Amendment No. 5 to Form S-1

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Emerging growth company

S-1/A 1 d596284ds1a.htm AMENDMENT NO. 5 TO FORM S-1 Amendment No. 5 to Form S-1

As filed with the Securities and Exchange Commission on April 4, 2019

Registration No. 333-226645

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Amendment No. 5

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

RATTLER MIDSTREAM LP

(formerly known as Rattler Midstream Partners LP)

(Exact Name of Registrant as Specified in Its Charter)


Delaware	4922	83-1404608
(State or Other Jurisdiction of Incorporation or Organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification Number)

500 West Texas Avenue

Suite 1200

Midland, Texas 79701

(432) 221-7400

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

Teresa L. Dick

Chief Financial Officer

515 Central Park Drive

Suite 500

Oklahoma City, Oklahoma 73105

(405) 463-6900

(Name, address, including zip code and telephone number, including area code, of agent for service)

Copies to:

Seth R. Molay, P.C.
Akin Gump Strauss Hauer & Feld LLP
2300 N. Field Street, Suite 1800
Dallas, TX 75201
(214) 969-4780

John Goodgame

Akin Gump Strauss Hauer & Feld LLP

1111 Louisiana Street, 44^th Floor
Houston, TX 77002
(713) 220-8144

J. Michael Chambers

John M. Greer

Latham & Watkins LLP

811 Main Street, Suite 3700

Houston, Texas 77002

(713) 546-5400

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

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

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

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a 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. (Check one):

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 accounting standards provided pursuant to Section 7(a)(2)(B) of the Securities Act. ☒

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

The information in this preliminary prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary 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 APRIL 4, 2019

PRELIMINARY PROSPECTUS

LOGO

Rattler Midstream LP

Common Units

Representing Limited Partner Interests

This is the initial public offering of common units representing limited partner interests in Rattler Midstream LP. We are offering common units in this offering. Prior to this offering, there has been no public market for our common units.

We expect that the initial public offering price will be between $ and $ per common unit. We have applied to list our common units on The Nasdaq Global Select Market, or Nasdaq, under the symbol “RTLR.” We are an “emerging growth company” as that term is used in the Jumpstart Our Business Startups Act of 2012, or the JOBS Act.

Even though we are organized as a limited partnership under state law, we will be treated as a corporation for U.S. federal income tax purposes. Accordingly, we will be subject to U.S. federal income tax at regular corporate rates on our net taxable income and distributions we make to holders of our common units will be taxable as ordinary dividend income to the extent of our current and accumulated earnings and profits as computed for U.S. federal income tax purposes.

Investing in our common units involves risk. Please read “Risk Factors” beginning on page 29.

These risks include the following:

•

We derive substantially all of our revenue from Diamondback Energy, Inc., or Diamondback. If Diamondback changes its business strategy, alters its current drilling and development plan on our dedicated acreage, or otherwise significantly reduces the volumes of crude oil, natural gas, produced water or fresh water with respect to which we perform midstream services, our revenue would decline and our business, financial condition, results of operations, cash flow and ability to make distributions to our common unitholders would be materially and adversely affected.

•

Our cash flow will be entirely dependent upon the ability of our subsidiary, Rattler Midstream Operating LLC, to make cash distributions to us.

•

Diamondback owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates, including Diamondback, have conflicts of interest with us and limited duties, and they may favor their own interests to the detriment of us and our common unitholders.

•

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

•

Our partnership agreement restricts the remedies available to our common unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty.

•

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.

Unitholders will experience immediate and substantial dilution in pro forma net tangible book value of $ per common unit.


	Per Common Unit	Total
Price to the public	$	$
Underwriting discount(1)	$	$
Proceeds to Rattler Midstream LP (before expenses)	$	$

(1)	We refer you to “Underwriting” beginning on page 193 of this prospectus for additional information regarding underwriting compensation.

The underwriters may purchase up to an additional common units from us at the public offering price, less the underwriting discount, within 30 days from the date of this prospectus to cover over-allotments.

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.

The underwriters expect to deliver the common units on or about , 2019 through the book-entry facilities of The Depository Trust Company.

Joint Book-Running Managers


Credit Suisse	BofA Merrill Lynch	J.P. Morgan
Barclays		Citigroup
Goldman Sachs & Co. LLC		Wells Fargo Securities

Senior Co-Managers


Capital One Securities				Scotia Howard Weil
SunTrust Robinson Humphrey				UBS Investment Bank

Co-Managers


Evercore ISI	Morgan Stanley		RBC Capital Markets
Simmons Energy \| A Division of Piper Jaffray^SM			Tudor, Pickering, Holt & Co.
Raymond James	Seaport Global Securities		Northland Capital Markets
PNC Capital Markets LLC		TD Securities

Prospectus dated , 2019

TABLE OF CONTENTS


	Page
PROSPECTUS SUMMARY		1

Overview		1
Our Assets		6
Permian Overview		8
Our Competitive Strengths		12
Our Business Strategies		14
Our Emerging Growth Company Status		15
Risk Factors		16
The Transactions		17
Ownership and Organizational Structure		18
Management		19
Principal Executive Offices and Internet Address		19
Summary of Conflicts of Interest and Fiduciary Duties		19
The Offering		21
Summary Historical and Pro Forma Financial Data		26
Non-GAAP Financial Measures		28

RISK FACTORS		29

Risks Related to Our Business		29
Risks Inherent in an Investment in Us		49
Risks Related to Taxation		60

USE OF PROCEEDS		61

CAPITALIZATION		62

DILUTION		63

CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS		65

Unaudited Pro Forma EBITDA and Distributable Cash Flow for the Year Ended December 31, 2018		67
Estimated EBITDA and Distributable Cash Flow for the Twelve Months Ending March 31, 2020		70

HOW WE MAKE DISTRIBUTIONS		78

Our Sources of Cash		78
Rattler LLC Units		78
Common Units		79
Class B Units		79
General Partner Interest		79

SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA		80

Non-GAAP Financial Measures		82

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		83

Overview		83
Our Business		83
How We Generate Revenue		85
How We Evaluate Our Operations		86
Factors Affecting the Comparability of Our Financial Results		87
Other Factors Impacting Our Business		89
Results of Operations		90
Capital Resources and Liquidity		92
Off-Balance Sheet Arrangements		93
Contractual Obligations		93
Critical Accounting Policies		93
Inflation		95
Qualitative and Quantitative Disclosures About Market Risk		95

INDUSTRY OVERVIEW		96

Crude Oil Midstream Industry		96
Natural Gas Midstream Industry		97
Produced, Flowback and Fresh Water Services Industry		98
Market Fundamentals		99
Permian Overview		106

BUSINESS		110

Overview		110
Our Assets		111
Diamondback Energy, Inc.		116
Our Acreage Dedication		119
Our Commercial Agreements with Diamondback		120
Title to Our Properties		122
Competition		123
Regulation of Operations		123
Environmental Matters		126
Employees		133
Insurance		134
Facilities		134
Legal Proceedings		134


	Page

MANAGEMENT		135

Management of Rattler Midstream LP		135
Executive Officers and Directors of Our General Partner		136
Director Independence		138
Committees of the Board of Directors		138
Indemnification Agreements		139

EXECUTIVE COMPENSATION AND OTHER INFORMATION		140

Long-Term Incentive Plan		141
Director Compensation		145

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT		146

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS		149

Distributions and Payments to Our General Partner and Its Affiliates		149
Agreements with our Affiliates in Connection with the Transactions		150
Procedures for Review, Approval and Ratification of Related Person Transactions		153

CONFLICTS OF INTEREST AND FIDUCIARY DUTIES		155

Conflicts of Interest		155
Fiduciary Duties		159

DESCRIPTION OF OUR UNITS		162

Common Units and Class B Units		162
Jury Trial Waiver		162
Transfer Agent and Registrar		162
Resignation or Removal		163
Transfer of Common Units and Class B Units		163
Exchange Listing		163

OUR PARTNERSHIP AGREEMENT		164

Organization and Duration		164
Purpose		164
Capital Contributions		164
Voting Rights		164
Class B Units		165
Limited Liability		166
Issuance of Additional Partnership Interests		167
Amendment of the Partnership Agreement		167
Prohibited Amendments		167
Opinion of Counsel and Unitholder Approval		169
Merger, Consolidation, Conversion, Sale or Other Disposition of Assets		169
Dissolution		170
Liquidation and Distribution of Proceeds		170
Withdrawal or Removal of Our General Partner		170
Transfer of General Partner Interest		171
Transfer of Ownership Interests in the General Partner		171
Change of Management Provisions		171
Limited Call Right		172
Non-Taxpaying Holders; Redemption		172
Non-Citizen Assignees; Redemption		172
Meetings; Voting		173
Status as Limited Partner		173
Indemnification		174
Reimbursement of Expenses		174
Books and Reports		174
Right to Inspect Our Books and Records		175
Registration Rights		175
Applicable Law; Forum, Venue and Jurisdiction		175

RATTLER LLC LIMITED LIABILITY COMPANY AGREEMENT		177

Organization and Duration		177
Purpose		177
Capital Contributions		177
Management; Voting Rights		177
Limited Liability		177
Applicable Law; Forum, Venue and Jurisdiction		178
Issuance of Additional Membership Interests		178
Transfer of Rattler LLC Units		179
Distributions and Allocations		179
Amendment of the Limited Liability Company Agreement		179
Dissolution		179
Liquidation and Distribution of Proceeds		180
Withdrawal or Removal of the Managing Member		180
Indemnification		180
Books and Reports		180


	Page

UNITS ELIGIBLE FOR FUTURE SALE		181

Rule 144		181
Our Partnership Agreement		181
Registration Rights Agreement		181
Lock-Up Agreements		182
Registration Statement on Form S-8		182

UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS		183

Corporate Status		184
Consequences to U.S. Holders		184
Consequences to Non-U.S. Holders		185
Distributions		185
Gain on Disposition of Common Units		186
Backup Withholding and Information Reporting		187
Additional Withholding Requirements under FATCA		187

INVESTMENT IN RATTLER MIDSTREAM LP BY EMPLOYEE BENEFIT PLANS		189

UNDERWRITING		193

Directed Unit Program		196
Other Relationships		197
Selling Restrictions		197

LEGAL MATTERS		199

EXPERTS		199

WHERE YOU CAN FIND ADDITIONAL INFORMATION		200

CAUTIONARY STATEMENT REGARDING FORWARD -LOOKING STATEMENTS		201

INDEX TO FINANCIAL STATEMENTS		F-1

APPENDIX A—FORM OF AGREEMENT OF LIMITED PARTNERSHIP OF RATTLER MIDSTREAM LP		A-1

APPENDIX B—FORM OF AGREEMENT OF LIMITED LIABILITY COMPANY OF RATTLER MIDSTREAM OPERATING LLC		B-1

APPENDIX C—GLOSSARY OF TERMS		C-1

You should rely only on the information contained in this prospectus or in any free writing prospectus prepared by or on behalf of us or to which we have referred you. We have not, and the underwriters have not, authorized any other person to provide you with information different from that contained in this prospectus and any free writing prospectus. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. Neither the delivery of this prospectus nor sale of our common units means that information contained in this prospectus is correct after the date of this prospectus. Our business, financial condition, results of operations and prospects may have changed since that date. We will update this prospectus as required by law.

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 “Cautionary Statement Regarding Forward-Looking Statements.”

Industry and Market Data

The data included in this prospectus regarding the midstream industry, including descriptions of trends in the market, are based on a variety of sources, including independent industry publications, government publications and other published independent sources and publicly available information, as well as our good faith estimates, which have been derived from management’s knowledge and experience in our industry. Although we have not independently verified the accuracy or completeness of the third party information included in this prospectus, based on management’s knowledge and experience, we believe that the third party sources are reliable and that the third party information included in this prospectus or in our estimates is accurate and complete as of the dates presented.

iii

PROSPECTUS SUMMARY

This summary highlights selected information contained elsewhere in this prospectus. This summary does not contain all of the information that you should consider before investing in our common units. You should carefully read the entire prospectus, including “Risk Factors” and the historical 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 29 for more information about important factors that you should consider before purchasing our common units.

References in this prospectus to “our predecessor,” “we,” “our,” “us” or like terms when used in a historical context refer to the assets and interests owned by Rattler LLC (as defined below) at the closing of this offering. When used in the present tense or prospectively, “the partnership,” “we,” “our,” “us” or like terms refer to Rattler Midstream LP (formerly Rattler Midstream Partners LP) and its subsidiaries, including Rattler LLC, after giving effect to the transactions that will occur at the closing of this offering. Except where expressly noted otherwise, references in this prospectus to “our sponsor” or “Diamondback” refer to Diamondback Energy, Inc. (Nasdaq: FANG) and its subsidiaries other than Rattler Midstream LP and its subsidiaries (including Rattler LLC). References in this prospectus to “Rattler LLC” refer to Rattler Midstream Operating LLC (formerly Rattler Midstream LLC). References in this prospectus to “our general partner” refer to Rattler Midstream GP LLC, a wholly-owned subsidiary of Diamondback. Upon completion of this offering, we will own an approximate % controlling managing member interest in Rattler LLC (or an approximate % controlling managing member interest in Rattler LLC if the underwriters exercise in full their option to purchase additional common units) and we will consolidate Rattler LLC in our financial statements. Unless otherwise specifically noted, financial results and operating data are shown on a 100% basis and are not adjusted to reflect Diamondback’s non-controlling interest in Rattler LLC. References in this prospectus to “our executive officers” and “our directors” refer to the executive officers and directors of our general partner, respectively. 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 C-1 of this prospectus.

Rattler Midstream LP

Overview

We are a growth-oriented Delaware limited partnership formed in July 2018 by Diamondback to own, operate, develop and acquire midstream infrastructure assets in the Midland and Delaware Basins of the Permian Basin, or the Permian, one of the most prolific oil producing areas in the world. Immediately following this offering, we expect to be the only publicly-traded, pure-play Permian midstream company focused on the Midland and Delaware Basins. We provide crude oil, natural gas and water-related midstream services (including fresh water sourcing and transportation and saltwater gathering and disposal) to Diamondback under long-term, fixed-fee contracts. As of January 1, 2019, the assets Diamondback has contributed to us include a total of 746 miles of pipeline across the Midland and Delaware Basins with a total of approximately 232,000 Bbl/d of crude oil gathering capacity, 2.685 MMBbl/d of permitted saltwater disposal, or SWD, capacity, 550,000 Bbl/d of fresh water gathering capacity, 53,500 Mcf/d of natural gas compression capability and 342,000 Mcf/d of natural gas gathering capacity. In addition to the midstream infrastructure assets that Diamondback contributed to us, we own equity interests in two long-haul crude oil pipelines, which, upon completion, will run from the Permian to the Texas Gulf Coast. We are critical to Diamondback’s growth plans because we provide a long-term midstream solution to its increasing crude oil, natural gas and water-related services needs through our robust infield gathering systems and SWD capabilities.

Our general partner’s management team consists of members of the management teams of Diamondback and the general partner of Viper Energy Partners LP (Nasdaq: VNOM), or Viper. We will elect to be treated as a

corporation for tax purposes because we expect that such treatment will expand the potential investor base for our units and will provide our unitholders with more liquidity and improve, if necessary, our access to capital. Unlike some traditional midstream entity structures, we do not have incentive distribution rights or subordinated units, so the economic interests of our common unitholders and our sponsor are aligned. We believe that our relationship with Diamondback and our common strategic and operational interests differentiate us in the public midstream sector and provide the optimal platform to pursue a balanced plan for future growth that benefits all unitholders equally. Immediately following this offering, we will have no outstanding indebtedness, and we do not plan on accessing the capital markets to fund our current organic growth opportunities.

We are Diamondback’s primary provider of midstream gathering and water-related services and are integral to Diamondback’s strategy of being a premier, low-cost, high-growth operator that can grow production at industry leading rates within cash flow. Each of our operating agreements contains a 15-year acreage dedication, or, collectively, the Acreage Dedication, from Diamondback that spans a total of approximately 423,000 gross acres across all service lines on Diamondback’s core leasehold in the Permian (a total of approximately 217,000 gross acres in the Midland Basin and a total of approximately 206,000 gross acres in the Delaware Basin). In this prospectus, we refer to the aggregate acreage subject to the Acreage Dedication as the Dedicated Acreage. We entered into commercial agreements with Diamondback that have initial terms ending in 2034. The fees charged under these agreements are based on market prevailing rates at the time of their implementation with annual escalators (subject to potential adjustment by regulators). These fixed-fee contracts, along with Diamondback’s strong well economics, extensive horizontal drilling inventory and low-cost operating model, minimize our direct exposure to commodity prices while providing us with stable and predictable cash flow over the long-term. In February 2019, we acquired a 10% equity interest in the EPIC Crude Oil Pipeline, which we refer to as EPIC or the EPIC project, and a 10% equity interest in the Gray Oak Pipeline, which we refer to as Gray Oak or the Gray Oak project. Once the EPIC and Gray Oak projects are operational, which is anticipated to occur in the second half of 2019, our equity interests in the EPIC and Gray Oak projects are expected to provide us with a steady, oil-weighted cash flow stream. These pipelines will also provide Diamondback with long-term long-haul transportation capacity for a portion of its Delaware and Midland Basin crude oil production.

Diamondback commenced operations in December 2007 with the acquisition of 4,174 net acres in the Midland Basin. By May 2016, through a series of subsequent acquisitions, Diamondback had built a pure play Midland Basin position of approximately 85,000 net acres. In 2016, Diamondback entered the Delaware Basin through two acreage acquisitions totaling 95,499 net acres. In addition, on October 31, 2018, Diamondback acquired 25,493 net acres in the Midland Basin from Ajax Resources, LLC, which we refer to as the Ajax acquisition, and, on November 29, 2018, subsequently acquired approximately 89,000 and 90,000 net acres in the Delaware and Midland Basin, respectively, in connection with Diamondback’s acquisition of Energen Corporation, which we refer to as the Energen acquisition.

Our midstream operations in the Midland and Delaware Basins were established to service Diamondback’s growing production and related need for midstream infrastructure to ensure reliable, low-cost, efficient development and operational flexibility. Our wholly-owned midstream system was built on Diamondback’s Delaware Basin acreage. This opportunity complemented Diamondback’s strategy to build a sizable and scalable Delaware Basin position with contiguous acreage to create economies of scale, control the value chain on its leasehold, maintain its position as a low-cost Permian operator and avoid the transportation of liquids by truck. Our Delaware Basin midstream infrastructure provides the ability to flow fresh water to the majority of Diamondback’s Delaware Basin leasehold, providing Diamondback flexibility related to drilling, completion and production plans throughout the field. We expect Diamondback will continue to be an active driller in the Delaware Basin and will create significant production growth as a result. Additionally, we believe that the quality of Diamondback’s underlying acreage will help ensure continued development even with lower commodity prices. As of December 31, 2018, only 345 of Diamondback’s approximately 5,407 gross wells in its Delaware

Basin drilling inventory had been developed, but our currently existing infrastructure in the Delaware Basin already has enough capacity to provide midstream services for substantially all of Diamondback’s currently anticipated development.

Our midstream infrastructure systems have been designed, built and acquired to offer the scale and services to accommodate Diamondback’s full field development plan and are expected to directly benefit from Diamondback’s proven ability to execute on its operational plan and grow its crude oil and natural gas production. Our assets were recently constructed, require minimal incremental capital expenditures and, as of January 1, 2019, have the ability to transport a total of approximately 232,000 Bbl/d of crude oil, 550,000 Bbl/d of fresh water and 342,000 Mcf/d of natural gas, as well as provide 53,500 Mcf/d of natural gas compression and 2.685 MMBbl/d of SWD. We believe that our status as Diamondback’s primary provider of midstream services will generate strong free cash flow that we can use to fund our capital programs and return capital to unitholders through distributions, positioning us as a leading, high-growth, self-funding midstream services provider. We also believe that the combination of our midstream assets and the firm crude oil takeaway capacity on the EPIC and Gray Oak projects will provide Diamondback critical access to a vital long-haul takeaway solution for its planned development on its existing acreage in the Permian. Once these pipelines are operational, which is anticipated to occur in the second half of 2019, our equity interests in the EPIC and Gray Oak projects are expected to provide us with a steady cash flow stream from oil-weighted long-haul crude oil transportation. Our strategy of proactively creating an outlet for Diamondback’s growing production will drive increased volumes through our midstream systems and increase our free cash flow generation capabilities.

Diamondback Energy, Inc.

Diamondback is an independent crude oil and natural gas company focused on the acquisition, development, exploration and exploitation of unconventional, onshore crude oil and natural gas reserves in the Permian in west Texas. This basin, which is one of the most prolific oil producing areas in the world, is characterized by an extensive production history, a favorable operating environment, long reserve life, multiple producing horizons, enhanced recovery potential and a large number of operators. Diamondback is listed on Nasdaq under the symbol “FANG” and had a market capitalization of approximately $17 billion as of March 31, 2019.

Diamondback began operations in December 2007 with its acquisition of 4,174 net acres in the Permian. Since its formation, Diamondback has made several accretive acquisitions, including the Ajax acquisition and the Energen acquisition in 2018. As of December 31, 2018, Diamondback’s total position in the Permian was approximately 461,000 net acres (195,000 net acres in the Midland Basin, 170,000 net acres in the Delaware Basin and 96,000 net acres in other areas of the Permian). In addition, Viper owns mineral interests underlying approximately 14,841 net royalty acres, primarily in the Midland and Delaware Basins, of which approximately 37% are operated by Diamondback. Diamondback owns Viper Energy Partners GP LLC, the general partner of Viper, and approximately 59% of the limited partner interests in Viper. Our structure as a partnership that will elect to be treated as a corporation for tax purposes will be similar to that of Viper. From their first full years as public companies in 2012 and 2014, respectively, through year end 2018, Diamondback’s and Viper’s production increased by a compound annual growth rate, or CAGR, of 88% and 54%, respectively, and proved reserves increased by a CAGR of 71% and 36%, respectively. Despite low commodity prices over the last two years (average crude oil price of approximately $51 per barrel in 2017 and approximately $65 per barrel in 2018), Diamondback grew its year-over-year production by 84% in 2017 and 65% in 2018 due to its peer leading operating metrics as evidenced by its cash operating costs of $8.33 per Boe over the same two-year period.

Diamondback Acquisition Track Record (2012 – December 31, 2018)

LOGO

The graph below shows Diamondback’s net Midland and Delaware Basin production and drilling activity from the quarter ended March 31, 2015 through the quarter ended December 31, 2018, and demonstrates the impact that its horizontal drilling program has had on its Midland and Delaware Basin production. A number of factors impact Diamondback’s production and drilling activity, including the number of drilling rigs that Diamondback operates on its acreage. See “Risk Factors—Risks Related to Our Business.”

Diamondback and Viper Net Production and Cumulative Wells Drilled

LOGO

(1)	Viper not included in cumulative wells drilled.

(2)	Viper and Diamondback production includes non-operated production.

As of December 31, 2018, Diamondback had identified approximately 10,000 gross economic potential horizontal drilling locations at $60 per barrel of oil, and the table below shows that the significant majority of those locations may remain economic at materially lower oil prices. Moreover, we believe that Diamondback’s location estimate is conservative relative to peer Permian operator spacing assumptions and there is still significant resource upside from additional zone delineation, downspacing and optimization of estimated ultimate recoveries, or EURs, through advanced drilling and completion techniques. Approximately 58% of Diamondback’s gross identified economic potential horizontal drilling locations at December 31, 2018 had

lateral lengths of at least 7,500 feet, with approximately 3,550 drilling locations in the Midland Basin and 2,768 drilling locations in the Delaware Basin.

Diamondback’s Horizontal Drilling Locations at Various Crude Oil Prices as of December 31, 2018


	Assumed crude oil price ($ / Bbl)(1)
Gross well count	$	40.00	$	50.00	$	55.00	$	60.00

Midland		2,639		4,530		5,231		5,479
Delaware		2,334		4,173		4,615		4,758

Total		4,973		8,703		9,846		10,237

Implied rig years(2)		17		29		33		34

(1)	Locations assumed to be economic at $3 per Mcf of natural gas and a 10% internal rate of return.

(2)	Assuming Diamondback completes 300 gross wells per year while running approximately 21 rigs in 2019.

As of December 31, 2018, Diamondback’s estimated proved crude oil and natural gas reserves were 992 MMBoe (approximately 65% proved developed producing). As of December 31, 2018, Diamondback’s estimated proved reserves were approximately 63% oil, 18% natural gas and 19% natural gas liquids, all in the Permian.

Diamondback produced, on average on a consolidated basis, 130.4 MBoe/d, in the Permian during the year ended December 31, 2018, with 72% of such volumes being crude oil. Our midstream operations in the Delaware Basin were established to service Diamondback’s growing production associated with its horizontal drilling program. Since our predecessor’s operations began in 2016, Diamondback’s overall horizontal production in the Delaware Basin has grown from an average of 0.307 net MBoe/d for the year ended December 31, 2016 to 31.1 net MBoe/d for the year ended December 31, 2018, an increase of 10,022%.

The table below shows Diamondback’s Permian drilling activities for the periods presented.


	Year Ended December 31,
	2016		2017		2018
Midland Basin
Number of wells completed		62		104		117
Approximate average lateral feet per horizontal well		8,378		9,328		9,394
Production (MBoe/d)		33.6		53.2		77.3
Delaware Basin
Number of wells completed		—		19		59
Approximate average lateral feet per horizontal well		—		7,306		9,187
Operated production (MBoe/d)		0.3		11.8		31.1
Total Permian (Midland and Delaware Basins)
Number of wells completed		62		123		176
Approximate average lateral feet per horizontal well		8,378		9,016		9,325
Operated production (MBoe/d)		33.9		64.9		108.4
Viper production (MBoe/d)		6.4		11.0		17.3
Nonoperated/other production (MBoe/d)		2.7		3.3		4.8
Consolidated production (MBoe/d)		43.0		79.2		130.4

Management believes that Diamondback is an operational and cost leader in the Permian with a track record of achieving robust production growth within cash flow and, beginning in 2018, was at the forefront of returning cash to shareholders through dividends. As of December 31, 2018, Diamondback was targeting over 27% annual production growth in 2019 and believed its asset base could support growth for multiple years at current commodity prices.

In connection with the completion of this offering, we will (i), in exchange for a $1.0 million cash contribution from Diamondback, issue Class B Units to Diamondback, representing an aggregate % voting limited partner interest in us (or an aggregate % voting limited partner interest in us if the underwriters exercise in full their option to purchase additional common units), (ii) issue a general partner interest in us to our general partner, in exchange for a $1.0 million cash contribution from our general partner, and (iii) cause Rattler LLC to use a portion of the net proceeds from this offering to make a distribution of approximately $ million to Diamondback. Diamondback, as the holder of the Class B Units, and the general partner, as the holder of the general partner interest, are entitled to receive cash preferred distributions equal to 8% per annum on the outstanding amount of their respective $1.0 million capital contributions, payable quarterly. Please read “—The Offering,” “Use of Proceeds,” “Security Ownership of Certain Beneficial Owners and Management,” “Certain Relationships and Related Party Transactions—Distributions and Payments to Our General Partner and Its Affiliates,” “Risk Factors—Risks Inherent in an Investment in Us” and “Conflicts of Interest and Fiduciary Duties.”

Our Assets

As of January 1, 2019, we own and operate a total of 746 miles of crude oil gathering pipelines, natural gas gathering pipelines and a fully integrated water system on acreage that overlays Diamondback’s seven core Midland and Delaware Basin development areas, which are characterized as areas with high concentrations of wells and undeveloped drilling locations with at least one bench with an EUR in excess of one million barrels of oil equivalent for a 7,500-foot lateral per type curves approved by Diamondback’s independent reserve engineer. Our water system sources and distributes fresh water for use in drilling and completion operations and collects flowback and produced water, which we refer to collectively as saltwater, for recycling and disposal. We also own a 10% equity interest in each of the EPIC and Gray Oak projects, long-haul crude oil pipelines under development that we expect, following commencement of operations, will provide us with a steady, oil-weighted cash flow stream. These pipelines will also provide Diamondback with long-term long-haul transportation capacity for a portion of its Delaware and Midland Basin crude oil production. These pipelines will provide Diamondback a total takeaway capacity of up to 200,000 Bbl/d.

The transportation of water and hydrocarbon volumes away from the producing wellhead is paramount to ensuring the efficient operations of a crude oil or natural gas well. To facilitate this transportation, our midstream infrastructure was built to include a network of gathering pipelines that collect and transport crude oil, natural gas, fresh water and produced water from Diamondback’s operations in the Midland and Delaware Basins. These assets are predominately located in Pecos, Reeves, Ward, Midland, Howard, Andrews, Martin and Glasscock Counties and have a total of approximately 232,000 Bbl/d of crude oil gathering capacity, 342,000 Mcf/d of natural gas gathering capacity, 53,500 Mcf/d of natural gas compression capability, 2.685 MMBbl/d of SWD capacity and 550,000 Bbl/d of fresh water gathering capacity as of January 1, 2019.

Crude oil and natural gas gathering and transportation assets

As of January 1, 2019, our crude oil and natural gas gathering system covers a total of approximately 270 miles. As of January 1, 2019, we have a total of approximately 101 miles of crude oil pipelines, 232,000 Bbl/d of crude oil gathering capacity, 79,000 Bbl of crude oil storage, 169 miles of natural gas pipelines, 342,000 Mcf/d of natural gas gathering capacity and 53,500 Mcf/d of natural gas compression capability. Our crude oil and natural gas gathering and transportation system is purpose built with firm capacity on intermediary pipelines providing

connections to long-haul pipelines that terminate on the Texas Gulf Coast. Our crude oil and natural gas gathered volumes averaged 68.4 MBoe/d for the quarter ended December 31, 2018. For the year ended December 31, 2018, our crude oil and natural gas gathered volumes averaged approximately 53.9 MBoe/d. Our Acreage Dedication along with our commercial agreements and operating footprint will allow us to capture the majority of the incremental production volumes associated with Diamondback’s horizontal drilling program.

Saltwater gathering and disposal assets

Crude oil and natural gas cannot be produced without significant produced water transport and disposal capacity given the high water volumes produced alongside the hydrocarbons. Produced water volumes are of particular importance in the Delaware Basin where the average well produces four to six barrels of water for every one barrel of crude oil while the average Midland Basin well produces one to two barrels of water for every one barrel of crude oil. At the well site, crude oil and produced water are separated to extract the crude oil for sale and the produced water for proper disposal and recycling. As of January 1, 2019, we own strategically located produced water gathering pipeline systems spanning a total of approximately 389 miles that connect approximately 2,500 crude oil and natural gas producing wells to our SWD well sites. As of January 1, 2019, we have a total of 122 SWD wells with an aggregate capacity of 2.685 MMBbl/d located across the Midland and Delaware Basins. Diamondback has instituted a program in its operations in the Delaware Basin and Spanish Trail acreage in the Midland Basin to use treated water for 15% to 30% of the water used during completion operations, which may be between 8,250 and 16,500 Bbl/d per completion crew operating in each field, as Diamondback traditionally uses 55,000 Bbl/d per completion crew. We expect to realize increased margins for SWD as a result of this recycling program.

Fresh water sourcing and distribution assets

Our fresh water sourcing and distribution system, with storage capacity of 43.2 MMBbl as of January 1, 2019, is critical to Diamondback’s completion operations, and distributes water from fresh water wells sourced from the Capitan Reef formation, Edwards-Trinity, Pecos Alluvium and Rustler aquifers in the Permian. Our fresh water system consists of a combination of permanent buried pipelines, portable surface pipelines and fresh water storage facilities, as well as pumping stations to transport the fresh water throughout the pipeline network. To the extent necessary, we will move surface pipelines to service completion operations in concert with Diamondback’s drilling program. Having access to fresh water sources is an important element of the hydraulic fracturing process in the Delaware Basin because modern completion methods require significantly more fresh water relative to the Midland Basin. To hydraulically fracture a 10,000 foot well, Diamondback currently estimates that approximately 425,000 barrels of water are required in the Midland Basin and approximately 650,000 barrels of water are required in the Delaware Basin. Because hydraulic fracturing relies on substantial volumes of fresh water, we believe our fresh water distribution services will be in high demand as Diamondback proceeds with its full field development plan over the next several years.

The following table provides information regarding our gathering, compression and transportation system as of December 31, 2018 and utilization for the quarter ended December 31, 2018.

Pipeline Infrastructure Assets


(miles)	Delaware Basin		Midland Basin		Permian Total
Crude oil		58		43		101
Natural gas		169		—		169
SWD		197		192		389
Fresh water		26		61		87

Total		450		296		746


(capacity/capability)	Delaware Basin		Midland Basin		Permian Total		Utilization
Crude oil (Bbl/d)		176,000		56,000		232,000		28.1	%
Natural gas compression (Mcf/d)		53,500		—		53,500		61.5	%
Natural gas pipeline (Mcf/d)		342,000		—		342,000		21.9	%
SWD (MMBbl/d)		1.266		1.419		2.685		31.7	%
Fresh water (Bbl/d)		120,000		430,000		550,000		60.9	%

Investments in long-haul crude oil pipelines

We own a 10% equity interest in the EPIC project, a long-haul crude oil pipeline that, upon completion, will be capable of transporting approximately 600,000 Bbl/d, which, with the installation of additional pumps and storage, can be increased to approximately 900,000 Bbl/d, from the Permian and the Eagle Ford Shale to Corpus Christi, Texas. This pipeline will provide Diamondback a total takeaway capacity of up to 100,000 Bbl/d.

We also own a 10% equity interest in the Gray Oak project, a long-haul crude oil pipeline that, upon completion, will be capable of transporting 900,000 Bbl/d from the Permian and the Eagle Ford Shale to points along the Texas Gulf Coast, including a marine terminal connection in Corpus Christi, Texas. This pipeline will provide Diamondback a total takeaway capacity of up to 100,000 Bbl/d.

Once these projects are operational, which is anticipated to occur in the second half of 2019, our equity interests in the EPIC and Gray Oak projects are expected to provide us with a steady cash flow stream from oil-weighted long-haul crude oil transportation. These long-haul crude oil pipelines will terminate in the refinery-dense, export-focused Texas Gulf Coast market, allowing Diamondback access to premium Texas Gulf Coast pricing as opposed to discounted local pricing at Midland, Texas, which recently fell to a low of negative $17.90 per barrel differential relative to WTI in August 2018.

Permian Overview

The Permian is one of the most prolific crude oil and natural gas basins in the world and spans approximately 75,000 square miles across west Texas and southeast New Mexico, encompassing several sub-basins, including the Midland Basin and the Delaware Basin. The Permian has a history of over 90 years of conventional crude oil and natural gas production and is characterized by high crude oil and liquids rich natural gas, multiple horizontal target horizons, extensive production history, long-lived reserves and high drilling success rates. The region has produced over 29 billion barrels of oil and 75 trillion cubic feet of natural gas, with remaining reserve estimates significantly exceeding these totals with the addition of shale resources. Unconventional shale development has led to the resurgence in development activity and Permian crude oil production has tripled from approximately one MMBbl/d to three MMBbl/d over the last ten years, with forecasted growth to over five MMBbl/d by the end of 2022.

Remaining Resources by Play and WTI Breakeven – Top Oil-Weighted U.S. Basins⁽²⁾

LOGO

(1)	Permian total includes only resources in the Delaware and Midland Basins.

(2)	Locations assumed to be economic at $3 per Mcf of natural gas and a 10% internal rate of return.

The Permian has a gross hydrocarbon column thickness of up to 3,800 feet, with multiple prospective unconventional reservoir targets across the basin. The “stacked-pay” nature of the Permian allows for the development of multiple horizontal wells from a single surface location, creating a “multiplier” effect for operated acreage values and further enhancing individual well economics due to shared infrastructure. In the Delaware Basin, operators are currently targeting up to ten benches in the Wolfcamp, Bone Springs and Avalon formations, while Midland Basin operators currently target up to eight different horizons across the Wolfcamp, Spraberry and Jo Mill formations. At current activity levels, there are more than 50 years of economic inventory remaining at current commodity prices. The Permian enjoys a favorable regulatory and operating environment, particularly in Texas, and features long-lived reserves, consistent geological attributes, high reservoir quality and historically high development success rates. Even during periods of low commodity prices, the Permian experienced significant growth due to high single well rates of return and industry leading breakeven prices below $35 per barrel. The Permian is the most actively developed North American play and, as of March 8, 2019, 57% (424 out of 741 total) of active onshore U.S. horizontal oil rigs were operating in the Permian according to Baker Hughes.

Permian Basin Horizontal Oil Rig Count Overview

(2012 – Current)

LOGO

Beginning in November 2014, during the recent commodity price downturn, Permian exploration and production, or E&P, companies began generally focusing on improving their operating efficiencies. Most E&P companies continue to be focused on optimizing the development of their assets through actions such as drilling longer laterals, further delineating zones, continued downspacing, using modern high intensity completion methods with local frac sand and utilizing multi-well pads. Although the Permian is already known as one of the most productive oil-weighted basins in the world, it is believed that there is still significant upside in the realizable resource potential. It is expected that many of the aforementioned techniques will further enhance crude oil and natural gas recoveries.

Operators initiated horizontal drilling programs at scale in the Midland Basin approximately three to five years earlier than they did in the Delaware Basin. As a result, the Delaware Basin is not as developed as the Midland Basin in both the upstream and midstream sectors. The graph below highlights the daily oil production of the three main basins in the Permian and illustrates that both the Midland and Delaware Basins make up an increasingly disproportionate percentage of total crude oil production in the Permian. This growth continued even through the recent period of lower crude oil prices. Additionally, the graph illustrates the Delaware Basin’s significant growth over the five year period ended September 30, 2018 in its contribution to total crude oil production in the Permian.

Permian Basin Total Daily Production (2012 – September 30, 2018)

LOGO

Crude oil production in the Permian increased at a 19% CAGR over the five year period ended September 30, 2018 and outpaced midstream infrastructure development. As a result of these supply and demand dynamics, the Midland, Texas oil differential to WTI recently fell to a low of negative $17.90 per barrel in August 2018, from a 2018 high of positive $1.90 per barrel in January. The development of midstream infrastructure to alleviate takeaway constraints continues to be a prevalent strategy in the Permian. Diamondback’s firm capacity on the EPIC and Gray Oak long-haul crude oil pipelines will help insulate it from future pricing dynamics in the local Midland, Texas market and, once operational, our equity investment in these pipelines is also expected to provide us with a steady cash flow stream from oil-weighted long-haul crude oil transportation.

Produced water is a natural byproduct of the crude oil and natural gas production process and is a particular focus in the water-heavy Permian. E&P companies are required to recycle or dispose of produced water associated with crude oil and natural gas production in an environmentally responsible manner. Produced water is water naturally trapped in subsurface formations and is brought to the surface during crude oil and natural gas exploration and production. Produced water is by far the largest volume byproduct stream associated with crude oil and natural gas exploration and production. Although produced water is a significant issue that operators have to address in both the Midland and Delaware Basins, the issue is much larger in the Delaware Basin. Delaware Basin wells generate approximately four to six barrels of produced water for every barrel of oil, while Midland Basin wells produce approximately one to two barrels of produced water for every barrel of oil. This difference in produced water production in Delaware Basin wells highlights the importance of having robust produced water infrastructure assets to support crude oil and natural gas production. We believe that in order for E&P companies to bring their hydrocarbons to market, they need to transport produced water efficiently using pipelines rather than trucks. Our purpose-built saltwater gathering, disposal and recycling system is designed to handle gathering

of up to 2,027 MBbl/d of produced water, allowing Diamondback to more efficiently develop its acreage and grow production on our Dedicated Acreage.

Fresh water acts as the primary carrier fluid in the hydraulic fracturing process that is used to complete horizontal wells and serves to open fissures in targeted geologic formations in order to allow the flow of hydrocarbons. Because the multi-stage fracturing of a single horizontal unconventional well can use several million gallons of fresh water, it is critical that large quantities of relatively fresh water be readily available in an uninterruptable stream throughout the completion operations. High intensity modern completion methods that are being implemented across the Permian utilize more proppant and require larger volumes of fresh water for hydraulic fracturing than earlier generation completion methods. Access to fresh water sources is critical to the completions process and there are a limited number of sources in the Permian, particularly in the Delaware Basin. We source our fresh water from the Capitan Reef formation, Edwards-Trinity, Pecos Alluvium and Rustler aquifers in the Permian. We believe that having reliable access to fresh water that can be transported by pipeline is essential for large scale production in the Delaware Basin because the average Diamondback well in the Delaware Basin requires approximately 650,000 barrels of water per well, compared to approximately 425,000 barrels of water per well in the Midland Basin.

Our Competitive Strengths

We have a number of competitive strengths that we believe will help us to successfully execute our business strategies, including:

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Fundamental, strategic relationship with Diamondback. We are integral to Diamondback’s strategy of remaining a premier, low-cost Permian operator that can grow production at peer leading rates within cash flow. The fundamental role we play in Diamondback’s operational success allows us to capitalize on our sponsor’s expected Permian production growth and strong track record of accretive acquisitions. We plan to build our midstream infrastructure in concert with and in advance of Diamondback’s expected production growth ramp in order to allow Diamondback the operational flexibility to execute on its growth plan. We are the primary provider of midstream services to Diamondback with an Acreage Dedication that spans a total of approximately 423,000 gross acres across all of our service lines and over the core of the Midland and Delaware Basins. We believe that Diamondback will continue its strong growth trajectory as a result of its management expertise, premier asset base with a deep inventory of economic potential horizontal drilling locations, well capitalized balance sheet and operational execution track record. As such, we expect Diamondback’s production growth will drive our free cash flow growth profile. Our capital expenditure programs will be tied directly to Diamondback’s activity. Our visibility into Diamondback’s drilling and production plans will allow us to utilize a synchronized midstream development plan that optimizes capital spending and free cash flow generation. We also believe our currently underutilized, high-capacity midstream systems, which originate at the wellhead and will access the Texas Gulf Coast export and refinery market through the EPIC and Gray Oak projects, in which we have a 10% equity interest, will facilitate the execution of Diamondback’s high-growth development program.

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Experienced management team with an extensive track record of value creation. The management team of our general partner consists of executives from Diamondback and the general partner of Viper, and we believe their significant experience, successful track record of shareholder-friendly value creation and discipline in deploying capital at Diamondback and Viper distinguish us from our peers. Over the past four years, Diamondback and Viper have generated returns on capital employed that demonstrate an efficient use of capital. Since their initial public offerings in 2012 and 2014 through December 31, 2018, Diamondback and Viper have outpaced guidance and peer performance on a per share basis, growing production by 4,327% and 616%, respectively, and reserves by 2,367% and 515%, respectively. Additionally, our general partner’s management team has a demonstrated history of returning capital to investors. Viper has grown its distribution rate per common unit by approximately 104% since its initial

public offering and, in February 2018, Diamondback became the first E&P company traded on the New York Stock Exchange or Nasdaq to announce the initiation of a quarterly dividend since 2007. We believe that the growth-oriented approach, expertise and success in the Permian of our general partner’s management team will help us deliver attractive unitholder returns.

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Asset base located in the core of the Permian with highly visible underlying production growth. At the closing of this offering, we expect to be the only publicly traded pure-play Permian midstream company focused on the Midland and Delaware Basins. As of January 1, 2019, we have a total of 746 miles of pipelines across the Midland and Delaware Basins with a total of approximately 232,000 Bbl/d of crude oil gathering capacity, 53,500 Mcf/d of natural gas compression capability, 342,000 Mcf/d of natural gas gathering capacity, 2.685 MMBbl/d of SWD capacity and 550,000 Bbl/d of fresh water gathering capacity, all located in what we believe is the core of the Midland and Delaware Basins of the Permian and overlaying Diamondback’s seven core development areas. These areas are characterized by high return single well economics that are among the best in the Lower 48 and a deep inventory of economic horizontal drilling locations. From its first full year as a public company through year end 2018, Diamondback has grown its production and reserves by CAGRs of 88% and 71%, respectively. Our strategically located assets provide critical midstream infrastructure for Diamondback’s multi-year organic development plan, and we expect to benefit directly from Diamondback’s proven ability to execute on its operational plan and grow production. Diamondback has one of the largest Permian acreage positions among independent E&P operators, with 461,000 net acres (195,000 net acres in the Midland Basin, 170,000 net acres in the Delaware Basin and 96,000 net acres in other areas of the Permian) as of December 31, 2018. Diamondback also has exposure to approximately 10,000 gross identified potential horizontal drilling locations as of December 31, 2018 that are economic at an oil price of $60 per barrel. In addition, mineral assets owned by Diamondback and by Viper, which is controlled by Diamondback, overlay part of our acreage, providing additional uplift to Diamondback’s single well economics. Diamondback has publicly stated that it plans to grow 2019 year-over-year production by 27%. Since the beginning of 2015, Diamondback’s cumulative cash flow has more than offset drilling, completion, equipment, infrastructure and dividend spending and it has demonstrated the ability to produce strong growth while efficiently deploying capital. We expect to benefit disproportionately as Diamondback accelerates its development of the Delaware Basin. The core location of our assets and the close proximity to other leading E&P operators provide additional opportunities to execute third party contracts for midstream services.

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Structural and strategic alignment with unitholders. We are focused on creating differentiated unitholder value and providing strong return on and return of capital to unitholders, which are core founding principles and have been demonstrated by both Diamondback and Viper since their respective initial public offerings. Diamondback and Viper have each shown a commitment to a return of capital through their distributions at Viper and, beginning in 2018, quarterly dividends at Diamondback. Through its ownership of Class B Units in us and its ownership of membership interests in Rattler LLC, or Rattler LLC Units, Diamondback will be our largest unitholder and at the closing of this offering, will have an approximate % ownership interest in us and Rattler LLC (or an approximate % ownership interest in us and Rattler LLC if the underwriters exercise in full their option to purchase additional common units), and will own 100% of our general partner. As a result, Diamondback will directly benefit if and to the extent that we grow free cash flow and distributions. Unlike some traditional midstream incentive structures, we do not have incentive distribution rights or subordinated units, which we believe will better align the interests of our unitholders with those of our sponsor. Additionally, we are structured as a partnership that will elect to be treated as a corporation for tax purposes, which we expect will increase stability and create a more liquid trading market for our common units, given our access to a potentially broader unitholder base. We believe that our relationship with Diamondback and resulting alignment of strategic and operational interests is a differentiator in the public midstream sector and provides the optimal platform to pursue a balanced plan for future growth that benefits all unitholders equally.

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High-margin business that generates significant, predictable free cash flow. Our revenue is generated as a result of our commercial agreements, which are fee-based and, as of January 1, 2019, include dedications of acreage in the Delaware Basin (a total of approximately 206,000 gross acres) and the Midland Basin (a total of approximately 217,000 gross acres). The fees charged under our commercial agreements are based upon the prevailing market rates at the time of execution with annual escalators (subject to potential adjustment by regulators). We believe our commercial agreements with Diamondback, which have initial terms ending in 2034, provide exposure to Diamondback’s leading growth profile with no direct commodity price exposure, thus enhancing the predictability of free cash flow and our performance. The current throughput of our assets relative to Diamondback’s total capacity positions us well to increase transported volumes as Diamondback increases production pursuant to its development program. As of December 31, 2018, only 345 of Diamondback’s approximately 5,407 gross wells in its Delaware Basin drilling inventory had been developed, providing decades of drilling inventory at current commodity prices that will drive volume growth on our systems. We believe that the operational leverage from increased utilization, along with minimal incremental capital expenditures to meet Diamondback’s anticipated volumes, will result in significant long-term free cash flow generation that supports a self-funding model which includes the return of capital to unitholders through a distribution.

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Financial flexibility and conservative capital structure. We have a conservative capital structure that we believe will provide us with the financial flexibility to execute our business strategies. Immediately upon completion of this offering, we expect to have no outstanding indebtedness and $ million of liquidity, including $600 million of available borrowings under Rattler LLC’s undrawn revolving credit facility. We believe that our significant liquidity and strong capital structure will allow us to execute our strategy of self-funding capital expenditures and distributions to our unitholders while limiting our reliance on the capital markets.

Our Business Strategies

Our primary objective is to increase unitholder value by executing the following business strategies:

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Grow by leveraging our strategic relationship with Diamondback and through accretive acquisitions. Diamondback, with its strong credit profile and well-capitalized balance sheet, including $702 million of liquidity as of December 31, 2018, is well positioned to pursue its growth-oriented upstream development strategy. Our provision of midstream services to Diamondback is an integral component of that strategy and critical to Diamondback’s success. Since its initial public offering in 2012, Diamondback has made nine significant acquisitions for a total of nearly $16 billion and expanded its acreage position in the Permian from approximately 51,000 net acres to approximately 461,000 net acres as of December 31, 2018, an increase of over 804%. Diamondback intends to utilize cash from distributions that it receives from Rattler LLC in part to fund its drilling and completion activities and drive additional production growth, which we believe will further support our growth strategy. We expect to grow organically with Diamondback as it increases production on the Dedicated Acreage, participate with Diamondback in acquisitions that contain midstream infrastructure and source additional acreage dedications from Diamondback and third-party producers and/or acquire complementary midstream assets on our own when these opportunities align with our strategic plan and are accretive to unitholders.

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Serve as the primary provider of midstream services for Diamondback. We own and operate midstream infrastructure assets that handle the majority of Diamondback’s midstream gathering and water-related needs in the Midland and Delaware Basins. Our midstream assets were built or acquired to support Diamondback’s multi-year growth with minimal incremental capital expenditures. For the quarter ended December 31, 2018, the average utilization of our crude oil and natural gas gathering systems was 25%. Diamondback has dedicated a total of approximately 423,000 gross acres across all service lines through the Acreage Dedication. Pursuant to this dedication, we will continue to provide (i) fresh water

sourcing, transportation and delivery, (ii) saltwater gathering, transportation and disposal, (iii) crude oil gathering, transportation and delivery and (iv) natural gas gathering, compression, transportation and delivery services for Diamondback until 2034, when each agreement will automatically renew on a year-to-year basis unless terminated by either us or Diamondback no later than 60 days prior to the end of the initial term or any subsequent one-year term thereafter. We expect that Diamondback’s production, and therefore its need for midstream services, will grow on the Dedicated Acreage from the continual development of its core areas and we intend to utilize this relationship with Diamondback to drive free cash flow growth and the payment of distributions to our unitholders.

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Focus on free cash flow generation to fund our capital plan, support our distribution policy and maximize unitholder returns. Our growth will be underpinned by high-margin, stable cash flow as a result of our long-term, fixed-fee contracts with Diamondback. In addition, other than our equity investments for the development of the EPIC and Gray Oak projects, we expect to have low future capital expenditure requirements, which will allow us to self-fund our capital program and make distribution payments to our unitholders. A core component of our strategy is to maximize free cash flow while maintaining a debt to equity ratio below 2.0.

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Emphasize providing midstream services under long-term, fixed-fee contracts to avoid direct commodity price exposure, mitigate volatility and enhance stability of our cash flow. Our commercial agreements with Diamondback are structured as 15-year, fixed-fee contracts, which mitigates our direct exposure to commodity prices and enhances stability and predictability of our cash flow. We intend to pursue future opportunities that primarily utilize fixed-fee structures to insulate our cash flow from direct commodity price exposure.

Our Emerging Growth Company Status

Because our predecessor had less than $1.07 billion in revenue during its last fiscal year, we qualify as an “emerging growth company” as defined in 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:

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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;

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

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

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exemption from compliance with any new requirements adopted by the Public Company Accounting Oversight Board 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

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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 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, or the Exchange Act.

We have elected to take advantage of all of the applicable JOBS Act provisions, except that we will elect to opt out of the exemption that allows emerging growth companies to extend the transition period for complying with new or revised financial accounting standards (this election is irrevocable); 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 exhaustive. Please read “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.”

Risks Related to Our Business

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We derive substantially all of our revenue from Diamondback. If Diamondback changes its business strategy, alters its current drilling and development plan on our Dedicated Acreage, or otherwise significantly reduces the volumes of crude oil, natural gas, produced water or fresh water with respect to which we perform midstream services, our revenue would decline and our business, financial condition, results of operations, cash flow and ability to make distributions to our common unitholders would be materially and adversely affected.

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Our cash flow will be entirely dependent upon the ability of our subsidiary, Rattler LLC, to make cash distributions to us.

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We may not have sufficient cash to pay any quarterly distribution on our common units and, regardless whether we have sufficient cash, we may choose not to pay any quarterly distribution on our common units because the board of directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion.

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On a pro forma basis, we would not have had sufficient cash available for distribution to pay any distributions on our common units for the year ended December 31, 2018.

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The assumptions underlying the forecast of 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 distributable cash flow to differ materially from our forecast.

Risks Inherent in an Investment in Us

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Our partnership agreement restricts the remedies available to our common unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty.

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Affiliates of our general partner and Diamondback may compete with us, and do not have any obligation to present business opportunities to us except to the extent provided in separate contractual agreements, such as our commercial agreements.

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

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

Risks Related to Taxation

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We are treated as a corporation for U.S. federal income tax purposes and our cash available for distribution to our common unitholders may be substantially reduced.

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Distributions to common unitholders may be taxable as dividends.

The Transactions

Rattler LLC was formed in July 2014 by Diamondback to serve as Diamondback’s primary vehicle to support its production growth and grow its midstream business in the Permian and in any other areas in which Diamondback may operate in the future.

Rattler Midstream LP was formed in July 2018 by Rattler Midstream GP LLC, our general partner and a wholly-owned subsidiary of Diamondback, to conduct this offering and to own interests in and operate Rattler LLC following the completion of this offering. Concurrently with the completion of this offering, the following transactions will occur:

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our general partner will contribute $1.0 million in cash to us in respect of its general partner interest, which we will retain at the partnership;

•

Diamondback will contribute $1.0 million in cash to us, which we will retain at the partnership, in exchange for Class B Units and the right to receive additional Class B Units if the underwriters do not exercise in full their option to purchase additional common units;

•

Rattler LLC will issue Rattler LLC Units to Diamondback and grant to Diamondback the right to receive additional Rattler LLC Units if the underwriters do not exercise in full their option to purchase additional common units;

•

we will issue common units (or common units if the underwriters exercise in full their option to purchase additional common units) to the public pursuant to this offering;

•

we will contribute all of the net proceeds from this offering to Rattler LLC in return for a number of Rattler LLC Units equal to the number of common units issued to the public;

•

Rattler LLC will distribute a portion of the net proceeds from this offering to Diamondback and retain a portion of the net proceeds for general company purposes, including to fund future capital expenditures;

•

we, our general partner and Rattler LLC will enter into an exchange agreement with Diamondback;

•

we will enter into a registration rights agreement with Diamondback; and

•

we, our general partner and Rattler LLC will enter into a services and secondment agreement with Diamondback.

In addition, if following the expiration of the underwriter’s option to purchase additional common units such option was not fully exercised, we will (1) issue a number of Class B Units to Diamondback equal to the difference between (i) the number of common units that the underwriters would have purchased had the underwriters exercised in full such option and (ii) the number of common units that the underwriters in fact purchased pursuant to such option and (2) Rattler LLC will issue a number of Rattler LLC Units to Diamondback equal to the number of Class B Units issued.

Following completion of this offering, Diamondback will own, through its ownership of Class B Units, an approximate % voting interest in us (or an approximate % voting interest in us if the underwriters exercise in full their option to purchase additional common units) and, through its ownership of Rattler LLC Units, an approximate % economic, non-voting interest in Rattler LLC (or an approximate % economic, non-voting interest in Rattler LLC if the underwriters exercise in full their option to purchase additional common units).

Neither our general partner interest nor our Class B Units will be entitled to participate in distributions made by us, except that (i) our Class B Units will be entitled to quarterly aggregate cash preferred distributions of 8% per annum on the $1.0 million capital contribution made in respect of such units, or $0.02 million in aggregate per quarter to all Class B Units, and (ii) our general partner will be entitled to a quarterly cash preferred distribution of 8% per annum on the $1.0 million capital contribution made in respect of its general partner interest, or $0.02 million per quarter.

Ownership and Organizational Structure

The diagram below sets forth a simplified version of our organizational structure after giving effect to the transactions described above, assuming the underwriters’ option to purchase additional common units from us is not exercised.

LOGO

Diamondback Energy, Inc. Public 100% membership interest Class B Units(1) Rattler % voting interest Midstream GP LLC common units(3) % voting interest Rattler LLC Units general partner % economic non-voting interest interest(2) Rattler Midstream LP Rattler LLC Units managing member interest % economic interest Rattler Midstream Operating LLC 10% membership interest Gray Oak pipeline, LLC 100% membership interest Tall City Towers LLC 10% limited partnership interest 10% voting interest EPIC Curde Holdings GP, LLC general partner interest EPIC Crude Holdings, LP

(1)

Each Class B Unit may be exchanged, together with one Rattler LLC Unit, for one common unit. Holders of Class B Units are not entitled to receive cash distributions in respect of the Class B Units other than their pro rata portion of the cash preferred distributions equal to 8% per annum payable quarterly on the $1.0 million capital contribution made to us by Diamondback in connection with the issuance of the Class B Units.

(2)

The holder of the general partner interest is not entitled to receive cash distributions in respect of the general partner interest other than the cash preferred distributions equal to 8% per annum payable quarterly on the $1.0 million capital contribution made to us by the general partner in respect of its general partner interest.

(3)	The common units are entitled to all distributions made by us other than the preferred distributions described above to be made in respect of the Class B Units and the general partner interest, which preferred distributions will be $0.04 million per quarter in the aggregate.

Management

We are managed and operated by the board of directors and the executive officers of our general partner, Rattler Midstream GP LLC. Diamondback is the sole owner of our general partner and has the right to appoint the entire board of directors of our general partner, including the independent directors appointed in accordance with Nasdaq listing standards. 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. Many of the executive officers and directors of our general partner also currently serve in senior leadership positions at Diamondback and the general partner of Viper. Please read “Management—Executive Officers and Directors of Our General Partner.”

Our operations will be conducted through, and our operating assets will be owned by, Rattler LLC. At the completion of this offering, we will be the sole managing member of Rattler LLC and will manage and operate it and its assets. We may, in certain circumstances, contract with third parties to provide personnel in support of our operations. However, neither we nor any of our subsidiaries will have any employees. Our general partner has the sole responsibility for providing the personnel necessary to conduct our operations, whether by directly hiring employees or by obtaining the services of personnel employed by Diamondback. In addition, pursuant to the services and secondment agreement that we will enter into at the closing of this offering, certain of Diamondback’s employees will be seconded to our general partner to provide certain management and all operational services with respect to our business under the direction and control of our general partner. 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 Diamondback, 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 500 West Texas, Suite 1200, Midland, Texas, 79701, and our telephone number is (432) 221-7400. Following the completion of this offering, our website will be located at www.rattlermidstream.com. We expect to make our periodic reports and other information filed with or furnished to the U.S. Securities and Exchange Commission, or 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 Fiduciary Duties

Under our partnership agreement, our general partner has a contractual duty to manage us in a manner it believes is not adverse to the interests of our partnership. However, because our general partner is a wholly-

owned subsidiary of Diamondback, 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 Diamondback. As a result of this relationship, conflicts of interest may arise in the future between us or our unitholders, on the one hand, and our general partner or its affiliates, including Diamondback, on the other hand. Please read “Conflicts of Interest and Fiduciary 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 Diamondback and its affiliates, are not restricted from competing with us, and do not have any obligation to present business opportunities to us except to the extent provided in separate contractual agreements, such as our commercial agreements. 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 Fiduciary Duties” and “Certain Relationships and Related Party Transactions.”

We have entered into, or will enter into, various agreements with Diamondback and its affiliates in connection with this offering. While not the result of arm’s-length negotiations, we believe the terms (including rates) of these agreements with Diamondback and its affiliates are or will be generally no less favorable to either party than those that could have been negotiated with unaffiliated parties with respect to similar services. Please read “Certain Relationships and Related Party Transactions—Agreements with our Affiliates in Connection with the Transactions.”

The Offering

Common units offered to the public

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

Option to purchase additional common units

We have granted the underwriters a 30-day option to purchase up to an additional common units.

Units outstanding after this offering

common units and Class B Units (or common units and Class B Units if the underwriters exercise in full their option to purchase additional common units).

If and to the extent the underwriters do not exercise their option to purchase additional common units, in whole or in part, we will issue up to an additional Class B Units, and Rattler LLC will issue an equal number of Rattler LLC Units, to Diamondback at the expiration of the option for no additional consideration. 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 sold to the public, and a number of Class B Units equal to the number of remaining common units not purchased by the underwriters pursuant to any exercise of the option will be issued to Diamondback at the expiration of the option period for no additional consideration and Rattler LLC will issue an equal number of Rattler LLC Units to Diamondback.

Use of proceeds

We expect to receive estimated net proceeds of approximately $ million from this offering, 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 the estimated underwriting discounts and commissions and estimated offering expenses. Our estimate assumes the underwriters’ option to purchase additional common units is not exercised. We intend to contribute the net proceeds from this offering to Rattler LLC in return for a number of Rattler LLC Units equal to the number of common units issued, representing approximately % of Rattler LLC’s outstanding membership interests after this offering. Our Rattler LLC Units will entitle us to sole management control of Rattler LLC. If and to the extent that the underwriters exercise their option to purchase additional common units, we will contribute the net proceeds thereof to Rattler LLC in return for a number of Rattler LLC Units equal to the number of common units purchased pursuant to the option. We intend for Rattler LLC to (i) retain $ million of the net proceeds from this offering and (ii) distribute the remainder of the net proceeds from this offering (approximately $ million) to Diamondback, in part to reimburse Diamondback for certain capital expenditures. We intend to use the $ million of retained net proceeds from this offering for general company purposes, including to fund future capital expenditures. Please read “Use of Proceeds.”

Cash distributions

In connection with the closing of this offering, the board of directors of our general partner will adopt a cash distribution policy, which we expect to initially require us to pay quarterly distributions to common unitholders of record on the applicable record date of $ per common unit within 60 days after the end of each quarter, beginning with the quarter ending June 30, 2019. We do not expect to make distributions for the period from the completion of this offering through March 31, 2019 within 60 days after March 31, 2019. Instead, we expect to adjust our distribution for the period ending June 30, 2019 by an amount that covers the period from the closing of this offering through March 31, 2019 based on the actual number of days in that period. We do not have a legal obligation to pay distributions at any rate or at all, and there is no guarantee that we will declare or pay quarterly cash distributions to our common unitholders. If we do not have sufficient cash at the end of each quarter, we may, but are under no obligation to, borrow funds to pay the distribution established by our cash distribution policy to our common unitholders.

The board of directors of our general partner may change our cash distribution policy at any time. Our partnership agreement does not require us to pay distributions to our common unitholders on a quarterly or other basis.

The Rattler LLC limited liability company agreement will provide that, in our capacity as managing member of Rattler LLC, we may cause Rattler LLC to pay cash distributions at any time and from time to time, which distributions will be paid pro rata in respect of all outstanding Rattler LLC Units. Rattler LLC’s ability to make any such distribution will be subject to applicable law as well as any contractual restrictions, such as those under its revolving credit

facility. Please read “Cash Distribution Policy and Restrictions on Distributions.”

Under our partnership agreement and the Rattler LLC limited liability company agreement, Rattler LLC will reimburse our general partner and its affiliates, including Diamondback, for costs and expenses they incur and payments they make on our behalf. Rattler LLC will make these payments before making any distributions in respect of the Rattler LLC Units.

We will be subject to a U.S. federal income tax rate of approximately 21%; however, we expect to generate net operating losses to offset taxable income for 2019 and 2020. Accordingly, we do not expect to pay meaningful U.S. federal income taxes during those periods. We estimate that cash distributions from Rattler LLC of approximately $ million would be required to support the payment of our currently contemplated quarterly distribution for four quarters (approximately $ million per quarter). If the underwriters exercise in full their option to purchase additional common units, we estimate that cash distributions from Rattler LLC of approximately $ million would be required to support the payment of our currently contemplated quarterly distribution for four quarters (approximately $ million per quarter). Our future tax liability may be greater than expected if we do not generate net operating losses sufficient to offset taxable income or if tax authorities challenge certain of our tax positions. In order to pay any contemplated distributions to our common unitholders, we must receive cash distributions from Rattler LLC sufficient to pay U.S. federal income tax on the income allocated to us by Rattler LLC in addition to the cash necessary to pay such distributions.

Because we will own a % membership interest in Rattler LLC at the completion of this offering (or a % membership interest in Rattler LLC if the underwriters exercise in full their option to purchase additional common units), for Rattler LLC to distribute $ million in cash to us (or $ million in cash to us if the underwriters exercise in full their option to purchase additional common units), Rattler LLC must generate cash available for distribution of at least $ million.

On a pro forma basis, assuming we had completed this offering and related transactions on January 1, 2018, Rattler LLC’s unaudited pro forma cash available for distribution for the year ended December 31, 2018 would have been a deficit of approximately $ million. Therefore, Rattler LLC would not have had sufficient cash available to pay distributions on the Rattler LLC Units, and we would not have had sufficient cash available to pay distributions on our common units, for the year ended December 31, 2018.

We believe, based on our financial forecast and related assumptions included in “Cash Distribution Policy and Restrictions on Distributions—Estimated EBITDA and Distributable Cash Flow for the Twelve Months Ending March 31, 2020,” we will generate

sufficient cash available for distribution to support the payment of our initially contemplated quarterly distribution of $ per common unit (or $ per common unit on an annualized basis) on all of our common units. However, we do not have a legal obligation to pay quarterly distributions and we might not pay quarterly distributions to our common unitholders in any quarter. Our actual results of operations, cash flow and financial condition during the forecast period may vary from the forecast, and there is no guarantee that we will make quarterly cash distributions to our common unitholders at the contemplated quarterly distribution rate or at all. Please read “Cash Distribution Policy and Restrictions on Distributions.”

Subordinated units

None.

Incentive distribution rights

None.

Issuance of additional partnership interests

Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests and options, rights, warrants, appreciation rights tracking, profit and phantom interests and other derivative instruments 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, all without the approval of any limited partners. Our unitholders will not have preemptive or participation rights to purchase their pro rata share of any additional units issued. 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 on an annual or other continuing basis. Our general partner may not be removed except by a vote of the holders of at least 66 2/3% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. In addition, any vote to remove our general partner must provide for the election of a successor general partner by the holders of a majority of the outstanding units, voting together as a single class. Upon the closing of this offering, Diamondback will own Class B Units equal to an aggregate of % of the voting interest in us. This will give Diamondback the ability to prevent the removal of 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 97% of the outstanding common units and Class B Units, treated as a single class, 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 current market price as of the date that is three days

before notice of exercise of the call right is first mailed and (ii) the highest 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. (If our general partner and its affiliates reduce their collective ownership of common units and Class B Units to below 75% of the outstanding units, taken as a whole, the ownership threshold to exercise the call right will be permanently reduced to 80%.) 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 no common units and Class B Units, which collectively would constitute approximately % of the common units and Class B Units treated as a single class (excluding any common units purchased by the directors, director nominees and executive officers of our general partner and certain other individuals as selected by our general partner 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.”

U.S. federal income tax consequences

Even though we are organized as a limited partnership under state law, we will be treated as a corporation for U.S. federal income tax purposes. Accordingly, we will be subject to U.S. federal income tax at regular corporate rates on our net taxable income. For a discussion of U.S. federal tax consequences, please read “United States Federal Income Tax Considerations.”

Directed unit program

At our request, the underwriters have reserved for sale, at the initial public offering price, up to 5% of the common units being offered by this prospectus for sale to the directors, director nominees and executive officers of our general partner and certain other individuals as selected by our general partner. 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 applied to list our common stock on Nasdaq under the trading symbol “RTLR.”

Summary Historical and Pro Forma Financial Data

The following table presents summary historical financial data of our predecessor and summary unaudited pro forma financial data for Rattler Midstream LP for the periods and as of the dates indicated. The summary historical financial data of our predecessor as of and for the years ended December 31, 2017 and 2018 are derived from the audited 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 and pro forma 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.”

Upon the completion of this offering, we will own a % controlling membership interest in Rattler LLC (assuming no exercise of the underwriters’ option to purchase additional common units) and Diamondback will own, through its ownership of Rattler LLC Units, a % economic non-voting interest in Rattler LLC (assuming no exercise of the underwriters’ option to purchase additional common units). However, as required by GAAP, we will consolidate 100% of the assets and operations of Rattler LLC in our financial statements and reflect a non-controlling interest.

The summary unaudited pro forma financial data presented in the following table for the year ended December 31, 2018 is derived from the unaudited pro forma combined financial statements included elsewhere in this prospectus. The unaudited pro forma combined balance sheet data as of December 31, 2018 and the unaudited pro forma combined statements of operations and statement of cash flows data for the year ended December 31, 2018 assume the offering and the related transactions occurred as of January 1, 2018. These transactions include, and the unaudited pro forma combined financial statements give effect to, the following:

•

the contribution to us by Diamondback in relation to the Class B Units of $1.0 million in cash, which we will retain at the partnership;

•

the contribution to us by our general partner in relation to its general partner interest of $1.0 million in cash, which we will retain at the partnership;

•

our issuance of Class B Units to Diamondback and the issuance by Rattler LLC of an equal number of Rattler LLC Units to Diamondback;

•

our issuance of common units pursuant to this offering in exchange for net proceeds of approximately $ million;

•

our contribution of all of the net proceeds from this offering to Rattler LLC in return for a number of Rattler LLC Units equal to the number of common units issued;

•

Rattler LLC’s distribution of a portion of the net proceeds to Diamondback and retention of a portion of the net proceeds for general company purposes, including to fund future capital expenditures;

•

Rattler LLC’s entrance into a new $600 million revolving credit facility;

•

the acquisition of the Fasken Center by Diamondback and contribution to Rattler LLC of all the membership interests in Tall City Towers LLC, or Tall Towers, as if such transactions occurred on January 1, 2018 for the purposes of preparing the unaudited pro forma combined statement of operations (for the year ended December 31, 2017, see the Fasken Midland Statement of Revenue and Certain Expenses included elsewhere in this prospectus); and

•

the contribution to Rattler LLC by Diamondback of certain crude oil gathering, SWD wells and land and buildings Diamondback acquired pursuant to the Ajax acquisition and the Energen acquisition.


	Rattler Midstream LP Predecessor Historical				Rattler Midstream LP Pro Forma
					Year Ended December 31, 2018
	Years Ended December 31,
	2018		2017
	(in thousands, except per unit data)
Statement of Operations Data:
Revenues
Total revenues	$	184,467	$	39,295	$	185,448
Costs and expenses
Operating expenses		74,438		10,557		74,547
Depreciation, amortization and accretion		25,134		3,486		35,108
Loss on sale of property, plant and equipment		2,577		—		2,577
General and administrative expenses		1,999		1,265		2,108

Total costs and expenses		104,148		15,308		114,340

Income from operations		80,319		23,987		71,108
Other income (expense)
Interest expense, net of amount capitalized		—		—		—
Income from equity investment		—		1,366		—

Total other income (expense)		—		1,366		—

Net income before income taxes		80,319		25,353		71,108
Provision for income taxes		17,359		4,688		15,305

Net income	$	62,960	$	20,665	$	55,803

Net income per common unit (basic and diluted)
Common units
Balance Sheet Data (at period end):
Total property, plant and equipment, net	$	561,921	$	255,323	$	859,533
Total assets		604,016		299,605		901,628
Member’s equity / partners’ capital		527,125		292,608		821,393
Statement of Cash Flows Data:
Net cash provided by operating activities	$	173,431	$	8
Net cash used in investing activities		164,876		—
Net cash provided by financing activities		—		—
Other Data:
EBITDA(1)	$	105,453	$	28,839	$	106,216

(1)	For our definition of the non-GAAP financial measure of EBITDA and a reconciliation of EBITDA to our most directly comparable financial measures calculated and presented in accordance with GAAP, please read “—Non-GAAP Financial Measures.”

Non-GAAP Financial Measures

We define EBITDA as net income before income taxes, net interest expense, depreciation, amortization and accretion. EBITDA is used as a supplemental financial measure by management and by external users of our financial statements, such as investors, industry analysts, lenders and ratings agencies, to assess:

•

our operating performance as compared to those of other companies in the midstream energy industry, without regard to financing methods, historical cost basis or capital structure;

•

the ability of our assets to generate sufficient cash flow to make distributions to our common unitholders;

•

our ability to incur and service debt and fund capital expenditures; and

•

the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

We believe that the presentation of EBITDA in this prospectus provides information useful to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to EBITDA are net income and net cash provided by operating activities. EBITDA should not be considered an alternative to net income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. EBITDA excludes some, but not all, items that affect net income or net cash, and these measures may vary from those of other companies. As a result, EBITDA as presented below may not be comparable to similarly titled measures of other companies.

The following tables present a reconciliation of EBITDA to net income and net cash provided by operating activities, the most directly comparable GAAP financial measures, on a historical basis and pro forma basis, as applicable, for each of the periods indicated.


	Rattler Midstream LP Predecessor Historical					Rattler Midstream LP Pro Forma
	Year Ended December 31,					Year Ended December 31,
	Year Ended December 31,					Year Ended December 31,
	2018			2017		2018
	(in thousands, except per unit data)
Reconciliation of net income to EBITDA:
Net income	$	62,960		$	20,665	$	55,803
Provision for income taxes		17,359			4,688		15,305
Interest expense, net of amount capitalized		—			—		—
Depreciation, amortization and accretion		25,134			3,486		35,108

EBITDA	$	105,453		$	28,839	$	106,216

Reconciliation of net cash provided by operating activities to EBITDA:
Net cash provided by operating activities	$	173,431		$	8
Changes in operating assets and liabilities		(65,401	)		27,465
Interest expense, net of amount capitalized		—			—
Stock based compensation and other		(2,577	)		1,366

EBITDA	$	105,453		$	28,839

RISK FACTORS

Investing in our common units involves risks. 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 and we will be treated as a corporation for U.S. federal income tax purposes. You should carefully consider the following risk factors together with all of the other information included in this prospectus, including the matters addressed under “Cautionary Statement Regarding 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 flow and ability to make cash distributions could be materially adversely affected. In that case, we may not be able to pay distributions on our common units, the trading price of our common units could decline and you could lose all or part of your investment.

Risks Related to Our Business

We derive substantially all of our revenue from Diamondback. If Diamondback changes its business strategy, alters its current drilling and development plan on the Dedicated Acreage, or otherwise significantly reduces the volumes of crude oil, natural gas, produced water or fresh water with respect to which we perform midstream services, our revenue would decline and our business, financial condition, results of operations, cash flow and ability to make distributions to our common unitholders would be materially and adversely affected.

We derive substantially all of our revenue from our commercial agreements with Diamondback, which agreements do not contain minimum volume commitments, as well as volumes attributable to third-party interest owners that participate in Diamondback’s operated wells and are charged under short-term contracts at market sensitive rates. As a result, we are subject to the operational and business risks of Diamondback, the most significant of which include the following:

•

a reduction in or slowing of Diamondback’s drilling and development plan on the Dedicated Acreage, which would directly and adversely impact Diamondback’s demand for our midstream services;

•

the volatility of crude oil, natural gas and NGL prices, which could have a negative effect on Diamondback’s drilling and development plan on the Dedicated Acreage or Diamondback’s ability to finance its operations and drilling and completion costs on that acreage;

•

the availability of capital on an economic basis to fund Diamondback’s exploration and development activities, if needed;

•

drilling and operating risks, including potential environmental liabilities, associated with Diamondback’s operations on the Dedicated Acreage;

•

future wells, or wells that are currently in the process of being completed, on acreage that is dedicated to us do not produce sufficient hydrocarbons or are dry holes, which would directly and adversely impact the hydrocarbon volumes on our systems and our revenue;

•

downstream processing and transportation capacity constraints and interruptions, including the failure of Diamondback to have sufficient contracted processing or transportation capacity; and

•

adverse effects of increased or changed governmental and environmental regulation or enforcement of existing regulation.

In addition, we are indirectly subject to the business risks of Diamondback generally and other factors, including, among others:

•

Diamondback’s financial condition, credit ratings, leverage, market reputation, liquidity and cash flow;

•

Diamondback’s ability to maintain or replace its reserves;

•

adverse effects of governmental and environmental regulation on Diamondback’s upstream operations; and

•

losses from pending or future litigation.

Further, we have no control over Diamondback’s business decisions and operations, and Diamondback is under no obligation to adopt a business strategy that is favorable to us. Thus, we are subject to the risk that Diamondback could cancel its planned development, breach its commitments with respect to future dedications or otherwise fail to pay or perform, including with respect to our commercial agreements. We cannot predict the extent to which Diamondback’s businesses would be impacted if conditions in the energy industry were to deteriorate nor can we estimate the impact such conditions would have on Diamondback’s ability to execute its drilling and development plan on the Dedicated Acreage or to perform under our commercial agreements. Any material non-payment or non-performance by Diamondback under our commercial agreements would have a significant adverse impact on our business, financial condition, results of operations and cash flow and could therefore materially adversely affect our ability to make cash distributions to our common unitholders.

Our commercial agreements with Diamondback carry initial terms ending in 2034, and there is no guarantee that we will be able to renew or replace these agreements on equal or better terms, or at all, upon their expiration. Our ability to renew or replace our commercial agreements following their expiration at rates sufficient to maintain our current revenues and cash flow could be adversely affected by activities beyond our control, including the activities of federal and state regulators, our competitors and Diamondback.

At the completion of this offering, we will not have any material customers other than Diamondback. However, we may in the future enter into material commercial contracts with other customers. To the extent we derive substantial income from or commit to capital projects to service new customers, each of the risks indicated above would apply to such arrangements and customers.

We expect that our only source of cash will be distributions from Rattler LLC, together with the $2.0 million of cash contributed to us in respect of our Class B Units and our general partner interest. We will only be able to make cash distributions to the extent that we have sufficient cash after the establishment of cash reserves and the payment of expenses. The Rattler LLC limited liability company agreement will provide that, in our capacity as managing member of Rattler LLC, we may cause Rattler LLC to pay cash distributions at any time and from time to time, which distributions will be paid pro rata in respect of all outstanding Rattler LLC Units. Rattler LLC’s ability to make any such distribution will be subject to applicable law as well as any contractual restrictions, such as those under its revolving credit facility. Please read “Cash Distribution Policy and Restrictions on Distributions.”

We will be subject to a U.S. federal income tax rate of approximately 21%; however, we expect to generate net operating losses to offset taxable income for 2019 and 2020. Accordingly, we do not expect to pay meaningful U.S. federal income taxes during those periods. We estimate that cash distributions from Rattler LLC of approximately $ million would be required to support the payment of our currently contemplated quarterly distribution for four quarters (approximately $ million per quarter). Our future tax liability may be greater than expected if we do not generate net operating losses sufficient to offset taxable income or if tax authorities challenge certain of our tax positions. In order to pay any contemplated distributions to our common unitholders, we must receive cash distributions from Rattler LLC sufficient to pay U.S. federal income tax on the income allocated to us by Rattler LLC in addition to the cash necessary to pay such distributions.

Because we will own a % membership interest in Rattler LLC at the completion of this offering (or a % membership interest in Rattler LLC if the underwriters exercise in full their option to purchase additional common units), for Rattler LLC to distribute $ million in cash to us, Rattler LLC must generate cash available for distribution of at least $ million.

Rattler LLC may not generate sufficient cash to support any distribution to our common unitholders; accordingly, we may not have sufficient cash each quarter to enable us to pay any distributions to our common unitholders. Furthermore, our partnership agreement does not require us to pay distributions on a quarterly basis or otherwise. The amount we will be able to distribute on our common units will depend on the amount of cash we receive from Rattler LLC, which in turn will principally depend on the amount of cash Rattler LLC generates from our operations, which will fluctuate from quarter to quarter based on, among other things:

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the volumes of crude oil we gather, the volumes of natural gas we gather, the volumes of produced water we collect, clean or dispose of and the volumes of fresh water we distribute and store;

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market prices of crude oil, natural gas and NGLs and their effect on Diamondback’s drilling and development plan on the Dedicated Acreage and the volumes of hydrocarbons that are produced on the Dedicated Acreage and for which we provide midstream services;

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Diamondback’s and our other customers’ ability to fund their drilling and development plan on the Dedicated Acreage;

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downstream processing and transportation capacity constraints and interruptions, including the failure of Diamondback and any other customers to have sufficient contracted processing or transportation capacity;

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

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regulatory action affecting:

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the supply of, or demand for, crude oil, natural gas, NGLs and water;

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the rates we can charge for our midstream services;

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the rates that EPIC and Gray Oak can charge for their transportation and terminal services;

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the terms upon which we are able to contract to provide our midstream services;

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our existing gathering and other commercial agreements; or

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our operating costs or our operating flexibility;

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the rates we charge for our midstream services;

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the rates that EPIC and Gray Oak charge for their transportation and terminal services;

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prevailing economic conditions; and

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adverse weather conditions.

In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:

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the level and timing of our capital expenditures, including capital calls associated with the EPIC and Gray Oak projects;

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our debt service requirements and other liabilities;

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

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fluctuations in our working capital needs;

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restrictions on distributions contained in any of our debt agreements;

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the cost of acquisitions, if any;

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

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

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other business risks affecting our cash levels.

The amount of our quarterly cash distributions, if any, may vary significantly both quarterly and annually. Unlike most publicly traded partnerships, we will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time.

Investors who are looking for an investment that will pay regular and predictable quarterly distributions should not invest in our common units. Our business performance may be more volatile, and our cash flow may be less stable, than the business performance and cash flow of publicly traded partnerships with traditional structures like minimum quarterly distributions, subordinated units and incentive distribution rights. As a result, our quarterly cash distributions may be volatile and may vary quarterly and annually. Unlike most publicly traded partnerships, we will not have a minimum quarterly distribution or an obligation to distribute all available cash generated by our operations. The amount of our quarterly cash distributions will generally depend on the performance of our business, which has a limited operating history. See “Cash Distribution Policy and Restrictions on Distributions.”

The board of directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion. Our partnership agreement does not require us to make any distributions on our common units at all.

Our partnership agreement does not require us to pay any distributions on our common units at all. Accordingly, the board of directors of our general partner may change our cash distribution policy at any time at its discretion and could elect not to pay distributions on our common units for one or more quarters. Any modification or revocation of our cash distribution policy could substantially reduce or eliminate the amounts of distributions to our common unitholders. The amount of distributions we make, if any, and the decision to make any distribution at all will be determined by the board of directors of our general partner, whose interests may differ from those of our common unitholders. Our general partner has limited duties to our common unitholders, which may permit it to favor its own interests or the interests of Diamondback to the detriment of our common unitholders.

On a pro forma basis, we would not have had sufficient cash available for distribution to pay any distributions on our common units for the year ended December 31, 2018.

On a pro forma basis, assuming we had completed this offering and related transactions as of January 1, 2018, Rattler LLC’s cash available for distribution would have been a deficit of approximately $ million for the year ended December 31, 2018. Therefore, Rattler LLC would have been unable to pay any distributions on its units, and we would have been unable to pay any distributions on our common units, for the year ended December 31, 2018. For a calculation of our ability to make cash distributions to our common unitholders based on our pro forma results, please read “Cash Distribution Policy and Restrictions on Distributions.”

The assumptions underlying the forecast of cash available for distributions 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 cash available for distributions to differ materially from our forecast.

The forecast of distributable cash flow set forth in “Cash Distribution Policy and Restrictions on Distributions” includes our forecast of our results of operations and cash available for distribution for the twelve months ending March 31, 2020. Our ability to pay our currently contemplated quarterly distributions 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 financial forecast has been prepared by management, and we have neither received nor requested an opinion or report on it from our or any other independent auditor. The assumptions and estimates underlying the forecast are substantially driven by Diamondback’s anticipated drilling and completion schedule and, although we consider our assumptions as to Diamondback’s ability to maintain that schedule reasonable as of the date of this prospectus, those estimates and Diamondback’s ability to achieve anticipated drilling and production targets are subject to a wide variety of significant business, economic and competitive risks and uncertainties that could cause actual results to differ materially from those contained in the forecast. If we do not achieve the forecasted results, we may not be able to pay the initially contemplated quarterly distribution or any distribution at all on our common units, in which event the market price of our common units may decline materially.

The forecast of our expenses and revenues include estimates of expenses to be incurred and revenues to be received include anticipated investments in, and capital contributions attributable to, the EPIC and Gray Oak projects, and a failure to timely fund such investments or contributions may result in revenues that differ materially from our forecast.

The forecast of our expenses and revenues include estimates of expenses to be incurred and revenues to be received attributed to our investments in the EPIC and Gray Oak projects. In order to realize any potential revenues associated with such pipelines, we will need to contribute future capital to these pipeline projects. To fund these investments, 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. While we have historically received funding from Diamondback, none of Diamondback, our general partner or any of their respective affiliates is committed to providing any direct or indirect financial support to these activities. Our failure to timely contribute additional capital could result in decreased revenues.

We own a minority interest in certain pipeline projects and our control of such pipeline projects is limited by provisions of the limited partnership and limited liability company agreements of such pipeline projects and by our percentage ownership in such pipeline projects.

The EPIC and Gray Oak projects are operated by entities in which we own 10% equity interests and that we do not operate; accordingly, we do not have an ownership stake that permits us to control the business activities of either entity. We have limited ability to influence the business decisions of such entities.

We will likely be unable to control the amount of cash we will receive from the operation of these projects and could be required to contribute significant amounts to fund our share of their operations, which could adversely affect our ability to distribute cash to our unitholders.

The amount of cash we have available for distribution to our common 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 on our common units during periods when we record net income for financial accounting purposes.

If Diamondback sells any of the Dedicated Acreage to a third party, the third party’s financial condition could be materially worse than Diamondback’s, and thus we could be subject to the nonpayment or nonperformance by the third party.

If Diamondback sells any of the Dedicated Acreage to a third party, the third party’s financial condition could be materially worse than Diamondback’s. In such a case, we may be subject to risks of loss resulting from

nonpayment or nonperformance by the third party, which risks may increase during periods of economic uncertainty. Furthermore, the third party may be subject to their own operating and regulatory risks, which could increase the risk that that third party may default on its obligations to us. Any material nonpayment or nonperformance by the third party could reduce our ability to make distributions to our common unitholders.

The Acreage Dedication is subject to additional risk in the event of a bankruptcy proceeding of Diamondback.

If in the future Diamondback is in financial distress or commences bankruptcy proceedings, our contracts with Diamondback, including the Acreage Dedication provisions, may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. If, in such a circumstance, any such contract is altered or rejected in bankruptcy proceedings, we could lose some or all of the expected revenues associated with that contract, which could have a material and adverse effect on our business, cash flow and results of operations.

Our business is difficult to evaluate because we have a limited operating history.

Rattler Midstream LP was formed in July 2018 and substantially all of our assets were acquired by our predecessor effective on or after January 1, 2016. Moreover, we do not have historical financial statements with respect to certain of our midstream assets for periods prior to their acquisition by Diamondback. As a result, there is only limited historical financial and operating information available upon which to base your evaluation of our performance.

Because of the natural decline in hydrocarbon production from existing wells, our success depends, in part, on our ability to maintain or increase hydrocarbon throughput volumes on our midstream systems, which depends on our customers’ levels of development and completion activity on our Dedicated Acreage.

The level of crude oil and natural gas volumes handled by our midstream systems depends on the level of production from crude oil and natural gas wells dedicated to our midstream systems, which may be less than expected and which will naturally decline over time. To maintain or increase throughput levels on our midstream systems, we must obtain production from wells completed by Diamondback and any third party customers on acreage dedicated to our midstream systems or execute agreements with other third parties in our areas of operation.

We have no control over Diamondback’s 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 Diamondback or other producers or their exploration and development decisions, which may be affected by, among other things:

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the availability and cost of capital;

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

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demand for crude oil, natural gas and NGLs;

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levels of reserves;

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geologic considerations;

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changes in the strategic importance Diamondback assigns to development in the Delaware Basin or the Midland Basin as opposed to other potential future operations they may acquire, which could adversely affect the financial and operational resources Diamondback is willing to devote to development of our Dedicated Acreage;

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increased levels of taxation related to the exploration and production of crude oil, natural gas and NGLs in our areas of operation;

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environmental or other governmental regulations, including the availability of permits, the regulation of hydraulic fracturing and a governmental determination that multiple facilities are to be treated as a single source for air permitting purposes; and

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the costs of producing crude oil, natural gas and NGLs and the availability and costs of drilling rigs and other equipment.

Due to these and other factors, even if reserves are known to exist in areas served by our midstream assets, producers, including Diamondback, may choose not to develop those reserves. If producers choose not to develop their reserves or they choose to slow their development rate in our areas of operation, utilization of our midstream systems will be below anticipated levels. Reductions in development activity, coupled with the natural decline in production from our current Dedicated Acreage, would result in our inability to maintain the then-current levels of utilization of our midstream assets, which could materially adversely affect our business, financial condition, results of operations, cash flow and ability to make cash distributions.

If Diamondback does not maintain its drilling activities on the Dedicated Acreage, the demand for our fresh water and SWD services could be reduced, which could have a material adverse effect on our results of operations, cash flow and ability to make distributions to our common unitholders.

The fresh water and SWD services we provide to Diamondback and any other customers assist in their drilling activities. If Diamondback does not maintain its drilling activities on the Dedicated Acreage, their demand for our fresh water and SWD services will be reduced regardless of whether we continue to provide our other midstream services for their production. If the demand for our fresh water or SWD services declines for this or any other reason, our results of operations, cash flow and ability to make distributions to our common unitholders could be materially adversely affected.

Dedicated Acreage may be lost as a result of title defects in the properties in which Diamondback invests.

It is Diamondback’s practice in acquiring oil and natural gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interests. Rather, Diamondback relies on the judgement of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. The existence of a material title deficiency can render a lease worthless. If Diamondback fails to cure any title defects, it may be delayed or prevented from utilizing the associated mineral interest which could result in a decrease in the volumes on our systems and an associated decrease in our revenues.

Our midstream assets are currently located exclusively in the Permian in Texas, making us vulnerable to risks associated with operating in a single geographic area.

Our midstream assets are currently located exclusively in the Permian in Texas. As a result of this concentration, we will be disproportionately 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 restrictions, drought related conditions or other weather-related conditions or interruption of the processing or transportation of crude oil, natural gas and water. If any of these factors were to impact the Permian more than other producing regions, our business, financial condition, results of operations and ability to make cash distributions could be adversely affected relative to other midstream companies that have a more geographically diversified asset portfolio.

Oil and natural gas producers’ operations, especially those using hydraulic fracturing, are substantially dependent on the availability of water. Restrictions on our ability to obtain water could reduce demand for our water services, which could have an adverse effect on our cash flow.

Water is an essential component of oil and natural gas production during both the drilling and hydraulic fracturing processes. However, the availability of suitable water supplies may be limited by prolonged drought

conditions and changing laws and regulations relating to water use and conservation. For example, in recent years, Texas has experienced extreme drought conditions. As a result of this severe drought, some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supply. A reduction in the availability of water could impact the water services we provide and, as a result, our financial condition, results of operations and cash available for distribution could be adversely affected.

If the third-party pipelines interconnected, or expected to be interconnected, to our pipelines become unavailable to transport or store crude oil or refined products, our revenue and available cash could be adversely affected.

We depend upon third-party pipelines and associated operations to provide delivery options from our pipelines. Because we do not control these pipelines and associated operations, their continuing operation is not within our control. If any pipeline were to become unavailable for current or future volumes of crude oil or refined products due to repairs, damage to the facility, lack of capacity, shut in by regulators or any other reason, our ability to operate efficiently and continue shipping crude oil and refined products to major demand centers could be restricted, thereby reducing revenue. Any temporary or permanent interruption at these pipelines could have a material adverse effect on our business, results of operations, financial condition or cash flow, including our ability to make distributions.

We cannot predict the rate at which Diamondback will develop the Dedicated Acreage or the areas it will decide to develop.

The Acreage Dedication covers midstream services in a number of areas that are at the early stages of development, in areas that Diamondback is still determining whether to develop, and in areas where we may have to acquire operating assets from third parties. In addition, Diamondback owns acreage in areas that are not dedicated to us. We cannot predict which of these areas Diamondback will determine to develop and at what time. Diamondback may decide to explore and develop areas in which we have a smaller operating interest in the midstream assets that service that area, or where the acreage is not dedicated to us, rather than areas in which we have a larger operating interest in the midstream assets that service that area. Diamondback’s 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 flow and ability to make cash distributions.

Acquisitions of assets or businesses may reduce, rather than increase, our distributable cash flow or may disrupt our business.

Even if we make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in our distributable cash flow. Any acquisition involves potential risks that may disrupt our business, including the following, among other things:

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mistaken assumptions about volumes or the timing of those volumes, revenues or costs, including synergies;

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an inability to successfully integrate the acquired assets or businesses;

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the assumption of unknown liabilities;

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exposure to potential lawsuits;

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limitations on rights to indemnity from the seller;

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

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unforeseen difficulties operating in new geographic areas; and

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customer or key employee losses at the acquired businesses.

Diamondback may suspend, reduce or terminate its obligations under our commercial agreements with it in certain circumstances, which could have a material adverse effect on our financial condition, results of operations, cash flow and ability to make distributions to our common unitholders.

We have entered into a gas gathering and compression agreement, a crude oil gathering agreement, a produced and flowback water gathering and disposal agreement and a freshwater purchase and services agreement with Diamondback, which include provisions that permit Diamondback to suspend, reduce or terminate its obligations under each agreement if certain events occur. These events include force majeure events that would prevent us from performing some or all of the required services under the applicable agreement. Diamondback has the discretion to make such decisions notwithstanding the fact that they may significantly and adversely affect us. Any such reduction, suspension or termination of Diamondback’s obligations under our commercial agreements would have a material adverse effect on our financial condition, results of operations, cash flow and ability to make distributions to our common unitholders. Please read “Business—Our Commercial Agreements with Diamondback.”

Increased competition from other companies that provide midstream services, or from alternative fuel sources, could have a negative impact on the demand for our services, which could adversely affect our financial results.

Our systems will compete for third party customers primarily with other crude oil and natural gas gathering systems and fresh and produced water service providers. Some of our competitors have greater financial resources and may now, or in the future, have access to greater supplies of crude oil, natural gas and fresh water than we do. Some of these competitors may expand or construct gathering systems that would create additional competition for the services we would provide to third party customers. In addition, potential third party customers may develop their own gathering systems instead of using ours. Moreover, Diamondback and its affiliates are not limited in their ability to compete with us, except with respect to the Acreage Dedication contained in our commercial agreements. See “Conflicts of Interest and Fiduciary Duties.”

Further, hydrocarbon fuels compete with other forms of energy available to end-users, including electricity and coal. Increased demand for such other forms of energy at the expense of hydrocarbons could lead to a reduction in demand for our services.

All of these competitive pressures could make it more difficult for us to attract new customers as we seek to expand our business, which could have a material adverse effect on our business, financial condition, results of operations and ability to make quarterly cash distributions to our common unitholders. In addition, competition could intensify the negative impact of factors that decrease demand for crude oil, natural gas and fresh water in the markets served by our systems, such as adverse economic conditions, weather, higher fuel costs and taxes or other governmental or regulatory actions that directly or indirectly increase the cost or limit the use of crude oil, natural gas and fresh water.

Our construction of new midstream assets may not result in revenue increases and may be subject to regulatory, environmental, political, contractual, legal and economic risks, which could adversely affect our cash flow, results of operations and financial condition and, as a result, our ability to distribute cash to unitholders.

The construction of additions or modifications to our existing systems and the expansion into new production areas to service Diamondback involve numerous regulatory, environmental, political and legal uncertainties beyond our control, may require the expenditure of significant amounts of capital, and we may not be able to construct in certain locations due to setback requirements or expand certain facilities that are deemed to be part of a single source. Regulations clarifying how crude oil and natural gas production facility emissions must be aggregated under the federal Clean Air Act, or CAA, permitting program were finalized in June 2016. This action clarified certain permitting requirements, yet could still impact permitting and compliance costs. As we build infrastructure to meet Diamondback’s needs, we may not be able to complete such projects 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 additional gathering assets, 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 or at all. We may construct facilities to capture anticipated future production growth from Diamondback or another customer in an area where such growth does not materialize. As a result, new 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 flow and ability to make cash distributions.

The construction of additions to our existing assets may require us to obtain new rights-of-way, surface use agreements or other real estate agreements prior to constructing new pipelines or facilities. We may be unable to timely obtain such rights-of-way to connect new crude oil, natural gas and water sources to our existing infrastructure 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, leases or other agreements, and our fees may only be increased above the annual year-over-year increase by mutual agreement between us and our customer. If the cost of renewing or obtaining new agreements increases, our cash flow could be adversely affected.

We are subject to regulation by multiple governmental agencies, which could adversely impact our business, results of operations and financial condition.

We are subject to regulation by multiple federal, state and local governmental agencies. Proposals and proceedings that affect the midstream industry are regularly considered by Congress, as well as by state legislatures and federal and state regulatory commissions, agencies and courts. We cannot predict when or whether any such proposals or proceedings may become effective or the magnitude of the impact changes in laws and regulations may have on our business. However, additions to the regulatory burden on our industry can increase our cost of doing business and affect our profitability.

The rates of our regulated crude oil assets are subject to review by federal regulators, which could adversely affect our revenues.

Rattler LLC has a Federal Energy Regulatory Commission, or FERC, tariff on file to gather crude oil in interstate commerce. Pipelines that gather or transport crude oil for third parties in interstate commerce are, among other things, subject to regulation of the rates and terms and conditions of service by FERC. We may also be required to respond to requests for information from government agencies, including compliance audits conducted by FERC.

FERC’s ratemaking policies are subject to change and may impact the rates charged and revenues received by Rattler LLC. In July 2016, the United States Court of Appeals for the District of Columbia Circuit issued its opinion in United Airlines, Inc., et al. v. FERC, finding that FERC had acted arbitrarily and capriciously when it failed to demonstrate that permitting an interstate petroleum products pipeline organized as a master limited partnership, or MLP, to include an income tax allowance in the cost of service underlying its rates in addition to the discounted cash flow return on equity would not result in the pipeline partnership owners double-recovering their income taxes. The court vacated FERC’s order and remanded to FERC to consider mechanisms for demonstrating that there is no double recovery as a result of the income tax allowance. On March 15, 2018, FERC issued a Revised Policy Statement on Treatment of Income Taxes in which FERC found that an impermissible double recovery results from granting a MLP pipeline both an income tax allowance and a return on equity pursuant to FERC’s discounted cash flow methodology. FERC revised its previous policy, stating that it would no longer permit an MLP pipeline to recover an income tax allowance in its cost of service. FERC stated it will address the application of the United Airlines decision to non-MLP partnership forms as those issues arise in subsequent proceedings. Further, FERC stated that it will incorporate the effects of the post-United Airlines policy changes and the Tax Cuts and Jobs Act of 2017 on industry-wide crude oil pipeline costs in the 2020 five-year review of the crude oil pipeline index level. FERC will also apply the revised Policy Statement and the Tax

Cuts and Jobs Act of 2017 to initial crude oil pipeline cost-of-service rates and cost-of-service rate changes on a going-forward basis under FERC’s existing ratemaking policies, including cost-of-service rate proceedings resulting from shipper-initiated complaints. On July 18, 2018, FERC dismissed requests for rehearing and clarification of the March 15, 2018 Revised Policy Statement, but provided further guidance, clarifying that a pass-through entity will not be precluded in a future proceeding from arguing and providing evidentiary support that it is entitled to an income tax allowance and demonstrating that its recovery of an income tax allowance does not result in a double recovery of investors’ income tax costs.

A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our operating expenses to increase, limit the rates we charge for certain services and decrease the amount of cash we have available for distribution.

Although FERC has not made a formal determination with respect to the facilities we consider to be natural gas gathering pipelines, we believe that our natural gas gathering pipelines meet the traditional tests that FERC has used to determine that pipelines perform primarily a gathering function and are, therefore, not subject to FERC jurisdiction. The distinction between FERC-regulated interstate transportation services and federally unregulated gathering services, however, has been the subject of substantial litigation, and FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our gathering facilities is subject to change based on future determinations by FERC, the courts or Congress. If FERC were to consider the status of an individual facility and determine that the facility or services provided by it are not exempt from FERC regulation under the Natural Gas Act of 1938, or NGA, and that the facility provides interstate transportation service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by FERC under the NGA or the Natural Gas Policy Act, or NGPA. Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, adversely affect our results of operations and cash flow. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of substantial civil penalties, as well as a requirement to disgorge revenues collected for such services in excess of the maximum rates established by FERC.

Even though we consider our natural gas gathering pipelines to be exempt from the jurisdiction of FERC under the NGA, FERC regulation of interstate natural gas transportation pipelines may indirectly impact gathering services. FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on interstate open access transportation, ratemaking, capacity release, and market center promotion may indirectly affect intrastate markets and gathering services. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that the FERC will continue to pursue this approach as it considers matters such as pipeline rates and rules and policies that may indirectly affect the natural gas gathering services.

Natural gas gathering may receive greater regulatory scrutiny at the state level; therefore, our natural gas gathering operations could be adversely affected should they become subject to the application of state regulation of rates and services. Our gathering operations could also be subject to safety and operational regulations relating to the design, construction, testing, operation, replacement and maintenance of gathering facilities. We cannot predict what effect, if any, such changes might have on our operations, but we could be required to incur additional capital expenditures and increased operating costs depending on future legislative and regulatory changes.

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

The U.S. Department of Transportation, or DOT, through the PHMSA and state agencies, enforces safety regulations with respect to the design, construction, operation, maintenance, inspection and management of

certain of our pipeline facilities. The PHMSA requires pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in high-consequence areas, or HCAs, defined as those areas that are unusually sensitive to environmental damage, that cross a navigable waterway, or that have a high population density. The regulations require operators to (i) perform ongoing assessments of pipeline integrity, (ii) identify and characterize applicable threats to pipeline segments that could impact a HCA, (iii) improve data collection, integration and analysis, (iv) repair and remediate pipelines as necessary and (v) implement preventive and mitigating actions. These regulations contain requirements for the development and implementation of pipeline integrity management programs, which include the inspection and testing of pipelines and the correction of anomalies. The PHMSA’s regulations also require that pipeline operation and maintenance personnel meet certain qualifications and that pipeline operators develop comprehensive spill response plans, including extensive spill response training for pipeline personnel.

The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, also known as the Pipeline Safety and Job Creation Act, and the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016, also known as the PIPES Act, are the most recent enactments of federal legislation to amend the Natural Gas Pipeline Safety Act of 1968, or NGPSA, and the Hazardous Liquids Pipeline Safety Act of 1979, or HLPSA, which are pipeline safety laws requiring increased safety measures for natural gas and hazardous liquids pipelines. Among other things, the Pipeline Safety and Job Creation Act directs the Secretary of Transportation to promulgate regulations relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation, material strength testing and verification of the maximum allowable pressure of certain pipelines. The Pipeline Safety and Job Creation Act also increases the maximum penalty for violation of pipeline safety regulations from $100,000 to $200,000 per violation per day of violation and from $1.0 million to $2.0 million for a related series of violations. To account for inflation, those maximum civil penalties have increased to $213,268 per violation per day, with a maximum of $2,132,679 for a related series of violations. The PIPES Act ensures that the Pipeline and Hazardous Materials Safety Administration, or PHMSA, completes the Pipeline Safety and Job Creation Act requirements; reforms PHMSA to be a more dynamic, data-driven regulator; and closes gaps in federal standards.

In October 2015, PHMSA issued a proposed rule that would significantly increase the number of miles of pipelines subject to the integrity management requirement. The proposed rule would also increase the responsibilities and obligations for hazardous liquid (including crude oil, condensate, natural gas liquids, and liquefied natural gas) pipeline operators that are already subject to integrity management requirements. In April 2016, PHMSA published a proposed rulemaking that would expand integrity management requirements and impose new pressure testing requirements on currently regulated gas 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 allowable operating pressure limits, and other requirements. PHMSA has not yet finalized such natural gas pipeline regulations. More recently, in January 2017, PHMSA finalized regulations for hazardous liquid pipelines that significantly extend and expand the reach of certain PHMSA integrity management requirements (i.e., periodic assessments, leak detection and repairs), regardless of the pipeline’s proximity to a high consequence area. The final rule would also impose new reporting requirements for certain unregulated pipelines, including all hazardous liquid gathering lines. However, PHMSA has delayed publication of the January 2017 rule in the federal register and, as a result, the rule has not yet become effective and may be modified. The safety enhancement requirements and other provisions of the Pipeline Safety and Job Creation Act and the PIPES Act, as well as any implementation of PHMSA rules thereunder and/or related rule making proceedings, could require us to install new or modified safety controls, pursue additional capital projects or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could have a material adverse effect on our results of operations or financial position.

If third party pipelines or other facilities interconnected to our midstream systems become partially or fully unavailable, or if the volumes we gather or treat do not meet the quality requirements of such pipelines or facilities, our business, financial condition, results of operations, cash flow and ability to make distributions to our common unitholders could be adversely affected.

Our midstream systems are connected to other pipelines or facilities, the majority of which are owned by third parties. The continuing operation of such third party pipelines or facilities is not within our control. If any of these pipelines or facilities becomes unable to transport, treat or process natural gas or crude oil, or if the volumes we gather or transport do not meet the quality requirements of such pipelines or facilities, our business, financial condition, results of operations, cash flow and ability to make distributions to our common unitholders could be adversely affected.

Our exposure to commodity price risk may change over time and we cannot guarantee the terms of any existing or future agreements for our midstream services with our customers.

We currently generate the majority of our revenues pursuant to fee-based agreements under which we are paid based on volumetric fees, rather than the underlying value of the commodity. Consequently, our existing operations and cash flow have little direct exposure to commodity price risk. However, Diamondback and our other customers are exposed to commodity price risk, and extended reduction in commodity prices could reduce the production volumes available for our midstream services in the future below expected levels. Although we intend to maintain fee-based pricing terms on both new contracts and existing contracts for which prices have not yet been set, our efforts to negotiate such terms may not be successful, which could have a materially adverse effect on our business.

Increased regulation of hydraulic fracturing could result in reductions or delays in crude oil and natural gas 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 Diamondback’s crude oil and natural gas production on our Dedicated Acreage is developed from unconventional sources that require hydraulic fracturing as part of the completion process. The majority of our fresh water services business is related to the storage and transportation of water for use in hydraulic fracturing. 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. There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, induced seismic activity, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally.

Hydraulic fracturing is typically regulated by state oil and gas commissions and similar agencies. Please read “Business—Regulation of Operations.” Some states and local governments, including those in which we operate, have adopted, and other states are considering adopting, regulations that could impose more stringent disclosure or well construction requirements on hydraulic fracturing operations. In addition, several states and local governments have banned or significantly restricted hydraulic fracturing and, over the past several years, federal agencies such as the Environmental Protection Agency, or the EPA, have sought to assert jurisdiction over the process. While the EPA under the current administration has generally sought to relax environmental regulation and reduce enforcement efforts, including with respect to energy developed from unconventional sources, environmental groups and states have filed lawsuits challenging the EPA’s recent actions. We cannot predict the results of these or future lawsuits, or how such lawsuits will affect the regulation of hydraulic fracturing operations. Certain environmental groups have also suggested that additional laws at the federal, state and local levels of government may be needed to more closely and uniformly regulate the hydraulic fracturing process. 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 crude oil and natural gas that move through our gathering systems and decrease demand for our water services, which in turn could materially adversely impact our revenues.

We, Diamondback 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 systems, we are subject to various 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 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 customers’ operations. These laws and regulations may also limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically or seismically sensitive areas, and other protected areas. Failure to comply with these laws, regulations and permits may result in strict liability (i.e., no showing of “fault” is required) that may be joint and several, or the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations or the issuance of injunctions or administrative orders 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 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 the amount of cash we have available for distribution. We cannot provide any 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 the amount of cash we have available for distribution.

Our operations also pose risks of environmental liability due to leakage, migration, releases or spills 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 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 in recent years. Even if federal regulatory burdens temporarily ease, the historic trend of more expansive and stricter environmental legislation and regulations applied to the crude oil and natural gas industry may continue in the long-term, and at the state and local levels, potentially resulting in increased costs of doing business and consequently affecting the amount of cash we have available for distribution. Please read “Business—Regulation of Operations.”

Climate change laws and regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the crude oil and natural gas that we gather while potential physical effects of climate change could disrupt Diamondback’s and our other customers’ 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, or GHGs, present an endangerment to public health and the environment, federal, state and local governments have taken

steps to reduce emissions of GHGs. The EPA has finalized a series of GHG monitoring, reporting and emissions control rules for the oil and natural gas industry, and the U.S. Congress has, from time to time, considered adopting legislation to reduce emissions. Almost one-half of the states have already taken measures to reduce emissions of GHGs primarily through the development of GHG emission inventories and/or regional GHG cap-and-trade programs.

The EPA has adopted regulations under existing provisions of the CAA that, among other things, establish Prevention of Significant Deterioration, or PSD, construction and Title V operating permit reviews for certain large stationary sources. Facilities required to obtain PSD permits will be required to meet “best available control technology” standards for their GHG emissions that will be established by the states or, in some cases, by the EPA on a case-by-case basis. In addition, on June 3, 2016, the EPA amended its regulations to impose new standards for methane and volatile organic compounds emissions for certain new, modified, and reconstructed equipment, processes, and activities across the oil and natural gas sector. However, in a March 28, 2017 executive order, President Trump directed the EPA to review the 2016 regulations and, if appropriate, to initiate a rulemaking to rescind or revise them consistent with the stated policy of promoting clean and safe development of the nation’s energy resources, while at the same time avoiding regulatory burdens that unnecessarily encumber energy production. On June 16, 2017, the EPA published a proposed rule to stay for two years certain requirements of the 2016 regulations, including fugitive emission requirements. Also, on September 11, 2018, the EPA announced a proposed rule to significantly reduce regulatory burdens imposed by the 2016 regulations. These EPA regulations, to the extent implemented, as well as future laws and their implementing regulations, could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources.

Climate and related energy policy, laws and regulations could change quickly, and substantial uncertainty exists about the nature of many potential developments that could impact the sources and uses of energy. At the international level, in December 2015, the United States participated in the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake “ambitious efforts” to limit the average global temperature, and to conserve and enhance sinks and reservoirs of GHGs. The Paris Agreement went into effect on November 4, 2016. The Paris Agreement establishes a framework for the parties to cooperate and report actions to reduce GHG emissions. However, on June 1, 2017, President Trump announced that the United States would withdraw from the Paris Agreement and begin negotiations to either re-enter or negotiate an entirely new agreement with more favorable terms for the United States. The Paris Agreement sets forth a specific exit process, whereby a party may not provide notice of its withdrawal until three years from the effective date, with such withdrawal taking effect one year from such notice. It is not clear what steps the Trump Administration plans to take to withdraw from the Paris Agreement, whether a new agreement can be negotiated, or what terms would be included in such an agreement. Furthermore, in response to the announcement, many state and local leaders stated their intent to intensify efforts to uphold the commitments set forth in the international accord. It is not possible at this time to predict the timing or effect of international treaties or regulations on our operations or to predict with certainty the future costs that we may incur in order to comply with such treaties or regulations.

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations 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 the crude oil, natural gas and water we gather. Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in crude oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for energy infrastructure projects, such as pipelines and terminal facilities. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased

frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our operations or our customer’s exploration and production operations, which in turn could affect demand for our services. Please read “Business—Regulation of Operations.”

Legislation or regulatory initiatives intended to address seismic activity could restrict our ability to dispose of saltwater gathered from Diamondback and our other customers, which could have a material adverse effect on our business.

We dispose of large volumes of saltwater gathered from Diamondback and our other customers produced in connection with their drilling and production operations by injecting it into wells pursuant to permits issued to us by governmental authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities. For example, there exists a growing concern that the injection of saltwater into belowground disposal wells triggers seismic activity in certain areas, including Texas, where we operate.

State and federal regulatory agencies have recently focused on a possible connection between hydraulic fracturing related activities, particularly the underground injection of wastewater into disposal wells, and the increased occurrence of seismic activity, and regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. In addition, a number of lawsuits have been filed in some states alleging that disposal well operations have caused seismic events, caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements regarding the permitting of disposal wells or otherwise to assess the relationship between seismicity and the use of such wells. For example, on October 28, 2014, the Texas Railroad Commission adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water or other oil and gas waste to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed new disposal well. If the permittee or an applicant of a disposal well permit fails to demonstrate that the produced water or other fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the agency may deny, modify, suspend or terminate the permit application or existing operating permit for that well. The Texas Railroad Commission has used this authority to deny permits for disposal wells.

The adoption and implementation of any new laws or regulations that restrict our ability to dispose of saltwater gathered from Diamondback and our other third party crude oil and natural gas producing customers, by limiting volumes, disposal rates, SWD well locations or otherwise, or requiring us to shut down our SWD wells, could have a material adverse effect on our business, financial condition and results of operations.

Certain plant or animal species are or could be designated as endangered or threatened, which could have a material impact on our and Diamondback’s operations.

The federal Endangered Species Act, or ESA, restricts activities that may affect endangered or threatened species or their habitats. Many states have analogous laws designed to protect endangered or threatened species. Such protections, and the designation of previously undesignated species under such laws, may affect our and Diamondback’s operations, and those of our other customers, by imposing additional costs, approvals and accompanying delays.

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 make cash distributions and, accordingly, the market price for our common units.

Our operations are subject to all of the hazards inherent in the gathering of crude oil, natural gas and produced water and the delivery and storage of fresh water, including:

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damage to pipelines, centralized gathering facilities, pump stations, related equipment and surrounding properties caused by design, installation, construction materials or operational flaws, natural disasters, acts of terrorism or acts of third parties;

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leaks of crude oil, natural gas or NGLs or losses of crude oil, natural gas or NGLs as a result of the malfunction of, or other disruptions associated with, equipment or facilities;

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fires, ruptures and explosions; and

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other hazards that could also result in personal injury and loss of life, pollution and 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:

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injury or loss of life;

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

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pollution and other environmental damage;

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regulatory investigations and penalties;

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suspension of our operations; and

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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 flow and ability to make cash distributions.

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

We may not own in fee the land on which our midstream systems have been constructed. We own in fee less than 5% of the land on which our midstream systems have been constructed, with the remainder held by surface use agreements, rights-of-way, surface leases or other easement rights, which may limit or restrict our rights or access to or use of the surface estates. Accommodating these competing rights of the surface owners may adversely affect our operations. In addition, we are 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, surface leases or other easement rights or if such usage rights 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. Our loss of these rights, through our inability to renew rights-of-way, surface leases or other easement rights or otherwise, could have a material adverse effect on our business, financial condition, results of operations, cash flow and ability to make cash distributions.

A shortage of equipment and skilled labor could reduce equipment availability and labor productivity and increase labor and equipment costs, which could have a material adverse effect on our business and results of operations.

Our gathering and other midstream services require special equipment and laborers who are skilled in multiple disciplines, such as equipment operators, mechanics and engineers, among others. If we experience shortages of necessary equipment or skilled labor in the future, our labor and equipment costs and overall productivity could be materially and adversely affected. If our equipment or labor prices increase or if we experience materially increased health and benefit costs for employees, our business and 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 individuals, all of whom are employees of Diamondback and provide services to us pursuant to the services and secondment agreement. 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 these individuals who represent all of our general partner’s senior management could have a material adverse effect on our business, financial condition, results of operations, cash flow and ability to make cash distributions.

Neither we nor our general partner have any employees, and we rely solely on the employees of Diamondback to manage our business. The management team of Diamondback, which includes the individuals who manage us, also perform similar services for Diamondback and Viper and own and operate Diamondback’s assets, and thus are not solely focused on our business.

Neither we nor our general partner have any employees and we rely solely on Diamondback to operate our assets and perform other management, administrative and operating services for us and our general partner.

Diamondback provides similar activities with respect to its own assets and operations, as well as the assets and operations of Viper. Because Diamondback provides services to us that are similar to those performed for itself and Viper, Diamondback may not have sufficient human, technical and other resources to provide those services at a level that Diamondback would be able to provide to us if it were solely focused on our business and operations. Diamondback may make internal decisions on how to allocate its available resources and expertise that may not always be in our best interest compared to Diamondback’s interests. There is no requirement that Diamondback favor us over itself in providing its services. If the employees of Diamondback and their affiliates do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our common unitholders may be reduced.

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

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

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incur or guarantee additional debt;

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redeem or repurchase units or make distributions under certain circumstances;

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make certain investments and acquisitions;

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incur certain liens or permit them to exist;

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enter into certain types of transactions with affiliates;

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merge or consolidate with another company; and

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transfer, sell or otherwise dispose of assets.

We expect Rattler LLC’s new revolving credit facility will also contain covenants requiring us to maintain certain financial ratios.

The provisions of Rattler LLC’s new revolving credit facility may affect our ability to obtain future financing and to pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, 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, our assets may be insufficient to repay such debt in full, and our common 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—Capital Resources and Liquidity.”

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

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

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our ability to obtain additional financing, if necessary, for working capital, capital expenditures (including building additional gathering pipelines needed for required connections and building additional centralized gathering facilities pursuant to our gathering agreements) or other purposes may be impaired or such financing may not be available on favorable terms;

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

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

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

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

Increases in interest rates could adversely affect our business.

We will have exposure to increases in interest rates. Immediately after the consummation of this offering, we do not expect to have any outstanding indebtedness. However, prior to or in connection with the completion of this offering we expect to enter into a new revolving credit facility. An increase in the interest rates we pay under the credit facility will result in an increase in our interest expense. As a result, our results of operations, cash flow and financial condition and, as a result, our ability to make cash distributions to our common unitholders, could be materially adversely affected by significant increases in interest rates.

In the future we may face increased obligations relating to the closing of our saltwater facilities and may be required to provide an increased level of financial assurance to guaranty the appropriate closure activities occur for a saltwater facility.

Obtaining a permit to own or operate saltwater facilities generally requires us to establish performance bonds, letters of credit or other forms of financial assurance to address clean-up and closure obligations. As we

acquire additional saltwater facilities or expand our existing saltwater facilities, these obligations will increase. Additionally, in the future, regulatory agencies may require us to increase the amount of our closure bonds at existing saltwater facilities. We have accrued approximately $0.38 million on our balance sheet related to our future closure obligations of our saltwater facilities as of December 31, 2017. However, actual costs could exceed our current expectations, as a result of, among other things, federal, state or local government regulatory action, increased costs charged by service providers that assist in closing saltwater facilities and additional environmental remediation requirements. The obligation to satisfy increased regulatory requirements associated with our produced and saltwater facilities could result in an increase of our operating costs and affect our ability to make distributions to our unitholders.

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. The volumes of condensate produced at our processing facilities 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.

A terrorist attack, cyber-attack or armed conflict could harm our business.

Terrorist activities, cyber-attacks, anti-terrorist efforts and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for crude oil and natural gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Crude oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

A cyber incident could result in information theft, data corruption, operational disruption and/or financial loss.

The oil and gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations including certain midstream activities. For example, software programs are used to manage gathering and transportation systems and for compliance reporting. The use of mobile communication devices has increased rapidly. Industrial control systems such as SCADA (supervisory control and data acquisition) now control large scale processes that can include multiple sites and long distances, such as crude oil and natural gas pipelines.

We depend on digital technology, including information systems and related infrastructure as well as cloud applications and services, to process and record financial and operating data and to communicate with our employees and business service providers. Our business service providers, including vendors and financial institutions, are also dependent on digital technology. The technologies needed to conduct midstream activities make certain information the target of theft or misappropriation.

As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, also has increased. A cyber-attack could include gaining unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption, or result in denial-of-service on websites. SCADA-based systems are potentially vulnerable to targeted cyber-attacks due to their critical role in operations.

Our technologies, systems, networks and those of our business partners may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period.

A cyber incident involving our information systems and related infrastructure, or that of our business service providers, could disrupt our business plans and negatively impact our operations in the following ways, among others:

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a cyber-attack on a vendor or other service provider could result in supply chain disruptions which could delay or halt development of additional infrastructure, effectively delaying the start of cash flow from the project;

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a cyber-attack on downstream pipelines could prevent us from delivering product at the tailgate of our facilities, resulting in a loss of revenues;

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a cyber-attack on a communications network or power grid could cause operational disruption resulting in loss of revenues;

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a deliberate corruption of our financial or operational data could result in events of non-compliance which could lead to regulatory fines or penalties; and

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business interruptions could result in expensive remediation efforts, distraction of management, damage to our reputation, or a negative impact on the price of our common units.

Our implementation of various controls and processes, including globally incorporating a risk-based cyber security framework, to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure is costly and labor intensive. Moreover, there can be no assurance that such measures will be sufficient to prevent security breaches from occurring. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities.

Risks Inherent in an Investment in Us

Following the offering, Diamondback will own and control our general partner and will appoint all of the directors of our general partner. All of the executive officers and certain of the directors of our general partner are also officers and/or directors of Diamondback. Although our general partner has a duty to manage us in a manner that it believes is not adverse to our interest, the executive officers and directors of our general partner have a fiduciary duty to manage our general partner in a manner that is in the best interests of Diamondback. Therefore, conflicts of interest may arise between Diamondback or any of its affiliates, including our general partner, on the one hand, and us and/or any of our common unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our common unitholders. These conflicts include the following situations, among others:

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our general partner is allowed to take into account the interests of parties other than us, such as Diamondback, in exercising certain rights under our partnership agreement;

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neither our partnership agreement nor any other agreement requires Diamondback to pursue a business strategy that favors us;

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our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limits our general partner’s liabilities and restricts

the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty;

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

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

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

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our 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 its affiliates on our behalf;

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

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our general partner may exercise its right to call and purchase common units if it and its affiliates own more than 97% of the common units and Class B Units, taken together (which threshold will be permanently reduced to 80% if our general partner and its affiliates (including Diamondback) collectively own less than 75% of the common units and Class B Units, taken together);

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our general partner controls the enforcement of obligations that it and its affiliates owe to us; and

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

In addition, Diamondback or its affiliates may compete with us. Please read “—Diamondback and other affiliates of our general partner may compete with us.” and “Conflicts of Interest and Fiduciary Duties.”

Our partnership agreement replaces our general partner’s fiduciary duties to our unitholders.

Our partnership agreement contains provisions that eliminate and replace the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, or otherwise free of fiduciary duties to us and our unitholders. This entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:

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how to allocate business opportunities among us and its affiliates;

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whether to exercise its call right;

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

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whether to exercise its registration rights; and

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whether or not to consent to any merger or consolidation of the partnership or any amendment to the partnership agreement.

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

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 common unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:

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whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is generally required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any higher standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

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our general partner and its executive officers and directors will not be liable for monetary damages or otherwise 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 such losses or liabilities were the result of conduct in which our general partner or its executive officers or directors engaged in bad faith, willful misconduct or fraud or, with respect to any criminal conduct, with knowledge that such conduct was unlawful; and

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

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

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

In connection with a situation involving a transaction with an affiliate or a conflict of interest, other than one where our general partner is permitted to act in its sole discretion, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our unitholders or the conflicts committee then it will be presumed that, in making its decision, taking any action or failing to act, the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Please read “Conflicts of Interest and Fiduciary Duties.”

Diamondback and other affiliates of our general partner may compete with us.

Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner, engaging in activities incidental to its ownership interest in us and providing management, advisory and administrative services to its affiliates or to other persons. However, affiliates of our general partner, including Diamondback, are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. In addition, Diamondback may compete with us for investment opportunities and may own an interest in entities that compete with us. Further, Diamondback and its affiliates, may acquire, develop or dispose of additional midstream properties or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets.

Diamondback is an established participant in the oil and natural gas industry and has resources greater than ours, which factors may make it more difficult for us to compete with Diamondback with respect to commercial activities as well as for potential acquisitions. As a result, competition from Diamondback and its affiliates could adversely impact our results of operations and cash available for distribution to our common unitholders.

Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers and

directors and Diamondback. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our common unitholders. Please read “Conflicts of Interest and Fiduciary Duties.”

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

Unlike the holders of common stock in a corporation, common unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Common unitholders have no right on an annual or ongoing basis to elect our general partner or its board of directors. The board of directors of our general partner, including the independent directors, is chosen entirely by Diamondback, as a result of it owning our general partner, and not by our common unitholders. Please read “Management—Management of Rattler Midstream LP” and “Certain Relationships and Related Party Transactions.” Unlike publicly traded corporations, we will not conduct annual meetings of our common unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. 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 except by a vote of the holders of at least 66 2/3% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. In addition, any vote to remove our general partner must provide for the election of a successor general partner by the holders of a majority of the outstanding units, voting together as a single class. Upon the closing of this offering, Diamondback will own of our Class B Units representing an approximate % voting interest in us (or Class B Units representing an approximate % voting interest in us if the underwriters exercise in full their option to purchase additional common units). This will give Diamondback the ability to prevent the removal of our general partner.

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

Our partnership agreement also contains provisions limiting the ability of common 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 our management.

Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.

If our common unitholders are dissatisfied with the performance of our general partner, they will have limited ability to remove our general partner. Common unitholders will be unable to remove our general partner without its consent because affiliates of our general partner will own sufficient units upon the completion of this offering to be able to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding units, voting as a single class, is required to remove our general partner. Following the closing of this offering, Diamondback will own of our Class B Units representing % of voting interests in us (or Class B Units representing % voting interests in us if the underwriters exercise in full their option to purchase additional common units).

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our units (other than our general partner and its affiliates and permitted transferees).

Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person or group that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, may not vote on any matter. Our partnership agreement also contains provisions limiting the ability of common unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the ability of our common unitholders to influence the manner or direction of management.

Cost reimbursements, which will be determined in our general partner’s sole discretion, and fees due our general partner and its affiliates for services provided will be substantial and will reduce the amount of cash we have available for distribution to you.

Under our partnership agreement, we are required to reimburse our general partner and its affiliates for all costs and expenses that they incur on our behalf for managing and controlling our business and operations, all of which expenses will be paid by Rattler LLC. Except to the extent reimbursed pursuant to our services and secondment agreement, our general partner determines the amount of these expenses. Under our services and secondment agreement, we will be required to reimburse Diamondback for the provision of certain operation services and related management services in support of our operations. Our general partner and its affiliates also may provide us other services for which we will be charged fees as determined by our general partner. The costs and expenses for which we will reimburse our general partner and its affiliates may include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. The costs and expenses for which we are required to reimburse our general partner and its affiliates are not subject to any caps or other limits. Payments to our general partner and its affiliates will be substantial and will reduce the amount of cash we have available to distribute to common unitholders.

In connection with the closing of this offering, Rattler LLC will enter into a tax sharing agreement with Diamondback pursuant to which Rattler LLC will reimburse Diamondback for its share of state and local income and other taxes borne by Diamondback as a result of Rattler LLC’s results being included in a combined or consolidated tax return filed by Diamondback with respect to taxable periods including or beginning on the closing date of this offering. Please read “Certain Relationships and Related Party Transactions—Agreements with our Affiliates in Connection with the Transactions.”

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 to a third party without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the owner of our general partner to transfer its membership interests in our general partner to a third party. After any such transfer, the new member or members of our general partner would then be in a position to replace the board of directors and the executive officers of our general partner with its own designees and thereby exert significant control over the decisions taken by the board of directors and the executive officers of our general partner. This effectively permits a “change of control” without the vote or consent of the common unitholders.

Common unitholders may have liability to repay distributions and in certain circumstances may be personally liable for the obligations of the partnership.

Under certain circumstances, common unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, or the Delaware Act, we may not make a distribution to our common unitholders if the distribution would cause our

liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of any 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. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

A limited partner that participates in the control of our business within the meaning of the Delaware Act may be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us under the reasonable belief that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. Please read “Our Partnership Agreement—Limited Liability.”

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, immediately following the completion of this offering, Diamondback will own Class B Units, which are exchangeable for an equal number of common units, representing an aggregate % limited partner interest (or, if the underwriters exercise in full their option to purchase additional common units, Class B Units, which are exchangeable for an equal number of common units, representing an aggregate % limited partner interest). 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 and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units may decline below the initial public offering price.

Common unitholders will experience immediate and substantial dilution in as adjusted net tangible book value of $ per common unit.

The 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) exceeds as adjusted net tangible book value of $ per common unit. Based on the assumed initial public offering price of $ per common unit, unitholders will incur immediate and substantial dilution of $ per common unit. Please read “Dilution.”

Contracts between us, on the one hand, and our general partner and its affiliates, on the other hand, will not be the result of arm’s-length negotiations.

Our partnership agreement allows our general partner to determine, in good faith, any amounts to pay itself or its affiliates for any services rendered to us. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Our general partner will determine in good faith the terms of any arrangement or transaction entered into after the completion of this offering. Similarly, agreements, contracts or arrangements between us and our general partner and its affiliates that are entered into following the completion of this offering will not be required to be negotiated on an arm’s-length basis, although, in some circumstances, our general partner may determine that the conflicts committee may make a determination on our behalf with respect to such arrangements.

Our general partner and its affiliates will have no obligation to permit us to use any assets or services of our general partner and its affiliates, except as may be provided in contracts entered into specifically for such use. There is no obligation of our general partner and its affiliates to enter into any contracts of this kind.

Common unitholders will have no right to enforce the obligations of our general partner and its affiliates under agreements with us.

Any agreements between us, on the one hand, and our general partner and its affiliates, on the other hand, will not grant to the common unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

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

The attorneys, independent accountants and others who will perform services for us will be retained by our general partner. Attorneys, independent accountants and others who will perform services for us will be selected by our general partner or our conflicts committee and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the common unitholders in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the common unitholders, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.

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

If at any time our general partner and its affiliates (including Diamondback) own more than 97% of our then-outstanding common units and Class B Units, taken together, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price equal to the greater of (i) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (ii) the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. (If, however, our general partner and its affiliates (including Diamondback) reduce their collective ownership of common units and Class B Units to below 75% of the outstanding units, taken as a whole, the ownership threshold to exercise the call right will be permanently reduced to 80%.) As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders may also incur a tax liability upon a sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from causing us to issue additional common units and then exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Exchange Act. The common units and Class B Units are considered limited partner interests of a single class for these provisions. 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 no common units and Class B Units, which collectively would constitute approximately % of the common units and Class B Units treated as a single class (excluding any common units purchased by the directors, director nominee and executive officers of our general partner and certain other individuals as selected by our general partner under our directed unit program). Please read “Our Partnership Agreement—Limited Call Right.”

We may issue additional common units and other equity interests without unitholder approval, which would dilute existing unitholder ownership interests.

Under our partnership agreement, we are authorized to issue an unlimited number of additional interests, including common units, without a vote of the unitholders. The issuance by us of additional common units or other equity interests of equal or senior rank will have the following effects:

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the proportionate ownership interest of common unitholders in us immediately prior to the issuance will decrease;

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the amount of cash distributions on each common unit may decrease;

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

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the market price of the common units may decline.

Please read “Our Partnership Agreement—Issuance of Additional Partnership Interests.”

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

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

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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.

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

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

The market price of our common units could be adversely affected by sales of substantial amounts of our common units in the public or private markets.

After the completion of this offering, assuming that the underwriters do not exercise their option to purchase additional common units, Diamondback will hold Class B Units, each of which, together with one Rattler LLC Unit, will be exchangeable for one common unit. All of the Class B Units will be owned by Diamondback and Class B Units must be redeemed (together with an equal number of the Rattler LLC Units) for common units prior to their sale to any person or entity not affiliated with Diamondback. Sales by holders of a substantial number of our common units in the public markets, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. In addition, we have agreed to provide certain registration rights to Diamondback. Pursuant to these registration rights, we have agreed to register, under the Securities Act, all of the common units owned by Diamondback and its assignees for resale (including common units issuable in exchange for Class B Units and Rattler LLC Units). Under our partnership agreement, our general partner and its affiliates also have registration rights relating to the offer and sale of any common units that they hold. Please read “Units Eligible for Future Sale.”

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

We have no history operating as a publicly-traded partnership. As a publicly-traded partnership, we will incur significant legal, accounting and other expenses that we did not incur prior to this offering. In addition, the

Sarbanes-Oxley Act of 2002, as well as rules implemented by the Securities Exchanges Commission, or the SEC, and Nasdaq, require publicly-traded entities to adopt various corporate governance practices that will further increase our costs. Before we are able to make distributions to our common unitholders, we must first pay or reserve cash for our expenses, including the costs of being a publicly-traded partnership. As a result, the amount of cash we have available for distribution to our common unitholders will be affected by the costs associated with being a publicly-traded partnership.

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

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

We estimate that we will incur approximately $1.4 million of incremental costs per year associated with being a publicly-traded partnership; however, it is possible that our actual incremental costs of being a publicly-traded partnership will be higher than we currently estimate.

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

We are classified as an “emerging growth company” under Section 2(a)(19) of the Securities Act. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things, (i) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act of 2002, (ii) comply with any new requirements adopted by the Public Company Accounting Oversight Board 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, (iii) comply with any new audit rules adopted by the Public Company Accounting Oversight Board after April 5, 2012 unless the SEC determines otherwise or (iv) provide certain disclosures regarding executive compensation required of larger public companies.

If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential common unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our common units.

Diamondback is a publicly traded corporation and has developed a system of internal controls for compliance with public reporting requirements. However, prior to this offering, our predecessor has not been required to file reports with the SEC on a stand-alone basis. Upon the completion of this offering, we will become subject to the public reporting requirements of the Exchange Act. We prepare our consolidated financial statements in accordance with GAAP, but our internal controls over financial reporting may not currently meet all standards applicable to companies with publicly traded securities. Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a publicly traded partnership. 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 of 2002. For example, Section 404 will require us, among other things, to annually review and report on, and our independent registered public accounting firm to attest to, the effectiveness of our internal controls over financial reporting. 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 common units.

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

We have applied for listing of our common units on Nasdaq. Because we will be a publicly traded limited partnership, Nasdaq does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Additionally, any future issuance of additional common units or other securities, including to affiliates, will not be subject to Nasdaq’s shareholder approval rules that apply to a corporation. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of Nasdaq’s corporate governance requirements. Please read “Management—Management of Rattler Midstream LP.”

Our partnership agreement includes exclusive forum, venue and jurisdiction provisions. By purchasing a common unit, a limited partner is irrevocably consenting to these provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of Delaware courts. Our partnership agreement also provides that any unitholder bringing an unsuccessful action will be obligated to reimburse us for any costs we have incurred in connection with such unsuccessful action.

Our partnership agreement is governed by Delaware law. Our partnership agreement includes exclusive forum, venue and jurisdiction provisions designating Delaware courts as the exclusive venue for most claims, suits, actions and proceedings involving us or our officers, directors and employees. In addition, if any person brings any of the aforementioned claims, suits, actions or proceedings and such person does not obtain a judgment on the merits that substantially achieves, in substance and amount, the full remedy sought, then such person shall be obligated to reimburse us and our affiliates for all fees, costs and expenses of every kind and description, including but not limited to all reasonable attorneys’ fees and other litigation expenses, that the parties may incur in connection with such claim, suit, action or proceeding. 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 Delaware courts. If a dispute were to arise between a limited partner and us or our officers, directors or employees, the limited partner may be required to pursue its legal remedies in Delaware which may be an inconvenient or distant location and which is considered to be a more corporate-friendly environment. These provisions may have the effect of discouraging lawsuits against us and our general partner’s directors and officers.

Holders of our common units may not be entitled to a jury trial with respect to claims arising under our partnership agreement, which could result in less favorable outcomes to the plaintiffs in any such action.

Our partnership agreement governing our common units provides that, to the fullest extent permitted by law, holders of our common units waive the right to a jury trial of any claim they may have against us arising out of or relating to our common units or our partnership agreement, including any claim under the U.S. federal securities laws.

If we opposed a jury trial demand based on the waiver, the court would determine whether the waiver was enforceable based on the facts and circumstances of that case in accordance with the applicable state and federal

law. To our knowledge, the enforceability of a contractual pre-dispute jury trial waiver in connection with claims arising under the federal securities laws has not been finally adjudicated by the United States Supreme Court. However, we believe that a contractual pre-dispute jury trial waiver provision is generally enforceable, including under the laws of the Delaware, which govern our partnership agreement, by a federal or state court in the State of Delaware, which has exclusive jurisdiction over matters arising under the partnership agreement. In determining whether to enforce a contractual pre-dispute jury trial waiver provision, courts will generally consider whether a party knowingly, intelligently and voluntarily waived the right to a jury trial. We believe that this is the case with respect to our partnership agreement and our common units. It is advisable that you consult legal counsel regarding the jury waiver provision before entering into the partnership agreement.

If you or any other holders or beneficial owners of our common units bring a claim against us in connection with matters arising under our partnership agreement or our common units, including claims under federal securities laws, you or such other holder or beneficial owner may not be entitled to a jury trial with respect to such claims, which may have the effect of limiting and discouraging lawsuits against us. If a lawsuit is brought against us under our partnership agreement, it may be heard only by a judge or justice of the applicable trial court, which would be conducted according to different civil procedures and may result in different outcomes than a trial by jury would have, including results that could be less favorable to the plaintiffs in any such action.

Nevertheless, if this jury trial waiver provision is not permitted by applicable law, an action could proceed under the terms of the partnership agreement with a jury trial. No condition, stipulation or provision of the partnership agreement or our common units serves as a waiver by any holder or beneficial owner of our common units or by us of compliance with the U.S. federal securities laws and the rules and regulations promulgated thereunder.

Our general partner may amend our partnership agreement, as it determines necessary or advisable, to permit the general partner to redeem the units of certain unitholders.

Our general partner may amend our partnership agreement, as it determines necessary or advisable, to obtain proof of the nationality, citizenship or other related status of our limited partners (and their owners, to the extent relevant) and to permit our general partner to redeem the units held by any person (i) whose nationality, citizenship or related status creates substantial risk of cancellation or forfeiture of any of our property and/or (ii) who fails to comply with the procedures established to obtain such proof. The redemption price in the case of such a redemption will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption. Please read “Our Partnership Agreement—Non-Citizen Assignees; Redemption.”

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.

If we are deemed to be an investment company under the Investment Company Act of 1940, or the Investment Company Act, our business would be subject to applicable restrictions under the Investment Company Act, which could make it impracticable for us to continue our business as contemplated.

We believe our company is not an investment company under Section 3(b)(1) of the Investment Company Act because we are primarily engaged in a non-investment company business. We intend to conduct our operations so that we will not be deemed an investment company. However, if we were to be deemed an investment company, restrictions imposed by the Investment Company Act, including limitations on our capital structure and our ability to transact with affiliates, could make it impractical for us to continue our business as contemplated.

Risks Related to Taxation

In addition to reading the following risk factors, if the unitholder is a non-U.S. investor, please read “United States Federal Income Tax Considerations” for a more complete discussion of certain expected U.S. federal income tax consequences of owning and disposing of our common units.

We will be treated as a corporation for U.S. federal income tax purposes and our cash available for distribution to our common unitholders may be substantially reduced.

Even though we are organized as a limited partnership under state law, we will be treated as a corporation for U.S. federal income tax purposes. Accordingly, we will be subject to U.S. federal income tax at regular corporate rates on our net taxable income. Because an entity-level tax is imposed on us due to our status as a corporation for U.S. federal income tax purposes, our distributable cash flow will be reduced by our tax liabilities, which reduction may be substantial.

Distributions to common unitholders will likely be taxable as dividends.

Because we will be treated as a corporation for U.S. federal income tax purposes, if we make distributions to our common unitholders from current or accumulated earnings and profits as computed for U.S. federal income tax purposes, such distributions will generally be taxable to our common unitholders as ordinary dividend income for U.S. federal income tax purposes. Such dividend distributions paid to non-corporate U.S. unitholders will be subject to U.S. federal income tax at preferential rates, provided that certain holding period and other requirements are satisfied. Any portion of our distributions to common unitholders that exceeds our current and accumulated earnings and profits as computed for U.S. federal income tax purposes will constitute a non-taxable return of capital distribution to the extent of a unitholder’s basis in its common units, and thereafter as gain on the sale or exchange of such common units.

Future regulations relating to and interpretations of the recently enacted Tax Cuts and Jobs Act may have a material impact on our financial condition and results of operations.

The Tax Cuts and Jobs Act of 2017, or the Tax Act, was signed into law on December 22, 2017. Among other things, the Tax Act reduces the U.S. corporate tax rate from 35% to 21%, imposes significant additional limitations on the deductibility of interest, and allows the expensing of capital expenditures. The Tax Act is highly complex and subject to interpretation. The presentation of our financial condition and results of operations is based upon our current interpretation of the provisions contained in the Tax Act. In the future, the Treasury Department and the Internal Revenue Service are expected to release regulations relating to and interpretive guidance of the legislation contained in the Tax Act. Any significant variance of our current interpretation of such legislation from any future regulations or interpretive guidance could result in a change to the presentation of our financial condition and results of operations and could negatively affect our business.

USE OF PROCEEDS

We expect to receive estimated 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 the estimated underwriting discounts and commissions and estimated offering expenses. Our estimate assumes the underwriters’ option to purchase additional common units is not exercised. We intend to contribute the net proceeds from this offering to Rattler LLC in return for a number of Rattler LLC Units equal to the number of common units issued, representing approximately % of Rattler LLC’s outstanding membership interests after this offering. Our Rattler LLC Units will entitle us to sole management control of Rattler LLC. We intend for Rattler LLC to (i) retain $ million of the net proceeds from this offering and (ii) distribute the remainder of the net proceeds from this offering (approximately $ million) to Diamondback, in part to reimburse Diamondback for certain capital expenditures. We intend to use the $ million of retained net proceeds from this offering for general company purposes, including to fund future capital expenditures.

If the underwriters exercise in full their option to purchase additional common units, we estimate that the additional proceeds to us will be approximately $ million, after deducting the estimated underwriting discounts and commissions and estimated offering expenses. If and to the extent the underwriters exercise their option to purchase additional common units, we will contribute the net proceeds thereof to Rattler LLC in return for a number of Rattler LLC Units equal to the number of common units purchased pursuant to the option. We intend for Rattler LLC to use the proceeds of any exercise of the underwriters’ option to make an additional cash distribution to Diamondback.

We may choose to increase or decrease the number of common units we are offering. Each increase or decrease of 1.0 million common units offered by us, assuming an initial public offering price of $ per common unit, would increase or decrease net proceeds to us from this offering by approximately $ million, resulting in a proportionate increase or decrease in the number of Rattler LLC Units we will purchase.

In connection with the closing of this offering, Diamondback will contribute $1.0 million in cash to us and our general partner will contribute $1.0 million in cash to us in respect of its general partner interest. We will retain those contributions at the partnership, and use them for general partnership purposes.

In addition, 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 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 and estimated offering expenses. Any such change in the net proceeds to us would increase or decrease, as the case may be, the amount we contribute to Rattler LLC and, accordingly, the amount of the distribution to be made to Diamondback by Rattler LLC.

CAPITALIZATION

The following table sets forth:

•

the historical cash and cash equivalents and capitalization of our predecessor as of December 31, 2018; and

•

our pro forma capitalization as of December 31, 2018, giving effect to the pro forma adjustments described in our unaudited pro forma combined financial statements included elsewhere in this prospectus, including this offering and the application of the net proceeds from 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, the proceeds thereof will be used by us to purchase a number of Rattler LLC Units equal to the number of common units purchased pursuant to the option. If the underwriters do not exercise their option to purchase additional common units, we will issue up to an additional Class B Units, and Rattler LLC will issue an equal number of Rattler LLC Units, to Diamondback at the expiration of the option for no additional consideration. 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 sold to the public, and a number of Class B Units equal to the number of remaining common units not purchased by the underwriters pursuant to any exercise of the option will be issued to Diamondback and Rattler LLC will issue an equal number of Rattler LLC Units to Diamondback, at the expiration of the option period for no additional consideration. Any Class B Units to be so issued to Diamondback will be issued pursuant to the exemption from registration provided under Section 4(a)(2) of the Securities Act.

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 combined 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 December 31, 2018
	Historical		Pro Forma(2)
	(in thousands)
Cash and cash equivalents	$	8,563	$

Long-term debt:
New revolving credit facility(1)	$	—	$	—
Member’s equity / partners’ capital:
Member’s equity	$	527,125	$
Common units		—
Class B Units		—
General partner interest		—
Non-controlling interest		—
Total member’s equity / partners’ capital		527,125

Total capitalization	$	527,125	$

(1)	In connection with the completion of this offering, Rattler LLC expects to enter into a new $600 million revolving credit facility. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Revolving Credit Facility.”

(2)	Assumes the mid-point of the price range set forth on the cover page of this prospectus.

DILUTION

Dilution is the amount by which the offering price paid by the purchasers of the common units sold in this offering will exceed the pro forma net tangible book value per common unit after this offering. Net tangible book value per common unit as of a particular date represents the amount of our predecessor’s total tangible assets less our predecessor’s total liabilities divided by the total number of common units outstanding as of such date. For the purpose of calculating dilution, we are including in the number of common units all common units that would be issued if all Class B Units, together with the Rattler LLC Units, held by Diamondback were exchanged for common units. We refer to this calculation as being on “a fully diluted basis.” As of December 31, 2018, after giving effect to the transactions contemplated to occur at the completion of this offering, our net tangible book value would have been approximately $ million, or $ per common unit. Purchasers of our common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit as illustrated in the following table.


Assumed initial public offering price per common unit(1)		$
Pro forma net tangible book value per common unit before this offering(2)	$
Increase in net tangible book value per unit attributable to purchasers in this offering
Decrease in as adjusted net tangible book value per common unit attributable to the distributions to Diamondback(3)

Less: Pro forma net tangible book value per unit after this offering(4)

Immediate dilution in as adjusted net tangible book value per common unit attributable to purchasers in this offering(5)(6)		$

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

(2)	Determined by dividing the pro forma net tangible book value before the offering of $ million by the number of common units ( ) issuable to Diamondback upon the exchange of all of its Class B Units and Rattler LLC Units.

(3)	Determined by dividing the expected distribution of $ million to Diamondback in connection with this offering by the number of common units ( ) issuable to Diamondback upon the exchange of all of its Class B Units and Rattler LLC Units.

(4)

Determined by dividing the pro forma net tangible book value after the offering, after giving effect to the application of the net proceeds of this offering, of $ million by the sum of the number of common units ( ) outstanding after this offering and the number of common units ( ) issuable to Diamondback upon the exchange of all of its Class B Units and Rattler LLC Units.

(5)

Assumes 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. 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.

(6)

Because the total number of common units outstanding on a fully diluted basis following 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 this offering due to any such exercise of the option.

The following table sets forth the number of common units (on a fully diluted basis) acquired, the total consideration paid or exchanged and the average price per common unit (on a fully diluted basis) paid by Diamondback and by purchasers of our common units in this offering, based on an assumed initial public offering price of $ per common unit and no exercise of the underwriters’ option to purchase additional common units.


	Units Acquired				Total Consideration
	Number	%			Amount	%
					(in millions)
Diamondback and its affiliates(1)(2)(3)				%	$			%
Purchasers in this offering				%				%

Total			100.0	%	$		100.0	%

(1)	Upon the completion of this offering, following the expiration of the underwriters’ option period, Diamondback will own Class B Units.

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

(3)

The assets contributed by Diamondback were recorded at historical cost in accordance with GAAP. Book value of the consideration provided by our general partner and its affiliates, as of December 31, 2018 was $ (excludes deferred taxes). At the closing of this Offering, we intend to make a distribution to Diamondback of approximately $ million.

CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

You should read the following discussion of our cash distribution policy in conjunction with the specific assumptions included in this section. Please read “—Estimated EBITDA and Distributable Cash Flow for the Twelve Months Ending March 31, 2020” below. In addition, you should read “Cautionary Statement Regarding 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 results of operations, you should refer to our predecessor’s audited historical financial statements as of December 31, 2017 and December 31, 2018 included elsewhere in this prospectus.

Cash Distribution Policy

In connection with the closing of this offering, the board of directors of our general partner will adopt a policy pursuant to which we will pay, to the extent legally available, cash distributions to common unitholders of record on the applicable record date of $ per common unit within 60 days after the end of each quarter beginning with the quarter ending June 30, 2019. Our first distribution will be prorated for the period from the closing of this offering through June 30, 2019. The board of directors of our general partner may change our distribution policy at any time and from time to time. Our partnership agreement does not require us to pay cash distributions on our common units on a quarterly or other basis. Please read “Risk Factors—Risks Inherent in an Investment in Us—The board of directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion. Our partnership agreement does not require us to make any distributions on our common units at all.”

Our Class B Units will be entitled to quarterly aggregate cash preferred distributions of 8% per annum on the $1.0 million capital contribution made in respect of such units, or $0.02 million in aggregate per quarter to all Class B Units, and our general partner will be entitled to a quarterly cash preferred distribution of 8% per annum on the $1.0 million capital contribution made in respect of its general partner interest, or $0.02 million per quarter. We will be required to make these distributions in any quarter before making any distributions on our common units. Other than those amounts, neither our general partner interest nor our Class B Units will be entitled to receive or participate in distributions made by us.

We are a holding company and substantially all of our operations will be carried out by Rattler LLC. Following the completion of this offering, we will control Rattler LLC and we will own Rattler LLC Units, representing an approximately % membership interest in Rattler LLC (if the underwriters exercise in full their option to purchase additional common units, we will own Rattler LLC Units, representing an approximately % membership interest in Rattler LLC).

We expect that our only source of cash will be distributions from Rattler LLC, together with the $2.0 million of cash contributed to us in respect of our Class B Units and our general partner interest. We will only be able to make cash distributions to the extent that we have sufficient cash after the establishment of cash reserves, including for federal income tax expenses, the payment of the preferred distribution on our general partner interest and our Class B Units and the payment of expenses. Rattler LLC will pay all of our expenses, including the expenses we expect to incur as a result of being a publicly traded entity, other than our U.S. federal income tax expense. We expect to initially pay our preferred distributions with cash held by us. The Rattler LLC limited liability company agreement will provide that, in our capacity as managing member of Rattler LLC, we may cause Rattler LLC to pay cash distributions at any time and from time to time, which distributions will be paid pro rata in respect of all outstanding Rattler LLC Units. Rattler LLC’s ability to make any such distribution will be subject to applicable law as well as any contractual restrictions, such as those under its revolving credit facility.

Under our partnership agreement, the services and secondment agreement and the Rattler LLC limited liability company agreement, Rattler LLC will reimburse our general partner and its affiliates, including

Diamondback, for costs and expenses they incur and payments they make on our behalf. Rattler LLC will make these payments before making any distributions in respect of the Rattler LLC Units.

Because we will own an approximate % membership interest in Rattler LLC at the completion of this offering (or an approximate % membership interest in Rattler LLC if the underwriters exercise in full their option to purchase additional common units), for Rattler LLC to distribute $ million in cash to us (or $ million in cash to us if the underwriters exercise in full their option to purchase additional common units), Rattler LLC must generate cash available for distribution of at least $ million.

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

There is no guarantee that we will receive quarterly distributions from Rattler LLC or that we will make cash distributions to our common unitholders. Our cash distribution policy may be changed at any time and is subject to certain restrictions, including the following:

•

Our common unitholders have no contractual or other legal right to receive cash distributions from us on a quarterly or other basis. At the completion of this offering, the board of directors of our general partner will adopt a cash distribution policy that requires us to pay quarterly distributions to common unitholders of record on the applicable record date of $ per common unit within 60 days after the end of each quarter, beginning with the quarter ending June 30, 2019. We do not expect to make distributions for the period from the completion of this offering through March 31, 2019 within 60 days after March 31, 2019. Instead, we expect to adjust our distribution for the period ending June 30, 2019 by an amount that covers the period from the closing of this offering through March 31, 2019 based on the actual number of days in that period.

•

We do not have any debt currently outstanding and, therefore, are not subject to any debt covenants. However, prior to or in connection with the closing of this offering, Rattler LLC expects to enter into a revolving credit facility to be used for general company purposes. We anticipate that any future debt agreements will contain certain financial tests and covenants that would require satisfaction before Rattler LLC could distribute cash to us and before we could distribute cash to our common unitholders. If we are unable to satisfy the restrictions under any future debt agreements, we could be prohibited from making a distribution to you notwithstanding our stated distribution policy.

•

Our business performance may be volatile, and our cash flow may be less stable, than the business performance and cash flow of other publicly traded companies. As a result, our quarterly cash distributions may be volatile and may vary quarterly and annually.

•

We do not have a minimum quarterly distribution or employ structures intended to maintain or increase quarterly distributions over time.

•

Prior to making any distributions in respect of any Rattler LLC units, Rattler LLC will reimburse our general partner and its affiliates for all direct and indirect expenses they incur on our behalf. Our partnership agreement and the services and secondment agreement provides that our general partner will determine the expenses that are allocable to us, but does not limit the amount of expenses for which our

general partner and its affiliates may be reimbursed. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of cash ultimately available to pay distributions to our common unitholders.

•

Prior to making any quarterly distributions on our common units, we must make distributions of $0.02 million in aggregate per quarter on our Class B Units and distributions of $0.02 million per quarter on our general partner interest.

•

Under Section 17-607 of the Delaware Act, we may not make a distribution and, under Section 18-607 of the Delaware Limited Liability Company Act, or the Delaware LLC Act, Rattler LLC may not make a distribution to us, if the distribution would cause our or Rattler LLC’s liabilities to exceed the fair value of our or its assets.

•

We may lack sufficient cash to pay distributions to our common unitholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors as well as increases in operating or general and administrative expenses, tax expenses, working capital requirements and anticipated cash needs.

•

The board of directors of our general partner may determine to accumulate cash rather than to distribute cash, whether to pay for capital expenditures or operating expenses or any other purpose deemed appropriate by that board.

Unaudited Pro Forma EBITDA and Distributable Cash Flow for the Year Ended December 31, 2018

The board of directors of our general partner intends to adopt a cash distribution policy following the closing of this offering pursuant to which we would intend to declare and pay quarterly distributions of $ per quarter ($ per year). Assuming that we issue common units in this offering, that would mean that we would distribute approximately $ million in aggregate to holders of our common units each quarter (or $ million per year). We will also pay an aggregate of $0.04 million per quarter in preferred distributions in respect of our Class B Units and general partner interest, which we will pay with cash held by us. We will be subject to a U.S. federal income tax rate of approximately 21%; however, we expect to generate net operating losses to offset taxable income for 2019 and 2020. Accordingly, we do not expect to pay meaningful U.S. federal income taxes during those periods. We estimate that cash distributions from Rattler LLC of approximately $ million would be required to support the payment of our currently contemplated quarterly distribution for four quarters (approximately $ million per quarter). Our future tax liability may be greater than expected if we do not generate net operating losses sufficient to offset taxable income or if tax authorities challenge certain of our tax positions. In order to pay any contemplated distributions to our common unitholders, we must receive cash distributions from Rattler LLC sufficient to pay U.S. federal income tax on the income allocated to us by Rattler LLC in addition to the cash necessary to pay such distributions. Because Rattler LLC would have Rattler LLC Units outstanding, that means that in order for Rattler LLC to make those distributions to us, it would have to distribute approximately $ million in aggregate to the holders of the Rattler LLC Units, of which we would hold approximately % and Diamondback would hold approximately %.

On a pro forma basis, assuming we had completed this offering and related transactions as of January 1, 2018, (i) Rattler LLC’s distributable cash flow would have been a deficit of approximately $ million for the year ended December 31, 2018 and, accordingly, (ii) Rattler LLC would not have had sufficient cash available to pay distributions on the Rattler LLC Units, and we would not have had sufficient cash available to pay distributions on our common units, for the year ended December 31, 2018.

The table below also assumes that our general partner has not established any reserves related to the conduct of Rattler LLC’s business, including any reserves to provide for future cash distributions to Rattler LLC’s unitholders, including us. The establishment of such reserves by our general partner could result in a reduction in cash available for distribution to us by Rattler LLC, which in turn could result in a reduction in cash distributions to our common unitholders.

We have based the pro forma assumptions upon currently available information and estimates. The pro forma amounts below do not purport to present the results of our operations had this offering and the related

transactions contemplated in this prospectus actually been completed as of the date indicated. As a result, the amount of pro forma distributable cash flow should only be viewed as a general indicator of the amount of distributable cash flow that we might have generated had we been formed and completed the transactions contemplated in this prospectus on January 1, 2018.

The following table illustrates, on a pro forma basis, for the year ended December 31, 2018, the amount of cash that would have been available for distribution to Rattler LLC’s unitholders, including us, and to our common unitholders, assuming in each case that this offering and the other transactions contemplated in this prospectus had been consummated as of January 1, 2018. Certain of the adjustments are explained in further detail in the footnotes to such adjustments.

Rattler Midstream LP

Unaudited Pro Forma EBITDA and Distributable Cash Flow


	Year Ended December 31, 2018
(In thousands)
Pro forma revenues of Rattler LLC:
Revenues—related party	$	169,396
Revenues—third party		3,292
Rental income—related party		2,540
Rental income—third party		8,855
Other real estate income—related party		322
Other real estate income—third party		1,043

Total pro forma revenues		185,448

Pro forma costs and expenses:
Direct operating expenses		33,714
Costs of goods sold (exclusive of depreciation and amortization shown below)		38,852
Real estate operating expenses		1,981
Depreciation, amortization and accretion		35,108
Loss on sale of property, plant and equipment		2,577
General and administrative expenses		2,108

Total pro forma costs and expenses		114,340

Pro forma income from operations		71,108
Other income:
Pro forma income from equity investment		—

Total other income		—

Pro forma net income before taxes		71,108

Provision for income taxes		15,305

Pro forma net income of Rattler LLC	$	55,803

Add:
Provision for income taxes		15,305
Depreciation, amortization and accretion		35,108

Pro forma EBITDA of Rattler LLC		106,216

Less:
Expansion capital expenditures(1)		217,376
Real estate capital expenditures(2)		111,300
Incremental public partnership general and administrative expenses(3)		836

Add:
Contributions from Diamondback to fund capital expenditures

Pro forma distributable cash flow of Rattler LLC	$

Distributions to unitholders of Rattler LLC	$
Excess (deficit) of pro forma distributable cash flow of Rattler LLC above distributions to unitholders of Rattler LLC
Preferred distributions to Diamondback
Preferred distributions to our general partner

Distributions to common unitholders of Rattler Midstream LP at the annualized distribution rate of $ per common unit	$

(1)

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 that increase existing system throughput. Examples of expansion capital expenditures include the construction, development or acquisition of additional gathering pipelines and compressor stations, in each case to the extent such capital

expenditures are expected to expand our operating capacity or revenue. Over the past two years, Diamondback constructed a significant portion of the midstream assets that were contributed to us, which is reflected in the amount of the expansion capital expenditures for the year ended December 31, 2018.

(2)

Real estate capital expenditures are cash expenditures related to two office towers and associated assets located in Midland, Texas, which we refer to as the Fasken Center. On January 31, 2018, Diamondback purchased the Fasken Center for approximately $110.0 million and contributed it to us effective as of that date.

(3)

Represents general and administrative expenses that we expect to incur annually as a result of being a publicly traded partnership, including costs associated with SEC reporting requirements, independent auditor fees, investor relations activities, stock exchange listing, registrar and transfer agent fees, director and officer liability insurance and director compensation.

Estimated EBITDA and Distributable Cash Flow for the Twelve Months Ending March 31, 2020

We forecast Rattler LLC’s estimated EBITDA and distributable cash flow during the twelve months ending March 31, 2020 will be approximately $260.3 million and $151.5 million, respectively. The forecasted amount of distributable cash flow for the twelve months ending March 31, 2020 would be sufficient for Rattler LLC to pay distributions of approximately $ million in respect of the Rattler LLC Units owned by us, which would provide us the amount we would need to pay distributions of $ per common unit for that same period. Our forecast assumes (i) that we will use all of the cash we receive from Rattler LLC for the twelve months ending March 31, 2020 to pay distributions to our common unitholders, (ii) that Rattler LLC will not distribute to us any cash in excess of that needed for such uses, (iii) we will use the net proceeds from this offering and borrowings under Rattler LLC’s new revolving credit facility to pay for capital expenditures and the portion of our investments in the EPIC and Gray Oak projects incurred during the forecast period and (iv) we will use cash held by Rattler Midstream LP to pay our preferred distributions. We will be subject to a U.S. federal income tax rate of approximately 21%; however, we expect to generate net operating losses to offset taxable income for 2019 and 2020. Accordingly, we do not expect to pay meaningful U.S. federal income taxes during those periods.

We are providing this forecast of estimated EBITDA and distributable cash flow to supplement the historical financial statements of our predecessor and our unaudited pro forma combined financial statements included elsewhere in the prospectus in support of our belief that, based on the assumptions stated herein, we should generate sufficient cash to allow us to make distributions at the quarterly distribution rate of $ per common unit on all of our common units for the twelve months ending March 31, 2020. Please read “—Significant Forecast Assumptions” for further information as to the assumptions we have made for the forecast. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies” for information as to the accounting policies we have followed for the financial forecast.

Our forecast is a forward-looking statement and reflects our judgment as of the date of this prospectus of our current outlook and expectations for the twelve months ending March 31, 2020. It should be read together with the historical audited consolidated financial statements of our predecessor and the accompanying notes thereto included elsewhere in this prospectus and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

We do not typically make public projections as to future earnings or other operating results. However, management has prepared this forecast to present the estimated EBITDA and distributable cash flow for the twelve months ending March 31, 2020. This forecast was not prepared with a view toward public disclosure or with a view toward complying with the guidelines established by the American Institute of Certified Public Accountants with respect to forecasted financial information, but, in the view of 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, our expected future financial performance. However, this information is not fact and should not be relied upon as being necessarily indicative of future results and readers of this prospectus are cautioned not to place undue reliance on the forecasted financial information.

Grant Thornton LLP has neither examined, compiled nor performed any procedures with respect to the accompanying prospective financial information and, accordingly, Grant Thornton LLP does not express opinions or any other form of assurance with respect thereto. The Grant Thornton LLP report included in this offering document relates to our audited historical financial information. The report does not extend to the prospective financial information and should not be read to do so.

The assumptions and estimates underlying our forecast, as described below under “—Significant Forecast Assumptions,” are inherently uncertain and, although we consider them reasonable as of the date of this prospectus, they are subject to a wide variety of significant business, economic, financial and competitive risks and uncertainties that could cause actual results to differ materially from those contained in our forecast, including the risks and uncertainties described in “Risk Factors.” Accordingly, our forecast may not be indicative of our future performance and actual results may differ materially from those presented in this forecast. Inclusion of this forecast in this prospectus should not be regarded as a representation by any person that the results contained in this forecast can or will be achieved.

We do not undertake any obligation to release publicly the results of any future revisions we may make to our forecast or to update our financial forecast or the assumptions used to prepare our forecast to reflect events or circumstances after the completion of this offering. In light of this, our forecast should not be regarded as a representation by us, the underwriters or any other person that we will make such distribution. Therefore, you are cautioned not to place undue reliance on this information.

For additional information relating to the principal assumptions used in preparing our forecast please read “—Significant Forecast Assumptions” below.


	Three Months Ending June 30, 2019			Three Months Ending September 30, 2019		Three Months Ending December 31, 2019		Three Months Ending March 31, 2020		Twelve Months Ending March 31, 2020
(In thousands)
Revenues of Rattler LLC:
Revenues—related party	$	61,456		$	66,178	$	71,149	$	77,511	$	276,294
Revenues—third party		19,508			21,529		23,327		25,175		89,539
Surface use		286			286		286		286		1,144
Rental income—related party		690			690		690		690		2,760
Rental income—third party		2,759			2,759		2,759		2,759		11,036
Other real estate income		336			336		336		336		1,344

Total revenues		85,035			91,778		98,547		106,757		382,117

Costs and expenses:
Operating expenses		23,224			25,119		27,292		29,275		104,910
Costs of goods sold (exclusive of depreciation and amortization shown below)		8,806			8,806		8,806		10,057		36,475
Depreciation, amortization and accretion		9,540			10,041		10,542		11,024		41,147
General and administrative expenses(1)		1,875			1,875		1,875		2,125		7,750
Interest expense(2)		3,125			375		430		672		4,602
Total costs and expenses		46,570			46,216		48,945		53,153		194,884

Income from operations		38,465			45,562		49,602		53,604		187,233
Other income:
Income from equity investments(3)		(2,054	)		2,667		3,816		2,094		6,523

Total other income		(2,054	)		2,667		3,816		2,094		6,523

Net income before taxes		36,411			48,229		53,418		55,698		193,756

Provision for income taxes		7,646			10,128		11,218		11,696		40,688
Net income of Rattler LLC	$	28,765		$	38,101	$	42,200	$	44,002	$	153,068

Add:
Interest expense and interest paid on equity investments(4)		4,885			2,859		3,389		3,676		14,809
Provision for income taxes		7,646			10,128		11,218		11,696		40,688
Depreciation, amortization and accretion(5)		9,540			11,411		13,644		15,015		49,610

EBITDA of Rattler LLC		50,836			62,499		70,451		74,389		258,175

Less:
Interest expense(2)		3,125			375		430		672		4,602
Expansion capital expenditures(6)		57,500			57,500		57,500		54,032		226,532
Maintenance capital expenditures(7)		2,500			2,500		2,500		2,500		10,000
Contribution to equity investments(3), (8)		37,500			25,000		29,400		9,776		101,676
EBITDA from equity investments(9)		(294	)		6,520		9,878		9,089		25,193

Add:
Net proceeds used to fund capital expenditures and equity investments(10)		33,832			67,275		48,889		—		149,996
Contributions from Diamondback to fund capital expenditures		53,516			—		—		—		53,516
Distributions from equity investments(3), (11)		26			—		11		44		81
Borrowings used to fund capital expenditures and equity investments		—			—		18,236		39,515		57,751

Distributable cash flow of Rattler LLC	$	37,879		$	37,879	$	37,879	$	37,879	$	151,516

Distributions to unitholders of Rattler LLC	$			$		$		$		$
Partnership cash used to fund preferred distributions	$	40		$	40	$	40	$	40	$	160
Distributions to Diamondback
Distributions to Rattler Midstream LP
Income tax expense of Rattler Midstream LP		—			—		—		—		—
Preferred distributions to Diamondback		20			20		20		20		80
Preferred distributions to our general partner		20			20		20		20		80

Distributions to common unitholders of Rattler Midstream LP at the annualized distribution rate of $ per common unit	$			$		$		$		$

(1)	Excludes the effect of any awards granted under the LTIP. Please read ”—General and Administrative Expenses.”

(2)

Represents cash interest expense on borrowings and commitment fees on undrawn portion of Rattler LLC’s new revolving credit facility that we expect to have in place at the closing of this offering. The forecasted interest expense for borrowings under the new revolving credit facility is based on an interest rate of London Interbank Offered Rate plus 1.25%, with a 0.5% upfront fee and 0.25% of annual commitment fees on committed amounts.

(3)

Equity investments represent our investments in the EPIC project and Gray Oak project. We account for these investments using the equity method of accounting pursuant to the guidance under Financial Accounting Standards Board Accounting Standards Codification Topic 323, “Investments—Equity Method and Joint Ventures.”

(4)

Represents cash interest expense on borrowings and commitment fees on undrawn portion of Rattler LLC’s new revolving credit facility that we expect to have in place at the closing of this offering. In addition, represents pro rata interest paid on equity investments in the EPIC and Gray Oak projects. The forecasted interest rate for the investment period for the pipeline investments is a blended rate of 5.3%, which is inclusive of all interest and fees for the EPIC project and Gray Oak project term loans and the Gray Oak member loan.

(5)	Represents depreciation, amortization and accretion on Rattler LLC assets and liabilities, in addition to depreciation, amortization and accretion on the equity investments.

(6)

Expansion capital expenditures represent 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 that increase existing system throughput.

(7)	Maintenance capital expenditures represent cash expenditures (including expenditures for the construction or development of new capital assets or the replacement, improvement or expansion of existing capital assets) made to maintain, over the long term, our operating capacity or revenue.

(8)

Contributions to equity investments represent cash contributed for our proportional share of capital expenditures within each investment. Of this total, $84.2 million relates to the EPIC project and $17.5 million relates to the Gray Oak project. In February 2019, we paid approximately $34.1 million as part of the option exercise price for our 10% equity interest in the EPIC project and approximately $81.3 million as part of our acquisition cost for our 10% interest in the Gray Oak project. In March 2019 and April 2019, we made capital contributions of approximately $33.0 million and $12.5 million, respectively, in respect of our interest in the Gray Oak project.

(9)

EBITDA from equity investments represents income (loss) from equity investment plus interest in the amount of $10.2 million and depreciation, amortization and accretion associated with equity investments in the amount of $8.5 million for the twelve months ending March 31, 2020. These amounts are reflected in the interest expense and interest paid on equity investment and depreciation, amortization and accretion adjustments to derived EBTIDA of Rattler LLC.

(10)	Assumes that Rattler LLC receives and retains net proceeds of $150 million from this offering.

(11)	Distributions to equity investments represent dividends on our investments in the EPIC project and Gray Oak project, as well as interest on the Gray Oak member loan.

EBITDA from Equity Investments Reconciliation


	Three Months Ending June 30, 2019			Three Months Ending September 30, 2019		Three Months Ending December 31, 2019		Three Months Ending March 31, 2020		Twelve Months Ending March 31, 2020
(In thousands)
Income (loss) from equity investment		(2,054	)		2,667		3,816		2,094		6,523
Interest from equity investment		1,760			2,484		2,959		3,004		10,207
Depreciation, amortization and accretion from equity investment		—			1,369		3,103		3,991		8,463

EBTIDA from equity investment	$	(294	)	$	6,520	$	9,878	$	9,089	$	25,193

Significant Forecast Assumptions

In order for us to declare and pay quarterly distributions of $ per common unit, or $ per common unit on an annualized basis, we estimate that Rattler LLC will have to distribute approximately $ per quarter, or $ million per year, based on the number of Rattler LLC Units to be outstanding after completion of this offering. We forecast Rattler LLC’s estimated distributable cash flow during the twelve months ending March 31, 2020 will be approximately $ million.

Set forth below are the material assumptions we have made to calculate the estimated EBITDA and distributable cash flow for the twelve months ending March 31, 2020. The forecast has been prepared by and is the responsibility of our management. Our assumptions reflect our expectations during the forecast period. While the assumptions disclosed in this prospectus do not include all of the assumptions used to calculate our forecast, the assumptions presented are those that we believe are material to our forecast. While we believe we have a reasonable basis for our assumptions, our forecasted results may not be achieved. There will likely be differences between our forecast and our actual results and those differences may be material. If our forecast is not achieved, Rattler LLC may not have sufficient distributable cash flow to pay distributions on the Rattler LLC Units, and we may not be able to pay any distributions on our common units.

General Considerations

Our predecessor’s historical results of operations include all of the results of operations of Rattler LLC on a 100% basis. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting the Comparability of Our Financial Results” and “Certain Relationships and Related Party Transactions—Agreements with our Affiliates in Connection with the Transactions—Equity Contribution Agreement.” Substantially all of our revenue will be derived from long-term, fixed-fee midstream services agreements with Diamondback.

Results and Volumes

The following table summarizes the pro forma revenues, volumes and EBITDA for our midstream services for Rattler LLC the year ended December 31, 2018, as well as our forecast regarding those same amounts for the twelve months ending March 31, 2020.


	Pro Forma Year Ended December 31, 2018		Forecasted Twelve Months Ending March 31, 2020
Midstream services:
Crude oil gathering volumes (Bbl/d)		47,338		100,573
Natural gas gathering volumes (MMBtu/d)		39,252		57,114
Fresh water services volumes (Bbl/d)		281,916		285,422
Saltwater services volumes (Bbl/d)		252,118		719,811
Total midstream services revenues ($ in thousands)	$	172,688	$	366,977
Real estate revenue ($ in thousands)	$	12,760	$	15,140
Total revenues ($ in thousands)	$	185,448	$	382,117
EBITDA ($ in thousands)	$	106,216	$	260,324

Revenue

We estimate that total revenues for the twelve months ending March 31, 2020 will be approximately $382 million compared to approximately $185 million for the pro forma year ended December 31, 2018. As a result of well completions, in addition to production from existing wells on our systems, we estimate that our average daily throughput for the twelve months ending March 31, 2020 will be 101 MBbl/d of crude oil and 57 MMBtu/d of natural gas. Our forecasted increase in volumes over the year ended December 31, 2018 is based on our expectation that Diamondback will complete the drilling and completion activities on our Dedicated Acreage consistent with their current development plan. Please read “Business—Our Commercial Agreements with Diamondback.”

Through the Acreage Dedication, Diamondback has exclusively dedicated to us the right to provide certain crude oil, natural gas and water-related midstream services (including fresh water sourcing and transportation and saltwater gathering and disposal) associated with its production on a total of approximately 206,000 gross acres in the Delaware Basin and 217,000 gross acres in the Midland Basin for initial terms ending in 2034. As of December 31, 2018, Diamondback had identified approximately 10,000 gross economic potential horizontal drilling locations at $60 per barrel of oil, the substantial majority of which are on lands covered by the Acreage Dedication. In addition, Diamondback has publicly announced that it expects to complete between 290 to 320 gross horizontal wells in 2019 and, accordingly, it is targeting over 27% annual production growth in 2019. We expect that we will be Diamondback’s primary midstream solution provider with respect to these wells and this production growth.

Our revenues are, in part, affected by commodity prices, which drive the level and pace of Diamondback’s exploration and production activities. See “Risk Factors—Risks Related to Our Business—Our exposure to commodity price risk may change over time and we cannot guarantee the terms of any existing or future agreements for our midstream services with our customers.” Diamondback’s exploration and production activities are driven by a number of variables that make the determination of the impact on our cash flows of different drilling and development plans difficult. However, we estimate that, if commodity prices were to fall to a level where Diamondback and all of our other customers halted drilling activities as of the beginning of the forecast period, we would be able to make distributions on all of our common units in accordance with our anticipated cash distribution policy for the forecast period.

Operating Expense

We estimate that total operating expense for the twelve months ending March 31, 2020 will be $105 million compared to approximately $36 million for the pro forma year ended December 31, 2018. Operating expense is forecasted to increase due to crude oil gathering volumes increasing by 53,235 Bbl/d, or 112%, natural gas gathering volumes increasing by 17,862 MMBtu/d, or 46%, fresh water services volumes increasing by 3,506 Bbl/d, or 1%, and saltwater services volumes increasing by 467,693 Bbl/d, or 186%. Operating expense is forecasted to increase by a greater percentage than the increase in overall volumes for our midstream services because saltwater services, which have higher unit operating expense than oil and gas gathering and freshwater services, comprise a relatively greater percentage of the forecasted volumes than the historical period.

Cost of Goods Sold

We estimate that total cost of goods sold for the twelve months ending March 31, 2020 will be $36 million compared to $39 million for the pro forma year ended December 31, 2018. Cost of goods sold is forecasted to decrease slightly, even though fresh water services volumes (the only midstream service included in this expense) are forecasted to increase by 3,506 Bbl/d, or 1%, because of the increased use of produced water that has been recycled, in addition to our expectation to source our fresh water from lower cost supplies.

General and Administrative Expenses

Our general and administrative expenses will consist of reimbursements to Diamondback of certain general and administrative expenses under the services and secondment agreement.

We expect total general and administrative expenses for the twelve months ending March 31, 2020 will be $8 million as compared to $2 million for the pro forma year ended December 31, 2018, excluding the impact of any phantom unit awards described below. The forecast period includes the $1.4 million of annual incremental publicly traded partnership expenses we expect to incur. The increase in general and administrative expenses primarily relates to increased personnel and associated administrative expenses due to our projected growth.

At the closing of this offering, we expect to grant awards of phantom units under the LTIP. Please read “Executive Compensation and Other Information.” We expect that those phantom units will be entitled to distribution equivalent payments; accordingly, for every 1,000,000 phantom units so granted, we expect that our general and administrative expenses for the twelve months ending March 31, 2020 would increase by $ million of expense associated with those distribution equivalent payments.

Depreciation, Amortization and Accretion

We estimate that depreciation, amortization and accretion for the twelve months ending March 31, 2020 will be $50 million as compared to approximately $26 million for the pro forma year ended December 31, 2018. Depreciation, amortization and accretion expense is forecasted to increase due to the contribution to Rattler LLC by Diamondback effective January 1, 2019 of certain crude oil gathering, SWD wells and land and buildings with a net book value of $298 million that Diamondback acquired pursuant to the Ajax acquisition and the Energen acquisition, in addition to $227 million of planned expansion capital expenditures, substantially all of which represent depreciable assets.

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 our total capital expenditures for the twelve months ending March 31, 2020 will be $338 million, including approximately $102 million of anticipated capital contributions to be made by us in connection with our minority interests in the EPIC and Gray Oak projects.

Income Tax Expense

We estimate that the provision for income taxes for the twelve months ending March 31, 2020 will be $41 million compared to approximately $17 million for the pro forma year ended December 31, 2018. The provision for income taxes, calculated at a U.S. federal income tax rate of approximately 21%, is forecasted to increase due to forecasted net income before taxes for the twelve months ending March 31, 2020 of $194 million compared to approximately $80 million for the pro forma year ended December 31, 2018.

Regulatory, Industry and Economic Factors

Our forecast of EBITDA and distributable cash flow for the twelve months ending March 31, 2020 is also based on the following significant assumptions related to regulatory, industry and economic factors:

•

Diamondback will not default under our commercial agreements or reduce, suspend or terminate its obligations, nor will any events occur that would be deemed a force majeure event, under such agreements;

•

the locations of Diamondback’s planned well development will not be determined uneconomic by us;

•

there will not be any new federal, state or local regulation, or any interpretation or application 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 or Diamondback’s development plan;

•

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.

HOW WE MAKE DISTRIBUTIONS

In connection with the closing of this offering, the board of directors of our general partner will adopt a policy pursuant to which we will pay, to the extent legally available, cash distributions to common unitholders of record on the applicable record date of $ per common unit within 60 days after the end of each quarter beginning with the quarter ending June 30, 2019. We do not expect to make distributions for the period from the completion of this offering through March 31, 2019 within 60 days after March 31, 2019. Instead, we expect to adjust our distribution for the period ending June 30, 2019 by an amount that covers the period from the closing of this offering through March 31, 2019 based on the actual number of days in that period. The board of directors of our general partner may change the foregoing distribution policy at any time and from time to time. We will also pay an aggregate of $0.04 million per quarter in preferred distributions in respect of our Class B Units and general partner interest. Our partnership agreement does not require us to pay cash distributions on a quarterly or other basis. See “Cash Distribution Policy and Restrictions on Distributions.”

Our Sources of Cash

Following the completion of this offering, our only cash-generating asset will consist of Rattler LLC Units (or Rattler LLC Units if the underwriters exercise in full their option to purchase additional common units), together with the $2.0 million contributed to us in respect of our Class B Units and our general partner interest. Therefore, our cash flow and resulting ability to make distributions will be completely dependent upon the ability of Rattler LLC to make distributions. Subject to applicable law and any contractual restrictions to which Rattler LLC may be subject, we will control whether and when Rattler LLC makes any distributions. Other than the initial distribution contemplated to be made to Diamondback by Rattler LLC in connection with the completion of this offering (including any exercise of the underwriters’ option to purchase additional common units), all distributions paid by Rattler LLC will be made pro rata in respect of all Rattler LLC Units outstanding at the time of distribution. The actual amount of cash that Rattler LLC will have available for distribution will primarily depend on the amount of cash Rattler LLC generates from its operations. For a description of factors that may impact our results and Rattler LLC’s results, please read “Cautionary Statement Regarding Forward-Looking Statements.”

In addition, the actual amount of cash that Rattler LLC will have available for distribution will depend on other factors, some of which are beyond Rattler LLC’s or our control, including:

•

the level of revenue Rattler LLC is able to generate from its business;

•

the level of capital expenditures Rattler LLC makes, including capital calls associated with the EPIC and Gray Oak projects;

•

the level of Rattler LLC’s operating, maintenance and general and administrative expenses or related obligations;

•

the cost of acquisitions, if any;

•

Rattler LLC’s debt service requirements and other liabilities;

•

Rattler LLC’s working capital needs;

•

restrictions on distributions contained in any future Rattler LLC debt agreements;

•

Rattler LLC’s ability to borrow under its revolving credit facility to make distributions; and

•

the amount, if any, of cash reserves established for the proper conduct of Rattler LLC’s business.

Rattler LLC Units

Following the completion of this offering, Rattler LLC will have Rattler LLC Units outstanding, of which (approximately %) will be owned by us and (approximately %) will be owned by Diamondback. If the underwriters exercise in full their option to purchase additional

common units, then (approximately %) will be owned by us and (approximately %) will be owned by Diamondback. Each Rattler LLC Unit will be entitled to receive cash distributions to the extent Rattler LLC makes distributions. Rattler LLC Units will not accrue arrearages. Rattler LLC’s limited liability company agreement requires Rattler LLC to make distributions, if any, to all record holders of Rattler LLC Units, pro rata.

Common Units

Following the completion of this offering, we will have common units outstanding (or if the underwriters exercise in full their option to purchase additional common units). Each common unit will be entitled to receive cash distributions to the extent we make distributions. Common units will not accrue arrearages. Our partnership agreement allows us to issue an unlimited number of additional equity interests of equal or senior rank.

Class B Units

Following the completion of this offering, we will have Class B Units outstanding (or Class B Units outstanding if the underwriters exercise in full their option to purchase additional common units). Class B Units will not be entitled to participate in distributions made by us, except that our Class B Units will be entitled to quarterly cash preferred distributions of 8% per annum on the $1.0 million capital contribution made in respect of such units, or $0.02 million in aggregate per quarter to all Class B Units.

General Partner Interest

Our general partner owns a general partner interest and is not entitled to participate in distributions made by us, except that it will be entitled to a quarterly cash preferred distribution of 8% per annum on the $1.0 million capital contribution made in respect of its general partner interest, or $0.02 million per quarter. Our general partner may acquire common units and other equity interests (including Class B Units) in the future and will be entitled to receive pro rata distributions in respect of those equity interests to the extent those equity interests are entitled to receive distributions.

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 for Rattler Midstream LP for the periods and as of the dates indicated. The selected historical financial data of our predecessor as of and for the years ended December 31, 2017 and 2018 are derived from the audited 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 and pro forma 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.”

Upon the completion of this offering, we will own a % controlling membership interest in Rattler LLC (assuming no exercise of the underwriters’ option to purchase additional common units) and Diamondback will own, through its ownership of Rattler LLC Units, a % economic, non-voting interest in Rattler LLC (assuming no exercise of the underwriters’ option to purchase additional common units). However, as required by GAAP, we will consolidate 100% of the assets and operations of Rattler LLC in our financial statements and reflect a non-controlling interest.

The selected unaudited pro forma financial data presented in the following table for the year ended December 31, 2018 is derived from the unaudited pro forma combined financial statements included elsewhere in this prospectus. The unaudited pro forma combined balance sheet data as of December 31, 2018 and the unaudited pro forma combined statements of operations and statement of cash flows data for the year ended December 31, 2018 assume the offering and the related transactions occurred as of January 1, 2018. These transactions include, and the unaudited pro forma combined financial statements give effect to, the following:

•

the contribution to us by Diamondback in relation to the Class B Units of $1.0 million in cash, which we will retain at the partnership;

•

the contribution to us by our general partner in relation to its general partner interest of $1.0 million in cash, which we will retain at the partnership;

•

our issuance of Class B Units to Diamondback and the issuance by Rattler LLC of an equal number of Rattler LLC Units to Diamondback;

•

our issuance of common units pursuant to this offering in exchange for net proceeds of approximately $ million;

•

our contribution of all of the net proceeds from this offering to Rattler LLC in return for a number of Rattler LLC Units equal to the number of common units issued;

•

Rattler LLC’s entrance into a new $600 million revolving credit facility;

•

the acquisition of the Fasken Center by Diamondback and contribution to Rattler LLC of all the membership interests in Tall Towers, as if such transactions occurred on January 1, 2018 for the purposes of preparing the unaudited pro forma combined statement of operations (for the year ended December 31, 2017, see the Fasken Midland Statement of Revenue and Certain Expenses included elsewhere in this prospectus); and

•

the contribution to Rattler LLC by Diamondback of certain crude oil gathering, SWD wells and land and buildings Diamondback acquired pursuant to the Ajax acquisition and the Energen acquisition.


	Rattler Midstream LP Predecessor Historical				Rattler Midstream LP Pro Forma
					Year Ended December 31, 2018
	Years Ended December 31,
	2018		2017
	(in thousands, except per unit data)
Statement of Operations Data:
Revenues
Total revenues	$	184,467	$	39,295	$	185,448
Costs and expenses
Operating expenses		74,438		10,557		74,547
Depreciation, amortization and accretion		25,134		3,486		35,108
Loss on sale of property, plant and equipment		2,577		—		2,577
General and administrative expenses		1,999		1,265		2,108

Total costs and expenses		104,148		15,308		114,340

Income from operations		80,319		23,987		71,108
Other income (expense)
Interest expense, net of amount capitalized		—		—		—
Income from equity investment		—		1,366		—

Total other income (expense)		—		1,366		—

Net income before income taxes		80,319		25,353		71,108
Provision for income taxes		17,359		4,688		15,305

Net income	$	62,960	$	20,665	$	55,803

Net income per common unit (basic and diluted)
Common units
Balance Sheet Data (at period end):
Total property, plant and equipment, net	$	561,921	$	255,323	$	859,533
Total assets		604,016		299,605		901,628
Member’s equity / partners’ capital		527,125		292,608		821,393
Statement of Cash Flows Data:
Net cash provided by operating activities	$	173,431	$	8
Net cash used in investing activities		164,876		—
Net cash provided by financing activities		—		—
Other Data:
EBITDA(1)	$	105,453	$	28,839	$	106,216

(1)	For our definition of the non-GAAP financial measure of EBITDA and a reconciliation of EBITDA to our most directly comparable financial measures calculated and presented in accordance with GAAP, please read “—Non-GAAP Financial Measures.”

Non-GAAP Financial Measures

•

our operating performance as compared to those of other companies in the midstream energy industry, without regard to financing methods, historical cost basis or capital structure;

•

the ability of our assets to generate sufficient cash flow to make distributions to our common unitholders;

•

our ability to incur and service debt and fund capital expenditures; and

•

the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.


	Rattler Midstream LP Predecessor Historical					Rattler Midstream LP Pro Forma
	Years Ended December 31,					Year Ended December 31, 2018
	2018			2017		Year Ended December 31, 2018
	(in thousands, except per unit data)
Reconciliation of net income to EBITDA:
Net income	$	62,960		$	20,665	$	55,803
Provision for income taxes		17,359			4,688		15,305
Interest expense, net of amount capitalized		—			—		—
Depreciation, amortization and accretion		25,134			3,486		35,108

EBITDA	$	105,453		$	28,839	$	106,216

Reconciliation of net cash provided by operating activities to EBITDA:
Net cash provided by operating activities	$	173,431		$	8
Changes in operating assets and liabilities		(65,401	)		27,465
Interest expense, net of amount capitalized		—			—
Stock based compensation and other		(2,577	)		1,366

EBITDA	$	105,453		$	28,839

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read the following discussion of the financial condition and results of operations of Rattler LLC, the predecessor of Rattler Midstream LP, or the partnership, in conjunction with the historical audited financial statements as of and for the years ended December 31, 2017 and 2018 and notes of Rattler LLC and the unaudited pro forma financial statements for the partnership included elsewhere in this prospectus. Among other things, the unaudited pro forma financial statements include more detailed information regarding the basis of presentation for the following information. This discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those discussed below. Factors that could cause or contribute to such differences include, but are not limited to, those identified below and those discussed in the sections entitled “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements” included elsewhere in this prospectus.

Upon completion of this offering, we will own an approximate % controlling managing member interest in Rattler LLC (or an approximate % controlling managing member interest if the underwriters exercise in full their option to purchase additional common units), and Diamondback will own, through its ownership of Class B Units, an approximate % voting interest in us (or an approximate % voting interest in us if the underwriters exercise in full their option to purchase additional common units) and, through its ownership of Rattler LLC Units, an approximate % economic, non-voting interest in Rattler LLC (or an approximate % economic, non-voting interest in Rattler LLC if the underwriters exercise in full their option to purchase additional common units), and we will consolidate Rattler LLC in our financial statements. Because we will consolidate Rattler LLC, financial results are shown on a 100% basis and are not adjusted to reflect Diamondback’s non-controlling interest in Rattler LLC.

Overview

We are a growth-oriented Delaware limited partnership formed in July 2018 by Diamondback to own, operate, develop and acquire midstream infrastructure assets in the Midland and Delaware Basins of the Permian, one of the most prolific oil producing areas in the world. Immediately following this offering, we expect to be the only publicly-traded, pure-play Permian midstream company focused on the Midland and Delaware Basins. We provide crude oil, natural gas and water-related midstream services (including fresh water sourcing and transportation and saltwater gathering and disposal) to Diamondback under long-term, fixed-fee contracts. As of January 1, 2019, the assets Diamondback has contributed to us include a total of 746 miles of pipeline across the Midland and Delaware Basins with a total of approximately 232,000 Bbl/d of crude oil gathering capacity, 2.685 MMBbl/d of permitted SWD capacity, 550,000 Bbl/d of fresh water gathering capacity, 53,500 Mcf/d of natural gas compression capability and 342,000 Mcf/d of natural gas gathering capacity. In addition to the midstream infrastructure assets that Diamondback contributed to us, we own equity interests in two long-haul crude oil pipelines, which, upon completion, will run from the Permian to the Texas Gulf Coast. We are critical to Diamondback’s growth plans because we provide a long-term midstream solution to its increasing crude oil, natural gas and water-related services needs through our robust infield gathering systems and SWD capabilities.

Our Business

Our general partner’s management team consists of members of the management teams of Diamondback and the general partner of Viper. We will elect to be treated as a corporation for tax purposes because we expect that such treatment will expand the potential investor base for our units and will provide our unitholders with more liquidity and improve, if necessary, our access to capital. Unlike some traditional midstream entity structures, we do not have incentive distribution rights or subordinated units, so the economic interests of our common unitholders and our sponsor are aligned. We believe that our relationship with Diamondback and our common strategic and operational interests differentiate us in the public midstream sector and provide the optimal platform to pursue a balanced plan for future growth that benefits all unitholders equally. Immediately following this offering, we will have no outstanding indebtedness, and we do not plan on accessing the capital markets to fund our current organic growth opportunities.

We are Diamondback’s primary provider of midstream gathering and water-related services and are integral to Diamondback’s strategy of being a premier, low-cost, high-growth operator that can grow production at industry leading rates within cash flow. We have Dedicated Acreage that spans a total of approximately 423,000 gross acres across all service lines on Diamondback’s core leasehold in the Permian (a total of approximately 217,000 gross acres in the Midland Basin and a total of approximately 206,000 gross acres in the Delaware Basin). We entered into commercial agreements with Diamondback that have initial terms ending in 2034. The fees charged under these agreements are based on market prevailing rates at the time of their implementation with annual escalators (subject to potential adjustment by regulators). These fixed-fee contracts, along with Diamondback’s strong well economics, extensive horizontal drilling inventory and low-cost operating model, minimize our direct exposure to commodity prices while providing us with stable and predictable cash flow over the long-term. In February 2019, we acquired a 10% equity interest in the EPIC project and a 10% equity interest in the Gray Oak project. Our total capital commitment with respect to our 10% interest in the EPIC project is currently anticipated to be approximately $118.8 million, which includes $34.1 million paid as part of the option exercise price. Our total capital commitment with respect to our 10% interest in the Gray Oak project is currently anticipated to be approximately $126.5 million, which includes $81.3 million paid as part of our acquisition cost for this interest and $33.0 million and $12.5 million contributed in March 2019 and April 2019, respectively, in respect of our equity interest. Once these pipelines are operational, which is anticipated to occur in the second half of 2019, our equity interests in the EPIC and Gray Oak projects are expected to provide us with a steady, oil-weighted cash flow stream. These pipelines will also provide Diamondback with long-term long-haul transportation capacity for a portion of its Delaware and Midland Basin crude oil production.

Diamondback commenced operations in December 2007 with the acquisition of 4,174 net acres in the Midland Basin. By May 2016, through a series of subsequent acquisitions, Diamondback had built a pure play Midland Basin position of approximately 85,000 net acres. In 2016, Diamondback entered the Delaware Basin through two acreage acquisitions totaling 95,499 net acres. In addition, on October 31, 2018, Diamondback acquired 25,493 net acres in the Midland Basin in connection with the Ajax acquisition, and, on November 29, 2018, subsequently acquired approximately 89,000 and 90,000 net acres in the Delaware and Midland Basin, respectively, in connection with the Energen acquisition.

will generate strong free cash flow that we can use to fund our capital programs and return capital to unitholders through distributions, positioning us as a leading, high-growth, self-funding midstream services provider. We also believe that the combination of our midstream assets and the firm crude oil takeaway capacity on the EPIC and Gray Oak projects will provide Diamondback critical access to a vital long-haul takeaway solution for its planned development on its existing acreage in the Permian. Once these pipelines are operational, which is anticipated to occur in the second half of 2019, our equity interests in the EPIC and Gray Oak projects are expected to provide us with a steady cash flow stream from oil-weighted long-haul crude oil transportation. Our strategy of proactively creating an outlet for Diamondback’s growing production will drive increased volumes through our midstream systems and increase our free cash flow generation capabilities.

How We Generate Revenue

Our results are primarily driven by the volumes of crude oil that we gather, transport and deliver; natural gas that we gather, compress, transport and deliver; fresh water that we source, transport and deliver; and produced water that we gather, transport and dispose of, and the fees we charge per unit of throughput for our midstream services.

Our crude oil infrastructure assets consist of gathering pipelines and metering facilities, which collectively gather crude oil for our customers. Our facilities gather crude oil from horizontal and vertical wells in Diamondback’s Spanish Trail, Utah and Reward fields within the Permian. Our natural gas gathering and compression system consists of gathering pipelines, compression and metering facilities, which collectively service the production from Diamondback’s Utah field within the Permian. Our fresh water sourcing and distribution assets consists of water wells, frac pits, pipelines and water treatment facilities, which collectively gather and distribute water from Permian aquifers to the drilling and completion sites through buried pipelines and temporary surface pipelines. Our saltwater gathering and disposal system spans approximately 389 miles and consists of gathering pipelines along with SWD wells and facilities which collectively gather and dispose of saltwater from operations throughout Diamondback’s Permian acreage.

We have entered into multiple fee-based commercial agreements with Diamondback, each with an initial term ending in 2034, utilizing our infrastructure assets or our planned infrastructure assets to provide an array of essential services critical to Diamondback’s upstream operations in the Delaware and Midland Basins. Our agreements include substantial acreage dedications. Please read “Business—Our Acreage Dedication.”

We have indirect exposure to commodity price risk in that persistent low commodity prices may cause Diamondback or other customers to delay drilling or shut in production, which would reduce the volumes available for gathering and processing by our infrastructure assets. If Diamondback delays drilling or temporarily shuts in production due to persistently low commodity prices or for any other reason, our revenue could decrease, as our commercial agreements do not contain minimum volume commitments. Please read “Risk Factors—Risks Related to Our Business—Because of the natural decline in hydrocarbon production from existing wells, our success depends, in part, on our ability to maintain or increase hydrocarbon throughput volumes on our midstream systems, which depends on our customers’ levels of development and completion activity on our Dedicated Acreage” and “Risk Factors—Risks Related to Our Business—Our construction of new midstream assets may not result in revenue increases and may be subject to regulatory, environmental, political, contractual, legal and economic risks, which could adversely affect our cash flow, results of operations and financial condition and, as a result, our ability to distribute cash to unitholders.”

Under each of our commercial agreements (other than the FERC-regulated crude oil gathering services agreement), the volumetric fees we charge are adjusted each calendar year by the amount of percentage change, if any, in the consumer price index from the preceding calendar year. No adjustment will be made if the percentage change would result in a fee below the initial fee set forth in the applicable commercial agreement and any adjustment to the volumetric fees shall not exceed three percent of the then-current fee. Further, the total adjustment of the fees shall never result in a cumulative volumetric fee adjustment of more than thirty percent of the initial fees set forth in the applicable commercial agreement. Please read “Business—Our Commercial Agreements with Diamondback.”

How We Evaluate Our Operations

Our management intends to use a variety of financial and operating metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability and include: (i) throughput volumes; (ii) EBITDA (as defined below) and (iii) operating expenses.

Throughput Volumes

The amount of revenue we generate primarily depends on the volumes of crude oil, natural gas and water for which we provide midstream services. These volumes are affected primarily by changes in the supply of and demand for crude oil and natural gas in the markets served directly or indirectly by our assets. By performing routine maintenance and monitoring our infrastructure, we are able to minimize service interruptions on our gathering, transportation and disposal systems.

Under our commercial agreements, we provide (i) crude oil gathering, transporting and delivering services, with approximately 150,000 gross dedicated acres, (ii) natural gas gathering compressing, transporting and delivery services, with approximately 90,000 gross dedicated acres and firm capacity for natural gas attributable to such acreage, (iii) produced water gathering, transporting and disposal services, with approximately 423,000 gross dedicated service acres and firm capacity for produced water and flowback water attributable to such acreage, and (iv) fresh water sourcing, transporting and delivering services, with approximately 241,000 gross dedicated service acres. We own equity interests in two long-haul crude oil pipelines under development that will provide firm takeaway for a portion of Diamondback’s estimated Delaware and Midland Basin production. These pipelines will provide a total takeaway capacity of approximately 1,500,000 Bbl/d which, with the installation of additional pumps and storage, can be increased to approximately 1,800,000 Bbl/d of crude oil directly to the Texas Gulf Coast with Diamondback’s committed volumes representing 200,000 Bbl/d. Please read “Certain Relationships and Related Party Transactions—Agreements with our Affiliates in Connection with the Transactions” for additional information about our commercial agreements with Diamondback.

Because the production rate of a well declines over time, our ability to provide gathering, compression and disposal services, and to maintain or increase the throughput volumes on our midstream systems, is contingent on our customers continually discovering and producing new volumes of crude oil and natural gas and generating produced water. Because fresh water services are largely dependent on well completion, our ability to provide fresh water services is contingent on our customers drilling and completing new wells. We derive substantially all of our revenue from our commercial agreements with Diamondback, which agreements do not contain minimum volume commitments. Our ability to maintain or increase existing throughput volumes on our midstream systems is impacted by:

•

successful drilling activity by our customers on our Dedicated Acreage and our ability to fund the capital costs required to connect our infrastructure assets to new wells;

•

our ability to utilize the remaining uncommitted capacity on, or add additional capacity to, our infrastructure assets;

•

our ability to manage the level of work-overs and re-completions of wells on existing pad sites to which our infrastructure assets are connected;

•

our ability to increase throughput volumes on our infrastructure assets by making outlet connections to existing or new third-party pipelines or other facilities, primarily driven by the anticipated supply of and demand for crude oil, natural gas and water;

•

our ability to identify and execute organic expansion projects to capture incremental volumes from Diamondback and third-parties;

•

our ability to compete for volumes from successful new wells in the areas in which we operate outside of our Dedicated Acreage; and

•

our ability to gather crude oil and natural gas and provide water services with respect to hydrocarbons produced on acreage that has been released from commitments with our competitors.

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

EBITDA

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our operating performance as compared to those of other companies in the midstream energy industry, without regard to financing methods, historical cost basis or capital structure;

•

the ability of our assets to generate sufficient cash flow to make distributions to our common unitholders;

•

our ability to incur and service debt and fund capital expenditures; and

•

the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

We believe that the presentation of EBITDA in this prospectus provides information useful to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to EBITDA are net income and net cash provided by operating activities. EBITDA should not be considered an alternative to net income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. EBITDA excludes some, but not all, items that affect net income or net cash, and these items may vary from those of other companies. As a result, our measure of EBITDA may not be comparable to similarly titled measures of other companies.

For a discussion of the non-GAAP financial measure of EBITDA and a reconciliation of EBITDA to its most comparable measures calculated and presented in accordance with GAAP, please read “Selected Historical and Pro Forma Financial Data—Non-GAAP Financial Measures.”

Operating Expense

We seek to maximize the profitability of our operations, in part, by minimizing, to the extent appropriate, expenses directly tied to operating our assets. Direct labor costs, ad valorem taxes, repair and non-capitalized maintenance costs, integrity management costs, utilities and contract services comprise the most significant portion of our operating expense. Many of these expenses remain relatively stable across broad ranges of throughput volumes, but a portion of these expenses can fluctuate from period to period depending on the mix of activities performed during that period and the timing of these expenses. We will seek to manage our maintenance expenses on our midstream systems by scheduling maintenance over time to avoid significant variability in our maintenance expenses and minimize their impact on our cash flow.

Factors Affecting the Comparability of Our Financial Results

Our future results of operations may not be comparable to our predecessor’s historical results of operations for the reasons described below:

Contribution of Midstream Assets

During the period from 2014 through 2017, Diamondback constructed and/or acquired various midstream and related assets located in the Delaware and Midland Basins which Diamondback contributed to Rattler LLC

during fiscal years 2016 and 2017. Effective February 28, 2017, Diamondback contributed to Rattler LLC certain midstream assets in the Utah field within the Permian that it acquired from Brigham Resources Midstream, LLC and other third parties. Effective January 1, 2018, Diamondback also contributed to Rattler LLC certain freshwater assets including certain freshwater wells, fresh water transportation lines and related assets located within the Permian. Effective January 1, 2019, Diamondback contributed to Rattler LLC certain midstream assets within the Permian that it acquired from Energen Corporation and other third parties.

In October 2014, Diamondback acquired a 25% membership interest in HMW Fluid Management LLC, a Texas limited liability company, or HMW LLC, that was formed to develop, own and operate an integrated water management system to gather, store, process, treat, distribute and dispose of water to E&P companies operating in Midland, Martin and Andrews Counties, Texas. On June 30, 2018, HMW LLC’s operating agreement was amended effective January 1, 2018. As a result of the amendment, Rattler LLC will no longer recognize an equity investment in HMW LLC but will instead consolidate its interests in the net assets of HMW LLC. In exchange for Rattler LLC’s 25% investment, Rattler LLC received a 50% undivided ownership interest in two of the four SWD wells and associated assets previously owned by HMW LLC. Rattler LLC’s basis in the assets is equivalent to its basis in the equity investment in HMW LLC.

Contribution of Fasken Center

Effective January 31, 2018, Diamondback contributed to Rattler LLC all of its membership interests in Tall Towers. Tall Towers owns two office towers and associated assets in Midland, Texas, which we refer to as the Fasken Center.

Equity Investments

In February 2019, we acquired a 10% equity interest in the EPIC project and a 10% equity interest in the Gray Oak project.

Revenues

Prior to this offering, our infrastructure assets were part of the integrated operations of Diamondback and were financed from cash flows from operations and funding from Diamondback. Commencing January 1, 2016, we began to earn revenues under our long-term commercial agreements with Diamondback and will receive separate fixed fees for the midstream services that we provide.

Our real estate assets were contributed by Diamondback effective January 31, 2018 and we earn revenue from these assets through various lease agreements.

Operating Expenses

In connection with this offering, we will enter into an services and secondment agreement with Diamondback under which we will pay fees to Diamondback with respect to certain operational services Diamondback will provide in support of our operations. Our predecessor recorded direct costs of running our businesses as well as certain costs allocated from Diamondback. As such, we expect that there will be differences in the results of our operations between our predecessor’s historical financial statements and our future financial statements.

General and Administrative Expenses

Our predecessor’s general and administrative expenses included an allocation of charges for the management and operation of our assets by Diamondback for general and administrative services, such as information technology, treasury, accounting, human resources and legal services and other financial and

administrative services. Following the completion of this offering, Diamondback will charge us a combination of direct and allocated charges for general and administrative services pursuant to our partnership agreement and the services and secondment agreement.

We anticipate incurring approximately $1.4 million annually of incremental general and administrative expenses attributable to being a publicly traded partnership, which includes expenses associated with annual, quarterly and current reporting with the SEC, tax return preparation, Sarbanes-Oxley compliance, listing on Nasdaq, independent auditor fees, legal fees, investor relations expenses, transfer agent and registrar fees, incremental salary and benefits costs of seconded employees, outside director fees and insurance expenses. These incremental general and administrative expenses and the variable component of the general and administrative costs that we anticipate incurring under the services and secondment agreement are not reflected in our historical financial statements.

Financing

There are differences in the way we will finance our operations as compared to the way our predecessor historically financed operations. Historically, our predecessor’s operations were financed as part of Diamondback’s integrated operations. We expect our sources of liquidity following this offering to include the portion of the net proceeds of this offering retained by Rattler LLC, cash generated from operations, borrowings under Rattler LLC’s new revolving credit facility and, if necessary, the issuance of additional equity or debt securities.

Immediately following the completion of this offering, we intend to have no debt outstanding and an available borrowing capacity of $600 million under Rattler LLC’s new revolving credit facility. Please read “—Capital Resources and Liquidity—Revolving Credit Facility.”

Income Taxes

Income tax expense includes U.S. federal and state taxes on operations, as applicable. Rattler LLC is a flow-through entity for U.S. federal tax purposes and all tax attributes flow through to its members, Diamondback and us. Even though we are organized as a limited partnership under state law, we will be treated as a corporation for U.S. federal income tax purposes and will be subject to U.S. federal and state income tax at regular corporate rates. Rattler LLC’s net income reflects provisions for income taxes as if it had been a corporation.

Other Factors Impacting Our Business

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

Supply and Demand for Crude Oil and Natural Gas

We currently generate a substantial portion of our revenues under fee-based commercial agreements with Diamondback. We expect these contracts to promote cash flow stability and minimize our direct exposure to commodity price fluctuations, since we generally do not own any of the crude oil, natural gas or water that we gather and do not engage in the trading of crude oil or natural gas. However, the volumetric fees we charge are adjusted each calendar year by the amount of percentage change, if any, in the consumer price index from the preceding calendar year. No adjustment will be made if the percentage change would result in a fee below the initial fee set forth in the applicable commercial agreement and any adjustment to the volumetric fees shall not exceed three percent of the then-current fee. Further, the total adjustment of the fees shall never result in a cumulative volumetric fee adjustment of more than thirty percent of the initial fees set forth in the applicable commercial agreement.

Additionally, commodity price fluctuations indirectly influence our activities and results of operations over the long-term, since they can affect production rates and investments by Diamondback and third-parties in the development of new crude oil and natural gas reserves. Generally, drilling and production activity will increase as crude oil and natural gas prices increase. Our throughput volumes depend primarily on the volumes of crude oil and natural gas produced by Diamondback in the Permian and, with respect to fresh water, the number of wells drilled and completed. Commodity prices are volatile and influenced by numerous factors beyond our or Diamondback’s control, including the domestic and global supply of and demand for crude oil and natural gas. The commodities trading markets, as well as other supply and demand factors, may also influence the selling prices of crude oil and natural gas. Furthermore, our ability to execute our growth strategy in the Permian will depend on crude oil and natural gas production in that area, which is also affected by the supply of and demand for crude oil and natural gas.

Regulatory Compliance

The regulation of crude oil and natural gas gathering and transportation and water services activities by federal and state regulatory agencies has a significant impact on our business. Please read “Business—Regulation of Operations.” Our operations are also impacted by new regulations, which have increased the time that it takes to obtain required permits.

Additionally, increased regulation of crude oil and natural gas producers in our areas of operation, including regulation associated with hydraulic fracturing, could reduce regional supply of crude oil, natural gas and water and, therefore, throughput on our infrastructure assets. For more information, see “Business—Regulation of Operations.”

Results of Operations

Year Ended December 31, 2018 Compared to the Year Ended December 31, 2017


	Year Ended December 31,				Increase / (Decrease) from Prior Year
($ in thousands)	2018		2017		Increase / (Decrease) from Prior Year
Revenues
Total revenues	$	184,467	$	39,295		369	%
Costs and expenses
Direct operating expenses		33,714		10,557		219	%
Costs of goods sold (exclusive of depreciation and amortization shown below)		38,852		—		—
Real estate operating expenses		1,872		—		—
Depreciation, amortization and accretion		25,134		3,486		621	%
General and administrative expenses		1,999		1,265		58	%
Loss on sale of property, plant and equipment		2,577		—		—

Total costs and expenses		104,148		15,308		580	%

Income from operations		80,319		23,987		235	%
Other income
Income from equity investment		—		1,366		—

Total other income		—		1,366		—

Net income before income taxes		80,319		25,353		217	%
Provision for income taxes		17,359		4,688		270	%

Net income	$	62,960	$	20,665		205	%

Revenues. Revenues increased by $145 million for the year ended December 31, 2018 as compared to the year ended December 31, 2017, primarily due to the contribution of fresh water assets by Diamondback on January 1, 2018 (which could not be segregated prior to that date), resulting in an additional $77.0 million in revenue. SWD services revenues increased by $44.5 million, crude oil gathering revenues increased by $8.4 million and natural gas gathering revenues increased by $3.5 million for the year ended December 31, 2018 as compared to the year ended December 31, 2017, while surface revenues remained relatively unchanged during that same period. Each of the increases in revenues was primarily due to additional asset contributions and asset buildouts, which led to continued increases of volume throughput. In addition, on January 31, 2018, Diamondback purchased certain real estate assets for approximately $110.0 million and contributed them to us effective as of that date. These real estate assets generated $11.8 million in revenue during the year ended December 31, 2018.

Income from Equity Investment. Income from equity investment decreased by $1.4 million for the year ended December 31, 2018 as compared to the year ended December 31, 2017. The decrease relates to Rattler LLC no longer recognizing an equity investment in HMW LLC, but rather consolidating its interest in the net assets of HMW LLC as of January 1, 2018. On June 30, 2018, HMW LLC’s operating agreement was amended, effective as of January 1, 2018. In exchange for Rattler LLC’s 25% investment, Rattler LLC received a 50% undivided ownership interest in two of the four SWD wells and associated assets previously owned by HMW LLC. Rattler LLC’s basis in the assets is equivalent to its basis in the equity investment in HMW LLC.

Direct Operating Expenses. Direct operating expense increased $23.2 million for the year ended December 31, 2018 as compared to the year ended December 31, 2017, primarily due to asset contributions from Diamondback resulting in additional operating costs and, secondarily, to continued development of existing services.

Cost of Goods Sold. On January 1, 2018, Diamondback contributed certain fresh water assets to us. We incurred $38.9 million in cost of goods sold related to the fresh water we sourced during the year ended December 31, 2018.

Real Estate Operating Expenses. On January 31, 2018, Diamondback purchased certain real estate assets for approximately $110.0 million and contributed them to us effective as of that date. We incurred $1.9 million in operating expenses related to these real estate assets during the year ended December 31, 2018.

Depreciation, Amortization and Accretion. Depreciation, amortization and accretion expense increased $21.6 million for the year ended December 31, 2018 as compared to the year ended December 31, 2017, primarily due to asset contributions from Diamondback and further development of existing gathering, transportation and disposal systems.

Loss on Sale of Property, Plant and Equipment. Under a swap agreement involving interests in certain SWD assets, which closed in May 2018, Rattler LLC exchanged its interests in two SWD assets for an additional interest in a third SWD asset. We recognized a loss of approximately $2.6 million because the net book value of the two SWD assets given up was $2.6 million greater than the agreed upon value of the SWD asset received.

General and Administrative Expenses. General and administrative expenses increased $0.7 million for the year ended December 31, 2018 as compared to the year ended December 31, 2017, primarily due to increased shared service allocations and additional professional service fees due to business growth and the contribution of additional midstream assets.

Capital Resources and Liquidity

Liquidity and Financing Arrangements

Historically, our sources of liquidity were based on cash flow from operations and funding from Diamondback.

We do not have any commitment from Diamondback or 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. We expect our sources of liquidity following this offering to include the portion of the net proceeds of this offering retained by Rattler LLC, cash generated from operations, borrowings under Rattler LLC’s new revolving credit facility and, if necessary, the issuance of additional equity or debt securities. We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements and long-term capital expenditure requirements and to make quarterly cash distributions.

The board of directors of our general partner will adopt a cash distribution policy pursuant to which we will distribute $ per common unit within 60 days after the end of each quarter, beginning with the quarter ending June 30, 2019, subject to applicable law and our obligations under certain contractual agreements. Please read “Cash Distribution Policy and Restrictions on Distributions.”

Revolving Credit Facility

In connection with the completion of this offering, we intend to enter into a new $600 million revolving credit facility to fund working capital and to finance acquisitions and other capital expenditures. The borrower under the new revolving credit facility will be Rattler LLC and all obligations of the borrower under the new revolving credit facility will be guaranteed by us and all wholly-owned material subsidiaries of Rattler LLC.

We expect that the closing of the new revolving credit facility will be subject to customary closing conditions, including the closing of this offering. The new revolving credit facility will also contain customary affirmative and negative covenants and events of default relating to the borrower, the partnership and their respective subsidiaries. We expect these covenants will include, among other things, limitations on the incurrence of indebtedness and liens, the making of investments, the sale of assets, transactions with affiliates, merging or consolidating with another company and the making of restricted payments. We expect that the new revolving credit facility will also contain specific provisions limiting us and Rattler LLC from engaging in certain business activities and events of default relating to certain changes in control.

Cash Flows

Net cash provided by operating activities, investing activities and financing activities for the years ended 2018 and 2017 were as follows:


	Year Ended December 31,
	2018			2017
	($ in thousands)
Net cash provided by operating activities	$	173,431		$	8
Net cash used in investing activities	$	(164,876	)	$	—
Net cash provided by (used in) financing activities	$	—		$	—

For the year ended December 31, 2018 as compared to the year ended December 31, 2017:

Net cash provided by operating activities increased by $173.4 million during the year ended December 31, 2018 compared to the year ended December 31, 2017. The increase was due to significant business growth

following asset contributions and the additional buildout of systems. Net cash used in investing activities increased by $164.9 million during the year ended December 31, 2018 compared to the year ended December 31, 2017 due to capital expenditures by Rattler LLC in 2018.

Capital Contributions and Capital Expenditures

For the year ended December 31, 2018, the total capital contributions by Diamondback to our predecessor were $171.2 million, of which $110 million related to Tall Towers, $1.3 million related to a field office, $1.5 million related to land, $32.8 million related to fresh water assets, $18.2 million related to SWD assets, $6.0 million related to fresh water inventory and $1.4 million in additional assets and liabilities, net, related to operations. During this period, Rattler LLC made capital expenditures of $164.9 million, comprised of $114.7 million related to SWD assets, $16.3 million related to crude oil gathering assets, $30.1 million related to natural gas gathering assets, $3.7 million related to fresh water gathering systems and $0.1 million related to land.

For the year ended December 31, 2017, the total capital contributions by Diamondback to our predecessor were $179.2 million, comprised of: $51.5 million of SWD assets; $44.7 million of crude oil gathering assets; $38.4 million of natural gas gathering assets and $23.8 million of fresh water gathering systems, net of accumulated depreciation of $3.2 million; $18.7 million of land; $1.6 million of equity method investments; $0.2 million of asset retirement obligations related to the contributed assets; and $3.5 million in additional assets and liabilities, net, related to operations.

We estimate that total capital expenditures related to midstream assets for the year ending December 31, 2019 will be between $225 million and $250 million. Our estimated capital expenditures do not include our anticipated total capital commitment of approximately $118.8 million for our 10% interest in the EPIC project, which includes $34.1 million paid as part of the option exercise price, or our anticipated total capital commitment of approximately $126.5 million for our 10% interest in the Gray Oak project, which includes $81.3 million paid as part of our acquisition cost for this interest and $33.0 million and $12.5 million contributed in March 2019 and April 2019, respectively, in respect of our equity interest.

Off-Balance Sheet Arrangements

None.

Contractual Obligations

As of December 31, 2018, we did not have any material contractual obligations. Our anticipated future capital commitments for the EPIC and Gray Oak projects are expected to be approximately $84.2 million and $17.5 million, respectively.

Critical Accounting Policies

Critical accounting policies are those that are important to our financial condition and require management’s most difficult, subjective or complex judgments. The amount of assets and liabilities as of the date of the consolidated financial statements, or the amount of revenue and expenses for the reported period, could differ significantly due to changes in these judgments or assumptions. We have evaluated the accounting policies used in the preparation of the accompanying consolidated financial statements of our predecessor and the related notes thereto and believe those policies are reasonable and appropriate.

We apply those accounting policies that we believe best reflect the underlying business and economic events, consistent with GAAP. Our more critical accounting policies include those related to revenue recognition,

including estimating the related revenue accruals, property and equipment and asset retirement obligations. Inherent in such policies are certain key assumptions and estimates. We periodically update the estimates used in the preparation of the financial statements based on our latest assessment of our current and projected business and the general economic environment. Our significant accounting policies are summarized in Note 2. Summary of Significant Accounting Policies to the audited consolidated financial statements of our predecessor appearing elsewhere in this prospectus. We believe the following to be our most critical accounting policies applied in the preparation of our predecessor’s financial statements.

Revenue Recognition

We provide gathering and compression and water handling and treatment services under fee-based contracts based on throughput. Under these arrangements, we receive fees for gathering oil and gas products, compression services, and water handling, disposal, and treatment services. The revenue we earn from these arrangements is directly related to (i) in the case of natural gas gathering and compression, the volumes of metered natural gas that we gather, compress, transport and deliver to other transmission delivery points, (ii) in the case of oil gathering, the volumes of metered oil that we gather, transport and deliver to other transmission delivery points, (iii) in the case of fresh water services, the quantities of fresh water sourced, transported and delivered to our customers for use in their well drilling and completion operations, and (iv) in the case of saltwater gathering and disposal services, the quantities of saltwater gathered, transported and disposed of for our customers. We recognize revenue when we satisfy a performance obligation by delivering a service to a customer. Rattler LLC earns substantially all of its midstream revenues from commercial agreements not with Diamondback or its affiliates. We recognize rental revenue from tenants on a straight-line basis over the lease term when collectability is reasonably assured and the tenant has taken possession or controls the physical use of the leased asset. Rental income-third party is comprised of revenues earned from lease agreements with Diamondback and its affiliates. Tenant recoveries related to reimbursement of real estate taxes, insurance, repairs and maintenance and other operating expenses are recognized as revenue in the period the applicable expenses are incurred. The reimbursements are recognized and presented gross, as we are generally the primary obligor with respect to purchasing goods and services from third-party suppliers, and have discretion in selecting the supplier and bear the associated credit risk.

Property, Plant and Equipment

Property, plant and equipment is recorded at cost upon acquisition and evaluated for potential impairment whenever events or circumstances indicate the carrying amount of the asset may not be recoverable through estimated future undiscounted cash flows. Expenditures which extend the useful lives of existing property, plant and equipment are capitalized.

When properties are retired or otherwise disposed, the related cost and accumulated depreciation are removed from the respective accounts and any gain or loss on disposition is recognized in the statement of operations.

Depreciation, Amortization and Accretion

The determination of estimated useful lives is a significant element in calculating depreciation, amortization and accretion. If the useful lives of assets were found to be shorter than originally estimated, depreciation, amortization and accretion charges would be accelerated.

Asset Retirement Obligations

Our asset retirement obligations, or ARO, consist of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our SWD and infrastructure assets. We recognize the fair value

of a liability for an ARO in the period in which it is incurred, when we have an existing legal obligation associated with the retirement of our infrastructure assets and the obligation can reasonably be estimated. The associated asset retirement cost is capitalized as part of the carrying cost of the infrastructure asset. The recognition of an ARO requires that management make numerous estimates, assumptions and judgments regarding factors such as: the credit-adjusted risk-free rate to be used, inflation rates and estimated probabilities, amounts and timing of settlements. In periods subsequent to initial measurement of the ARO, we recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Revisions also result in increases or decreases in the carrying cost of the asset. Increases in the ARO liability due to passage of time impact net income as accretion expense. The related capitalized cost, including revisions thereto, is charged to expense through depreciation.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy. We have experienced inflationary pressure on the cost of labor and equipment as increasing crude oil and natural gas prices have increased development activity in our areas of operations, especially in the Delaware Basin.

Qualitative and Quantitative Disclosures About Market Risk

Commodity Price Risk

We currently generate the majority of our revenues pursuant to fee-based agreements with Diamondback under which we are paid based on volumetric fees, rather than the underlying value of the commodity. Consequently, our existing operations and cash flow have little direct exposure to commodity price risk. However, Diamondback and our other customers are exposed to commodity price risk, and extended reduction in commodity prices could reduce the production volumes available for our midstream services in the future below expected levels. Although we intend to maintain fee-based pricing terms on both new contracts and existing contracts for which prices have not yet been set, our efforts to negotiate such terms may not be successful, which could have a materially adverse effect on our business.

We may acquire or develop additional midstream assets in a manner that increases our exposure to commodity price risk. Future exposure to the volatility of crude oil, natural gas and NGL prices could have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to make cash distributions to our unitholders.

INDUSTRY OVERVIEW

We provide crude oil, natural gas and water-related midstream services (including fresh water sourcing and transportation and saltwater gathering and disposal) to Diamondback in the Permian. The market we serve, which begins at the source of production and extends through the gathering, processing and treating of hydrocarbons delivering them to takeaway pipelines, is a major component of what is commonly referred to as the “midstream” market.

Crude Oil Midstream Industry

The crude oil midstream industry provides the link between the exploration and production of crude oil from the wellhead and the delivery of crude oil to storage facilities, terminals, crude oil pipelines and refineries. The U.S. crude oil midstream system is comprised of a network of pipelines, terminals, storage facilities, waterborne vessels, railcars and trucks. Companies generate revenues at various links within the midstream value chain by gathering, treating, transporting, storing or marketing crude oil. Our crude oil midstream operations currently focus on the gathering of crude oil from the point of production and transporting it to refineries and export terminals. The following diagram illustrates the various components of the crude oil midstream value chain and some of the services that are specifically offered by us:

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Crude Oil Midstream Services

The services we provide or have investments in are generally classified into the categories described below.

Gathering. Crude oil gathering assets provide the link between crude oil production gathered at the well site or nearby collection points and crude oil terminals, storage facilities, long-haul crude oil pipelines and refineries. Crude oil gathering assets generally consist of a network of small-diameter pipelines that are connected directly to the well site or central receipt points delivering into large-diameter trunk lines. Pipeline transportation is generally the lowest cost option for transporting crude oil. Competition in the crude oil gathering industry is typically regional and based on proximity to crude oil producers, as well as access to viable delivery points. Overall demand for gathering services in a particular area is generally driven by crude oil producer activity in the area. To the extent there are not enough volumes to justify construction of or connection to a pipeline system, trucking crude oil from a well site to nearby collection points can also be an alternative to crude oil gathering pipeline systems, but is typically not the lowest cost option for transporting crude oil from a producer’s perspective.

Long-haul Pipelines. After crude oil has been collected from the well site through gathering systems, it is often loaded onto long-haul pipelines for transportation to major hubs, refineries, or export terminals outside of the basin. These long-haul pipelines are typically constructed of large diameter pipes that can cover long distances both above and below ground. Pipelines are generally the preferred method for transporting large volumes of crude oil over long distances because they are more cost-effective than other transportation options such as rail or truck. Long-haul pipeline operators usually earn fees based upon the volume of crude oil transported.

Natural Gas Midstream Industry

The natural gas midstream industry provides the link between the exploration and production of natural gas from the wellhead and the delivery of natural gas and its by-products to industrial, commercial and residential end-users. The principal components of the industry consist of gathering, compressing, treating, dehydrating, processing, fractionating and transporting natural gas and natural gas liquids (NGLs). Competition in the industry is generally driven by proximity of midstream assets to natural gas producing wells. Companies within this industry provide services at various stages along the natural gas value chain by gathering natural gas from producers at the wellhead, separating the hydrocarbons into dry gas (methane) and NGLs and then routing the separated dry gas and NGL streams to the next intermediate stage of the value chain or to transportation pipelines for delivery to markets. Our natural gas midstream operations currently focus on the gathering and compression of natural gas. The following diagram illustrates the various components of the natural gas midstream value chain:

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Natural Gas Midstream Services

The services we provide are generally classified into the categories described below.

Gathering. At the initial stages of the midstream value chain, a network of typically small diameter pipelines known as gathering systems directly connect to wellheads, pad sites or other receipt points in the production area. These gathering systems transport natural gas from the wellhead and other receipt points either to compressor stations, treating and processing plants (if the natural gas is wet) or directly to intrastate or interstate pipelines (if the natural gas is dry).

Gathering systems are typically designed to be highly flexible to provide different levels of service (such as higher or lower pressure) and scalable to allow for additional production and well connections without significant

incremental capital expenditures. Gathering systems are operated at pressures that both meet the contractual service requirements and maximize the total throughput from all connected wells. Competition in the natural gas gathering industry is typically regional and based on proximity to natural gas producers, as well as access to viable treating and processing plants or intrastate and interstate pipelines. Overall demand for gathering services in a particular area is generally driven by natural gas producer activity in the area.

Compression. Gathering systems are operated at design pressures that enable the maximum amount of production to be gathered from connected wells. Through a mechanical process known as compression, volumes of natural gas at a given pressure are compressed to a sufficiently higher pressure, thereby allowing those volumes to be delivered into a higher pressure downstream pipeline to be brought to market. Since wells produce at progressively lower field pressures as they age, it becomes necessary to add additional compression over time near the wellhead to maintain throughput across the gathering system. Compression is also used in transportation of natural gas to support the movement of gas across pipeline systems and in storage to enhance withdrawal and injection capability.

Produced, Flowback and Fresh Water Services Industry

The hydraulic fracturing process associated with unconventional crude oil and natural gas production is highly dependent on the sourcing of fresh water and the disposal of water volumes produced. Hydraulic fracturing requires large volumes of fresh water, which is combined with sand (or another proppant) and fracturing chemical additives. This mixture is pumped at high pressure into the well to crack open previously impenetrable rock to release hydrocarbons.

Fresh Water. Fresh water refers to water with low salinity that has been treated, has been withdrawn from a river or ground water, or produced water that has been recycled. Many producers rely on third party providers for sourcing and distribution services.

Crude oil and natural gas operations produce two primary types of produced water by-products, which we refer to as saltwater:

Produced Water. Produced water is water that naturally occurs in the formation that returns up to the surface over the life of a producing crude oil or natural gas well. Produced water must be continually separated from a well’s valuable crude oil and natural gas production and hauled away via pipeline or truck for a well to continue producing. Produced water is the largest by-product by volume associated with crude oil and natural gas production and can comprise over 95% of the total oilfield by-product by volume.

Flowback. In the drilling and completion stages of crude oil and natural gas production, large volumes of fresh water and other types of fluids are required. After fresh water is pumped into the well during the hydraulic fracturing process, it returns to the surface over time with the produced hydrocarbons. Ten to fifty percent of the water returns as “flowback” during the first several weeks following the fracturing process, and a large percentage of the remainder, as well as pre-existing water in the formation, returns to the surface as produced water over the life of the well.

Produced water management typically involves transportation, processing and disposal often through the use of SWD wells. We are directly engaged in the gathering, recycling and disposal of produced water in SWD wells.

The following diagram illustrates the various components of produced water and fresh water gathering, transportation and disposal and some of the services that are specifically offered by us:

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Fresh Water and Saltwater Midstream Services

The services we provide are generally classified into the categories described below.

Fresh Water Sourcing and Distribution. Fresh water is often sourced from below ground aquifers or other natural fresh water sources and transported to drill sites through pipelines.

SWD Facilities / Wells. Saltwater gathering pipeline systems connect crude oil and gas producing wells to SWD well sites. The primary methods for handling produced water include SWD wells, where produced water is treated and injected subsurface; evaporation pits, where the water is evaporated at the surface; and recycling facilities, where produced water is treated in a manner that allows some portion of the water to be recycled for future fracturing processes or other beneficial uses.

Market Fundamentals

According to the U.S. Energy Information Administration, or the EIA, both total energy supply and demand are expected to increase over the coming decades. In the U.S., the EIA estimates that energy production will increase by about 20% from 2018 through 2050, with much of the increase in petroleum supply expected to come from unconventional oil wells. The Southwest U.S., in particular the Permian, is expected to play a key role in domestic petroleum production growth.

Crude Oil Supply and Demand

Crude oil is a significant component of energy consumption. The EIA expects global petroleum liquids consumption to grow 25% from 100 MMBbl/d in 2018 to 125 MMBbl/d by 2050. The following chart illustrates expected growth in petroleum and other liquids consumption.

Global Petroleum Liquids Consumption

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In accordance with consumption growth, forecasts published by the EIA anticipate U.S. crude oil production to increase in the coming years, with unconventional production playing an important role. As of February 2019, U.S. crude oil production was 11.9 MMBbl/d, which represents a 1.0 MMBbl/d increase from the 2018 average of 10.9 MMBbl/d. According to the EIA, the increase in U.S. crude oil production is largely due to new technologies, including hydraulic fracturing and horizontal drilling. Crude oil production increases in the U.S. will be dependent on oil from tight oil formations, with both the aforementioned technological developments and forecasted U.S. crude prices enabling economic production of these vast quantities of crude oil. As depicted in the graph below, 106% of the 1.6 MMBbl/d increase in crude oil production from 2019 through 2024 is projected to be from increases in tight oil production.

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U.S. Lower 48 Onshore Crude Oil Production by Source

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Production growth in the Permian is expected to make up a majority of the increase in domestic crude oil production. Based on EIA projections, the Southwest region, which encompasses the Permian and Barnett Shale, will continue to be the single highest producing region in the U.S. through 2050. From 2019 through 2024, the EIA expects a 26% increase in Southwest region production, as shown in the graph below.

U.S. Lower 48 Onshore Crude Oil Production by Region

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The aforementioned trends in global consumption and domestic production are expected to impact the U.S.’s trade position. Historically, the U.S. has been a net importer of petroleum, however, according to the EIA, as domestic production and global demand continue to grow, the U.S. is expected to become a net exporter. This trend is evidenced in the chart below.

Petroleum Net Imports as a Percentage of Product Supplied

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The EIA expects crude prices to rise over the next several years and is currently forecasting average 2024 WTI and Brent prices of $75/Bbl and $79/Bbl, respectively, versus an average of $68/Bbl and $73/Bbl during 2019. According to the EIA, this trend of increasing prices will be a factor in the future growth of U.S. crude oil production and exports for two reasons. First, an annual increase in WTI pricing over the next five years should continue to enable economic unconventional drilling. Second, WTI crude is expected to trade at a $3 to $5 a barrel discount to Brent crude, an international benchmark for oil price, meaning producers with access to international markets realize a premium on their crude oil. Both of these trends are evidenced in the chart below.

Projected Spot Price for Brent and WTI Crude Oil

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Natural Gas Supply and Demand

Natural gas is a significant component of energy consumption in the U.S. According to the EIA, natural gas consumption accounted for approximately 30% of all energy used in the U.S. in 2018 and demand is expected to grow 19%, from 29.3 quadrillion BTU in 2018 to 35.0 quadrillion BTU by 2050. The following chart illustrates this expected growth in U.S. natural gas demand through 2050.

Natural Gas Consumption by Sector

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Natural gas also accounts for a significant share of U.S. energy production, and its proportion of U.S. energy production is expected to continue to grow through the coming decades. The EIA estimates that total U.S. energy production will increase by 20% from 2018 through 2050, while natural gas production will increase by 47% over this same time period.

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In addition to increasing domestic consumption and production, domestic natural gas consumers will also compete for supply with foreign natural gas consumers. As shown in the graph below, the U.S. has historically been a net importer of natural gas. However, the EIA forecasts predict U.S. exports of natural gas to more than quadruple from 2018 to 2023. This growth is primarily driven by increases in exports of liquefied natural gas, or LNG, to meet surging international demand.

U.S. Natural Gas Net Exports

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Natural Gas Prices

Despite the availability of abundant domestic resources, the EIA projects that the growth in demand for natural gas, largely from the electric power and industrial sectors, exports to Mexico and demand for liquefied natural gas exports, will result in upward pressure on pricing through 2050. The chart below illustrates the EIA’s forecasted rise in natural gas prices through 2024.

Projected Spot Price for Natural Gas at Henry Hub

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Permian Overview

Remaining Resources by Play and WTI Breakeven—Top Oil-Weighted U.S. Basins⁽²⁾

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(1)	Permian total includes only resources in the Delaware and Midland Basins.

(2)	Locations assumed to be economic at $3 per Mcf of natural gas and a 10% internal rate of return.

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Permian Basin Horizontal Oil Rig Count Overview

(2012 – Current)

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Beginning in November 2014, during the recent commodity price downturn, Permian E&P companies began generally focusing on improving their operating efficiencies. Most E&P companies continue to be focused on optimizing the development of their assets through actions such as drilling longer laterals, further delineating zones, continued downspacing, using modern high intensity completion methods with local frac sand and utilizing multi-well pads. Although the Permian is already known as one of the most productive oil-weighted basins in the world, it is believed that there is still significant upside in the realizable resource potential. It is expected that many of the aforementioned techniques will further enhance crude oil and natural gas recoveries.

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Permian Basin Total Daily Production (2012 – September 30, 2018)

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BUSINESS

Overview

We are a growth-oriented Delaware limited partnership formed in July 2018 by Diamondback to own, operate, develop and acquire midstream infrastructure assets in the Midland and Delaware Basins of the Permian, one of the most prolific oil producing areas in the world. Immediately following this offering, we expect to be the only publicly-traded, pure-play Permian midstream company focused on the Midland and Delaware Basins. We provide crude oil, natural gas and water-related midstream services (including fresh water sourcing and transportation and saltwater gathering and disposal) to Diamondback under long-term, fixed-fee contracts. As of January 1, 2019, the assets Diamondback has contributed to us include a total of 746 miles of pipeline across the Midland and Delaware Basins with a total of approximately 232,000 Bbl/d of crude oil gathering capacity, 2.685 MMBbl/d of permitted SWD capacity, 550,000 Bbl/d of fresh water gathering capacity, 53,500 Mcf/d of natural gas compression capability and 342,000 Mcf/d of natural gas gathering capacity. In addition to the midstream infrastructure assets that Diamondback contributed to us, we own equity interests in two long-haul crude oil pipelines, which, upon completion, will run from the Permian to the Texas Gulf Coast. We are critical to Diamondback’s growth plans because we provide a long-term midstream solution to its increasing crude oil, natural gas and water-related services needs through our robust infield gathering systems and SWD capabilities.

We are Diamondback’s primary provider of midstream gathering and water-related services and are integral to Diamondback’s strategy of being a premier, low-cost, high-growth operator that can grow production at industry leading rates within cash flow. We have Dedicated Acreage that spans a total of approximately 423,000 gross acres across all service lines on Diamondback’s core leasehold in the Permian (a total of approximately 217,000 gross acres in the Midland Basin and a total of approximately 206,000 gross acres in the Delaware Basin). We entered into commercial agreements with Diamondback that have initial terms ending in 2034. The fees charged under these agreements are based on market prevailing rates at the time of their implementation with annual escalators (subject to potential adjustment by regulators). These fixed-fee contracts, along with Diamondback’s strong well economics, extensive horizontal drilling inventory and low-cost operating model, minimize our direct exposure to commodity prices while providing us with stable and predictable cash flow over the long-term. In February 2019, we acquired a 10% equity interest in the EPIC project and a 10% equity interest in the Gray Oak project. Our total capital commitment with respect to our 10% interest in the EPIC project is currently anticipated to be approximately $118.8 million, which includes $34.1 million paid as part of the option exercise price. Our total capital commitment with respect to our 10% interest in the Gray Oak project is currently anticipated to be approximately $126.5 million, which includes $81.3 million paid as part of our acquisition cost for this interest and $33.0 million and $12.5 million contributed in March 2019 and April 2019, respectively, in respect of our equity interest. Once these pipelines are operational, which is anticipated to occur in the second half of 2019, our equity interests in the EPIC and Gray Oak projects are expected to provide us with a steady, oil-weighted cash flow stream. These pipelines will also provide Diamondback with long-term long-haul transportation capacity for a portion of its Delaware and Midland Basin crude oil production.

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Midland Basin position of approximately 85,000 net acres. In 2016, Diamondback entered the Delaware Basin through two acreage acquisitions totaling 95,499 net acres. In addition, on October 31, 2018, Diamondback acquired 25,493 net acres in the Midland Basin in connection with the Ajax acquisition, and, on November 29, 2018, subsequently acquired approximately 89,000 and 90,000 net acres in the Delaware and Midland Basin, respectively, in connection with the Energen acquisition.