe/d in 2020. The high level of exploration and production has coincided with increased M&A activity. According to Wood Mackenzie, there was over $17 billion in upstream M&A activity in the Delaware Basin in 2016 and over $13 billion in the first half of 2017.

Mexico

The Nueva Era Pipeline, in which our sponsor holds a 50% ownership interest that will be subject to our ROFR, is currently being constructed from Webb County, Texas to the Monterrey, Mexico area. Mexico has emerged as an important and growing market for U.S. natural gas producers as demand for natural gas, particularly from Mexico’s electric power sector, has outpaced supply. We believe that the ongoing deregulation of the Mexican oil and gas industry will create opportunities for U.S. natural gas producers to serve this excess demand. According to Wood Mackenzie, natural gas demand in Mexico may increase to 7 Bcf/d by 2020, making Mexico one of the largest natural gas consumers globally. While Mexico has considerable natural gas resources, the development of its shale gas resources is proceeding slowly. Consequently, Mexico is expected to rely on increased imports of natural gas and LNG. Continued midstream infrastructure build out and optimization of existing South Texas infrastructure will be required to bring U.S. hydrocarbons to Mexico.

Business Strategies

Our primary business objective is to own and operate a diversified set of assets that generate stable and growing cash flows that will allow us to pay and increase our quarterly cash distribution per unit over time. We intend to accomplish this objective by executing the following strategies:

•

Growing and diversifying our business by pursuing accretive acquisitions from our sponsor and third parties. We intend to pursue opportunities to grow and diversify our business through accretive acquisitions of additional interests in OpCo and other assets from our sponsor. We will have a right of first refusal with respect to our sponsor’s additional interests in OpCo, as well as our sponsor’s interests in the Port Arthur terminal, the Nueva Era pipeline, the EFG system expansion, the Corpus Christi terminal and, upon closing of the Catalyst joint venture, the Delaware Basin gathering and processing assets. In addition, through our partnership with our sponsor, we monitor the marketplace to identify and pursue acquisitions from third parties. We intend to leverage the experience of our management team to identify and pursue acquisition opportunities, with a particular focus on opportunities in the midstream industry that we believe will complement our existing assets through operating synergies and interconnection.

•

Pursuing economically attractive organic growth opportunities and enhancing the profitability of our existing assets. We seek attractive organic expansion and asset enhancement opportunities that leverage our existing asset footprint, strategic relationships with our customers and our management team’s expertise in constructing, developing and optimizing infrastructure assets. Our goal is to increase the profitability of our existing asset base by identifying organic development projects that are designed to extend our geographic reach, diversify our asset mix and customer base, expand our existing assets, enhance our end-market access and maximize our throughput volumes. We also plan to selectively pursue strategic opportunities in new geographic locations.

•

Focusing on fee-based revenue with minimal direct commodity-price exposure. As we expand and diversify our business, we intend to maintain our focus on providing services to our customers under

long-term, fee-based arrangements with minimum volume commitments, demand payments and deficiency payments. We believe this will enhance the stability of our cash flows during changing commodity price environments.

•

Maintaining a conservative and flexible capital structure in order to support our long-term access to capital. We intend to continue our commitment to financial discipline by maintaining a conservative capital structure and appropriate access to liquidity. We intend to fund our expansion projects and acquisitions through a prudent combination of equity and debt capital. We believe our conservative capital structure, when combined with our stable, fee-based cash flows, will afford us efficient access to capital markets at a competitive cost of capital to take advantage of future growth opportunities.

Competitive Strengths

We believe that we are well-positioned to achieve our primary business objective and successfully execute our business strategies by capitalizing on the following competitive strengths:

•

Our strategic relationship with our sponsor. Through our relationship with our sponsor, we will have access to talented management, robust industry knowledge and seasoned commercial relationships throughout the midstream industry that promote business development. As the owner of a % limited partner interest in us, a 100% interest in our general partner, all of our incentive distribution rights and a % interest in OpCo, we believe our sponsor has a vested interest in our success and will be incentivized to support our business plan and pursue projects that will enhance the overall value of our business and support a stable base of cash flows. We expect that our relationship with our sponsor will also create economies of scale, including shared overhead expenses that we believe will reduce our operating expenditures relative to competitors. In addition, we believe that our right of first refusal with respect to our sponsor’s additional interests in OpCo, as well as our sponsor’s interests in the Port Arthur terminal, the Nueva Era pipeline, the EFG system expansion, the Corpus Christi terminal and, upon closing of the Catalyst joint venture, the Delaware Basin gathering and processing assets, will provide us with access to meaningful, highly visible growth opportunities in key geographic areas, including South Texas, the Gulf Coast and Mexico.

•

Recently constructed, strategically located and diversified asset base. Our assets are strategically located between prolific hydrocarbon supply and robust demand areas in both the natural gas and hydrocarbon liquids value chain. This includes natural gas and NGL production and demand centers and refined product hubs, serving both domestic and international markets. We expect to continue our focus on geographic areas that we believe hold long-term economic opportunity for both our supply- and demand-driven customers, including in Mexico, where we intend to grow as a supply source by leveraging the integrated nature of our South Texas assets, such as our sponsor’s planned interconnection between the Nueva Era pipeline and our EFG system. In addition, the substantial majority of our assets were constructed within the last 5 years, and therefore we do not expect to incur significant maintenance capital expenditures associated with these assets in the near future.

•

Fee-based revenues generated by long-term contracts. The substantial majority of our gross margin is generated under long-term, fee-based agreements with annual inflation escalators and either minimum volume commitments or demand payments from our customers. As of June 30, 2017, our gas gathering, processing and transportation agreements had remaining minimum volume commitments totaling approximately 3,354 Bcf and remaining demand payments of approximately $1,082 million through 2042. As of June 30, 2017, our terminalling agreements had remaining minimum volume commitments totaling approximately 20,257 MBbls through 2021. For the twelve months ending September 30, 2018, we estimate that approximately 69% of our gross margin will be supported by minimum volume commitments. Please read “Cash Distribution Policy and Restrictions on Distributions—Estimated Adjusted EBITDA and Distributable Cash Flow for the Twelve Months Ending September 30, 2018” and “Cash Distribution Policy and Restrictions on Distributions—Significant Forecast Assumptions.”

•

Experienced management team with proven record of origination, construction, development, operation, acquisition and integration expertise. Our executive management team has an average of approximately 20 years of energy industry experience and a proven track record of originating projects and owning, developing and managing midstream infrastructure. We intend to leverage this expertise to successfully develop our assets and efficiently manage our operations. Our management team has also established strong relationships with producers, marketers and end-users of hydrocarbons throughout the North American upstream and midstream industries, which we believe will be beneficial to us in pursuing acquisition and organic expansion opportunities. In addition, we will employ engineering, construction and operations teams that have significant experience in designing, constructing and operating large midstream infrastructure projects.

•

Capital structure focused on financial flexibility and alignment of interests with unitholders. At the closing of this offering, we expect to have approximately $ million of borrowing capacity available to us under our new, undrawn revolving credit facility. We believe our borrowing capacity and anticipated access to private and public debt and equity capital will provide us with the requisite financial flexibility to execute our business strategy. Additionally, by establishing a long-term incentive plan under which we expect to issue equity awards to our management team and certain of our employees, we believe we align the long-term interests of our personnel with our unitholders.

Our Relationship with Our Sponsor and its Investors

We believe that our relationship with our sponsor and its investors represents a critical and differentiating strength of our platform. Our sponsor is a privately-owned midstream energy company formed in 2011 by Mike Howard, the Chief Executive Officer and Chairman of our general partner, and Brad Bynum, the President of our general partner, with initial investments from EnLink Midstream Operating, L.P. (“EnLink”) and Quanta Services, Inc. In December 2013, Alinda acquired a common capital interest in our sponsor. In 2016, AIMCo invested $400 million in our sponsor through acquisitions of our sponsor’s preferred interests and has committed to invest up to an additional $100 million in preferred interests at the election of our sponsor, subject to certain conditions. In March 2017, AIMCo acquired EnLink’s entire interest in our sponsor. As of September 12, 2017, Alinda and AIMCo owned approximately 59% and 28% of our sponsor’s common capital interests, respectively, with management and other private investors owning the remaining 13%. In connection with the closing of this offering, the selling unitholder, an affiliate of AIMCo, will receive $ in net proceeds from the sale of common units it will receive in connection with the AIMCo Exchange. The selling unitholder has expressed an intent to use the net proceeds to fund additional investments in our sponsor to acquire and develop additional assets that our sponsor may offer to us in the future. However, the selling unitholder is under no contractual obligation to use the proceeds in this manner and we cannot guarantee that it will do so.

Alinda is an independent investment firm that invests in infrastructure assets that provide essential services to communities, governments and businesses. As of June 30, 2017, Alinda had approximately $9 billion of assets under management. AIMCo is one of Canada’s largest and most diversified institutional investment managers and invests globally on behalf of 32 pension, endowment and government funds in the Province of Alberta. AIMCo had approximately C$100 billion of assets under management as of June 30, 2017.

Under our omnibus agreement, our sponsor will grant us a ROFR with respect to its remaining interest in OpCo, as well as interests in certain other midstream assets that it owns or is developing. Pursuant to our ROFR, before our sponsor can sell any of these assets to any third party, it must allow us to match an offer to purchase these interests. Through our ROFR, we expect to have the opportunity to acquire additional midstream infrastructure assets that have been developed by our sponsor, which both minimize our construction capital costs and should allow us to increase our distributable cash flow over time. Further, we believe that our sponsor will continue to develop midstream assets in the future and may offer us the opportunity to purchase such assets. However, we are under no obligation to purchase any ROFR assets, and our sponsor is only under an obligation

to permit us to match the offer on a ROFR asset to the extent that our sponsor decides to sell such ROFR asset to a third party. We do not know when or if our sponsor will elect to sell any ROFR assets. The consummation and timing of any acquisition of additional interests in OpCo or other ROFR assets will depend upon, among other things, our sponsor’s willingness to offer the asset for sale and obtain any necessary third party consents, the determination that the asset is suitable for our business at that particular time, our ability to agree on a mutually acceptable price, our ability to negotiate an acceptable purchase agreement with respect to the asset and our ability to obtain financing on acceptable terms if necessary. Please read “Business—Our ROFR Assets” and “Certain Relationships and Related Party Transactions—Agreements with Our Affiliates in Connection with the Transactions—Omnibus Agreement.”

In connection with the closing of this offering (assuming the underwriters do not exercise their option to purchase additional common units), we will (i) issue common units and subordinated units to our sponsor, representing an aggregate % limited partner interest in us, (ii) issue all of our incentive distribution rights to our general partner and (iii) issue common units to the public and use the net proceeds from this offering to repay the outstanding balance of $ million under the term loan portion of our sponsor’s credit facility that we will assume in connection with the closing of this offering. In addition, AIMCo will exchange a portion of our sponsor’s preferred interests for common units in us that our sponsor will receive and the selling unitholder will sell of those common units to the public in this offering. Unless the underwriters exercise their option to purchase additional units, we do not expect our sponsor or any of our sponsor’s directors or officers to receive any of the net proceeds from this offering, or any other payment, compensation or equity interests in us in connection with this offering. Following the AIMCo exchange and the sale of common units to the public by the selling unitholder, our sponsor will own an aggregate % limited partner interest in us and a 100% interest in our general partner, and AIMCo will own a % limited partner interest in us. We do not expect our sponsor or any of our sponsor’s or general partner’s directors or officers to receive any of the net proceeds from this offering, or any other payment, compensation or equity interests in us in connection with this offering, except to the extent our sponsor receives a distribution from the proceeds of any exercise of the underwriters’ option to purchase additional units or such directors or officers receive grants of equity securities under our long-term incentive plan. Please read “—The Transactions.”

Given our sponsor’s significant ownership interests in us following this offering, we believe that it will be incentivized to promote and support the successful execution of our business strategies; however, we can provide no assurance that we will benefit from our relationship with our sponsor. While our relationship with our sponsor is a significant strength, it is also a source of potential risks and conflicts. Please read “Risk Factors—Risks Inherent in an Investment in Us” and “Conflicts of Interest and Duties.”

Our Emerging Growth Company Status

As a partnership with less than $1.07 billion in revenue during its last fiscal year, we qualify as an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”). As an emerging growth company, we may, for up to five years, take advantage of specified exemptions from reporting and other regulatory requirements that are otherwise applicable generally to public companies. These exemptions include:

•

the presentation of only two years of audited financial statements and only two years of related Management’s Discussion and Analysis of Financial Condition and Results of Operations in this prospectus;

•

deferral of the auditor attestation requirement on the effectiveness of our system of internal control over financial reporting;

•

exemption from the adoption of new or revised financial accounting standards until they would apply to private companies;

•

exemption from compliance with any new requirements adopted by the Public Company Accounting Oversight Board (the “PCAOB”) requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer; and

•

reduced disclosure about executive compensation arrangements.

We may take advantage of these provisions until we are no longer an emerging growth company, which will occur on the earliest of (i) the last day of the fiscal year following the fifth anniversary of this offering, (ii) the last day of the fiscal year in which we have equal to or more than $1.07 billion in annual revenue, (iii) the date on which we issue more than $1.0 billion of non-convertible debt over a three-year period and (iv) the date on which we are deemed to be a “large accelerated filer,” as defined in Rule 12b-2 promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”).

We have elected to take advantage of all of the applicable JOBS Act provisions, including the exemption that allows emerging growth companies to extend the transition period for complying with new or revised financial accounting standards.

Accordingly, the information that we provide you may be different than what you may receive from other public companies in which you hold equity interests.

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. Below is a summary of certain key risk factors that you should consider in evaluating an investment in our common units. However, this list is not exclusive. Please read “Risk Factors” and “Forward-Looking Statements.”

Risks Related to Our Business

•

We may not generate sufficient distributable cash flow to support the payment of the minimum quarterly distribution to our unitholders.

•

Because of the natural decline in production from existing wells in our areas of operation, our success depends in part on producers replacing declining production and also on our ability to obtain new sources of natural gas. Any decrease in the volumes of natural gas, condensate or other products for which we provide midstream services could adversely affect our business and operating results.

•

•

We may be unable to grow by acquiring interests in our ROFR assets owned by our sponsor or midstream assets acquired or developed by our sponsor, which could limit our ability to increase our distributable cash flow.

•

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.

Risks Inherent in an Investment in Us

•

Our general partner and its affiliates, including our sponsor, have conflicts of interest with us and limited fiduciary duties to us and our unitholders, and they may favor their own interests to our detriment and that of our unitholders. Additionally, we have no control over the business decisions and operations of our sponsor, and our sponsor is not under any obligation to adopt a business strategy that favors us.

•

Unitholders have very limited voting rights, and, even if they are dissatisfied, they will have limited ability to remove our general partner.

•

In response to a change in tax law, our general partner may elect to convert or restructure the partnership to an entity taxable as a corporation for U.S. federal income tax purposes without unitholder consent.

Tax Risks

•

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, or if we were otherwise subjected to a material amount of additional entity-level taxation, then our distributable cash flow to our unitholders would be substantially reduced.

•

Our unitholders’ share of our income will be taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.

The Transactions

In connection with the closing of this offering, our sponsor will contribute to us a 100% interest in OpCo GP and a % limited partner interest in OpCo, which will own substantially all of our sponsor’s current assets and operations. In addition, in connection with the closing of this offering, we will:

•

issue to our sponsor (i) common units, representing a % limited partner interest in us and (ii) subordinated units, representing a 50% limited partner interest in us;

•

issue all of our incentive distribution rights to our general partner;

•

assume the outstanding balance of $ million under the term loan portion of our sponsor’s credit facility;

•

issue common units to the public, representing a % limited partner interest in us, and will apply the net proceeds as described in “Use of Proceeds”;

•

enter into a new $ million revolving credit facility; and

•

enter into an omnibus agreement with our sponsor and our general partner as described in “Certain Relationships and Related Party Transactions—Agreements with Our Affiliates in Connection with the Transactions.”

In addition, AIMCo will exchange of our sponsor’s preferred interests for of our common units issued to our sponsor as described above and will sell of those common units to the public in this offering. Following the AIMCo exchange and the sale of common units to the public by the selling unitholder, our sponsor will own an aggregate % limited partner interest in us, and AIMCo will own a % limited partner interest in us.

The number of common units to be issued to our sponsor includes common units that will be issued at the expiration of the underwriters’ option to purchase additional common units, assuming that the underwriters do not exercise the option. Any exercise of the underwriters’ option to purchase additional common units would reduce the common units shown as held by our sponsor by the number to be purchased by the underwriters from us 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 exercise will be issued to the public, and any remaining common units not purchased by the underwriters pursuant to any exercise of the option will be issued to our sponsor at the expiration of the option period for no additional consideration. We will use any net proceeds from the exercise of the underwriters’ option to purchase additional common units from us to make a cash distribution to our sponsor.

Ownership and Organizational Structure

After giving effect to the transactions described above, assuming the underwriters’ option to purchase additional common units from us is not exercised, our partnership interests will be held as follows:


Public common units		%
Common units held by AIMCo		%
Common units held by our sponsor		%
Subordinated units held by our sponsor	50.0	%
Non-economic general partner interest	—	%

Total	100	%

The following simplified diagram depicts our organizational structure after giving effect to the transactions described above.

LOGO

Management of Howard Midstream Partners, LP

We are managed and operated by the board of directors and executive officers of Howard Midstream GP, LLC, our general partner. Our sponsor owns our general partner and has the right to appoint the entire board of directors of our general partner and, unlike shareholders in a publicly traded corporation, our unitholders will not be entitled to elect our general partner or the board of directors of our general partner. Prior to the listing of our common units on the New York Stock Exchange (“NYSE”) in advance of the closing of this offering, we expect that our sponsor will appoint a total of seven members to the board of directors of our general partner, with one appointee meeting the independence standards of the NYSE. Our general partner is 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 within 12 months of the date of this prospectus. Our sponsor will appoint one additional independent director within 90 days of the date of this prospectus and a third independent director within 12 months of the date of this prospectus as required by the listing standards of the NYSE. Many of the executive officers and directors of our general partner also currently serve as executive officers and directors of our sponsor. Please read “Management—Directors and Executive Officers of Howard Midstream GP, LLC.”

In order to maintain operational flexibility, our initial operations will be conducted through, and our initial operating assets will be owned by, OpCo. However, neither we nor OpCo 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 our sponsor 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 affiliates of our sponsor, 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 16211 La Cantera Parkway, Suite 202, San Antonio, Texas 78256, and our telephone number is (210) 298-2222. Following the completion of this offering, our website will be located at www. .com. We expect to make our periodic reports and other information filed with or furnished to the U.S. 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.

Summary of Conflicts of Interest and Duties

Under our partnership agreement, our general partner has a duty to manage us in a manner it believes is in the best interests of our partnership. However, because our general partner is a wholly owned subsidiary of our sponsor, the officers and directors of our general partner have a duty to manage the business of our general partner in a manner that is in the best interests of our sponsor. As a result of this relationship, 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 our sponsor, Alinda and AIMCo, on the other hand. For example, our general partner will be entitled to make determinations that affect the amount of cash distributions we make to the holders of common units, which in turn has an effect on whether our general partner receives incentive cash distributions. In addition, 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 expiration of the subordination period. All of these actions are permitted under our partnership agreement and would not be a breach of any duty (fiduciary or otherwise) of our general partner. Please read “Conflicts of Interest and Duties.”

Delaware law provides that a Delaware limited partnership may, in its partnership agreement, expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to limited partners and the partnership. 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 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 our sponsor, are not restricted from competing with us, and neither our general partner nor its affiliates has any obligation to present business opportunities to us except with respect to the ROFR contained in our omnibus agreement. 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. Please read “Conflicts of Interest and Duties—Duties of Our General Partner” and “Certain Relationships and Related Party Transactions.”

The Offering

Common units offered to the public by us

common units.

common units if the underwriters exercise in full their option to purchase additional common units from us.

Common units offered to the public by the selling unitholder

common units

Units outstanding after this offering

common units and subordinated units, each representing an aggregate % limited partner interest in us.

The number of common units outstanding after this offering includes common units that are available to be issued to the underwriters pursuant to their option to purchase additional common units from us. The number of common units purchased by the underwriters pursuant to any exercise of the option will be issued to the public. If the underwriters do not exercise their option to purchase additional common units, in whole or in part, any remaining common units not purchased by the underwriters pursuant to the option will be issued to our sponsor at the expiration of the option period for no additional consideration. Accordingly, any exercise of the underwriters’ option, in whole or in part, 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.

Use of proceeds

We expect to receive net proceeds of approximately $ million from the sale of common units offered by this prospectus, based on an assumed initial public offering price of $ per common unit (the mid-point of the price range set forth on the cover page of this prospectus), after deducting underwriting discounts and commissions, the structuring fees and estimated offering expenses. Our estimate assumes the underwriters’ option to purchase additional common units is not exercised. We intend to use the net proceeds from this offering to repay the outstanding balance of $ million under the term loan portion of our sponsor’s credit facility that we will assume in connection with the closing of this offering. We will not receive any proceeds from the sale of common units by the selling unitholder. Please read “Use of Proceeds.”

If the underwriters exercise in full their option to purchase additional common units, we expect to receive net proceeds of approximately $ million, after deducting underwriting discounts and commissions, the structuring fees and estimated offering expenses. We will use any net proceeds we receive from the exercise of the underwriters’ option to purchase additional common units to make a cash distribution to our sponsor.

Affiliates of certain of the underwriters are lenders under our sponsor’s credit facility and, accordingly, will receive a portion of the proceeds of this offering. Please read “Underwriting.”

Cash distributions

We intend to make a minimum quarterly distribution of $ per unit to the extent we have sufficient cash at the end of each quarter after establishment of cash reserves and payment of fees and expenses, including payments to our general partner. We refer to this cash as “available cash.” Our ability to pay the minimum quarterly distribution is subject to various restrictions and other factors described in more detail under the caption “Cash Distribution Policy and Restrictions on Distributions.”

We do not expect to make distributions for the period that began on , 2017 and ends on the day prior to the closing of this offering. We will adjust the amount of our first distribution for the period from the closing of this offering through , 2017 based on the number of days in that period.

In general, we will pay any cash distributions we make each quarter in the following manner:

•

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

•

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

•

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, our general partner will receive increasing percentages, up to 50%, of the cash we distribute in excess of that amount. We refer to these distributions as “incentive distributions.” In certain circumstances, our general partner, as the initial holder of our incentive distribution rights, has the right to reset the target distribution levels described above to higher levels based on our cash distributions at the time of the exercise of this reset election. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

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 “Cash Distribution Policy and Restrictions on Distributions—Estimated Adjusted EBITDA and Distributable Cash Flow for the Twelve Months Ending September 30, 2018,” that we will generate sufficient distributable cash flow to support the payment of the aggregate minimum quarterly distributions of $ million on all of our common units and subordinated units for the twelve months

ending September 30, 2018. However, we do not have a legal obligation to pay distributions at our minimum quarterly distribution rate or at any other rate except as provided in our partnership agreement, and there is no guarantee that we will make quarterly cash distributions to our unitholders. Please read “Cash Distribution Policy and Restrictions on Distributions.”

Subordinated units

Following the completion of this offering, our sponsor will own all of our subordinated units. The principal difference between our common units and subordinated units is that for any quarter during the subordination period, the subordinated units will not be entitled to receive any distribution until the common units have received the minimum quarterly distribution for such quarter plus any arrearages in the payment of the minimum quarterly distribution from prior quarters during the subordination period. Subordinated units will not accrue arrearages.

Conversion of subordinated units

The subordination period will end on the first business day after the date that we have earned and paid distributions of at least (i) $ (the annualized minimum quarterly distribution) on each of the outstanding common units and subordinated units for each of three consecutive, non-overlapping four-quarter periods ending on or after , 2020 or (ii) $ (150% of the annualized minimum quarterly distribution) on each of the outstanding common units and subordinated units and the related distributions on the incentive distribution rights for any four-quarter period ending on or after , 2018, in each case provided there are no arrearages in payment of the minimum quarterly distributions on our common units at that time.

When the subordination period ends, each outstanding subordinated unit will convert into one common unit, and common units will no longer be entitled to arrearages. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordinated Units and Subordination Period.”

Issuance of additional partnership interests

Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests and options, rights, warrants and appreciation rights relating to the partnership interests for any partnership purpose at any time and from time to time to such persons for such consideration and on such terms and conditions as our general partner shall determine in its sole discretion, all without the approval of any limited partners.

In addition, 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 those interests to persons other than our general partner and its affiliates, to

the extent necessary to maintain the percentage interest of the general partner and its affiliates, including such interest represented by common units, subordinated units and other partnership interests that existed immediately prior to each issuance. The other holders of common units will not have preemptive rights to acquire additional common units or other partnership interests. Please read “Units Eligible for Future Sale” and “Our Partnership Agreement—Issuance of Additional Partnership 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 initially, on an annual or other continuing basis. Our general partner may not be removed unless such removal is both (i) for cause and (ii) approved 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. Following the completion of this offering, our sponsor will own % 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 exercise in full their option to purchase additional common units) and AIMCo will own % of our total outstanding common units. As a result, our public unitholders will have limited ability to remove our general partner. Please read “Our 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 has 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 our common units over the 20 trading days preceding the date that is three business 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. Following the completion of this offering and assuming the underwriters’ option to purchase additional common units from us is not exercised, our general partner and its affiliates will own approximately % of our common units (excluding any common units purchased by the directors and executive officers of our general partner, directors of our sponsor and certain other individuals as selected by our sponsor under our directed unit program). At the end of the subordination period (which could occur as early as within the quarter ending , 2018), assuming no additional issuances of common units by us (other than upon the conversion of the subordinated units) and the underwriters’ option to purchase additional common units from us is not exercised, our general partner and its affiliates will own % of our outstanding common units (excluding any common units purchased by the directors and

executive officers of our general partner, directors of our sponsor and certain other individuals as selected by our sponsor under our directed unit program) and therefore would not be able to exercise the call right at that time. Please read “Our Partnership Agreement—Limited Call Right.”

Possible redemption of ineligible holders

The aggregate redemption price for redeemable interests will be an amount equal to the then-current market price (the date of determination of which will be the date fixed for redemption) of limited partner interests of the class to be so redeemed multiplied by the number of limited partner interests of each such class included among the redeemable interests. For these purposes, the “current market price” means, as of any date for any class of limited partner interests, the average of the daily closing prices per limited partner interest of such class for the 20 consecutive trading days immediately prior to such date. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. The units held by any person the general partner determines is not an eligible holder will not be entitled to voting rights.

Please read “Our Partnership Agreement—Possible Redemption of Ineligible Holders.”

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 , 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 Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Ratio of Taxable Income to Distributions.”

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 Federal Income Tax Consequences.”

Directed unit program

At our request, the underwriters have reserved for sale, at the initial public offering price, up to % of the common units being offered by this prospectus for sale to the directors, director nominee and executive officers of our general partner, directors of our sponsor and certain other individuals as selected by our sponsor. We do not know if these persons will choose to purchase all or any portion of these reserved common units, but any purchases they do make will reduce the number of common units available to the general public. Please read “Underwriting—Directed Unit Program.”

Exchange listing

We have been approved to list our common units on the NYSE under the symbol “HMP.”

Summary Historical and Pro Forma Financial Data

The following table presents summary historical financial data of our sponsor, which is our Predecessor for accounting purposes, and summary unaudited pro forma financial data of Howard Midstream Partners, LP for the periods and as of the dates indicated. The following summary historical financial data of our Predecessor consists of all of the assets and operations of our sponsor on a 100% basis. In connection with the closing of this offering, our sponsor will contribute to us a 100% interest in OpCo GP and a % limited partnership interest in OpCo, which will own substantially all of our sponsor’s current assets and operations. As required by GAAP, we will consolidate 100% of the assets and operations of OpCo in our financial statements for so long as we continue to have a controlling financial interest in OpCo.

The summary historical financial data of our Predecessor as of and for the years ended December 31, 2016 and 2015, and as of June 30, 2017 and for the six months ended June 30, 2017 and 2016, is derived from the audited and unaudited consolidated financial statements of our Predecessor appearing elsewhere in this prospectus. The following table should be read together with, and is qualified in its entirety by reference to, the historical audited, historical unaudited interim and unaudited pro forma consolidated financial statements and the accompanying notes included elsewhere in this prospectus. The table should also be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The summary unaudited pro forma financial data presented in the following table for the year ended December 31, 2016 and as of and for the six months ended June 30, 2017 is derived from the unaudited pro forma consolidated financial statements included elsewhere in this prospectus. The unaudited pro forma consolidated balance sheet assumes the offering and the related transactions occurred as of June 30, 2017, and the unaudited pro forma consolidated statements of operations for the year ended December 31, 2016 and for the six months ended June 30, 2017 assume the offering and the related transactions occurred as of January 1, 2016. These transactions include, and the unaudited pro forma consolidated financial statements give effect to, the following:

•

the contribution by our sponsor of certain of its operating subsidiaries to OpCo;

•

our sponsor’s contribution to us of a % limited partnership interest in OpCo;

•

our assumption of the outstanding balance of $ million under the term loan portion of our sponsor’s credit facility;

•

the consummation of this offering and our issuance of (i) common units to the public and (ii) common units and subordinated units to our sponsor;

•

the application of the net proceeds of this offering as described in “Use of Proceeds”;

•

our entry into a new $ million revolving credit facility; and

•

our entry into an omnibus agreement with our sponsor.

The unaudited pro forma consolidated financial statements do not give effect to an estimated $3.0 million in incremental general and administrative expenses that we expect to incur annually as a result of being a publicly traded partnership.

The following table presents the non-GAAP financial measures of Adjusted EBITDA and gross margin, which we use in our business as important supplemental measures of our performance. Adjusted EBITDA and gross margin are not calculated or presented in accordance with GAAP. For a definition of Adjusted EBITDA and gross margin and a reconciliation to their most directly comparable financial measures calculated in accordance with GAAP, please read “Selected Historical and Pro Forma Financial Data—Non-GAAP Financial Measures.”


	Predecessor Historical												Pro Forma
	Year Ended December 31,						Six Months Ended June 30,						Year Ended December 31, 2016			Six Months Ended June 30, 2017
	2016			2015			2017			2016			Year Ended December 31, 2016			Six Months Ended June 30, 2017
	(in thousands, except per unit data)
Statements of Operations Data
Total operating revenues	$	246,650		$	320,839		$	124,878		$	130,687		$	242,041		$	119,280
Operating costs and expenses:
Cost of products sold (excluding depreciation and amortization)		79,366			147,039			38,146			42,659			79,366			38,146
Operations and maintenance		45,325			42,184			22,536			23,072			41,704			19,545
Depreciation and amortization		58,549			45,226			30,428			28,680			55,203			28,228
General and administrative		31,483			36,160			25,698			15,415			25,076			8,488

Total operating costs and expenses		214,723			270,609			116,808			109,826			201,349			94,407

Operating income		31,927			50,230			8,070			20,861			40,692			24,873
Other income (expense):
Interest expense		(29,732	)		(22,204	)		(11,951	)		(16,416	)		(1,184	)		(584	)
Equity in earnings (loss) of unconsolidated affiliates		4,897			—			164			(162	)		—			—
Other income (expense)		896			2,401			1			722			(13	)		52

Income (loss) before income taxes		7,988			30,427			(3,716	)		5,005			39,495			24,341
State income taxes		255			99			143			247			255			128

Net income (loss)	$	7,733		$	30,328		$	(3,859	)	$	4,758		$	39,240		$	24,213

Net (loss) income attributable to noncontrolling interests		(1,924	)		(92	)		(257	)		(924	)

Net income (loss) attributable to controlling interests	$	9,657		$	30,420		$	(3,602	)	$	5,682		$			$

Net income per limited partner unit (basic and diluted)
Common units													$			$
Subordinated units													$			$
Balance sheet data (at period end)
Total property and equipment, net	$	866,607		$	867,834		$	883,820								$	754,334
Total assets		1,330,790			1,258,512			1,357,849									1,095,801
Long-term liabilities		486,290			768,048			508,424
Members’ equity		811,786			440,049			810,585
Statement of cash flows data
Net cash provided by operating activities	$	71,894		$	91,462		$	22,874		$	38,822
Net cash used in investing activities		(171,999	)		(628,416	)		(25,354	)		(71,044	)
Net cash provided by financing activities		83,805			518,420			8,987			22,409
Other data
Capital expenditures	$	93,160		$	108,022		$	31,544		$	71,191
Adjusted EBITDA⁽¹⁾		102,026			118,860			52,321			56,077		$	106,959		$	54,646
Adjusted EBITDA attributable to controlling interest⁽¹⁾		102,236			117,460			51,947			56,360
Gross margin⁽¹⁾		167,284			173,800			86,732			88,028			162,675			81,134

(1)	For Definitions of Adjusted EBITDA and gross margin and reconciliations to their most directly comparable financial measures calculated in accordance with GAAP, please read “Selected Historical and Pro Forma Financial Data—Non-GAAP Financial Measures.”

RISK FACTORS

Limited partner interests are inherently different from the 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 a similar business. You should carefully consider the following risk factors together with all of the other information included in this prospectus, including the matters addressed under “Forward-Looking Statements,” in evaluating an investment in our common units. If any of the following risks were to occur, our business, financial condition, results of operations, cash flows and ability to make cash distributions could be materially adversely affected. In any of those cases, we may not be able to pay the minimum quarterly distribution 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

We may not generate sufficient distributable cash flow to support the payment of the minimum quarterly distribution to our unitholders.

In order to support the payment of the minimum quarterly distribution of $ per unit per quarter, or $ per unit on an annualized basis, we must generate distributable cash flow of approximately $ million per quarter, or approximately $ million per year, based on the number of common units and subordinated units to be outstanding immediately after the completion of this offering. We may not generate sufficient distributable cash flow to support the payment of the minimum quarterly distribution to our unitholders.

The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

•

the volume of natural gas we gather, compress, process and dehydrate, the volume of condensate and NGLs we treat, store and terminal, the volumes of refined products we store and terminal and the fees we are paid for performing such services;

•

market prices of natural gas, NGLs, condensate and crude oil and their effect on our customers’ drilling and development plans on acreage where we provide gathering services and their effect on the volumes of hydrocarbons that are produced on such acreage and for which we provide midstream and terminalling services;

•

our customers’ ability to fund their drilling and development plans;

•

capital expenditures necessary for us to maintain and grow our liquids storage and terminalling business and build out our midstream systems to gather natural gas from new well completions on acreage where we provide gathering services;

•

the levels of our operating expenses, capital expenses, maintenance expenses and general and administrative expenses;

•

regulatory action affecting: (i) the supply of, or demand for, natural gas, NGLs and condensate, (ii) the terms upon which we are able to contract to provide our midstream services, (iii) our existing gathering, terminalling and other commercial agreements or (iv) our operating costs or our operating flexibility;

•

the rates we charge third parties for our midstream services;

•

prevailing economic conditions; and

•

adverse weather conditions.

In addition, the actual amount of distributable cash flow that we generate will also depend on other factors, some of which are beyond our control, including:

•

the level and timing of our capital expenditures;

•

our debt service requirements and other liabilities;

•

our ability to borrow under our debt agreements to fund our capital expenditures and operating expenditures and 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;

•

the fees and expenses of our general partner and its affiliates (including our sponsor) that we are required to reimburse;

•

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

•

other business risks affecting our cash levels.

The estimated Adjusted EBITDA and distributable cash flow discussion in “Cash Distribution Policy and Restrictions on Distributions” sets forth our forecasted Adjusted EBITDA and distributable cash flow for the twelve months ending September 30, 2018. Our ability to pay the full minimum quarterly distribution in the forecast period is based on a number of assumptions that may not prove to be correct and that are discussed in “Cash Distribution Policy and Restrictions on Distributions.” Our management has prepared the financial forecast and has neither requested nor received an opinion or report on it from our or any other independent auditor. The assumptions and estimates underlying the forecast are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks, including risks that expansion projects do not result in an increase in gathered, processed, transported and sold volumes, and uncertainties that could cause actual results to differ materially from those forecasted. If we do not achieve the forecasted results, we may not be able to pay the full minimum quarterly distribution or any amount on our common or subordinated units, in which event the market price of our common units may decline materially.

We are subject to risks due to frequent and often substantial fluctuations in commodity prices. In the past, the prices of natural gas, NGLs and other commodities have been extremely volatile, and we expect this volatility to continue. Our future cash flow may be materially adversely affected if commodity markets experience significant, prolonged pricing deterioration.

The markets for and prices of natural gas, NGLs and other commodities depend on factors that are beyond our control. These factors include the supply of and demand for these commodities, which fluctuate with changes in market and economic conditions and other factors, including:

•

the levels of domestic production and consumer demand;

•

the availability of transportation systems with adequate capacity;

•

the volatility and uncertainty of regional pricing differentials;

•

worldwide economic conditions;

•

worldwide political events, including actions taken by foreign oil and natural gas producing nations;

•

worldwide weather events and conditions, including natural disasters and seasonal changes;

•

the price and availability of alternative fuels;

•

the effect of energy conservation measures;

•

the nature and extent of governmental regulation (including environmental requirements) and taxation;

•

fluctuations in demand from electric power generators and industrial customers; and

•

the anticipated future prices of oil, natural gas, NGLs, condensate and other commodities.

Because of the natural decline in production from existing wells in our areas of operation, our success depends in part on producers replacing declining production and also on our ability to obtain new sources of natural gas. Any decrease in the volumes of natural gas, condensate or other products for which we provide midstream services 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 our 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 our systems, we must obtain production from new wells completed by our contracted customers or execute agreements with other third-party producers in our areas of operations. The primary factors affecting our ability to obtain new sources of natural gas include (i) the level of successful drilling activity in our 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 our customers’ or other producers’ levels of development and completion activity in our areas of operation, the amount of reserves associated with wells connected to our systems or the rate at which production from a well declines. In addition, we have no control over our customers’ exploration and development decisions, which may be affected by, among other things:

•

the availability and cost of capital;

•

prevailing and projected crude oil, natural gas and NGL prices;

•

demand for crude oil, natural gas and NGLs;

•

levels of reserves;

•

geological considerations;

•

environmental or other governmental regulations, including the availability of drilling permits and the regulation of hydraulic fracturing; and

•

the availability of drilling rigs and other costs of production and equipment.

Fluctuations in energy prices can also greatly affect the development of oil and natural gas reserves. Drilling and production activity generally decreases as crude oil and natural gas prices decrease. Declines in crude oil and 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 from present levels. Sustained reductions in exploration or production activity in our areas of operation could lead to reduced utilization of our assets.

Because of these and other factors, even if natural gas reserves are known to exist in areas served by our 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.

In addition, to the extent the acreage dedications supporting our midstream assets expire, we or our customers may be unable or unwilling to renew those dedications on similar terms, or at all, which will exacerbate any issues we encounter in connection with replacing declining production.

The following are material factors that could lead to a sustained decrease in market demand for refined products:

•

a sustained recession or other adverse economic conditions that result in lower purchases of refined petroleum products;

•

higher refined products prices due to an increase in the market price of crude oil, changes in economic conditions or other factors;

•

higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of gasoline or other refined products;

•

a shift by consumers to more fuel-efficient or alternative fuel vehicles or an increase in fuel economy, whether as a result of technological advances by manufacturers, pending legislation proposing to mandate higher fuel economy, or otherwise; and

•

a temporary or permanent material increase in the price of refined products as compared to alternative sources of refined products available to our customers.

If any or all of these factors were to occur, demand for the midstream services we provide with respect to refined products would decrease, which could materially and adversely affect our results of operations, financial position or cash flows.

We do not intend to obtain independent evaluations of natural gas reserves connected to our gathering and transportation systems on a regular or ongoing basis; therefore, in the future, volumes of natural gas on our systems could be less than we anticipate.

We do not intend to obtain independent evaluations of natural gas reserves connected to our systems on a regular or ongoing basis. Accordingly, we may not have independent estimates of total reserves dedicated to some or all of our systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our gathering and transportation systems are less than we anticipate and we are unable to secure additional sources of natural gas, it could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

Part of our strategy for growing our business and increasing distributions to our unitholders is dependent upon our ability to make acquisitions that increase our distributable cash flow. Part of the acquisition component of our growth strategy is based upon our expectation of future divestitures by our sponsor to us of retained assets or other acquired or developed midstream assets. Our sponsor has granted us a right of first refusal to acquire its retained % interest in OpCo, as well as its interests in the Port Arthur terminal, the Nueva Era pipeline, the EFG system expansion, the Corpus Christi terminal and, upon closing of the Catalyst joint venture, the Delaware Basin gathering and processing assets, to the extent our sponsor decides to sell such assets during the seven-year period following the completion of this offering. We are under no obligation to purchase any ROFR assets, and our sponsor is only under an obligation to permit us to match an offer on a ROFR asset to the extent that our sponsor decides to sell such ROFR asset to a third party. We may never purchase any interest in a ROFR asset or any other asset from our sponsor for several reasons, including the following:

•

our sponsor may choose not to sell the ROFR assets or any other asset;

•

our sponsor may be unable to commercially develop the ROFR assets;

•

our sponsor may choose not to obtain any necessary third party consents to offer the ROFR assets for sale;

•

we may not make acceptable offers for the ROFR assets;

•

we and our sponsor may be unable to agree to terms acceptable to both parties;

•

we may be unable to obtain financing to purchase these assets on acceptable terms or at all; or

•

we may be prohibited by the terms of our new revolving credit facility or other contracts from purchasing some or all of these assets, and our sponsor may be prohibited by the terms of its debt agreements or other contracts from selling some or all of these assets. If we or our sponsor must seek waivers of such provisions or refinance debt governed by such provisions in order to consummate a sale of these assets, we or our sponsor may be unable to do so in a timely manner or at all.

We do not know when or if our sponsor will elect to sell any ROFR assets, and we can provide no assurance that we will be able to successfully consummate any future acquisition of all or any portion of such ROFR assets. Furthermore, if our sponsor reduces its ownership interest in us, it may be less willing to sell ROFR assets to us. In addition, except for our ROFR, there are no restrictions on our sponsor’s ability to transfer its assets to a third party or non-controlled affiliate. If we do not acquire all or a significant portion of the ROFR assets or other midstream assets from our sponsor, our ability to grow our business and increase our cash distributions to our unitholders may be significantly limited.

If we are unable to make accretive acquisitions from third parties, whether because we are (i) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts, (ii) unable to obtain financing for these acquisitions on economically acceptable terms or (iii) outbid by competitors or for any other reason, 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;

•

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, particularly given the relatively small size of our management team and its limited history with our assets;

•

the assumption of unknown liabilities;

•

limitations on rights to indemnity from the seller;

•

mistaken assumptions about the overall costs of equity or debt;

•

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

•

unforeseen difficulties operating in new geographic areas and business lines; and

•

customer or key employee losses at the acquired businesses.

If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and our unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

If we acquire all or a portion of our sponsor’s interest in the Nueva Era pipeline or the EFG system expansion, we may be subject to additional risks associated with operations in Mexico and contracting with CFE, which could adversely affect our business and operating results.

If we acquire all or a portion of our sponsor’s interest in the Nueva Era pipeline or the EFG system expansion pursuant to our right of first refusal, we will have operations in Mexico that will be subject to a different regulatory framework and additional risks that may not be applicable to our domestic assets. These risks include fluctuations in foreign currency; exposure to changes in demand in northern Mexico; changes or differences in regulatory regimes and tax law; alterations in global economic conditions or foreign policy; risks associated with servicing the project finance debt supporting the development of the Nueva Era pipeline; and additional risks associated with further demands on the time and attention of our management team in identifying and responding to risks arising from operations in new markets.

Further, our interest in the Nueva Era pipeline and the EFG system expansion would be subject to a 25-year contract with CFE, an investment grade, sovereign utility of Mexico. As such, we would be subject to counterparty risks unique to the Mexican government, which may adopt policies or take actions, separate from any contractual rights they may have, that may, among other things, impact the value of our assets and business in Mexico and our ability to export into Mexico. If terminated, we may be unable to replace the contract on similar terms or at all. These additional risks associated with an interest in the Nueva Era pipeline and the EFG system expansion could adversely affect our business and operating results.

We have restated our financial statements and determined that there was a material weakness in our internal control over financial reporting. If another material weakness occurs or persists in the future or if we otherwise fail to develop or maintain an effective system of internal controls over financial reporting, we may not be able to report our financial results accurately and timely or prevent fraud, which would likely have a negative impact on the market price of our common units.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with GAAP. Under standards established by the PCAOB, a deficiency in internal control over financial reporting exists when the design or operation of a control does not allow management or personnel, in the normal course of performing their assigned functions, to prevent or detect misstatements on a timely basis. The PCAOB defines a material weakness as a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of annual or interim financial statements will not be prevented, or detected and corrected, on a timely basis.

During the preparation of our financial statements for the years ended December 31, 2015 and 2016, we identified a material weakness in our internal control over financial reporting. The material weakness related to improper application of GAAP over non-routine transactions which resulted in a restatement of our December 31, 2015 financial statements. We have implemented measures designed to improve our internal control over financial reporting to address the underlying causes of the material weakness by hiring additional accounting professionals with GAAP and SEC reporting experience. Our remediation efforts may not enable us to remedy or avoid material weaknesses in the future.

Our independent registered public accounting firm was not required to, and did not, perform an evaluation of our internal control over financial reporting as of December 31, 2016 in accordance with the provisions of the Sarbanes-Oxley Act of 2002, as amended, and the regulations promulgated thereunder (the “Sarbanes-Oxley Act”). Accordingly, we cannot assure you that we have identified all, or that we will not in the future have additional, material weaknesses. A material weakness may still exist when we report on the effectiveness of our internal control over financial reporting as required by Section 404 of the Sarbanes-Oxley Act after the completion of this offering.

Additional material weaknesses may be identified in the future. If we identify such issues or if we are unable to produce accurate and timely financial statements, the trading price of our common units may decline and we may be unable to maintain compliance with the NYSE listing standards.

Our contracts are subject to renewal risks.

We contract with our customers for natural gas and NGL gathering and processing and refined product storage and terminalling services on our assets under contracts with terms of various durations. As these contracts expire, we will have to negotiate extensions or renewals with existing suppliers and customers or enter into new contracts with other suppliers and customers. We may not be able to obtain new contracts on favorable commercial terms or at all. We also may be unable to maintain the economic structure of a particular contract with an existing customer or maintain the overall mix of our contract portfolio. Our inability to renew existing contracts on favorable terms or to successfully manage our overall contract mix over time may have a material adverse effect on our business, results of operations and financial condition.

Contracts with customers are subject to additional risk in the event of a bankruptcy proceeding.

To the extent any of our customers is in financial distress or commences bankruptcy proceedings, our contracts with them, including provisions relating to dedications of production, may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. If a contract with a customer is altered or rejected in bankruptcy proceedings, we could lose some or all of the expected revenues associated with that contract, which could cause the market price of our common units to decline.

Certain of our gathering and processing agreements contain provisions that can reduce the cash flow stability that the agreements were designed to achieve.

Our fee-based gathering and processing agreements are generally designed to generate stable cash flows to us over the life of the contract term while also minimizing our direct commodity price risk. However, some of our gathering and processing agreements contain provisions that can reduce the cash flow stability that these agreements were designed to achieve. The primary mechanism on which we rely to generate our stable cash flows under these agreements is a minimum volume commitment. If a customer’s actual throughput volumes are less than its minimum volume commitment for the applicable period, it must make a deficiency payment to us at the end of that contract month, or year, as applicable. The amount of the deficiency payment is based on the difference between the actual throughput volume shipped and the minimum volume commitment for the applicable period, multiplied by the applicable gathering and processing fees. To the extent that a customer’s actual throughput volumes are above or below its minimum volume commitment for the applicable period, many of the agreements contain provisions to reduce or delay these deficiency payments. Because some of these contracts contain a crediting mechanism that allows the customer to build a “bank” of credits that it can utilize to reduce deficiency payments owed in subsequent periods or under separate agreements with the same customer, we may receive lower gathering and processing fees in a particular contract year than we would otherwise be entitled to receive under a customer’s minimum volume commitment. As of June 30, 2017, our customers had no aggregate historical excess revenue on our northeast gathering system.

The combined effect of the minimum volume commitment and the ability to build a surplus credit could result in our receiving no revenues or cash flows from such customers in a future period because these customers could cease delivering throughput volumes at a time when their respective minimum volume commitments for the applicable period have been satisfied with previous throughput volume deliveries. If this circumstance were to occur, it could materially and adversely affect our gross margin, business, financial condition, results of operations, cash flows and ability to make cash distributions.

If credits under certain third-party gathering and processing agreements exist, and cash reserves are not made for potential application of the credits to deficiencies on future minimum commitments, or if the customer is able and elects to use any applicable credits upon the expiration or termination of such agreement, actions taken by our general partner may affect the amount of cash available to unitholders or accelerate the conversion of subordinated units.

The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner. These decisions may include whether cash received in connection with surplus volumes above minimum volume commitments with significant third-party customers may result in lower fees, and therefore less cash received, in future periods as credits are applied against future minimum volume commitments. Please read “—Certain of our gathering and processing agreements contain provisions that can reduce the cash flow stability that the agreements were designed to achieve.”

Distributions of available cash relating to surplus volumes in earlier periods may have the purpose or effect of (1) enabling our general partner or its affiliates to receive distributions on either subordinated units or incentive distribution rights held by them, or (2) accelerating the conversion of subordinated units. Please read “Conflicts of Interest and Duties—Conflicts of Interest—Actions taken by our general partner may affect the amount of cash available for distribution to unitholders or accelerate the right to convert subordinated units.”

If third-party pipelines or other midstream facilities interconnected to our gathering systems and terminalling facilities become partially or fully unavailable, our gross margin, cash flow and ability to make cash distributions to our unitholders could be adversely affected.

Our assets connect to other pipelines or facilities owned and operated by unaffiliated third parties. The continuing operation of third-party pipelines, processing and fractionation plants, compressor stations and other midstream facilities is not within our control. These third-party pipelines, processing and fractionation plants, compressor stations and other midstream facilities may become unavailable because of testing, turnarounds, line repair, maintenance, reduced operating pressure, lack of operating capacity, force majeure events, 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 becomes unable to receive or transport natural gas, our gross margin, cash flow and ability to make cash distributions to our unitholders could be adversely affected.

We cannot predict the rate at which our customers will develop acreage that is dedicated to us or the areas they will decide to develop.

Our acreage dedication and commitments from our customers cover midstream services in a number of areas that are at the early stages of development, in areas that our customers are still determining whether to develop, and in areas where we may have to construct pipeline laterals or acquire operating assets from third parties to connect our gathering systems to pad sites located within the acreage dedications. We cannot predict which of these areas our customers will develop and at what time. Our customers may decide to explore and develop areas in which the acreage is not dedicated to us. Our customers’ decision to develop acreage that is not dedicated to us or in which we have a smaller operating interest may adversely affect our business, financial condition, results of operations, cash flows and ability to make cash distributions.

To maintain and grow our business, we will be required to make substantial capital expenditures. If we are unable to obtain needed capital or financing on satisfactory terms, our ability to make cash distributions may be diminished or our financial leverage could increase.

In order to maintain and grow our business, we will need to make substantial capital expenditures to fund our share of maintenance and growth capital expenditures, to purchase or construct new midstream systems, or to fulfill our commitments to service acreage committed to us by our customers. If we do not make sufficient or

effective capital expenditures, we will be unable to maintain and grow our business and, as a result, we may be unable to maintain or raise the level of our future cash distributions. To fund our capital expenditures, we will be required to use cash from our operations, incur debt or sell additional common units or other equity securities. Using cash from our operations will reduce cash available for distribution to our unitholders. Our ability to obtain bank financing or our ability to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering and the covenants in our existing debt agreements, as well as by general economic conditions, contingencies and uncertainties that are beyond our control. Also, due to our relationship with our sponsor, our ability to access the capital markets, or the pricing or other terms of any capital markets transactions, may be adversely affected by any impairment to the financial condition of our sponsor. Any material limitation on our ability to access capital as a result of such adverse changes to our sponsor could limit our ability to obtain future financing under favorable terms, or at all, or could result in increased financing costs in the future. Similarly, material adverse changes affecting our sponsor could negatively impact our unit price, limiting our ability to raise capital through equity issuances or debt financing, or could negatively affect our ability to engage in, expand or pursue our business activities, or could also prevent us from engaging in certain transactions that might otherwise be considered beneficial to us. We will also rely on our sponsor to make its portion of capital expenditures on our assets, and to the extent that our sponsor is unable or unwilling to make these capital expenditures, we may not be able to grow at our expected rate or at all.

Even if we are successful in obtaining the necessary funds to support our growth plan, the terms of such financings could limit our ability to pay distributions to our unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional limited partner interests may result in significant unitholder dilution and would increase the aggregate amount of cash required to maintain the then-current distribution rate, which could materially decrease our ability to pay distributions at the then-prevailing distribution rate. While our Predecessor has been historically funded by its operations and capital contributions from its investors, none of our sponsor, our general partner or any of their respective affiliates has a binding obligation to provide any direct financial support to fund our growth.

We rely on gathering and processing revenues generated by assets that are currently located in South Texas and in Northeastern Pennsylvania. As a result of this concentration, we will be exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, market limitations, water shortages or other drought related conditions or interruption of the processing or transportation of natural gas, NGLs or condensate. If any of these factors were to impact our areas of operation more than other producing regions, our business, financial condition, results of operations and ability to make cash distributions will be adversely affected relative to other midstream companies that have a more geographically diversified asset portfolio.

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

We compete with other midstream companies in our areas of operation. Some of our competitors are large companies that have greater financial, managerial and other resources than we do. In addition, some of our competitors have assets in closer proximity to natural gas supplies and have available idle capacity in existing assets that would not require new capital investments for use. Our competitors may expand or construct gathering, compression, treating, processing or transportation systems or terminal facilities that would create additional competition for the services we provide to our customers. In addition, our customers may develop their own gathering, compression, treating, processing or transportation systems or terminal facilities in lieu of using ours. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenue and cash flow 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 ability to make cash distributions to our unitholders.

We depend on a relatively limited number of customers for a significant portion of our revenues. The loss of, or material nonpayment or nonperformance by, any one or more of these customers could adversely affect our ability to make cash distributions to you.

A significant percentage of our revenue is attributable to a relatively limited number of customers. Our top ten customers collectively accounted for approximately 82% and 84% of our revenue for the year ended December 31, 2016 and the six months ended June 30, 2017, respectively. We have gathering, processing, natural gas sales and/or transmission contracts with each of these customers of varying duration and commercial terms. If we were unable to renew our contracts with one or more of these customers on favorable terms, we may not be able to replace any of these customers in a timely fashion, on favorable terms or at all. Three customers, Southwestern Energy Company (“Southwestern Energy”), EnLink and MGI Supply, Ltd., accounted for approximately 26%, 14% and 10% of our revenue, respectively, for the year ended December 31, 2016. In addition, three customers, Southwestern Energy, EnLink and Swift Energy Company, accounted for approximately 24%, 16% and 10% of our revenue, respectively, for the six months ended June 30, 2017. Some of our customers may have material financial and liquidity issues that could have a significant effect on their creditworthiness or may, as a result of operational incidents or other events, be disproportionately affected as compared to larger, better-capitalized companies. Severe financial problems encountered by our customers could limit our ability to collect amounts owed to us or to enforce performance of obligations under contractual arrangements. Any material nonpayment or nonperformance by any of our key customers could have a material adverse effect on our revenue, gross margin and cash flows and our ability to make cash distributions to our unitholders. 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 limited number of customers for a substantial portion of our revenue.

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.

Our operations are subject to all of the hazards inherent in the gathering and compression of natural gas and storage and terminalling of refined products, including:

•

damage to pipelines, compressor stations, storage tanks, loading racks, pump stations, related equipment and surrounding properties caused by design, installation, construction materials or operational flaws, natural disasters, acts of terrorism and acts of third parties;

•

leaks or losses of natural gas, condensate or refined product as a result of the malfunction of, or other disruptions associated with, equipment or facilities;

•

fires, ruptures, landslides, mine subsidence and explosions; and

•

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

Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:

•

injury or loss of life;

•

damage to and destruction of property, natural resources and equipment;

•

pollution and other environmental damage;

•

regulatory investigations and penalties;

•

suspension of our operations; and

•

repair and remediation costs.

We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to make cash distributions.

Our exposure to direct commodity price risk may vary over time.

We generate the substantial majority of our revenues under fee-based contracts and fixed-margin arrangements under which we are paid based on the volumes of natural gas that we gather, process, treat, compress and transport, rather than the value of the underlying natural gas or NGLs. Consequently, the majority of our existing operations and cash flows have limited direct exposure to commodity price risk. Although we intend to enter into similar contracts and arrangements with new customers in the future, our efforts to obtain such contractual terms may not be successful. In addition, we may acquire or develop additional midstream assets or change the arrangements under which we gather, process, sell, terminal or store our customer’s volumes, in either case, in a manner that increases our exposure to commodity price risk. Future increases in direct exposure to the volatility of oil and natural gas prices could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

We may not successfully balance our purchases and sales of natural gas and other hydrocarbons, which would increase our exposure to commodity price risks.

We purchase from producers and other suppliers a portion of the natural gas that flows through our pipelines and processing facilities for sale to third parties, including natural gas marketers and other purchasers. We are exposed to fluctuations in the price of natural gas through volumes sold pursuant to percent-of-proceeds arrangements and, to a lesser extent, through volumes sold pursuant to our fixed-margin arrangements.

In order to mitigate our direct commodity price exposure, we typically do not enter into natural gas hedge contracts, but rather attempt to balance our natural gas sales with our natural gas purchases on an aggregate basis across all of our systems. We may not be successful in balancing our purchases and sales, and as such may become exposed to fluctuations in the price of natural gas. For example, we are currently net purchasers of natural gas on certain of our systems and net sellers of natural gas on certain of our other systems. Our overall net position with respect to natural gas can change over time and our exposure to fluctuations in natural gas prices could materially increase, which in turn could result in increased volatility in our revenue, gross margin and cash flows.

Although we enter into back-to-back purchases and sales of natural gas in our fixed-margin arrangements in which we purchase natural gas from producers or suppliers at receipt points on our systems and simultaneously sell an identical volume of natural gas at delivery points on our systems, we may not be able to mitigate all exposure to commodity price risks. For example, the volumes or timing of our purchases and sales may not correspond. In addition, a producer or supplier could fail to deliver contracted volumes or deliver in excess of contracted volumes, or a purchaser could purchase less than contracted volumes. Any of these actions could cause our purchases and sales to become unbalanced. If our purchases and sales are unbalanced, we will face increased exposure to commodity price risks, which in turn could result in increased volatility in our revenue, gross margin and cash flows.

Our construction of new midstream assets may not result in revenue increases and may be subject to regulatory, environmental, political, legal and economic 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 our existing systems involves numerous regulatory, environmental, political and legal uncertainties beyond our control and may require the expenditure of significant

amounts of capital. Financing may not be available on economically acceptable terms or at all. If we undertake these projects, we may not be able to complete them on schedule, at the budgeted cost or at all.

Our revenues may not increase immediately, or at all, upon the expenditure of funds on a particular project. For instance, if we build a processing facility, the construction may occur over an extended period of time, and we may not receive any material increases in revenues until the project is completed. Additionally, we may construct facilities to capture anticipated future production growth in an area in which such growth does not materialize. As a result, new gathering, compression, dehydration, treating or other midstream assets may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our business, financial condition, results of operations, cash flows and ability to make cash distributions.

The construction of additions to our existing assets may require us to obtain permits or new rights-of-way prior to constructing new pipelines or facilities. We may be unable to timely obtain such permits or rights-of-way to connect new natural gas supplies to our existing gathering pipelines or capitalize on other attractive expansion 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. Moreover, the issuance of new permits for our construction activities could be subject to legal challenges from third parties, which could result in delays and adversely affect our operations.

As our only initial asset is our controlling ownership interest in OpCo, our cash flow will initially depend entirely on the performance of OpCo and its ability to distribute cash to us.

We have a holding company structure, meaning the sole source of our initial earnings and cash flow is the earnings of and cash distributions from OpCo. Therefore, our ability to make quarterly distributions to our unitholders initially will be completely dependent upon the performance of OpCo, its subsidiaries and their ability to distribute funds to us. We are the sole member of the general partner of OpCo, and we control and manage OpCo through our ownership of OpCo’s general partner.

The limited partnership agreement governing OpCo requires that the general partner of such OpCo cause OpCo to distribute all of its available cash each quarter, less the amounts of cash reserves that the general partner determines are necessary or appropriate in its reasonable discretion to provide for the proper conduct of OpCo’s business.

The amount of cash OpCo and its subsidiaries generate from their respective operations will fluctuate from quarter to quarter based on events and circumstances, and the actual amount of cash they will have available for distribution to their partners, including us, also will depend on certain factors. For a description of the events, circumstances and factors that may affect the cash distributions from OpCo please read “—We may not generate sufficient distributable cash flow to support the payment of the minimum quarterly distribution to our unitholders.”

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

We expect to enter into a new revolving credit facility prior to or in connection with the closing of this offering. Our new revolving credit facility will limit our ability to, among other things:

•

incur certain liens or permit them to exist;

•

transfer, sell or otherwise dispose of certain assets;

•

merge or consolidate with another company;

•

make certain loans and investments;

•

incur or guarantee additional debt;

•

enter into certain types of transactions with affiliates;

•

redeem or repurchase units or make distributions under certain circumstances;

•

make certain changes to our business, our accounting practices and our organizational documents; and

•

enter into certain restrictive agreements and certain derivative contracts.

Our new revolving credit facility will also 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 assure you that we will meet any such ratios and tests.

The provisions of our new revolving credit facility may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, our obligations under our new credit facility will be secured by substantially all of our assets. A failure to comply with the provisions of our new revolving credit facility could result in a default or an event of default that could enable our lenders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of our debt is accelerated and we do not have sufficient cash available to repay such indebtedness, the lenders could foreclose on their security interests and liquidate some or all of our assets to repay the outstanding principal and interest, and our unitholders could experience a partial or total loss of their investment. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

Our businesses and results of operations are subject to seasonal fluctuations, which could result in fluctuations in our operating results and common unit price.

Our business is subject to seasonal fluctuations. Demand for natural gas generally decreases during the spring and fall months and increases during the summer and winter months. Severe or prolonged winters may, however, impact our ability to complete additional well connections or complete construction projects, particularly in our Northeastern Pennsylvania operations, which may impact the rate of our growth. Severe winter weather may also impact or slow the ability of our customers to execute their planned drilling and development plans. In addition, the volumes of condensate produced at our Live Oak stabilizer fluctuate seasonally, with volumes generally increasing in the winter months and decreasing in the summer months as a result of the physical properties of natural gas and comingled liquids. Severe or prolonged summers may adversely affect our results of operations at our Live Oak stabilizer.

Our gathering systems are subject to state regulation that could have a material adverse effect on our operations and cash flows.

State regulation of our gathering systems includes various safety, environmental and, in some circumstances, nondiscriminatory take and common purchaser requirements, as well as complaint-based rate regulation. Other state regulations may not directly apply to our business, but may nonetheless affect the availability of natural gas for purchase, compression and sale. If regulatory agencies in the states in which we offer gathering or intrastate transportation services change their policies or alter our rates or terms and conditions of service, it could also adversely affect our business, financial condition, results of operations, cash flows and ability to make cash distributions.

A change in the use or jurisdictional characterization or regulation 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 materially and adversely affect our business, financial condition, results of operations, cash flows and ability to make cash distributions.

We believe our gathering and transportation operations are exempt from regulation by FERC, under the Natural Gas Act of 1938 (the “NGA”), and are not subject to regulation under the Interstate Commerce Act (the

“ICA”). Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC under the NGA, and the ICA only governs liquids transportation service in interstate commerce. Although FERC has not made any formal determinations with respect to any of our facilities we consider to be gathering facilities, we believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish that a natural gas pipeline is a gathering pipeline not subject to FERC or NGA jurisdiction. We believe that our NGL pipeline does not provide transportation service in interstate commerce subject to FERC ICA jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and over time FERC’s policy for determining which facilities it regulates has changed. In addition, FERC determines whether facilities are gathering facilities or provide interstate transportation service on a case-by-case basis, so the classification and regulation of our gathering facilities may be subject to change based on changes in use or future determinations by FERC, the courts, or Congress. If FERC were to consider the status of an individual facility or service and determine that any of our facilities or services are subject to FERC regulation, the rates for, and terms and conditions of, services provided by us would be subject to modification by the FERC under the NGA, the Natural Gas Policy Act of 1978 (the “NGPA”) or the ICA. Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our business, financial condition, results of operations, cash flows and ability to make cash distributions.

Other FERC regulations may indirectly affect our businesses and the markets for products derived from these businesses. FERC’s policies and practices across the range of its regulatory activities, including, for example, its policies on open access transportation, priority of service, market manipulation, ratemaking, quality standards, capacity release and capacity use, may indirectly affect the intrastate natural gas market. Should we fail to comply with any applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines, which could have a material adverse effect on our results of operations and cash flows. For more information regarding federal and state regulation of our operations, please read “Business—Regulation of Operations.”

Failure to comply with applicable market behavior rules, regulations and orders could subject us to substantial penalties and fines.

In August 2005, Congress enacted the Energy Policy Act of 2005 (the “EPAct 2005”). Among other matters, the EPAct 2005 amended the NGA to add an anti-manipulation provision that makes it unlawful for “any entity” to engage in prohibited behavior in contravention of rules and regulation to be prescribed by FERC and, furthermore, provides FERC with additional civil penalty authority. In January 2006, FERC issued Order No. 670, a rule implementing the anti-manipulation provisions of the EPAct 2005. The rules make it unlawful for any entity, directly or indirectly in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC or the purchase or sale of transportation services subject to the jurisdiction of FERC, to (1) use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. Such anti-manipulation rules apply to interstate gas pipelines and storage companies and intrastate gas pipelines and storage companies that provide interstate services, such as NGPA Section 311 service, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction. The anti-manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering to the extent such transactions do not have a “nexus” to jurisdictional transactions. The EPAct 2005 also amended the NGA and the NGPA to give FERC authority to impose civil penalties for violations of these statutes and FERC’s regulations, rules, and orders, up to $1,000,000 per violation per day for violations occurring after August 8, 2005. In January 2017, FERC increased that maximum penalty to $1,213,503 per violation per day to account for inflation. In connection with this enhanced civil penalty authority, FERC issued a revised policy statement on enforcement to provide guidance regarding the enforcement of the statutes, orders, rules and regulations it administers, including factors to be considered in determining the appropriate enforcement action to be taken. In addition, the Commodities Futures Trading Commission (the “CFTC”) is directed under the

Commodities Exchange Act (the “CEA”) to prevent price manipulations for the commodity and futures markets, including the energy futures markets. Pursuant to the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) and other authority, the CFTC has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets. The CFTC also has statutory authority to seek civil penalties of up to the greater of $1,116,156 or triple the monetary gain to the violator for violations of the anti-market manipulation sections of the CEA. Should we fail to comply with all applicable FERC, CFTC, or other statutes, rules, regulations and orders governing market behavior, we could be subject to substantial penalties and fines.

We may incur significant costs and liabilities as a result of pipeline and related facility integrity management programs and any related pipeline repair or preventative or remedial measures.

The Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a series of rules and regulations requiring pipeline operators to develop integrity management programs for natural gas transmission and hazardous liquid pipelines and related facilities located where a leak or rupture could do the most harm, i.e., in high consequence areas (“HCAs”). The regulations require operators of covered pipeline and facilities to:

•

perform ongoing assessments of pipeline and related facility integrity;

•

identify and characterize applicable threats to pipeline segments that could impact an HCA;

•

improve data collection, integration and analysis;

•

repair and remediate the pipeline as necessary; and

•

implement preventive and mitigating actions.

In addition, certain states have adopted regulations similar to existing PHMSA regulations for intrastate gathering and transmission lines. These regulations 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 require us to incur increased operating costs that could be significant and have a material adverse effect on our results of operations or financial position.

The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (the “2011 Pipeline Safety Act”) among other things, increased the maximum civil penalty for pipeline safety violations and 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 and testing to confirm the material strength of pipe operating above 30% of specified minimum yield strength in HCAs. Should our operations fail to comply with PHMSA or comparable state regulations, we could be subject to substantial penalties and fines. Effective April 27, 2017, the maximum civil penalties PHMSA can impose are $209,002 per violation per day, with a maximum of $2,090,022 for a related series of violations.

In August 2011, PHMSA published an advanced notice of proposed rulemaking to solicit comments on the need for changes to its safety regulations, including whether to extend the integrity management program requirements to additional types of facilities, such as gathering pipelines and related facilities. Additionally, in 2012, PHMSA issued an advisory bulletin providing guidance on the verification of records related to pipeline maximum allowable operating pressure, which could result in additional requirements for the pressure testing of pipelines or the reduction of maximum operating pressures to verifiable pressures. In April 2016, pursuant to one of the requirements in the 2011 Pipeline Safety Act, PHMSA published a proposed rulemaking that would expand integrity management requirements and impose new pressure testing requirements on currently regulated gas gathering and transmission pipelines. The proposal would also significantly expand the regulation of gas gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, maximum allowance operating pressure limits, and other

requirements. More recently, in January 2017, PHMSA finalized new regulations for hazardous liquid pipelines that significantly extend and expand the reach of certain PHMSA integrity management requirements (i.e., periodic assessments, repairs and leak detection), regardless of the pipeline’s proximity to an HCA. The final rule also requires all pipelines in or affecting an HCA to be capable of accommodating in-line inspection tools within the next 20 years. In addition, the final rule extends annual and accident reporting requirements to gravity lines and all gathering lines and also imposes inspection requirements on pipelines in areas affected by extreme weather events and natural disasters, such as hurricanes, landslides, floods, earthquakes, or other similar events that are likely to damage infrastructure. The timing for implementation of this rule is uncertain at this time due to the recent change in Presidential Administrations.

Additional future regulatory action expanding PHMSA jurisdiction and imposing stricter integrity management requirements is likely. In June 2016, the President signed into law new legislation entitled Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (the “PIPES Act”). The PIPES Act reauthorizes PHMSA through 2019, and grants PHMSA authority to issue emergency orders, including authority to issue prohibitions and safety measures on owners and operators of natural gas or hazardous liquid pipeline facilities to address imminent hazards, without prior notice or an opportunity for a hearing. In addition, the PIPES Act requires enhanced release reporting requirements, requiring a review of both natural gas and hazardous liquid integrity management programs, and mandating the creation of a working group to consider the development of an information-sharing system related to integrity risk analyses. The PIPES Act also requires that PHMSA publish periodic updates on the status of those mandates outstanding from 2011 Pipeline Safety Act, of which approximately half remain to be completed. The adoption of these and other laws or regulations that apply more comprehensive or stringent safety standards could require us to install new or modified safety controls, pursue new capital projects, or conduct maintenance programs on an accelerated basis, all of which could require us to incur increased operational costs that could be significant. While we cannot predict the outcome of legislative or regulatory initiatives, such legislative and regulatory changes could have a material effect on our cash flow. Please read “Business—Regulation of Operations—Pipeline Regulation.”

Our business could be adversely affected by the adoption of more stringent regulations regarding the transportation of hydrocarbons by rail.

As a result of hydraulic fracturing and other improvements in extraction technologies, there has been a substantial increase in the volume of crude oil and liquid hydrocarbons produced and transported in North America, and a geographic shift in that production versus historical production. The increase in volume and shift in geography resulted in a growing percentage of hydrocarbons being transported by rail. High profile accidents in Quebec, North Dakota and Virginia in July 2013, December 2013 and April 2014, respectively (all involving trains carrying crude oil), have raised concerns about the environmental and safety risks associated with crude oil transport by rail and the associated risks arising from railcar design.

Although there has been no legislative response to the accidents referenced above, there has been increased pressure on lawmakers to update rail safety standards, including design standards for railcars. On May 1, 2015, PHMSA, in consultation with the Federal Railroad Administration (the “FRA”), adopted a final rule that, among other things, applies enhanced tank car standards to certain trains carrying flammable liquids, including crude oil and ethanol. The rule requires tank cars carrying flammable liquids to have a 9/16 inch tank shell, 11 gauge jacket, half inch full height head shield, thermal protection, and improved pressure relief devices and bottom outlet valves. Existing tank cars must be retrofitted with most of the same criteria based on a prescriptive retrofit schedule. Older legacy DOT Specification 111 tank cars must be phased out by as early as January 2018 if they are not retrofitted to comply with the new standards. The final rule also imposes a number of operational requirements affecting the rail transportation of flammable liquids, including certain speed restrictions, enhanced braking systems, and new sampling and testing requirements. In addition, the FRA and PHMSA have issued a series of safety advisories and emergency orders to address safety issues related to trains carrying flammable liquids. The FRA also published a final rule in July 2015, which imposes new standards on railroads to properly secure rolling equipment. On August 10, 2016, PHMSA, in coordination with the FRA, announced a final rule

codifying certain requirements of the Fixing America’s Surface Transportation Act of 2015 (the “FAST Act”), thereby building upon the May 2015 rule and expanding the requirements to use the enhanced tank car for shipping all flammable liquids, regardless of the length of the train. The rule also requires that new tank cars be equipped with a thermal protection blanket and that older tank cars retrofitted to the new standard be equipped with top fittings protection and a thermal protection blanket. The FAST Act also requires a modified phase-out schedule for older DOT Specification 111 tank cars, such that older tank cars are phased out faster regarding highly flammable, unrefined petroleum products that require a certain level of packaging protection. In addition, in July 2016, PHMSA proposed a new rule that would expand the applicability of comprehensive oil spill response plans so that any railroad that transports a single train carrying 20 or more loaded tank cars of liquid petroleum oil in a continuous block or a single train carrying 35 or more loaded tank cars of liquid petroleum oil throughout the train must have a current, comprehensive, written plan. More recently, in response to a petition from the New York Attorney General, PHMSA issued an advance notice of proposed rulemaking in January 2017 stating that it is considering revising the Hazardous Materials Regulations to establish vapor pressure limits for unrefined petroleum-based products and potentially all Class 3 flammable liquid hazardous materials that would apply during the transportation of the products or materials by any mode. In addition, in February 2016, the FRA modified its accident and incident reports to gather additional data concerning rail cars carrying crude oil in any train involved in a FRA-reportable accident. A number of states have also proposed or enacted laws in recent years that encourage safer rail operations or urge the federal government to strengthen requirements for these operations.

We do not anticipate the May 2015 tank car rule and the August 2016 rule to materially adversely affect our operations. However, the adoption of additional federal, state, provincial or local laws or regulations, including any voluntary measures by the rail industry regarding railcar design or crude oil and liquid hydrocarbon rail transport activities, or efforts by local communities to restrict or limit rail traffic involving hydrocarbons could materially affect our business, financial condition or results of operations by decreasing demand for our services.

Increased regulation of hydraulic fracturing could result in reductions or delays in natural gas, NGL and crude oil production by our customers, which could reduce the throughput on our gathering and other midstream systems, which could adversely impact our revenues.

We do not conduct hydraulic fracturing operations, but substantially all of our customers’ natural gas production is developed from unconventional sources, such as shales, that require hydraulic fracturing as part of the completion process. Hydraulic fracturing is a well-stimulation process that utilizes large volumes of water and sand combined with fracturing chemical additives that are pumped at high pressure to crack open previously impenetrable rock to release hydrocarbons. Hydraulic fracturing is typically regulated by state oil and gas commissions and similar agencies. Some states, including those in which we operate, have adopted, and other states are considering adopting, regulations that could impose more stringent disclosure and well construction requirements on hydraulic fracturing operations, or otherwise seek to ban some or all of these activities. For example, Pennsylvania, where our northeast gathering operations are located, has expanded environmental agency oversight of hydraulic fracturing operations in new regulations that took effect October 2016. Further, the U.S. Environmental Protection Agency (the “EPA”) has asserted certain regulatory authority over hydraulic fracturing and has moved forward with various regulatory actions, including the issuance of new regulations requiring green completions for hydraulically fractured wells and emission requirements for certain midstream equipment. In addition, the EPA and other federal agencies have conducted various studies concerning the potential environmental impacts of hydraulic fracturing activities. Certain environmental groups have also suggested that additional laws may be needed 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. We cannot predict whether any such legislation will be enacted and if so, what its provisions would be. Additional levels of regulation and permits required through the adoption of new laws and regulations at the federal, state or local level could lead to delays, increased operating costs and process prohibitions that could reduce the volumes of natural gas and liquids that move through our gathering systems, which in turn could

materially adversely affect our business, financial condition, results of operations, cash flows and ability to make cash distributions.

We or any third-party customers may incur significant liability under, or costs and expenditures to comply with, environmental and worker health and safety regulations, which are complex and subject to frequent change.

As an owner and operator of gathering and compressing systems and terminals, we are subject to various stringent federal, state and local laws and regulations relating to the discharge of materials into, and protection of, the environment and worker health and safety. 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, oftentimes requiring difficult and costly response actions. These laws and regulations may impose numerous obligations that are applicable to our and our customers’ operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from our or our customers’ operations, the imposition of specific standards addressing worker protection, and the imposition of substantial liabilities and remedial obligations for pollution or contamination resulting from our and our customer’s operations. Our failure to comply with these laws, regulations and permits may result in joint and several or strict liability or the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and/or the issuance of injunctions limiting or preventing some or all of our operations. Private parties, including the owners of the properties through which our gathering systems pass, may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for non-compliance, with environmental laws and regulations or for remediation costs, personal injury or property damage. We may not be able to recover all or any of these costs from insurance. In addition, we may experience a delay in obtaining or be unable to obtain required permits, which may cause us to lose potential and current customers, interrupt our operations and limit our growth and revenues, which in turn could affect our business, financial condition, results of operations, cash flows and ability to make cash distributions. There is no assurance that changes in or additions to public policy regarding the protection of the environment and worker health and safety will not have a significant impact on our operations and cash available for distribution.

Our operations also pose risks of environmental liability due to leakage, migration, releases or spills from our operations to surface or subsurface soils, surface water or groundwater. Certain environmental laws impose strict as well as joint and several liability for costs required to remediate and restore sites where hazardous substances, hydrocarbons or solid wastes have been stored or released. We may be required to remediate contaminated properties currently or formerly owned or operated by us regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, potentially resulting in increased costs of doing business and consequently affecting our business, financial condition, results of operations, cash flows and ability to make cash distributions. Please read “Business—Regulation of Operations—Regulation of Environmental and Occupational Safety and Health Matters.”

Climate change laws and regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the natural gas that we gather and the potential physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.

In response to findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, establish Prevention of Significant Deterioration

(“PSD”), construction and Title V operating permit reviews for certain large stationary sources that emit GHGs. Facilities required to obtain PSD permits for their GHG emissions will also be required to meet “best available control technology” standards that are established by the states or, in some cases, by the EPA on a case-by-case basis. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore oil and gas sources in the U.S. on an annual basis. We are monitoring and file annual required reports for the GHG emissions from our operations in accordance with the GHG emissions reporting rule. More recently, in June 2016, the EPA finalized new regulations that set emissions standards and leak detection and repair requirements for methane and volatile organic compounds from new and modified oil and natural gas production and natural gas processing and transmission facilities. However, in April 2017, the EPA announced that it will review this rule and initiate reconsideration proceedings to potentially revise or rescind portions of the methane rule. Subsequently, effective June 2, 2017, the EPA issued a 90-day stay of certain requirements under the methane rule, but this stay was vacated by a three-judge panel of the U.S. Court of Appeals for the D.C. Circuit on July 3, 2017 and again by an en banc D.C. Circuit on July 31, 2017. On August 10, 2017, the D.C. Circuit Court rejected petitions for an en banc review of its July 31, 2017 ruling. In the interim, on July 16, 2017, the EPA had issued a proposed rule that would provide a two-year extension of the initial 90-day stay. Substantial uncertainty exists with respect to implementation of this methane rule. Pennsylvania, where we operate, has also proposed a new general permit for compressor stations, transmission stations and processing plants, and imposes methane emission control and leak detection and repair requirements similar to those imposed under the EPA methane rules.

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 GHG emissions at the federal level 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. Further, in December 2015, nearly 200 countries, including the United States, proposed an agreement to limit global GHG emissions (the “Paris Agreement”). The United States signed the Paris Agreement in April 2016, and the Paris Agreement entered into force in November 2016. The United States is one of over 70 nations having ratified or otherwise consented to be bound by the Paris Agreement. The GHG emission reductions called for by the Paris Agreement are not binding. On June 1, 2017, President Trump announced that the United States planned to withdraw from the Paris Agreement and to seek negotiations either to reenter the Paris Agreement on different terms or establish a new framework agreement. The Paris Agreement provides for a four-year exit process beginning in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process is uncertain, and the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement, if it chooses to do so, are unclear at this time. Implementation of the Paris Agreement or the imposition of other climate change regulations, could have an adverse effect on our business.

Although it is not possible at this time to predict how future legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. Substantial limitations on GHG emissions could also adversely affect demand for our pipeline transportation and terminalling services.

Finally, increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, rising sea levels and other climatic events; given the physical locations of our operations, if any such effects were to occur, they could have an adverse effect on our facilities and operations or on our customers’ exploration and production operations.

Certain plant or animal species are or could be designated as endangered or threatened, which could impede, delay or prevent our ability to expand our operations.

The federal Endangered Species Act (the “ESA”) restricts activities that may affect endangered or threatened species or their habitats. Many states have analogous laws designed to protect their own designated endangered or threatened species. Such protections, and the designation of previously unidentified endangered or threatened species under such laws, may affect our ability to construct new facilities or expand operations, or increase our costs of doing so.

We may not own in fee the land on which our pipelines and facilities are located, which could result in disruptions to our operations.

Substantially all of the land on which our midstream assets are located is held by surface use agreement, rights-of-way or other easement rights. We are, therefore, subject to the possibility of more onerous terms or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate. We may obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. While some states allow regulated facilities to request that a court exercise condemnation powers on their behalf in certain circumstances, not all of our pipelines and facilities are subject to such statutory rights. Furthermore, when available, condemnation proceedings may be lengthy and costly, and may result in higher rights-of-way costs. Our loss of these rights, through our inability to renew right-of-way or otherwise, could have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to make cash distributions.

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

The midstream oil and natural gas industry 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.

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

We depend on the services of a relatively small group of our general partner’s senior management and technical personnel. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. The loss of the services of our general partner’s senior management or technical personnel could have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to make cash distributions.

We do not have any officers or employees and rely on officers of our general partner and employees of our sponsor.

We are managed and operated by the board of directors and executive officers of our general partner. Our general partner has no employees and relies on the employees of our sponsor, including the officers and employees of our general partner, to conduct our business and activities.

Our sponsor conducts businesses and activities of its own in which we have no economic interest. As a result, there could be material competition for the time and effort of the officers and employees who provide services to both our general partner and to our sponsor. If our general partner and the officers and employees of our sponsor do not devote sufficient attention to the management and operation of our business and activities, our

business, financial condition, results of operations, cash flows and ability to make cash distributions could be materially 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:

•

our ability to obtain additional financing, if necessary, for working capital, capital expenditures (or other purposes may be impaired or such financing may not be available on favorable terms;

•

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 and, potentially, principal payments on our debt;

•

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

•

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.

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

The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on our 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 might fail to make cash distributions during periods when we record net income for financial accounting purposes.

Increases in interest rates could adversely affect our business.

We will have exposure to increases in interest rates. After the consummation of this offering on a pro forma basis, we do not expect to have any outstanding indebtedness. However, in connection with the completion of this offering we expect to enter into a new $ million revolving credit facility. As a result of changes to the interest rate applicable to outstanding borrowings under our revolving credit facility, our results of operations, cash flows and financial condition and, as a result, our ability to make cash distributions to our unitholders, could be materially adversely affected by significant increases in interest rates.

None of the proceeds from the sale of common units by the selling unitholder in this offering will be available to fund our operations or to pay distributions.

We will not receive any proceeds from the sale of common units by the selling unitholder in this offering. Consequently, none of the proceeds from such sale will be available to fund our operations or to pay distributions to the public unitholders. Please read “Use of Proceeds.”

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, each of which could materially and adversely affect our business. 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

Our general partner and its affiliates, including our sponsor, have conflicts of interest with us and limited fiduciary duties to us and our unitholders, and they may favor their own interests to our detriment and that of our unitholders. Additionally, we have no control over the business decisions and operations of our sponsor, and our sponsor is not under any obligation to adopt a business strategy that favors us.

Following the completion of this offering and the AIMCo exchange, our sponsor will directly own an aggregate % limited partner interest in us (or an aggregate % limited partner interest in us if the underwriters exercise in full their option to purchase additional common units). In addition, our sponsor will own and control our general partner. Our sponsor will also continue to own a % noncontrolling equity interest in OpCo following the completion of this offering. Although our general partner has a duty to manage us in a manner that is in the best interests of our partnership and our unitholders, the directors and officers of our general partner also have a duty to manage our general partner in a manner that is in the best interests of our sponsor. Conflicts of interest may arise between our sponsor and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts, the general partner may favor its own interests and the interests of its affiliates, including our sponsor, over the interests of our common unitholders. These conflicts include, among others, the following situations:

•

neither our partnership agreement nor any other agreement requires our sponsor to pursue a business strategy that favors us or utilizes our assets, which could involve decisions by our sponsor to undertake acquisition opportunities for itself. Each of our sponsor’s directors and officers have a fiduciary duty to make these decisions in the best interests of the members of our sponsor;

•

our sponsor may be constrained by the terms of its debt instruments from taking actions, or refraining from taking actions, that may be in our best interests;

•

our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties and limits our general partner’s liabilities and the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty under applicable Delaware law;

•

except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;

•

our general partner will determine the amount and timing of, among other things, cash expenditures, borrowings and repayments of indebtedness, the issuance of additional partnership interests, the creation, increase or reduction in cash reserves in any quarter and asset purchases and sales, each of which can affect the amount of cash that is available for distribution to unitholders;

•

our general partner will determine the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can

affect the amount of cash that is distributed to our unitholders and to our general partner, the amount of adjusted operating surplus generated in any given period and the ability of the subordinated units to convert into common units;

•

our general partner will determine which costs incurred by it are reimbursable by us;

•

our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate expiration of the subordination period;

•

our partnership agreement permits us to classify 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 to our general partner in respect of the general partner interest or the incentive distribution rights;

•

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;

•

our general partner intends to limit its liability regarding our contractual and other obligations;

•

our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if it and its affiliates own more than 80% of the common units;

•

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

•

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

•

our general partner, or any transferee holding incentive distribution rights, may elect to cause us to issue common units and general partner interests 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 the board of directors of our general partner, which we refer to as our conflicts committee, or our common unitholders. This election could result in lower distributions to our common unitholders in certain situations.

Neither our sponsor nor any other affiliates of our general partner will be prohibited or restricted from owning assets or engaging in businesses that compete directly or indirectly with us. Under the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to our general partner or any of its affiliates, including our sponsor and executive officers and directors of our general partner. 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. Consequently, our sponsor and other affiliates of our general partner may acquire, construct or dispose of additional midstream assets in the future without any obligation to offer us the opportunity to purchase any of those assets except in the case of the ROFR assets. As a result, competition from our sponsor and other affiliates of our general partner could materially and adversely impact our results of operations and distributable cash flow. 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 unitholders. Please read “Certain Relationships and Related Party Transactions—Agreements with Our Affiliates in Connection with the Transactions—Omnibus Agreement” and “Conflicts of Interest and Duties.”

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

Our partnership agreement requires that we distribute all of our available cash to our unitholders, subject to some limitations. As a result, we expect to rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. Therefore, to the extent we are unable to finance our growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we will distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional partnership interests in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional partnership interests 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 partnership interests. The incurrence of additional commercial bank borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may reduce the amount of cash that we have available to distribute to our unitholders.

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

Delaware law provides that a Delaware limited partnership may, in its partnership agreement, expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to limited partners and the partnership, provided that the partnership agreement 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 provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law and replaces those duties with several different contractual standards. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, free of any duties to us and our unitholders. This provision entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. By purchasing a common unit, a unitholder is treated as having consented to the provisions in our partnership agreement, including the provisions discussed above. Please read “Conflicts of Interest and Duties—Duties of Our General Partner.”

Our partnership agreement restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner (including those acting on its behalf, such as its board of directors and executive officers) that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement:

•

provides that 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 subjectively believes that the determination or the decision to take or decline to take such action is in the best interests of our partnership, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

•

provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in a manner that meets the contractual good faith standard established by our partnership agreement;

•

provides that 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 engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

•

provides that our general partner will not be in breach of its obligations under our partnership agreement or its fiduciary duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is approved in accordance with, or otherwise meets the standards set forth in, our partnership agreement.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, our partnership agreement provides that any determination by our general partner must be made in a manner that meets the contractual good faith standard established by our partnership agreement, and that our conflicts committee and the board of directors of our general partner are entitled to a presumption that they acted in that manner. 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 Duties.”

Reimbursements due to our general partner and its affiliates for services provided to us or on our behalf will reduce cash available for distribution to our common unitholders. The amount and timing of such reimbursements will be determined by our general partner.

Prior to making any distribution on our common units, we will reimburse our general partner and its affiliates, including our sponsor, for expenses they incur and payments they make on our behalf. Under our omnibus agreement, we will reimburse our general partner and its affiliates for certain expenses incurred on our behalf, which we project to be approximately $ million for the twelve months ending September 30, 2018 and includes, among other items, compensation expense for all employees required to manage and operate our business. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of available cash to pay cash distributions to our common unitholders. Please read “Cash Distribution Policy and Restrictions on Distributions.”

Unitholders have very limited voting rights, and, even if they are dissatisfied, they will have limited ability to remove our general partner.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. For example, 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 board of directors of our general partner is chosen by its sole member, our sponsor. 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 our common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Our general partner may not be removed unless such removal is both (i) for cause and (ii) approved 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. “Cause” is narrowly defined under our partnership agreement

to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable to us or any limited partner for actual fraud or willful misconduct in its capacity as our general partner. Cause does not include most cases of poor management of the business. Following the completion of this offering and the AIMCo exchange, our sponsor will own % 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 exercise in full their option to purchase additional common units). As a result, our public unitholders will have limited ability to remove our general partner.

Furthermore, unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees, and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter.

Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest in us to a third party without the consent of the unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of our sponsor to transfer its membership interest in our general partner to a third party. Any such new owner 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 of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its incentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers its incentive distribution rights to a third party but retains its general partner interest, our general partner or our sponsor may not have the same incentive to contribute additional assets and increase quarterly distributions to unitholders over time as it would if it had retained ownership of the incentive distribution rights.

Our general partner may elect to convert the Partnership to a corporation for U.S. federal income tax purposes without unitholder consent.

Under our partnership agreement, if, in connection with the enactment of U.S. federal income tax legislation or a change in the official interpretation of existing U.S. federal income tax legislation by a governmental authority, our general partner determines that (i) the Partnership should no longer be characterized as a partnership for U.S. federal or applicable state and local income tax purposes or (ii) common units held by unitholders other than the general partner and its affiliates should be converted into or exchanged for interests in a newly formed entity taxed as a corporation or an entity taxable at the entity level for U.S. federal or applicable state and local income tax purposes whose sole asset is its interest in the Partnership (the “parent corporation”), then our general partner may, without unitholder approval, cause the Partnership to be treated as an entity taxable as a corporation or subject to entity-level taxation for U.S. federal or applicable state and local income tax purposes or cause the common units held by unitholders other than the general partner and its affiliates to be converted into or exchanged for interests in the parent corporation. Any such event may be taxable or nontaxable to our unitholders, depending on the form of the transaction. The tax liability, if any, of a unitholder as a result of such an event may vary depending on the unitholder’s particular situation and may vary from the tax liability of

our general partner and our sponsor. In addition, if our general partner causes an interest in the Partnership to be held by a parent corporation, our sponsor may choose to retain its partnership interest in us rather than convert its partnership interest into parent corporation shares. Please read “Our Partnership Agreement—Election to be Treated as a Corporation.”

We may issue an unlimited number of additional partnership interests without unitholder approval, which would dilute unitholder interests.

At any time, we may issue an unlimited number of general partner interests or limited partner interests of any type without the approval of our unitholders and our unitholders, other than our general partner and its affiliates, will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such general partner interests or limited partner interests. Further, there are no limitations in our partnership agreement on our ability to issue equity securities that rank equal or senior to our common units as to distributions or in liquidation or that have special voting rights and other rights. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects, among others:

•

our unitholders’ proportionate ownership interest in us will decrease;

•

the amount of cash we have available to distribute on each unit may decrease;

•

because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

•

the ratio of taxable income to distributions may increase;

•

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

•

the market price of our common units may decline.

The issuance by us of additional general partner interests may have the following effects, among others, if such general partner interests are issued to a person who is not an affiliate of our sponsor:

•

management of our business may no longer reside solely with our current general partner; and

•

affiliates of the newly admitted general partner may compete with us, and neither that general partner nor such affiliates will have any obligation to present business opportunities to us except with respect to rights of first refusal in our omnibus agreement.

Our sponsor or AIMCo may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.

After the completion of this offering, assuming that the underwriters do not exercise their option to purchase additional common units, our sponsor will hold common units and subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and may convert earlier under certain circumstances. In addition, AIMCo will exchange a portion of our sponsor’s preferred interests for of our common units and sell of those common units to the public in this offering.

Additionally, we have agreed to provide our sponsor and AIMCo with certain registration rights under applicable securities laws. The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.

Our general partner’s discretion in establishing cash reserves may reduce the amount of cash we have available to distribute to unitholders.

Our partnership agreement requires our general partner to deduct from operating surplus the cash reserves that it determines are necessary to fund our future operating expenditures. In addition, the partnership agreement permits the general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party, or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash we have available to distribute to unitholders.

Affiliates of our general partner, including our sponsor and its investors, including Alinda and AIMCo, may compete with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to us except with respect to rights of first refusal contained in our omnibus agreement.

Neither our partnership agreement nor our omnibus agreement will prohibit our sponsor and its investors, including Alinda and AIMCo, or any other affiliates of our general partner, from owning assets or engaging in businesses that compete directly or indirectly with us. Under the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to our general partner or any of its affiliates, including our sponsor and its investors and executive officers and directors of our general partner. 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. Consequently, our sponsor and its investors and other affiliates of our general partner may acquire, construct or dispose of additional midstream assets in the future without any obligation to offer us the opportunity to purchase any of those assets. As a result, competition from our sponsor and its investors and other affiliates of our general partner could materially and adversely impact our results of operations and distributable cash flow.

Our general partner has a limited call right that may require you to sell your common units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% of our then-outstanding 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 not less than their then-current market price. As a result, you may be required to sell your common units at an undesirable time or price and may receive little, no or negative return on your investment. You may also incur a tax liability upon a sale of your units. Following the completion of this offering and assuming the underwriters’ option to purchase additional common units from us is not exercised, our general partner and its affiliates will own approximately % of our common units (excluding any common units purchased by the directors and executive officers of our general partner, directors of our sponsor and certain other individuals as selected by our sponsor under our directed unit program). At the end of the subordination period (which could occur as early as within the quarter ending , 2018), assuming no additional issuances of common units by us (other than upon the conversion of the subordinated units) and the underwriters’ option to purchase additional common units from us is not exercised, our general partner and its affiliates will own approximately % of our outstanding common units (excluding any common units purchased by the directors and executive officers of our general partner, directors of our sponsor and certain other individuals as selected by our sponsor under our directed unit program) and therefore would not be able to exercise the call right at that time. Please read “Our Partnership Agreement—Limited Call Right.”

Unitholders may have to repay distributions that were wrongfully distributed to them.

Under certain circumstances, unitholders may have to repay amounts wrongfully 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 you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Transferees of common units are liable for the obligations of the transferor to make contributions to the partnership that are known to the transferee at the time of the transfer and for unknown obligations if the liabilities could be determined from our 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.

Prior to this offering, there has been no public market for our common units. After this offering, there will be only publicly traded common units, assuming the underwriters’ option to purchase additional common units from us is not exercised. In addition, following the completion of this offering, our sponsor will own common units and subordinated units, representing an aggregate % limited partner interest (or common units and subordinated units, representing an aggregate % limited partner interest, if the underwriters exercise in full their option to purchase additional common units). We do not know the extent to which investor interest will lead to the development of an active 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, the 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 offered hereby will be determined by negotiations between us, the selling unitholder and the representatives of the underwriters and may not be indicative of the market price of the common units in the trading market. The market price of our common units may decline below the initial public offering price.

Our general partner, or any transferee holding incentive distribution rights, 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 our conflicts committee or our common unitholders. This election could result in lower distributions to our common unitholders in certain situations.

Our general partner has the right, at any time when there are no subordinated units outstanding and it has received distributions on its incentive distribution rights at the highest level to which it is entitled ( %) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election, 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 our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units. The number of common units to be issued to our general partner will be equal to that number of common units that would have entitled their holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentive distribution rights in such two quarters. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per

common unit without such conversion. It is possible, however, that our general partner 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 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 they would have otherwise received had we not issued new common units in connection with resetting the target distribution levels. Additionally, our general partner has the right to transfer all or any portion of our incentive distribution rights at any time, and such transferee shall have the same rights as the general partner relative to resetting target distributions if our general partner concurs that the tests for resetting target distributions have been fulfilled. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—General Partner’s Right to Reset Incentive Distribution Levels.”

Units held by persons who our general partner determines are not “eligible holders” at the time of any requested certification in the future may be subject to redemption.

As a result of certain laws and regulations to which we are or may in the future become subject, we may require owners of our common units to certify that they are both U.S. citizens and subject to U.S. federal income taxation on our income. Units held by persons who our general partner determines are not “eligible holders” at the time of any requested certification in the future may be subject to redemption. “Eligible holders” are limited partners whose (or whose owners’) (i) U.S. federal income tax status or lack of proof of U.S. federal income tax status does not have and is not reasonably likely to have, as determined by our general partner, a material adverse effect on the rates that can be charged to customers by us or our subsidiaries with respect to assets that are subject to regulation by FERC or similar regulatory body and (ii) nationality, citizenship or other related status does not create and is not reasonably likely to create, as determined by our general partner, a substantial risk of cancellation or forfeiture of any property in which we have an interest. The aggregate redemption price for redeemable interests will be an amount equal to the current market price (the date of determination of which will be the date fixed for redemption) of limited partner interests of the class to be so redeemed multiplied by the number of limited partner interests of each such class included among the redeemable interests. For these purposes, the “current market price” means, as of any date for any class of limited partner interests, the average of the daily closing prices per limited partner interest of such class for the 20 consecutive trading days immediately prior to such date. As a result, your common units may be redeemed at an undesirable time or price and you may not receive any return on your investment. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. The units held by any person the general partner determines is not an eligible holder will not be entitled to voting rights. Please read “Our Partnership Agreement—Possible Redemption of Ineligible Holders.”

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

Our partnership agreement will provide that, with certain limited exceptions, 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) shall be the exclusive forum for any claims, suits, actions or proceedings (i) arising out of or relating in any way to our partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of our partnership agreement or the duties, obligations or liabilities among our partners, or obligations or liabilities of our partners to us, or the rights or powers of, or restrictions on, our partners or us), (ii) brought in a derivative manner on our behalf, (iii) asserting a claim of breach of a duty owed by any of our, or our general partner’s, directors, officers, or other employees, or owed by our general partner, to us or our partners, (iv) asserting a claim against us arising pursuant to any provision of the Delaware Act or (v) asserting a claim against us governed by the internal affairs doctrine.

In addition, our partnership agreement provides that each limited partner irrevocably waives the right to trial by jury in any such claim, suit, action or proceeding. 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 court) in connection with any such claims, suits, actions or proceedings. These provisions may have the effect of discouraging lawsuits against us and our general partner’s directors and officers. Please read “Our Partnership Agreement—Applicable Law; Exclusive Forum.”

The NYSE does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.

We have been approved to list our common units on the NYSE. Because we will be a publicly traded limited partnership, the NYSE does not require us to have, and we do not intend to have, a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Upon the listing of our common units on the NYSE prior to the closing of this offering, we expect the board of directors of our general partner will have one director who is independent as defined under the NYSE’s independence standard and our sponsor will appoint two additional independent directors within 12 months of the date of this prospectus as required by the listing standards of the NYSE. Additionally, any future issuance of additional common units or other securities, including to affiliates, will not be subject to the NYSE’s shareholder approval rules that apply to corporations. Accordingly, unitholders will not have the same corporate governance controls or protections afforded to the stockholders of corporations that are subject to all of the NYSE corporate governance requirements. Please read “Management—Management of Howard Midstream Partners, LP.”

We are not currently required to make an assessment of our internal control over financial reporting.

We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes- Oxley Act, and are therefore not required to make a formal assessment of the effectiveness of our internal control 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, 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 control 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 control 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 have implemented additional internal controls, reporting systems and procedures and hired additional accounting, finance and legal staff. Please read “—Risks Related to Our Business—We have restated our financial statements and determined that there was a material weakness in our internal control over financial reporting. If another material weakness occurs or persists in the future or if we otherwise fail to develop or maintain an effective system of internal controls over financial reporting, we may not be able to report our financial results accurately and timely or prevent fraud, which would likely have a negative impact on the market price of our common units.” Furthermore, while we generally must comply with Section 404 of the Sarbanes-Oxley Act of 2002 for our fiscal year ending December 31, 2018, 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 of 1933, as amended (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, 2022. 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.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our units.

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. In addition, the Sarbanes-Oxley Act and related rules subsequently implemented by the SEC and the NYSE have required changes in the corporate governance practices of publicly traded companies. We expect these rules and regulations to increase 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 publicly traded partnership reporting requirements. We also expect these new rules and regulations to make it more difficult and more expensive for our general partner to obtain director and officer liability insurance and to possibly result in our general partner having to accept reduced policy limits and coverage. As a result, it may be more difficult for our general partner to attract and retain qualified persons to serve on its board of directors or as executive officers.

We have included $3.0 million of estimated incremental annual costs associated with being a publicly traded partnership in our financial forecast included elsewhere in this prospectus. However, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than such amount.

For as long as we are an emerging growth company, we will not be required to comply with certain disclosure requirements that apply to other public companies.

We are an “emerging growth company” under the JOBS Act. For as long as we remain an “emerging growth company,” we may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies, including not being required to 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 of the Sarbanes-Oxley Act and reduced disclosure obligations regarding executive compensation in our periodic reports. We will remain an emerging growth company for up to five years, although we will lose that status sooner if we have equal to or more than $1.07 billion of revenues in a fiscal year, have more than $700 million in market value of our limited partner interests held by non-affiliates, or issue more than $1.0 billion of non-convertible debt over a three-year period.

In addition, the JOBS Act provides that an emerging growth company can delay adopting new or revised accounting standards until such time as those standards apply to private companies. We have elected to take advantage of this exemption and, therefore, will be subject to different accounting standards as compared to public companies that are not emerging growth companies.

To the extent that we rely on any of the exemptions available to emerging growth companies, you will receive less information about us than issuers that are not emerging growth companies. If some investors find our common units to be less attractive as a result, there may be a less active trading market for our common units and our trading price may be more volatile.

If we are deemed an “investment company” under the Investment Company Act of 1940, it would adversely affect the price of our common units and could have a material adverse effect on our business.

Our initial assets will consist of direct and indirect ownership interests in our operating subsidiaries. If a sufficient amount of our assets, such as our ownership interests in these subsidiaries or other assets acquired in the future, are deemed to be “investment securities” as defined in the Investment Company Act of 1940 (the “Investment Company Act”), we would have to, among other things, register as an investment company under the Investment Company Act, qualify for an exception from registration, obtain exemptive relief from the SEC or modify our organizational structure or our contract rights to fall outside the definition of an investment company. If we were to be determined to be an investment company under the Investment Company Act, we would lose our qualification as a partnership for federal income tax purposes in which case we would be treated as a corporation for federal income tax purposes. As a result, we would pay federal income tax on our taxable income at the corporate tax rate, distributions to you would generally be taxed again as corporate distributions and none of our income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced, thereby causing a substantial reduction in the value of our common units. Please read “Material Federal Income Tax Consequences—Partnership Status.”

Moreover, registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase of additional interests in OpCo from our sponsor, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us or our affiliates. The occurrence of some or all of these events would, among other things, adversely affect the price of our common units and could have a material adverse effect on our business.

Tax Risks

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

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. We have not requested a ruling from the IRS on this or any other tax matter affecting us.

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. A change in our business, a change in current law or our failure to satisfy the requirements under the Internal Revenue Code of 1986, as amended (the “Internal Revenue Code”) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our distributable cash flow would be substantially reduced and we might need to raise funds to pay such corporate level tax. Imposition of

any such taxes may substantially reduce the cash available for distribution to you. Therefore, if we were treated as a corporation for federal income tax purposes, there would be a material reduction in the anticipated cash flow and after-tax return to our 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 to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution levels may be adjusted to reflect the impact of that law on us.

If we were subjected to a material amount of additional entity-level taxation by individual states, counties or cities, it would reduce our cash available for distribution to our unitholders.

Changes in current state, county or city law may subject us to additional entity-level taxation by individual states, counties or cities. Several states have subjected, or are evaluating ways to subject, partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution to you. Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to entity-level taxation, the minimum quarterly distribution amount and the target distribution levels may be adjusted to reflect the impact of that law on us.

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

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, members of Congress and the President have periodically considered substantive changes to the existing federal income tax laws that would affect the tax treatment of certain publicly traded partnerships, including the elimination of partnership tax treatment for publicly traded partnerships. Any modification to the federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible for us to satisfy the requirements of the exception pursuant to which we will be treated as a partnership for federal income tax purposes. Please read “Material Federal Income Tax Consequences—Partnership Status.” 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 any such changes could negatively impact the value of an investment in our common units.

Our unitholders’ share of our income will be taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.

Because a unitholder will be treated as a partner to whom we will allocate taxable income that could be different in amount than the cash we distribute, a unitholder’s allocable share of our taxable income will be taxable to it, which may require the payment of federal income taxes and, in some cases, state and local income taxes, on its share of our taxable income even if it receives no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.

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, and the IRS’s positions

may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse impact on the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders (including holders of our subordinated units) because the costs will reduce our distributable cash flow.

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

If our unitholders sell common units, they will recognize a gain or loss for federal income tax purposes equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of their allocable share of our net taxable income decrease their tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the common units a unitholder sells will, in effect, become taxable income to the unitholder if it sells such common units at a price greater than its tax basis in those common units, even if the price received is less than its original cost. Furthermore, a substantial portion of the amount realized on any sale of your common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, a unitholder that sells common units may incur a tax liability in excess of the amount of cash received from the sale. Please read “Material Federal Income Tax Consequences—Disposition of Common Units—Recognition of Gain or Loss.”

Tax-exempt entities and non-United States persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

An investment in our common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-United States 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. Distributions to non-United States persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-United States persons will be required to file federal income tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-United States person, you should consult a tax advisor before investing in our common units.

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

Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing and proposed Treasury regulations promulgated under the Internal Revenue Code (the “Treasury Regulations”). A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. Latham & Watkins LLP is unable to opine as to the validity of such filing positions. 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 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 will adopt.

We will prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first business 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 business day of each month, instead of on the basis of the date a particular unit is transferred. The United States Treasury Department and the IRS recently issued Treasury Regulations that permit publicly traded partnerships to use a monthly simplifying convention that is similar to ours, but they do not specifically authorize all aspects of the proration method we have adopted. If the IRS were to successfully challenge this method, we could be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of those common units. If so, he would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of the loaned common units, he may no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Latham & Watkins LLP has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to effect a short sale of common units; therefore, our unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units.

We will adopt certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methodologies or the resulting allocations, and such a challenge could adversely affect the value of our common units.

In determining the items of income, gain, loss and deduction allocable to our unitholders, in certain circumstances, including when we issue additional units, we must determine the fair market value of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make many fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.

A successful IRS challenge to these methods or allocations could adversely affect the amount, character and timing of taxable income or loss 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 our 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 technically terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a 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. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead we would be treated as a new partnership for federal income tax purposes. If treated as a new partnership, we must make new tax elections, including a new election under Section 754 of the Internal Revenue Code and could be subject to penalties if we are unable to determine that a termination occurred. The IRS administers a publicly traded partnership technical termination relief program whereby, if a publicly traded partnership that technically terminated requests publicly traded partnership technical termination relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years. Please read “Material Federal Income Tax Consequences—Disposition of Common Units—Constructive Termination.”

If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case our cash available for distribution to our unitholders could be substantially reduced.

Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. Generally, we expect to elect to have unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, but there can be no assurance that such election will be effective in all circumstances. If we are unable to have our unitholders and former unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own our units during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders could be substantially reduced. These rules are not applicable to us for tax years beginning on or prior to December 31, 2017.

As a result of investing in our common units, you may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or control property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We initially expect to conduct business or own property in Texas and Pennsylvania. Texas and Pennsylvania impose an income tax on corporations and other entities. Pennsylvania also currently imposes a personal income tax on individuals. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal income tax. It is your responsibility to file all federal, 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. Please consult your tax advisor.

USE OF PROCEEDS

We expect to receive net proceeds of approximately $ million from the sale of common units offered by this prospectus, based on an assumed initial public offering price of $ per common unit (the mid-point of the price range set forth on the cover page of this prospectus), after deducting underwriting discounts and commissions, the structuring fees and estimated offering expenses. Our estimate assumes the underwriters’ option to purchase additional common units is not exercised. We intend to use the net proceeds from this offering to repay the outstanding balance of $ million under the term loan portion of our sponsor’s credit facility that we will assume in connection with the closing of this offering. As of June 30, 2017, our sponsor had an outstanding balance of $300 million under the term loan portion of its credit facility, $ million of which our sponsor repaid prior to our assumption of the remaining balance in connection with the closing of this offering. The term loan bears interest at a rate of 4.41% and matures on May 9, 2019. We will not receive any proceeds from the sale of common units by the selling unitholder in this offering.

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 such exercise will be issued to the public and the remainder of the additional common units will be issued to our sponsor at the expiration of the option period. In the event that the underwriters do not exercise such option, all of the additional common units will be issued to our sponsor. Any such common units issued to our sponsor will be issued for no additional consideration. If the underwriters exercise in full their option to purchase additional common units, we expect to receive net proceeds of approximately $ million, after deducting underwriting discounts and commissions, the structuring fees and estimated offering expenses. We will use any net proceeds from the exercise of the underwriters’ option to purchase additional common units from us to make a cash distribution to our sponsor.

If we choose to sell fewer common units in this offering, the number of common units to be held by our sponsor after consummation of this offering will be increased by an amount equivalent to such decrease in the number of units sold. Likewise, if we choose to sell more common units in this offering, the number of common units to be held by our sponsor after consummation of this offering will be reduced by an amount equivalent to such increase in the number of units sold. Additionally, the initial public offering price may be greater or less than the assumed initial public offering price. The actual initial public offering price is subject to market conditions and negotiations between us, the selling unitholder and the underwriters. A $1.00 increase (decrease) in the assumed initial public offering price of $ per common unit would increase (decrease) the net proceeds to us from this offering by approximately $ million, assuming the number of common units offered by us, as set forth on the cover page of this prospectus, remains the same and assuming the underwriters do not exercise their option to purchase additional common units, and after deducting underwriting discounts and commissions, the structuring fees and estimated offering expenses. The actual initial public offering price is subject to market conditions and negotiations between us, the selling unitholder and the underwriters.

Affiliates of certain of the underwriters are lenders under our sponsor’s credit facility and, accordingly, will receive a portion of the proceeds of this offering. Please read “Underwriting.”

CAPITALIZATION

The following table sets forth:

•

the historical cash and cash equivalents and capitalization of our Predecessor as of June 30, 2017; and

•

our pro forma capitalization as of June 30, 2017, giving effect to the pro forma adjustments described in our unaudited pro forma consolidated financial statements included elsewhere in this prospectus, including this offering and the application of the net proceeds of this offering in the manner described under “Use of Proceeds” and the other transactions described under “Prospectus Summary—The Transactions.”

The following table assumes that the underwriters do not exercise their option to purchase additional common units. 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 such exercise will be issued to the public and the remainder of the additional common units will be issued to our sponsor at the expiration of the option period. In the event that the underwriters do not exercise such option, all of the additional common units will be issued to our sponsor. Any such common units issued to our sponsor will be issued for no additional consideration.

This table is derived from, should be read together with and is qualified in its entirety by reference to the historical financial statements and the accompanying notes and the unaudited pro forma consolidated financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Prospectus Summary—The Transactions,” “Use of Proceeds” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”


	As of June 30, 2017
	Predecessor Historical			Pro Forma
	(in thousands)
Cash	$	22,852		$

Long-term debt (including current maturities):
New revolving credit facility⁽¹⁾		—			—
Predecessor credit facility⁽²⁾		510,000
Debt issuance costs, net		(4,413	)
Other		226

Total long-term debt		505,813

Partners’/members’ equity:
Held by Public⁽³⁾
Common unitholders		—
Members’ Equity		777,992
Held by our sponsor
Common units		—
Subordinated units		—
General partner interest		—
Total partners’ equity		—

Noncontrolling interest		32,593

Total partners’ capital		810,585

Total capitalization	$	1,316,398		$

(1)

In connection with the closing of this offering, we expect to enter into a new revolving credit facility, which will remain undrawn at the closing of this offering. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Our Credit Agreement.”

(2)	As of June 30, 2017, our sponsor had an outstanding balance of $300 million under the term loan portion of its credit facility, $ million of which our sponsor repaid prior to our assumption of the remaining balance in connection with the closing of this offering.

(3)

In connection with the closing of this offering, the selling unitholder will exchange a portion of our sponsor’s preferred interests for of the common units in us that our sponsor will receive in connection with this offering. The selling unitholder will sell such common units to the public in this offering.

DILUTION

Dilution is the amount by which the offering price per common unit in this offering will exceed the pro forma net tangible book value per unit after the offering. On a pro forma basis as of June 30, 2017, after giving effect to the offering of common units and the related transactions, our net tangible book value was approximately $ million, or $ per unit. Purchasers of common units in this offering will experience substantial and immediate dilution in pro forma 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⁽¹⁾		$
Pro forma net tangible book value per unit before the offering⁽²⁾	$
Increase in pro forma net tangible book value per common unit attributable to purchasers in this offering
Less: Pro forma net tangible book value per common unit after the offering⁽³⁾

Immediate dilution in net tangible book value per common unit to purchasers in this offering⁽⁴⁾⁽⁵⁾		$

(1)	The mid-point of the price range set forth on the cover of this prospectus

(2)	Determined by dividing the pro forma net tangible book value of the contributed assets and liabilities by the number of units ( common units and subordinated units) to be issued to our sponsor for its contribution of assets and liabilities to us.

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

(4)	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.

(5)

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

The following table sets forth the partnership interests that we will issue and the total consideration contributed to us by our general partner and its affiliates in respect of their partnership interests and by the purchasers of common units in this offering upon consummation of the transactions contemplated by this prospectus.


	Units Acquired				Total Consideration
	Number	Percent			Amount	Percent
					(in thousands)
General Partner and its affiliates^(1)(2)(3)				%	$			%
Purchasers in this offering				%	$			%

Total			100.0	%	$		100.0	%

(1)	Upon the completion of the transactions contemplated by this prospectus, our sponsor will own common units and subordinated units.

(2)	Assumes the underwriters’ option to purchase additional common units is not exercised.

(3)	The assets contributed by our sponsor were recorded at historical cost in accordance with GAAP. Book value of the consideration provided by the general partner and its affiliates, as of June 30, 2017, after giving effect to the application of the net proceeds of the offering, is as follows.


		(in millions)
Book value of net assets contributed		$
Less: Distribution to our sponsor from net proceeds of this offering

Total consideration		$

CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

The following discussion of our cash distribution policy should be read in conjunction with the specific assumptions included in this section. 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 results of operations, please refer to our historical financial statements and the accompanying notes and the unaudited pro forma consolidated financial statements and the accompanying notes included elsewhere in this prospectus.

General

Rationale for Our Cash Distribution Policy

Our partnership agreement requires that we distribute all of our available cash quarterly. This requirement forms the basis of our cash distribution policy and reflects a basic judgment that our unitholders will be better served by distributing our available cash rather than retaining it because, among other reasons, we believe we will generally finance any expansion capital expenditures from external financing sources. Under our current cash distribution policy, we intend to make a minimum quarterly distribution to the holders of our common units and subordinated units of $ per unit, or $ per unit on an annualized basis, to the extent we have sufficient available cash after the establishment of cash reserves and the payment of costs and expenses, including the payment of expenses to our general partner and its affiliates, including our sponsor. However, other than the requirement in our partnership agreement to distribute all of our available cash each quarter, we have no legal obligation to make quarterly or other cash distributions in this or any other amount, and the board of directors of our general partner has considerable discretion to determine the amount of our available cash each quarter. In addition, the board of directors of our general partner may change our cash distribution policy at any time, subject to the requirement in our partnership agreement to distribute all of our available cash quarterly. Generally, our available cash is the sum of (i) all cash on hand at the end of a quarter after the payment of our expenses and the establishment of cash reserves and (ii) if the board of directors of our general partner so determines, all or any portion of additional cash on hand resulting from working capital borrowings made after the end of the quarter. Because we are not subject to an entity-level federal income tax, we expect to have more cash to distribute than would be the case if we were subject to entity-level federal income tax. If we do not generate sufficient available cash from our operations, we may, but are under no obligation to, borrow funds to pay the minimum quarterly distribution to our unitholders.

Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy

Although our partnership agreement requires that we distribute all of our available cash quarterly, there is no guarantee that we will make quarterly cash distributions to our unitholders at our minimum quarterly distribution rate or at any other rate, and we have no legal obligation to do so. Our current cash distribution policy is subject to certain restrictions, as well as the considerable discretion of the board of directors of our general partner in determining the amount of our available cash each quarter. The following factors will affect our ability to make cash distributions, as well as the amount of any cash distributions we make:

•

We expect that our cash distribution policy will be subject to restrictions on cash distributions under our new revolving credit facility. We expect that one such restriction would prohibit us from making cash distributions while an event of default has occurred and is continuing under our new revolving credit facility, notwithstanding our cash distribution policy. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Our Credit Agreement.”

•

The amount of cash that we distribute and the decision to make any distribution is determined by the board of directors of our general partner, taking into consideration the terms of our partnership agreement. Specifically, the board of directors of our general partner will have the authority to establish cash reserves to provide for the proper conduct of our business, comply with applicable law or any agreement to which we are a party or by which we are bound or our assets are subject and provide funds for future cash distributions to our unitholders, and the establishment of or increase in those reserves could result in a reduction in cash distributions from levels we currently anticipate pursuant to our stated cash distribution policy. Any decision to establish cash reserves made by the board of directors of our general partner in good faith will be binding on our unitholders. Please read “Conflicts of Interest and Duties—Conflicts of Interest.”

•

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. Please read “Our Partnership Agreement—Amendment of Our 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. Following the completion of this offering, our sponsor will own our general partner, common units and subordinated units, representing an aggregate % limited partner interest (or common units and subordinated units, representing an aggregate % limited partner interest, if the underwriters exercise in full their option to purchase additional common units).

•

Under Section 17-607 of the Delaware Act, we may not make a distribution 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 cash flow shortfalls attributable to a number of operational, commercial or other factors as well as increases in our operating or general and administrative expenses, principal and interest payments on our debt, tax expenses, working capital requirements and anticipated cash needs. Our available cash is directly impacted by the cash expenses necessary to run our business and will be reduced dollar-for-dollar to the extent such uses of cash increase. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Distributions of Available Cash.”

•

Our ability to make cash distributions to our unitholders depends on the performance of our operating subsidiaries and their ability to distribute cash to us.

To the extent that our general partner determines not to distribute the full minimum quarterly distribution on our common units with respect to any quarter during the subordination period, the common units will accrue an arrearage equal to the difference between the minimum quarterly distribution and the amount of the cash distribution actually paid on the common units with respect to that quarter. The aggregate amount of any such arrearages must be paid on the common units before any distributions of available cash from operating surplus may be made on the subordinated units and before any subordinated units may convert into common units. The subordinated units will not accrue any arrearages. After the end of the subordination period, our common units will no longer accrue any arrearages. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordinated Units and Subordination Period.”

Our Ability to Grow Is Dependent on Our Ability to Access External Expansion Capital

Our partnership agreement requires us to distribute all of our available cash to our unitholders on a quarterly basis. As a result, we expect that we will rely primarily upon our cash reserves and external financing sources, including borrowings under our new revolving credit facility and the issuance of debt and equity securities, to

fund future acquisitions and other expansion capital expenditures. While our Predecessor has been historically funded by its operations and capital contributions from its investors, we do not have any commitment from our sponsor, our general partner or any of their respective affiliates to fund our cash flow deficits or provide other direct or indirect financial assistance to us following the closing of this offering. Following the completion of this offering, a portion of our sponsor’s preferred interests owned by AIMCo will be exchanged for common units in us that our sponsor will receive in connection with the closing of this offering. Following the AIMCo exchange and the sale of common units to the public by the selling unitholder, our sponsor will own an aggregate % limited partner interest in us (or an aggregate % limited partner interest in us if the underwriters exercise in full their option to purchase additional common units), and AIMCo will own a % limited partner interest in us. In addition, our sponsor will own a 100% interest in our general partner, which will hold all of our incentive distribution rights. Given our sponsor’s significant ownership interests in us following the closing of this offering, we believe our sponsor will be incentivized to promote and support the successful execution of our business strategies, including by providing us with direct or indirect financial assistance; however, we can provide no assurances that our sponsor will provide such direct or indirect financial assistance.

To the extent we are unable to finance growth with external sources of capital, the requirement in our partnership agreement to distribute all of our available cash and our current cash distribution policy may significantly impair our ability to grow. In addition, because we will distribute all of our available cash, our growth may not be as fast as businesses that reinvest all of their available cash to expand ongoing operations. We expect that our new revolving credit facility will restrict our ability to incur additional debt, including through the issuance of debt securities. Please read “Risk Factors—Risks Related to Our Business—Restrictions in our new revolving credit facility could adversely affect our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.” To the extent we issue additional partnership interests, the payment of distributions on those additional partnership interests may increase the risk that we will be unable to maintain or increase our cash distributions per common unit. There are no limitations in our partnership agreement on our ability to issue additional partnership interests, including partnership interests ranking senior to our common units, and our common unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such additional partnership interests. If we incur additional debt (under our new revolving credit facility or otherwise) to finance our growth strategy, we will have increased interest expense, which in turn will reduce the available cash that we have to distribute to our unitholders. Please read “Risk Factors—Risks Related to Our Business—Debt we incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.”

Our Minimum Quarterly Distribution

Upon the consummation of this offering, our partnership agreement will provide for a minimum quarterly distribution of $ per unit for each whole calendar quarter, or $ per unit on an annualized basis. Our ability to make cash distributions at the minimum quarterly distribution rate will be subject to the factors described above under “—General—Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.” Quarterly cash distributions, if any, will be made within 45 days after the end of each calendar quarter to holders of record on or about the first day of each such month in which such distributions are made. We do not expect to make cash distributions for the period that began on , 2017 and ends on the day prior to the closing of this offering. We will adjust the amount of our first distribution for the period from the closing of this offering through , 2017 based on the number of days in that period.

The amount of available cash needed to pay the minimum quarterly distribution on all of our common units and subordinated units that will be outstanding immediately after this offering for one quarter and on an annualized basis (assuming no exercise of the underwriters’ option to purchase additional common units) is summarized in the table below:

Minimum Quarterly
Distributions

(in millions)

Number of
Units⁽¹⁾

One Quarter

Annualized
(Four
Quarters)

Publicly held common units

Common units held by AIMCo

Common units held by our sponsor

Subordinated units held by our sponsor

Total

(1)	Does not include common units to be issued in connection with the Howard Midstream Partners, LP 2017 Long-Term Incentive Plan. Please read “Management—Our Long-Term Incentive Plan.”

Our general partner will also initially hold all of the incentive distribution rights, which entitle the holder to increasing percentages, up to a maximum of 50.0%, of the cash we distribute in excess of $ per unit per quarter.

During the subordination period, before we make any quarterly distributions to our subordinated unitholders, our common unitholders are entitled to receive payment of the full minimum quarterly distribution for such quarter plus any arrearages in distributions of the minimum quarterly distribution from prior quarters. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordinated Units and Subordination Period.” We cannot guarantee, however, that we will pay distributions on our common units at our minimum quarterly distribution rate or at any other rate in any quarter.

Although 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, 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 other standard imposed by the Delaware Act or any other law, rule or regulation or at equity. Our partnership agreement provides that, in order for a determination by our general partner to be made in “good faith,” our general partner must subjectively believe that the determination is in the best interests of our partnership. In making such determination, our general partner may take into account the totality of the circumstances or the totality of the relationships between the parties involved, including other relationships or transactions that may be particularly favorable or advantageous to us. Please read “Conflicts of Interest and Duties.”

The provision in our partnership agreement requiring us to distribute all of our available cash quarterly may not be modified without amending our partnership agreement; however, as described above, 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, the amount of reserves the board of directors of our general partner establishes in accordance with our partnership agreement and the amount of available cash from working capital borrowings.

Additionally, the board of directors of our general partner may reduce the minimum quarterly distribution and the target distribution levels if legislation is enacted or modified or action is taken by our general partner as described under “Our Partnership Agreement—Election to be Treated as a Corporation” that results in our partnership becoming taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes. In such an event, the minimum quarterly distribution and the target distribution levels may be reduced proportionately by the percentage decrease in our available cash resulting from the estimated tax

liability we would incur in the quarter in which such legislation is effective. The minimum quarterly distribution will also be proportionately adjusted in the event of any distribution, combination or subdivision of common units in accordance with the partnership agreement, or in the event of a distribution of available cash from capital surplus. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels.” The minimum quarterly distribution is also subject to adjustment if the holder(s) of the incentive distribution rights (initially only our general partner) elect to reset the target distribution levels related to the incentive distribution rights. In connection with any such reset, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution amount per common unit for the two quarters immediately preceding the reset. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—General Partner’s Right to Reset Incentive Distribution Levels.”

In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our annualized minimum quarterly distribution of $ per unit for the twelve months ending September 30, 2018. In those sections, we present two tables, consisting of:

•

“Unaudited Pro Forma Adjusted EBITDA and Distributable Cash Flow for the Year Ended December 31, 2016 and the Twelve Months Ended June 30, 2017,” in which we present the amount of Adjusted EBITDA and distributable cash flow we would have generated on a pro forma basis for the year ended December 31, 2016 and the twelve months ended June 30, 2017, derived from our unaudited pro forma consolidated financial statements that are included in this prospectus, as adjusted to give pro forma effect to this offering and the related formation transactions; and

•

“Estimated Adjusted EBITDA and Distributable Cash Flow for the Twelve Months Ending September 30, 2018,” in which we provide our estimated forecast of our ability to generate sufficient Adjusted EBITDA and distributable cash flow to support the payment of the minimum quarterly distribution on all common units and subordinated units for the twelve months ending September 30, 2018.

Unless otherwise specifically noted, the amounts set forth in the following sections reflect the pro forma historical and forecasted results attributable to 100% of the assets and operations of our operating subsidiaries and are not adjusted to reflect our sponsor’s noncontrolling interest in OpCo. In connection with the completion of this offering our sponsor will contribute to us a % controlling interest in OpCo and our sponsor will retain a % noncontrolling equity interest in OpCo. Please read “Prospectus Summary—The Transactions” and “Prospectus Summary—Ownership and Organizational Structure.” Following the completion of this offering, we will consolidate the results of operations of OpCo and then record a noncontrolling interest deduction for our sponsor’s retained interest in OpCo.

Unaudited Pro Forma Adjusted EBITDA and Distributable Cash Flow for the Year Ended December 31, 2016 and the Twelve Months Ended June 30, 2017

If we had completed the transactions contemplated in this prospectus on January 1, 2016, pro forma distributable cash flow attributable to us for the year ended December 31, 2016 and the twelve months ended June 30, 2017 would have been approximately $ million and $ million, respectively. These amounts would have been sufficient to support the payment of the minimum quarterly distribution of $ per unit per quarter ($ per unit on an annualized basis) on all of our common units and subordinated units for the year ended December 31, 2016 and the twelve months ended June 30, 2017.

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, Adjusted EBITDA and distributable cash flow are primarily cash accounting concepts, while our unaudited pro forma consolidated financial statements have been prepared on an accrual basis. As a result, you should view the amounts of pro forma Adjusted EBITDA and distributable cash flow only as general indications of the amounts of Adjusted EBITDA and distributable cash flow that we might have generated had we been formed on January 1, 2016.

The following table illustrates, on a pro forma basis, for the year ended December 31, 2016 and the twelve months ended June 30, 2017, the amount of Adjusted EBITDA and distributable cash flow that would have been generated, assuming that this offering and the other transactions contemplated in this prospectus had been consummated on January 1, 2016.

Howard Midstream Partners, LP

Unaudited Pro Forma Adjusted EBITDA and Distributable Cash Flow


	Year Ended December 31, 2016⁽¹⁾			Twelve Months Ended June 30, 2017⁽¹⁾
	(in thousands)
Revenues
Gathering and processing services	$	133,622		$	130,035
Natural gas sales		33,147			17,224
Natural gas liquid sales		32,269			52,590
Natural gas liquid sales—related party		33,698			23,675
Liquids handling services		9,305			9,874

Total revenues		242,041			233,398

Costs of products sold (excluding depreciation and amortization)		75,792			71,194
Cost of products sold—related party (excluding depreciation and amortization)		3,574			3,659

Gross Margin		162,675			158,545

Expenses
Operations and maintenance⁽²⁾		41,704			39,306
Depreciation and amortization⁽²⁾		55,203			56,216
General and administrative⁽²⁾		25,076			22,474

Total expenses		121,983			117,996

Operating income		40,692			40,549
Interest expense⁽³⁾		(656	)		(635	)
Other (expense) income		(13	)		62

Income before income taxes		40,023			39,976
State income taxes		255			136

Net income		39,768			39,840

Net income (loss) attributable to noncontrolling interest⁽⁴⁾		84			(14	)

Net income attributable to OpCo	$	39,684		$	39,854

Add:
Net income (loss) attributable to noncontrolling interest		84			(14	)
Depreciation and amortization		55,203			56,216
Interest expense		656			635
Other (expense) income		13			(62	)
State income taxes		255			136
Unit-based compensation⁽⁵⁾		7,666			6,255

Adjusted EBITDA		103,561			103,020

Less:
Adjusted EBITDA attributable to noncontrolling interest⁽⁴⁾		155			417

Adjusted EBITDA attributable to OpCo	$	103,406		$	102,603

Less:
Cash interest expense		656			635
Cash state income taxes		244			125
Maintenance capital expenditures⁽⁶⁾		2,701			2,511
Expansion capital expenditures⁽⁷⁾		37,086			26,282
Add:
Capital contribution from HEP to fund expansion capital expenditures⁽⁸⁾		37,086			26,282

Estimated distributable cash flow attributable to OpCo	$	99,805		$	99,332

Less:
Estimated distributable cash flow attributable to non-controlling interest in OpCo⁽⁹⁾
Cash interest expense⁽¹⁰⁾		1,600			1,600
Incremental general and administrative expenses⁽¹¹⁾		3,000			3,000

Estimated distributable cash flow attributable to Howard Midstream Partners, LP

Minimum annual distribution per unit	$	—		$	—
Annual distribution to:
Public common unitholders
HEP:
Common units
Subordinated units

Total annual distributions at the minimum quarterly distribution rate	$	—		$	—

Excess distributable cash flow attributable to Howard Midstream Partners, LP over aggregate minimum quarterly distributions	$	—		$	—

(1)	Certain entities of the Predecessor that are not being contributed to OpCo have been excluded from this calculation of pro forma Adjusted EBITDA and distributable cash flow.

(2)	Amounts have been adjusted to remove corporate allocations of our Predecessor and include certain expenses that will be charged in accordance with the omnibus agreement.

(3)

Represents the interest expense attributable to 100% of the assets and operations of OpCo, consisting of interest expense on capital leases and parent performance guarantees. Does not reflect the interest expense associated with the Partnership’s new revolving credit facility, which will be borne solely by the Partnership, as borrower, and not by OpCo.

(4)	Amounts attributable to noncontrolling interest in our non-wholly owned consolidated subsidiaries within OpCo.

(5)

We were allocated our proportionate share of unit-based compensation expenses initially recognized by our sponsor. These non-cash charges are described in more detail in Note 10 to the audited financial statements of our Predecessor for the years ended December 31, 2016 and 2015 appearing elsewhere in this prospectus.

(6)

(7)

Expansion capital expenditures are cash expenditures to construct new midstream infrastructure and 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, including well connections or the establishment of other delivery points that increase existing system throughput. Examples of expansion capital expenditures include the construction, development or acquisition of additional gathering pipelines, terminals, plants, facilities and compressor stations, in each case to the extent such capital expenditures are expected to expand our operating capacity, operating income or revenue.

(8)	Expansion capital expenditures have been funded by our sponsor directly.

(9)	Represents our sponsor’s retained % interest in OpCo’s distributable cash flow.

(10)	Cash interest includes payment of commitment fees incurred in connection with our new revolving credit facility.

(11)	Reflects an adjustment of approximately $3.0 million of estimated annual incremental general and administrative expenses as a result of being a publicly traded partnership. The expenses of being a publicly traded partnership will be borne solely by the Partnership and not by OpCo.

Estimated Adjusted EBITDA and Distributable Cash Flow for the Twelve Months Ending September 30, 2018

We forecast that our estimated Adjusted EBITDA and distributable cash flow attributable to us for the twelve months ending September 30, 2018 will be approximately $ million and $ million, respectively. In order to pay the aggregate annualized minimum quarterly distribution to all of our unitholders for the twelve months ending September 30, 2018, we must generate Adjusted EBITDA and distributable cash flow attributable to us of at least $ million and $ million, respectively. The number of outstanding units on which we have based our belief does not include any common units that may be issued under the long-term incentive plan that our general partner will adopt prior to the closing of this offering.

We have not historically made public projections as to future operations, earnings or other results. However, management has prepared the forecast of estimated Adjusted EBITDA and distributable cash flow for the twelve months ending September 30, 2018, and the related assumptions set forth below, to substantiate our belief that we will have sufficient Adjusted EBITDA and distributable cash flow to pay the aggregate annualized minimum quarterly distribution to all of our unitholders for the twelve months ending September 30, 2018. Please read “—Significant Forecast Assumptions.” This forecast is a forward-looking statement and should be read together with our historical and unaudited pro forma consolidated financial statements and the accompanying notes included elsewhere in this prospectus and “Management’s Discussion and Analysis of Financial Condition and

Results of Operations.” This forecast was not prepared with a view toward complying with the published guidelines of the SEC or guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the assumptions on which we base our belief that we can generate sufficient Adjusted EBITDA and distributable cash flow to pay the minimum quarterly distribution to all unitholders and our general partner for the forecasted period. However, this information is not fact and should not be relied upon as being necessarily indicative of our future results, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information.

The prospective financial information included in this prospectus has been prepared by, and is the responsibility of, our management. Neither Grant Thornton LLP nor PricewaterhouseCoopers LLP have compiled or performed any procedures with respect to the accompanying prospective financial information and, accordingly, neither Grant Thornton LLP nor PricewaterhouseCoopers LLP express an opinion or any other form of assurance with respect thereto. The Grant Thornton LLP report included in this prospectus relates to our historical financial information. The PricewaterhouseCoopers LLP report included in this prospectus relates to Angelina Gathering Company, LLC, an acquired subsidiary (“Angelina”). Neither report extends to the prospective financial information and should not be read to do so.

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 that would enable us to generate our estimated Adjusted EBITDA and distributable cash flow.

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

Howard Midstream Partners, LP

Estimated Adjusted EBITDA and Distributable Cash Flow


	Twelve Months Ending September 30, 2018
	(in thousands)
Revenues
Gathering and processing services	$	142,880
Natural gas sales		13,856
Natural gas liquid sales		66,024
Natural gas liquid sales—related party		—
Liquids handling services		10,452

Total revenues		233,211

Cost of products sold (excluding depreciation and amortization)		66,058
Cost of products sold—related party (excluding depreciation and amortization)		—

Gross margin		167,153

Expenses
Operations and maintenance		43,425
Depreciation and amortization		56,641
General and administrative		14,419

Total expenses		114,485

Operating income		52,669
Interest expense⁽¹⁾		(472	)
Other (expense) income		—

Income before income taxes		52,197
State income taxes		192

Net income		52,005

Net income attributable to noncontrolling interest⁽²⁾		301

Net income attributable to OpCo	$	51,703

Add:
Net income attributable to noncontrolling interest		301
Depreciation and amortization		56,641
Interest expense		472
Other (expense) income		—
State income taxes		192
Unit-based compensation⁽³⁾		—

Adjusted EBITDA		109,310

Less:
EBITDA attributable to noncontrolling interest⁽²⁾		225

Adjusted EBITDA attributable to OpCo	$	109,085

Less:
Cash interest expense		472
Cash state income taxes		192
Maintenance capital expenditures⁽⁴⁾		3,463
Expansion capital expenditures⁽⁵⁾		12,727
Add:
Capital contributions to fund expansion capital expenditures⁽⁶⁾		12,727

Estimated distributable cash flow attributable to OpCo	$	104,958

Estimated distributable cash flow attributable to noncontrolling interest in OpCo⁽⁷⁾
Cash interest expense⁽⁸⁾		1,383
Incremental general and administrative expenses⁽⁹⁾		3,000

Estimated distributable cash flow attributable to Howard Midstream Partners, LP		$

Minimum annual distribution per unit	$	—
Annual distribution to:
Public common unitholders⁽¹⁰⁾
HEP:
Common units
Subordinated units

Total annual distributions at the minimum quarterly distribution rate	$	—

Excess distributable cash flow attributable to Howard Midstream Partners, LP over aggregate minimum quarterly distributions	$	—

(1)	Represents the interest expense attributable to 100% of the assets and operations of OpCo, consisting of fees paid to our sponsor for providing financial guarantees on certain contracts. Fees are calculated at our

sponsor’s cost of debt based on an agreed upon maximum exposure. Does not reflect the interest expense associated with the Partnership’s new revolving credit facility, which will be borne solely by the Partnership, as borrower, and not by OpCo.

(2)	Amounts attributable to noncontrolling interest in our non-wholly owned consolidated subsidiaries within OpCo.

(3)	OpCo will no longer be allocated unit-based compensation expenses initially recognized by our sponsor.

(4)

Maintenance capital expenditures are cash expenditures (including the replacement or improvement of existing capital assets) made to maintain, over the long-term, our operating capacity, operating income or revenue. Examples of maintenance capital expenditures are expenditures to repair, refurbish and replace pipelines and storage tanks, to maintain equipment reliability, integrity and safety and to comply with environmental laws and regulations. Please read “—Significant Forecast Assumptions—Capital Expenditures.”

(5)

(6)	OpCo capital expenditures will be funded by our sponsor and us in proportion to our relative ownership interests in OpCo.

(7)	Noncontrolling interest is based on the assumption that our sponsor retains a % interest in OpCo.

(8)

Cash interest expense includes interest on borrowed money and commitment fees on our new revolving credit facility. We expect to use borrowings under our new revolving credit facility to fund our expansion capital expenditures. Interest expense related to our new revolving credit facility is based on an assumed interest rate of 3.2% on outstanding borrowings under the facility and an assumed interest rate of 0.375% on undrawn portions of the facility. Please read “—Significant Forecast Assumptions—Financing” for more information on our assumed interest rates relating to drawn and undrawn portions of our new revolving credit facility.

(9)

Reflects an adjustment of $3.0 million of estimated annual incremental general and administrative expenses as a result of being a publicly traded partnership, which includes expenses associated with: annual and quarterly reports to unitholders; tax return and Schedule K-1 preparation and distribution; Sarbanes-Oxley Act compliance expenses; expenses associated with listing on the NYSE; independent auditor fees; legal fees; investor relations activities; registrar and transfer agent fees; incremental director and officer liability insurance expenses; and director compensation. The expenses of being a publicly traded partnership will be borne solely by the Partnership and not by OpCo.

(10)	The number of outstanding units on which we base our forecasted distributions to public common unitholders does not include any common units that may be issued under the long-term incentive plan that our general partner will adopt prior to the closing of this offering.

Significant Forecast Assumptions

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 September 30, 2018. While the assumptions disclosed in this prospectus are not all-inclusive, the assumptions listed below are those that we believe are material to our forecasted results of operations. We believe we have a reasonable objective basis for these assumptions and that our actual results of operations will approximate those reflected in our forecast, but we can give no assurance that our forecasted results of operations will be achieved. There likely will 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 Considerations

Our Predecessor’s historical results of operations include all of the results of operations of our sponsor on a 100% basis, which includes 100% of the results of OpCo, as well as 100% of the results of certain other midstream assets that our sponsor will retain after the completion of this offering. In connection with the closing of this offering, our sponsor will contribute to us a 100% interest in OpCo GP and a % limited partner interest in OpCo, which will own substantially all of our sponsor’s current assets and operations. Unless otherwise specifically noted, the amounts set forth in these assumptions reflect results attributable to the assets and operations of our sponsor contributed to OpCo in connection with the closing of this offering. Please read “Prospectus Summary—The Transactions” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Impacting the Comparability of Our Financial Results.”

We operate our assets through two business segments—our Natural Gas segment and our Liquids segment. The following table summarizes gross margin generated by the assets in our Natural Gas segment and our Liquids segment.


	Year Ended December 31, 2016		Twelve Months Ended June 30, 2017		Twelve Months Ending September 30, 2018
	($ in millions)
Natural Gas Segment Gross Margin	$	138.6	$	135.7	$	145.5
Liquids Segment Gross Margin	$	24.1	$	22.9	$	21.6

Total OpCo Gross Margin	$	162.7	$	158.5	$	167.2

Natural Gas Segment

Our Natural Gas segment includes six natural gas gathering systems located in South Texas and Northeastern Pennsylvania and a cryogenic natural gas processing plant and related infrastructure located in South Texas. We expect that 98% of the segment gross margin generated by our Natural Gas segment for the twelve months ending September 30, 2018 will be related to fee-based revenue derived primarily from fixed gathering and processing fees or fixed-margin arrangements primarily related to natural gas and NGL sales.

Gathering and processing services revenue from our Natural Gas segment is primarily fee-based in nature and generated from (i) transportation fees charged on volumes transported through our systems, (ii) processing fees charged for volumes processed at our Reveille processing plant, (iii) ancillary fees related to compression, treating, dehydration and conditioning services and (iv) minimum volume commitments and demand payments under our gathering and processing agreements. Minimum volume commitments represent volumes that our customers contractually commit to deliver to an existing gathering system or plant. Our customers generally pay us an agreed upon rate for amounts delivered up to the minimum volume commitment or, in the event actual deliveries fall short of the minimum volume commitment, a deficiency payment at an agreed upon deficiency rate multiplied by the shortfall amount. In the event our customers deliver volumes in excess of their minimum volume commitments, some of our commercial agreements allow such customers to credit the excess volumes against minimum volume commitments in future periods, which vary by agreement, or against minimum volume commitments such customers may have on our other gathering systems.

In addition to our natural gas gathering and processing services, we also generate revenue in our Natural Gas segment through natural gas sales and NGL sales related to (i) marketing services we offer to some of our gathering and processing customers and (ii) a small percentage-of-proceeds component in some of our contracts. Under our marketing services, the revenues we recognize for natural gas sold are largely offset by the cost of products sold for natural gas purchased in connection with those sales in back-to-back arrangements, which generates a fixed margin and substantially mitigates commodity price exposure. Under our percentage-of-proceeds contracts, we retain a percentage of natural gas and NGLs that we process and transport to sell for our own account or are paid a percentage of the proceeds our customer receives for the natural gas and NGLs that we deliver.

Liquids Segment

Our Liquids segment includes a deepwater marine terminal in Brownsville, Texas, a condensate and NGL processing and stabilization facility in Live Oak County, Texas and a rail terminal in Live Oak County, Texas. We expect that 100% of the segment gross margin generated by our Liquids segment for the twelve months ending September 30, 2018 will be related to fee-based revenue derived primarily from fixed storage and terminalling fees or fixed-margin arrangements primarily related to natural gas and NGL sales.

Natural gas sales and NGL sales from our Liquids segment are related to our Live Oak stabilizer. We buy inlet volumes delivered to the facility and sell the rich residue gas, NGLs and stabilized condensate based on a fixed differential to index pricing by component. While the back-to-back, fixed-differential pricing arrangements eliminate a significant amount of potential commodity price exposure, the composition of volumes delivered may vary, impacting our revenue and segment gross margin.

In addition to our natural gas and NGL sales, our Liquids segment includes handling services that are primarily fee-based in nature and are generated from (i) throughput fees based on the volume of product delivered to our facilities, (ii) fixed storage capacity fees and (iii) ancillary fees for product heating, product transfer, railcar handling and other services.

Revenue, Cost of Products Sold and Gross Margin

General

We estimate that we will generate revenue of approximately $233.2 million for the twelve months ending September 30, 2018, as compared to approximately $233.4 million for the twelve months ended June 30, 2017 and $242.0 million for the year ended December 31, 2016. Gross margin is projected to increase to $167.2 million for the twelve months ending September 30, 2018 from $158.5 million for the twelve months ended June 30, 2017 and $162.7 million for the year ended December 31, 2016. The decrease in our estimated revenue during the forecast period is primarily due to lower forecasted volumes across both our Natural Gas and Liquids segments, specifically our marketing business. The increase in our estimated gross margin during the forecast period is primarily due to increased minimum volume commitments in our Natural Gas segments, partially offset by lower forecasted volumes across both our Natural Gas and Liquids segments, as described below.

Our forecasted revenue and gross margin have been estimated by considering the contracted capacity and minimum volume commitments under our gathering, processing and terminalling agreements and forecasted volumes with respect to our existing customers. We expect that any substantial variances between actual and forecasted revenues and gross margin during the forecast period will be driven primarily by differences between actual and forecasted volumes. With respect to agreements that are not fully supported by minimum volume commitments, variances in actual volumes will drive changes in actual revenue and gross margin that we generate from such agreements. Please read “Business—Commercial Agreements.” In addition, with respect to agreements that are supported by minimum volume commitments, fluctuations in actual volumes will influence the actual revenue and gross margin we generate under those agreements, as certain of our agreements allow our customers to credit excess volumes against minimum volume commitments in future periods or on other gathering systems. We estimate that our customers have aggregate historical excess volumes that can be credited towards future minimum volume commitment deficiencies of approximately 135.4 Bcf as of September 30, 2017, which will result in a decrease in revenue and gross margin of approximately $10.4 million for the twelve months ending September 30, 2018, as reflected in the forecast. During the forecast period, we expect certain of our customers to utilize 20.7 Bcf of historical excess volumes against minimum volume commitment deficiencies incurred during the forecast period, partially offset by certain other customers that are expected to generate 12.4 Bcf of excess volumes during the forecast period. As a result, we forecast aggregate excess volumes that can be credited towards future minimum volume commitment deficiencies of approximately 127.2 Bcf as of September 30, 2018.

For the twelve months ending September 30, 2018, we expect approximately $158.6 million, or 68%, of our forecasted revenue to come from our Natural Gas segment and approximately $74.6 million, or 32%, of our forecasted revenue to come from our Liquids segment. We expect approximately $145.5 million, or approximately 87%, of our total forecasted gross margin to come from our Natural Gas segment and approximately $21.6 million, or approximately 13%, of our total forecasted gross margin to come from our Liquids segment.

Further, we estimate that our cost of products sold for the twelve months ending September 30, 2018 will be $66.1 million, as compared to $74.9 million for the twelve months ended June 30, 2017 and $79.4 million for the year ended December 31, 2016. The decrease in cost of products sold during our forecast period corresponds to a decrease in revenue related to the marketing business and the Live Oak stabilizer, as described below.

Natural Gas Segment

We expect we will generate approximately $145.5 million in segment gross margin from our Natural Gas segment for the twelve months ending September 30, 2018 compared with $135.7 million in segment gross margin for the twelve months ended June 30, 2017 and $138.6 million in segment gross margin for the year ended December 31, 2016. The increase in segment gross margin during the forecast period is primarily due to increased minimum volume commitments on our existing northeast gathering assets and from the development of the Tioga system, partially offset by lower forecasted volumes across our northeast gathering, South Texas gathering and South Texas processing assets.


	Twelve Months Ending September 30, 2018
	Gathering & Processing Services		Natural Gas Sales		Natural Gas Liquid Sales		Total
Forecasted Revenue ($ in millions)	$	142.9	$	13.6	$	2.2	$	158.6
% of Natural Gas Segment Revenue		90%		9%		1%		100%
Forecasted Gross Margin ($ in millions)	$	142.9	$	1.1	$	1.5	$	145.5
% of Natural Gas Segment Gross Margin		98%		1%		1%		100%

As reflected below, we expect reduced volumes as a result of our customers significantly slowing or temporarily reducing or halting drilling programs in reaction to lower commodity prices over the prior eighteen months. As a result, there has not been sufficient new well production to offset the declining production on existing wells delivered into our systems. Our primary customers added 24 new wells for the year ended December 31, 2016, and 24 new wells have begun flowing natural gas onto our systems since January 1, 2017. While we have assumed only eight additional wells will be drilled in our areas of operation during the twelve months ending September 30, 2018 for purposes of this forecast, we anticipate as many as 42 additional wells may be drilled during this period based on discussions with our customers. As commodity prices continue to stabilize and increase, we expect rig activity to increase. Accordingly, we expect that throughput on our assets will increase relative to our forecasted volumes below as activity returns to our areas of operations.


	Year Ended December 31, 2016		Twelve Months Ended June 30, 2017		Twelve Months Ending September 30, 2018
	($ in millions)
Natural Gas Segment
Northeast Gathering Assets
Volumes (Mcf/d)		415,054		380,269		317,341
Gross Margin	$	70.3	$	66.2	$	91.5
South Texas Gathering Assets
Volumes (Mcf/d)⁽¹⁾		364,815		366,344		278,651
Gross Margin	$	49.0	$	50.7	$	41.7
South Texas Processing Assets
Volumes (MMBtu/d)		74,294		66,117		44,500
Gross Margin	$	18.6	$	18.4	$	12.1
Marketing
Gross Margin	$	0.7	$	0.5	$	0.2
Total Natural Gas Segment Gathering Volumes (Mcf/d)⁽¹⁾		779,870		746,613		595,992
Gross Margin	$	138.6	$	135.7	$	145.5

(1)	Assumes 1.2 MMBtu/mcf factor for volumes transported on the MD System.

We estimate that 76% of our segment gross margin in our Natural Gas segment for the twelve months ending September 30, 2018 will be supported by minimum volume commitments and demand payments, which mitigates the variability related to the volumes delivered to our systems. For the twelve months ending September 30, 2018, we estimate that our customers will deliver an average of 595,992 Mcf/d under our gathering and processing agreements, as compared to 746,613 Mcf/d for the twelve months ended June 30, 2017 and 779,870 Mcf/d for the year ended December 31, 2016. If our customers deliver volumes 10% greater than those we forecast under our gathering and processing agreements for the twelve months ending September 30, 2018, we expect our estimated distributable cash flow attributable to OpCo would increase 4%, or $3.9 million, to $108.8 million. If volumes delivered to our system for the twelve months ending September 30, 2018 are 10% below our forecasted volumes, we expect our estimated distributable cash flow attributable to OpCo would decrease 4%, or $3.7 million, to $101.3 million.

Cost of products sold in the Natural Gas segment consists of the cost of natural gas and NGL sales by our marketing companies. These costs, as well as the associated revenues, fluctuate with changes in market prices and volumes purchased and, under our back-to-back arrangements, have minimal impact on our segment gross margin or operating income. For the twelve months ending September 30, 2018, we estimate that our cost of products sold in the Natural Gas segment will be $13.1 million, as compared to $17.3 million for the twelve months ended June 30, 2017 and $31.7 million for the year ended December 31, 2016. The decrease in cost of products sold in the Natural Gas segment is primarily attributable to lower purchase volumes experienced by the gas marketing companies within the segment.

Due to the back-to-back nature of our marketing arrangements, we expect our gross margin associated with our marketing business to remain relatively stable even though our revenue and cost of products sold fluctuates with commodity prices and the volumes that we market.

Liquids Segment

We expect we will generate approximately $21.6 million in segment gross margin from our Liquids segment for the twelve months ending September 30, 2018 compared with $22.9 million in segment gross margin for the twelve months ended June 30, 2017 and $24.1 million for the year ended December 31, 2016. The decrease in segment gross margin is primarily due to a decline in revenue resulting from lower forecasted volumes at the Live Oak stabilizer and corresponding to a decline in cost of products sold.


	Twelve Months Ending September 30, 2018
	Natural Gas Sales		Natural Gas Liquid Sales		Liquids Handling Services		Total
			($ in millions)
Forecasted Revenue	$	0.3	$	63.8	$	10.5	$	74.6
% of Liquids Segment Revenue		0%		86%		14%		100%
Forecasted Gross Margin	$	0.3	$	15.7	$	5.7	$	21.6
% of Liquids Segment Gross Margin		1%		72%		26%		100%

As reflected below, the expected decreases in volumes at our Live Oak stabilizer are attributable to reduced drilling activity in the surrounding area that the facility services, resulting in a lower supply of condensate requiring stabilization as well as opening up capacity for on-spec NGLs at other facilities that had not historically been available to our customers. We expect to see volumes decline at our Live Oak stabilizer from 7,428 and 7,051 barrels per day during the twelve months ended June 30, 2017 and the year ended December 31, 2016, respectively, to 5,944 barrels per day for the twelve months ending September 30, 2018. While we are forecasting reduced activity in the area, we believe drilling and production activity will increase as commodity prices continue to stabilize and increase. Our Live Oak stabilizer is located in a strategic area of the Eagle Ford that experienced high levels of activity in the past, and we believe increased activity in that area will drive more volumes through our facility in the future.

The expected decrease in volumes at our Brownsville facility is attributable to potential downtime at certain refineries that could result in supply constraints for one of our largest customers at the Brownsville facility. As a result, we have forecasted volumes to be at the minimum volumes supported by our contracts. However, we believe we may experience increases in volumes above our contracted minimum volumes due to improved utilization at the refineries that support the majority of our current volumes.


	Year Ended December 31, 2016		Twelve Months Ended June 30, 2017		Twelve Months Ending September 30, 2018
	($ in millions)
Liquids Segment
Brownsville Terminal
Billable Throughput (Bbls/month)		570,947		612,776		532,796
Gross Margin	$	5.6	$	6.3	$	5.6
Live Oak Stabilizer & Rail Terminal
Stabilizer Volumes (Bbl/d)		7,051		7,428		5,944
Gross Margin	$	18.5	$	16.5	$	16.0
Total Liquids Segment
Gross Margin	$	24.1	$	22.9	$	21.6

We estimate that 21% of our segment gross margin in our Liquids segment for the twelve months ending September 30, 2018 will be supported by terminal service agreements with minimum service payments. If our customers deliver volumes 10% greater than those we forecast in our Liquids segment for the twelve months ending September 30, 2018, we expect our estimated distributable cash flow attributable to OpCo would increase 2%, or $1.7 million, to $106.7 million. If volumes delivered for the twelve months ending September 30, 2018 are 10% below our forecasted volumes, we expect our estimated distributable cash flow attributable to OpCo would decrease 2%, or $1.6 million, to $103.4 million.

Cost of products sold in our Liquids segment primarily comprises off-spec and on-spec NGL purchases made directly from our suppliers and then processed and remarketed to various customers. The costs of these NGL purchases vary due to changes in market prices, volumes purchased and the differentials we offer to our customers. For the twelve months ending September 30, 2018, we estimate that cost of products sold in our Liquids segment will be $52.9 million, as compared to $58.3 million for the twelve months ended June 30, 2017. The decrease in cost of products sold in our Liquids segment corresponds to an overall decline in purchased volumes at our Live Oak stabilizer. The expected increase of cost of products sold in our Liquids segment to $52.9 million for the twelve months ending September 30, 2018 as compared to $47.6 million for the year ended December 31, 2016 is attributable to an estimated increase in commodity prices related to natural gas and NGL sales at our Live Oak stabilizer, partially offset by an overall decline in purchased volumes at our Live Oak stabilizer. However, because we buy and sell rich residue gas, NGLs and stabilized condensate based on a fixed differential to index pricing by component, increases in cost of products sold will generally correspond to an increase in revenue.

Commodity Price Assumptions

We estimate that the price of natural gas, NGLs and condensate for the twelve months ending September 30, 2018 will average $3.08 MMBtu at Henry Hub, $0.65 per gallon at Mont Belvieu and $1.05 per gallon at Mont Belvieu, respectively. The Henry Hub natural gas pricing assumptions are based on average futures contracts pricing as of July 17, 2017 for each respective commodity for the twelve months ending September 30, 2018. The Mont Belvieu NGL and condensate pricing assumptions are based on the expected composition of components, with individual component pricing assumptions based on average futures contracts pricing as of July 17, 2017 for each respective commodity for the twelve months ending September 30, 2018.

We expect that 98% of the segment gross margin generated by our Natural Gas segment for the twelve months ending September 30, 2018 will be related to fee-based revenue or fixed-margin arrangements, and only 2% of segment gross margin will be directly exposed to commodity prices. Our marketing businesses primarily buy and sell natural gas on fixed differentials to index prices.

We also expect that 100% of the segment gross margin generated by our Liquids segment for the twelve months ending September 30, 2018 will be related to fee-based revenue or fixed-margin arrangements. Our Live Oak stabilizer purchases on-spec and off-spec NGLs and sells rich natural gas, NGLs and condensate by hydrocarbon component on a fixed differential to index pricing. Because we currently generate the substantial majority of our revenues pursuant to long-term, fee-based agreements that include minimum volume commitments, our limited direct commodity price exposure relates primarily to the small percentage-of-proceeds component we earn under some of our gathering and processing contracts. Our limited direct commodity price exposure also relates to (i) our purchase of on-spec and off-spec NGLs by our Live Oak stabilizer, and (ii) our purchase and sale of natural gas and NGLs by our marketing companies. However, due to the back-to-back arrangements we enter for these transactions, we believe this risk is substantially mitigated.

Operations and Maintenance Expense

Our operations and maintenance expenses include labor costs, compressor and equipment rental costs, utility costs, insurance premiums, taxes and other operating costs. We estimate that we will incur operating

expenses of approximately $43.4 million for the twelve months ending September 30, 2018 as compared to $39.3 million for the twelve months ended June 30, 2017 and $41.7 million for the year ended December 31, 2016. The increase in operations and maintenance expenses as compared to the twelve months ended June 30, 2017 and the year ended December 31, 2016 primarily relates to costs associated with the continued development of our northeast gathering assets.

Depreciation and Amortization Expense

We estimate depreciation and amortization expense for the twelve months ending September 30, 2018 of approximately $56.6 million as compared to $56.2 million for the twelve months ended June 30, 2017 and $55.2 million for the year ended December 31, 2016. Estimated depreciation and amortization expense reflects management’s estimates, which are based on consistent average depreciable asset lives and depreciation methodologies. The increase in depreciation and amortization expense primarily relates to the development of our northeast gathering assets.

General and Administrative Expenses

Our general and administrative expenses will consist of (i) direct general and administrative expenses incurred by us and (ii) an annual fee we pay to our sponsor for the provision of general and administrative services under our omnibus agreement.

We expect total OpCo-incurred general and administrative expenses for the twelve months ending September 30, 2018 will be $14.4 million, as compared to $22.5 million for the twelve months ended June 30, 2017 and $25.1 million for the year ended December 31, 2016. The decline in general and administrative expenses as compared to the twelve months ended June 30, 2017 primarily relates to $6.3 million in non-recurring equity compensation expenses and $2.1 million in non-recurring transaction and litigation expenses that occurred in the twelve months ended June 30, 2017. The decline in general and administrative expenses as compared to the year ended December 31, 2016 primarily relates to $7.7 million in non-recurring equity compensation expenses and $3.4 million in non-recurring transaction and litigation expenses that occurred in the year ended December 31, 2016.

For the twelve months ending September 30, 2018, we also expect the partnership to incur approximately $3.0 million of estimated annual incremental general and administrative expenses as a result of being a publicly traded partnership, which includes expenses associated with: annual and quarterly reports to unitholders; tax return and Schedule K-1 preparation and distribution; Sarbanes-Oxley Act compliance expenses; expenses associated with listing on the NYSE; independent auditor fees; legal fees; investor relations activities; registrar and transfer agent fees; incremental director and officer liability insurance expenses; and director compensation.

Capital Expenditures

The midstream energy business is capital intensive, requiring the maintenance of existing gathering systems and other midstream assets and facilities and the acquisition or construction and development of new gathering systems and other midstream assets and facilities. We estimate that total capital expenditures attributable to OpCo for the twelve months ending September 30, 2018 will be $16.2 million (approximately $ million net to our ownership interest in OpCo) based on the following assumptions.

•

Maintenance capital expenditures. We estimate that our maintenance capital expenditures will be approximately $3.5 million (approximately $ million net to our ownership interest in OpCo) for the twelve months ending September 30, 2018 compared to an average of $1.3 million per year during the period from 2013 to 2016. The types of expenditures we expect to incur include cash expenditures (including the replacement or improvement of existing capital assets) made to maintain, over the long term, our operating capacity, operating income or revenue. The substantial majority of our assets were constructed within the last 5 years and therefore do not currently require significant maintenance capital expenditures. As our assets age, we expect maintenance capital expenditures to increase.

•

Expansion capital expenditures. We estimate that our expansion capital expenditures will be approximately $12.7 million (approximately $ million net to our ownership interest in OpCo) for the twelve months ending September 30, 2018. The types of expenditures we expect to incur include cash expenditures to construct new midstream infrastructure and those expenditures incurred in order to reduce costs, increase revenues or increase system throughput or capacity from current levels.

•

Tioga System. The majority of our expected expansion capital expenditures relates to $11.8 million to expand and upgrade the Tioga system, one of our northeast gathering assets. The first phase of the Tioga system was placed into service in December 2016. The second phase of the system, comprised of approximately two miles of pipeline and 8,875 horsepower of compression, is expected to be placed into service in the third quarter of 2017. Once in service, Southwestern Energy will pay us fees on actual and minimum committed volumes delivered from central delivery points in the Marcellus Shale formation into a major interstate natural gas pipeline that delivers gas to the East Coast and other downstream markets. We expect to fund our share of the $11.8 million of expansion capital expenditures related to the expansion and upgrades to our Tioga system with borrowings under our revolving credit facility.

•

Northeast Gathering Lateral. We are also forecasting to spend $0.7 million to construct approximately four miles of pipe to transport natural gas from new well pads on our Greenzweig system. We expect this expansion to allow us to transport an additional 45-50 MMcf/d once the wells are completed, which we expect to occur in the second half of 2017.

While we do not currently anticipate, and our forecast does not reflect, any acquisitions during the twelve months ending September 30, 2018, our management will continue to evaluate potential growth opportunities through accretive acquisition from time to time, and we may elect to pursue such acquisitions during the forecast period. However, we cannot assure you that we will be able to identify attractive acquisition opportunities or, if identified, that we will be able to negotiate acceptable purchase agreements.

Financing

At the closing of this offering, we expect to enter into a new $ million revolving credit facility. We expect to fund our $ million share of the remaining expansion capital expenditures during the forecast period with borrowings under our revolving credit facility. As of September 30, 2018, we expect outstanding borrowings of $ million under our new revolving credit facility. We expect that the unused portion of the new revolving credit facility will be subject to a commitment fee equal to the amount of the unused portion times an applicable margin of 0.375%. As a result, we have assumed interest rates of 3.2% and 0.375% on drawn and undrawn portions of our new revolving credit facility, respectively, during the forecast period. The 3.2% assumed interest rate for outstanding borrowings is based on LIBOR plus the applicable margin of 1.75% based on our estimated borrowings.

Regulatory, Industry and Economic Factors

Our forecast of distributable cash flow for the twelve months ending September 30, 2018 is also based on the following significant assumptions related to regulatory, industry and economic factors:

•

there will not be any new foreign, federal, state or local regulation, or any interpretation of existing regulation, of the portions of the midstream energy industry in which we operate that will be materially adverse to our business;

•

there will not be any material accidents, weather-related incidents, unscheduled downtime or similar unanticipated events with respect to our assets;

•

there will not be a shortage of skilled labor; and

•

there will not be any material adverse changes in the midstream energy industry, commodity prices, capital markets or overall economic conditions.

PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS

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 , 2017, we distribute all of our available cash to unitholders of record on the applicable record date. We will adjust the amount of our distribution for the period from the closing of this offering through , 2017, based on the actual length of the period.

Definition of Available Cash

Available cash generally means, for any quarter, all cash and cash equivalents on hand at the end of that quarter:

•

less, the amount of cash reserves established by our general partner to:

•

provide for the proper conduct of our business (including reserves for our future capital expenditures, future acquisitions and anticipated future debt service requirements);

•

comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation to which we or any of our subsidiaries is a party or by which we or such subsidiary is bound or we or such subsidiary’s assets are subject; or

•

provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for distributions pursuant to this bullet point if the effect of such reserves will prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for the current quarter);

•

plus, cash distributions received after the end of the quarter from any equity interest in any person (other than a subsidiary of us), which distributions are paid by such person in respect of operations conducted by such person during such quarter;

•

plus, if our general partner so determines, all or any portion of the cash (i) on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter or (ii) available to be borrowed as a working capital borrowing as of the date of determination of available cash with respect to such quarter.

The purpose and effect of the last bullet point above is to allow our general partner, if it so decides, to use cash from working capital borrowings made after the end of the quarter to pay distributions to unitholders. Under our partnership agreement, working capital borrowings are generally borrowings incurred under a credit facility, commercial paper facility or similar financing arrangement that are used solely for working capital purposes or to pay distributions to our partners and with the intent of the borrower to repay such borrowings within twelve months with funds other than from additional working capital borrowings.

Intent to Distribute the Minimum Quarterly Distribution

Under our current cash distribution policy, we intend to make a minimum quarterly distribution to the holders of our common units and subordinated units of $ per unit, or $ per unit on an annualized basis, to the extent we have sufficient available cash after the establishment of cash reserves and the payment of costs and

expenses, including reimbursements of expenses to our general partner. 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—Our Credit Agreement.”

General Partner Interest

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 will initially own the incentive distribution rights and may in the future own common units or other equity interests in us and will be entitled to receive distributions on any such interests.

Incentive Distribution Rights

Our incentive distribution rights represent the right to receive increasing percentages, up to a maximum of 50.0%, of the available cash we distribute from operating surplus (as defined below) in excess of $ per unit per quarter. The aggregate maximum distribution of 50.0% does not include any distributions that the holders of our incentive distribution rights may receive on common or subordinated units that they own. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest. Please read “—Incentive Distribution Rights” below.

Operating Surplus and Capital Surplus

General

All cash distributed to unitholders will be characterized as either being paid from “operating surplus” or “capital surplus.” We treat distributions of available cash from operating surplus differently than distributions of available cash from capital surplus.

Operating Surplus

We define operating surplus as:

•

$ million (as described below); plus

•

an amount equal to the aggregate amount of cash collected with respect to accounts receivable distributed to our sponsor prior to the closing of this offering; plus

•

all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions (as defined below) and the termination of hedge contracts, provided that cash receipts from the termination of a commodity hedge or interest rate hedge prior to its scheduled settlement or 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; plus

•

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

•

cash distributions (including incremental distributions on incentive distribution rights) paid in respect of equity issued, other than equity issued in this offering, to finance all or a portion of expansion capital expenditures in respect of the period from the date that we enter into a binding obligation to commence the construction, development, replacement, improvement or expansion of a capital asset and ending on 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 (including incremental distributions on incentive distribution rights) paid in respect of equity issued, other than equity issued in this offering, to pay interest and related fees on debt incurred, or to pay distributions on equity issued, to finance the expansion capital expenditures referred to in the prior bullet point; 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.

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 operations. For example, it includes a provision that will enable us, if we choose, to distribute as operating surplus up to $ million of 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 repayments are made. However, if working capital borrowings, which increase operating surplus, are not repaid during the twelve-month period following the borrowing, they will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowings are in fact repaid, they will not be treated as a further reduction in operating surplus because operating surplus will have been previously reduced by the deemed repayment.

We define interim capital transactions as (i) borrowings, refinancings or refundings of indebtedness (other than working capital borrowings and items purchased on open account or for a deferred purchase price in the ordinary course of business) and sales of debt securities, (ii) sales of equity securities, (iii) sales or other dispositions of assets, other than sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business and sales or other dispositions of assets as part of normal asset retirements or replacements and (iv) capital contributions received by us and our subsidiaries.

We define operating expenditures as all of our cash expenditures, including, but not limited to, taxes, reimbursements of expenses of our general partner and its affiliates, officer, director and employee compensation, debt service payments, payments made in the ordinary course of business under interest rate hedge contracts and commodity hedge contracts (provided that payments made in connection with the termination of any interest rate hedge contract or commodity hedge contract prior to its scheduled 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 and amounts paid in connection with the initial purchase of an interest rate hedge contract or a commodity hedge contract will be amortized over the life of such interest rate hedge contract or commodity hedge contract), maintenance capital expenditures (as discussed in further detail below), and repayment of working capital borrowings; provided, however, that operating expenditures will not include:

•

repayments 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;

•

expansion capital expenditures;

•

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

•

distributions to our partners;

•

repurchases of partnership interests (excluding repurchases we or our general partner make to satisfy obligations under employee benefit plans); or

•

any other expenditures or payments using the proceeds from 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;

•

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; and

•

capital contributions received.

Characterization of Cash Distributions

All available cash distributed by us on any date from any source will be treated as distributed from operating surplus until the sum of all available cash distributed by us 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. We anticipate that distributions from operating surplus generally will not represent a return of capital. However, operating surplus, as defined in our partnership agreement, includes certain components, including a $ million cash basket, that represent non-operating sources of cash. Consequently, it is possible that all or a portion of specific distributions from operating surplus may represent a return of capital. Any available cash distributed by us in excess of our cumulative operating surplus will be deemed to be capital surplus under our partnership agreement. Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering and as a return of capital. We do not anticipate that we will make any distributions from capital surplus.

Capital Expenditures

Maintenance capital expenditures are cash expenditures (including the replacement or improvement of existing capital assets) made to maintain, over the long term, our operating capacity, operating income or revenue. Examples of maintenance capital expenditures are expenditures to repair, refurbish and replace pipelines and storage tanks, to maintain equipment reliability, integrity and safety and to comply with environmental laws and regulations. In addition, we designate a portion of our capital expenditures to maintain throughput as maintenance capital to the extent such capital expenditures are necessary to maintain, over the long term, our operating capacity, operating income or revenue.

compressor stations, in each case to the extent such capital expenditures are expected to expand our operating capacity, operating income or revenue. In the future, if we make acquisitions that increase system throughput or capacity, the associated capital expenditures may also be considered expansion capital expenditures. Expansion capital expenditures include interest payments (and related fees) on debt incurred to finance all or a portion of expansion capital expenditures in respect of the period from the date that we enter into a binding obligation to commence the construction, development, replacement, improvement or expansion of a capital asset and ending on the earlier to occur of the date that such capital improvement commences commercial service and the date that such capital improvement is disposed of or abandoned.

As described above, expansion capital expenditures are not operating expenditures, and thus will not reduce operating surplus.

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

Subordinated Units and 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 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. Subordinated units are deemed “subordinated” because for a period of time, referred to as the “subordination period,” the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters. Furthermore, no arrearages will accrue or be payable on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that, during the subordination period, there will be available cash to be distributed on the common units.

Subordination Period

Except as described below, the subordination period will begin on the closing date of this offering and will extend until the first business day following the distribution of available cash in respect of any quarter beginning after , 2020, that each of the following tests are met:

•

distributions of available cash from operating surplus on each of the outstanding common units 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 units and subordinated units on a fully diluted basis; and

•

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

For the period after closing of this offering through , 2017, our partnership agreement will prorate the minimum quarterly distribution based on the actual length of the period, and use such prorated distribution for all purposes, including in determining whether the test described above has been satisfied.

Early Termination of the Subordination Period

Notwithstanding the foregoing, the subordination period will automatically terminate on the first business day following the distribution of available cash in respect of any quarter, beginning with the quarter ending , 2018, that each of the following tests are met:

•

distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded $ (150% of the annualized minimum quarterly distribution), plus the related distributions on incentive distribution rights, 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 150% of the sum of (i) $ (the annualized minimum quarterly distribution) on all of the outstanding common units and subordinated units during that period on a fully diluted basis and (ii) the corresponding distributions on the incentive distribution rights; and

•

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

Expiration of the Subordination Period

When the subordination period ends, each outstanding subordinated unit will convert into one common unit and will thereafter 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 drawdowns of reserves of cash established in prior periods. Adjusted operating surplus for a period consists of:

•

operating surplus generated with respect to that period (excluding any amounts attributable to the item described in the first bullet under the caption “—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 decrease made in subsequent periods to cash reserves for operating expenditures initially established with respect to that period to the extent such decrease results in a reduction in adjusted operating surplus in subsequent periods; 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.

Distributions of Available Cash from Operating Surplus During the Subordination Period

We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

•

first, 100% to the common unitholders, pro rata, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;

•

second, 100% to the common unitholders, pro rata, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;

•

third, 100% to the subordinated unitholders, pro rata, until we distribute for each outstanding subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

•

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

The preceding discussion is based on the assumption that we do not issue additional classes of equity securities.

Distributions of Available Cash from Operating Surplus After the Subordination Period

We will make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:

•

first, 100% to all common unitholders, pro rata, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter; and

•

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

The preceding discussion is based on the assumption that that we do not issue additional classes of equity securities.

Incentive Distribution Rights

Incentive distribution rights represent the right to receive an increasing percentage (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 will initially hold the incentive distribution rights, but may transfer these rights separately from its general partner interest. The following discussion assumes that our general partner continues to own the incentive distribution rights.

If for any quarter:

•

we have distributed available cash from operating surplus to the common unitholders 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, we will distribute any additional available cash from operating surplus for that quarter among the unitholders and our general partner in the following manner:

•

first, 100% to all unitholders, pro rata until each unitholder receives a total of $ per unit for that quarter (the “first target distribution”);

•

second, 85% to all unitholders, pro rata, and 15% to our general partner, until each unitholder receives a total of $ per unit for that quarter (the “second target distribution”);

•

third, 75% to all unitholders, pro rata, and 25% to our general partner, until each unitholder receives a total of $ per unit for that quarter (the “third target distribution”); and

•

thereafter, 50% to all unitholders, pro rata, and 50% to our general partner.

Percentage Allocations of Available Cash from Operating Surplus

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our general partner and the

unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution per Unit Target Amount.” The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner assume that our general partner has not transferred its incentive distribution rights and that there are no arrearages on common units.


	Total Quarterly Distribution Per Unit Target Amount		Marginal Percentage Interest in Distributions
	Total Quarterly Distribution Per Unit Target Amount		Unitholders			General Partner
Minimum Quarterly Distribution	$			100	%		—
First Target Distribution	above $	up to $		100	%		—
Second Target Distribution	above $	up to $		85	%		15	%
Third Target Distribution	above $	up to $		75	%		25	%
Thereafter	above $			50	%		50	%

General Partner’s Right to Reset Incentive Distribution Levels

Our general partner, as the initial holder of our incentive distribution rights, has the right under our partnership agreement, subject to certain conditions, 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 minimum quarterly distribution amount and target distribution levels upon which the incentive distribution payments to our general partner would be set. If our general partner 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 our general partner holds all of the incentive distribution rights at the time that a reset election is made.

Our general partner’s right to reset the minimum quarterly distribution amount and the target distribution levels upon which the incentive distributions payable to our general partner are based may be exercised, without approval of our unitholders or the conflicts committee, at any time when there are no subordinated units outstanding, we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distributions for each of the four consecutive fiscal quarters immediately preceding such time and the amount of each such distribution did not exceed adjusted operating surplus for such quarter. If our general partner and its affiliates are not the holders of a majority of the incentive distribution rights at the time an election is made to reset the minimum quarterly distribution amount and the target distribution levels, then the proposed reset will be subject to the prior written concurrence of the general partner that the conditions described above have been satisfied. The reset minimum quarterly distribution amount and target distribution levels will be higher than the minimum quarterly distribution amount and the target distribution levels prior to the reset such that the holder of the incentive distribution rights will not receive any incentive distributions under the reset target distribution levels until cash distributions per unit following this event increase as described below. We anticipate that our general partner 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 to our general partner.

In connection with the resetting of the minimum quarterly distribution amount and the target distribution levels and the corresponding relinquishment by our general partner of incentive distribution payments based on the target distributions prior to the reset, our general partner will be entitled to receive a number of newly issued common units based on a predetermined formula described below that takes into account the “cash parity” value of the average cash distributions related to the incentive distribution rights received by our general partner for the two quarters immediately preceding the reset event as compared to the average cash distributions per common unit during that two-quarter period.

The number of common units that our general partner (or the then-holder of the incentive distribution rights, if other than our general partner) would be entitled to receive from us in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels then in effect would be equal to the quotient determined by dividing (x) the average aggregate amount of cash distributions received by our general partner in respect of its incentive distribution rights during the two consecutive fiscal quarters ended immediately prior to the date of such reset election by (y) the average of the aggregate amount of cash distributed per common unit during each of these two quarters.

Following a reset election, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election (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 distribute all of our available cash from operating surplus for each quarter thereafter as follows:

•

first, 100% to all unitholders, pro rata, until each unitholder receives an amount 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 our general partner, 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 our general partner, 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 our general partner.

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner at various cash distribution levels (1) pursuant to the cash distribution provisions of our partnership agreement in effect at the completion of this offering, as well as (2) 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 two fiscal quarters immediately preceding the reset election was $ .


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

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

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

(3)	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 our general partner with respect to its incentive distribution rights, based on an average of the amounts distributed for the two quarters 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 two consecutive non-overlapping quarters prior to the reset.

Quarterly Distribution Per
Unit
Prior to Reset

Cash Distributions to
Common Unitholders
Prior to Reset

Cash Distribution to
Our General Partner
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 our general partner in respect of its our incentive distribution rights, with respect to the quarter after the reset occurs. The table reflects that, as a result of the reset, there would be common units outstanding and that the average distribution to each common unit would be $ . The number of common units issued as a result of the reset was calculated by dividing (x) as the average of the amounts received by general partner in respect of its incentive distribution rights for the two consecutive non-overlapping quarters prior to the reset as shown in the table above, by (y) the average of the cash distributions made on each common unit per quarter for the two consecutive non-overlapping quarters prior to the reset as shown in the table above, or $ .

Cash Distributions
to Common
Unitholders After
Reset

Cash Distribution to
Our General Partner After Reset

Quarterly Distribution Per
Unit After Reset

Common
Units

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 $

Our general partner (or the holder of the incentive distribution rights, if other than our general partner) will be entitled to cause the minimum quarterly distribution amount and 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 immediately preceding 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

We will make distributions of available cash from capital surplus, if any, in the following manner:

•

first, 100% to all unitholders, pro rata, until we distribute for each common unit that was issued in this offering, an amount of available cash from capital surplus equal to the initial public offering price in this offering;

•

second, 100% to all 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 outstanding common units; and

•

thereafter, as if they were from operating surplus.

The preceding discussion is based on the assumption we do not issue additional classes of equity securities.

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. The initial public offering price less any distributions of capital surplus per unit is referred to as the “unrecovered initial unit price.” 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 corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution after any of these distributions are made, the effects of distributions of capital surplus may make it easier for our general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

Once we distribute capital surplus on a unit issued in this offering in an amount equal to the initial unit price, we will reduce the minimum quarterly distribution and the target distribution levels to zero. Then, after distributing an amount of capital surplus for each common unit equal to any unpaid arrearages of the minimum quarterly distributions on outstanding common units, we will then make all future distributions from operating surplus, with 50% being paid to the unitholders, pro rata, and 50% to the holder of our incentive distribution rights.

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 units into fewer units or subdivide our units into a greater number of units, we will proportionately adjust:

•

the minimum quarterly distribution;

•

target distribution levels;

•

the unrecovered initial unit price; and

•

the arrearages per common unit in payment of the minimum quarterly distribution on the common 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 unrecovered initial unit price would each be reduced to 50% of its initial level and each subordinated unit would be split into two units. We will not make any adjustment by reason of the issuance of additional units for cash or property (including additional common units issued under any compensation or benefit plans).

In addition, if legislation is enacted or if the official interpretation of existing law is modified by a governmental authority or if action is taken by our general partner as described under “Our Partnership Agreement—Election to be Treated as a Corporation,” so that we become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels for each quarter may be reduced by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter

(reduced by the amount of the estimated tax liability for such quarter payable by reason of such legislation or interpretation) and the denominator of which is the sum of available cash for that quarter (reduced by the amount of the estimated tax liability for such quarter payable by reason of such legislation or interpretation) plus our general partner’s estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference may be accounted for in subsequent quarters.

Distributions of Cash Upon Liquidation

General

If we dissolve in accordance with our 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 our general partner, 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 outstanding common units to a preference over the holders of outstanding subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their unrecovered 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 holders of common units 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 our general partner.

Manner of Adjustments for Gain

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

•

first, to our general partner to the extent any negative balance in its capital account;

•

second, 100% to the common unitholders, pro rata until the capital account for each common unit is equal to the sum of:

(1)

the unrecovered initial unit price;

(2)

the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and

(3)

any unpaid arrearages in payment of the minimum quarterly distribution;

•

third, 100% to the subordinated unitholders, pro rata until the capital account for each subordinated unit is equal to the sum of:

(1)

the unrecovered initial unit price; and

(2)

the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;

•

fourth, 100% to all unitholders, pro rata until we allocate under this paragraph an amount per unit equal to:

(1)

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

(2)

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 100% to the unitholders, pro rata, for each quarter of our existence;

•

fifth, 85% to all unitholders, pro rata, and 15% to our general partner, until we allocate under this paragraph an amount per unit equal to:

(1)

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

(2)

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% to the unitholders, pro rata, and 15% to our general partner for each quarter of our existence;

•

sixth, 75% to all unitholders, pro rata, and 25% to our general partner, until we allocate under this paragraph an amount per unit equal to:

(1)

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

(2)

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% to the unitholders, pro rata, and 25% to our general partner for each quarter of our existence; and

•

thereafter, 50% to all unitholders, pro rata, and 50% to our general partner.

The percentages set forth above are based on the assumption that our general partner has not transferred its incentive distribution rights and that we do not issue additional classes of equity securities.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the third bullet point above will no longer be applicable.

Manner of Adjustments for Losses

If our liquidation occurs before the end of the subordination period, after making allocations of loss to the unitholders in a manner intended to offset in reverse order the allocations of gains that have previously been allocated, we will generally allocate any loss to our unitholders in the following manner:

•

first, 100% to the 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, 100.0% to the holders of common units in accordance with their percentage interest in us, until the capital accounts of the common unitholders have been reduced to zero; and

•

thereafter, 100% to our general partner.

The percentages set forth above are based on the assumption that we do not issue additional classes of equity securities.

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.

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 tax

100

purposes, unrecognized gain resulting from the adjustments to the unitholders and the general partner 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. In 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 units 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.

101

SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA

The following table presents selected historical financial data of our Predecessor and selected unaudited pro forma financial data of Howard Midstream Partners, LP for the periods and as of the dates indicated. The following selected historical financial data of our sponsor consists of all of the assets and operations of our Predecessor on a 100% basis. In connection with the closing of this offering, our sponsor will contribute to us a 100% interest in OpCo GP and a % limited partnership interest in OpCo, which will own substantially all of our sponsor’s current assets and operations. As required by GAAP, we will consolidate 100% of the assets and operations of OpCo in our financial statements for so long as we continue to have a controlling financial interest in OpCo.

The selected historical financial data of our Predecessor as of and for the years ended December 31, 2016 and 2015, and as of June 30, 2017 and for the six months ended June 30, 2017 and 2016, is derived from the audited and unaudited consolidated financial statements of our Predecessor appearing elsewhere in this prospectus. The following table should be read together with, and is qualified in its entirety by reference to, the historical audited, historical unaudited interim and unaudited pro forma consolidated financial statements and the accompanying notes included elsewhere in this prospectus. The table should also be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The selected unaudited pro forma financial data presented in the following table for the year ended December 31, 2016 and as of and for the six months ended June 30, 2017 are derived from the unaudited pro forma consolidated financial statements included elsewhere in this prospectus. The unaudited pro forma consolidated balance sheet assumes the offering and the related transactions occurred as of June 30, 2017, and the unaudited pro forma consolidated statements of operations for the year ended December 31, 2016 and the six months ended June 30, 2017 assume the offering and the related transactions occurred as of January 1, 2016. These transactions include, and the unaudited pro forma consolidated financial statements give effect to, the following:

•

the contribution by our sponsor of certain of its operating subsidiaries to OpCo;

•

our sponsor’s contribution to us of a % limited partnership interest in OpCo;

•

our assumption of the outstanding balance of $ million under the term loan portion of our sponsor’s credit facility;

•

the consummation of this offering and our issuance of (i) common units to the public and (ii) common units and subordinated units to our sponsor;

•

the application of the net proceeds of this offering as described in “Use of Proceeds”;

•

our entry into a new $ million revolving credit facility; and

•

our entry into an omnibus agreement with our sponsor.

102

Large accelerated filer

Accelerated filer

Non-accelerated filer

☒ (Do not check if a smaller reporting company)

Smaller reporting company

Emerging Growth Company ☒

The following table presents the non-GAAP financial measures of Adjusted EBITDA and gross margin, which we use in our business as important supplemental measures of our performance. Adjusted EBITDA and gross margin are not financial measures defined by GAAP. We explain these measures under “—Non-GAAP Financial Measures” below and reconcile them to their most directly comparable financial measures calculated and presented in accordance with GAAP.


	Predecessor Historical								Pro Forma
	Year Ended December 31,				Six Months Ended June 30,				Year Ended December 31, 2016		Six Months Ended June 30, 2017
	2016		2015		2017		2016		Year Ended December 31, 2016		Six Months Ended June 30, 2017
	(in thousands, except per unit data)
Statements of Operations Data
Total operating revenues	$	246,650	$	320,839	$	124,878	$	130,687	$	242,041	$	119,280
Operating costs and expenses:
Cost of products sold (excluding depreciation and amortization)		79,366		147,039		38,146		42,659		79,366		38,146
Operations and maintenance		45,325		42,184

Howard Midstream Partners, LP S-1