S-1 1 d596284ds1.htm S-1 S-1
Table of Contents

As filed with the Securities and Exchange Commission on August 7, 2018

Registration No. 333-                

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

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

9400 N. Broadway

Suite 700

Oklahoma City, Oklahoma 73114

(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
1700 Pacific Avenue, Suite 4100
Dallas, TX 75201
(214) 969-4780
 

John Goodgame

Akin Gump Strauss Hauer & Feld LLP

1111 Louisiana Street, 44th 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):

 

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

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.  

 

 

CALCULATION OF REGISTRATION FEE

 

 

Title of each class of

securities to be registered

  Proposed Maximum
Aggregate Offering Price(1)(2)
  Amount of
Registration Fee

Common units representing limited partner interests

  $100,000,000   $12,450

 

 

(1)

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

(2)

Estimated solely for purposes of calculating the registration fee pursuant to Rule 457(o) of the Securities Act of 1933, as amended.

 

 

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

 

 

 


Table of Contents

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 AUGUST 7, 2018

PROSPECTUS

Rattler Midstream Partners LP

             Common Units

Representing Limited Partner Interests

 

 

This is the initial public offering of common units representing limited partner interests in Rattler Midstream Partners 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 intend to apply 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 LLC, to make cash distributions to us.

 

   

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.

 

   

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

     $                                  $                  

Proceeds to Rattler Midstream Partners LP (before expenses)

     $                                  $                  

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                      , 2018 through the book-entry facilities of The Depository Trust Company.

Lead Book-Running Managers

 

Credit Suisse   BofA Merrill Lynch   J.P. Morgan

Prospectus dated                      , 2018


Table of Contents

 

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

     15  

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

     58  

USE OF PROCEEDS

     60  

CAPITALIZATION

     61  

DILUTION

     62  

CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

     64  

Unaudited Pro Forma EBITDA and Distributable Cash Flow for the Year Ended December 31, 2017 and Twelve Months Ended                     , 2018

     66  

Estimated EBITDA and Distributable Cash Flow for the Twelve Months Ending                     , 2019

     69  

HOW WE MAKE DISTRIBUTIONS

     75  

Our Sources of Cash

     75  

Rattler LLC Units

     75  

Common Units

     76  

Class B Units

     76  

General Partner Interest

     76  

SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA

     77  

Non-GAAP Financial Measures

     79  

MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     80  

Overview

     80  

Our Business

     80  

How We Generate Revenue

     82  

How We Evaluate Our Operations

     82  

Factors Affecting the Comparability of Our Financial Results

     84  

Other Factors Impacting Our Business

     86  

Results of Operations

     87  

Capital Resources and Liquidity

     89  

Off-Balance Sheet Arrangements

     91  

Critical Accounting Policies

     91  

Inflation

     92  

Qualitative and Quantitative Disclosures About Market Risk

     92  

INDUSTRY OVERVIEW

     94  

Crude Oil Midstream Industry

     94  

Natural Gas Midstream Industry

     95  

Produced, Flowback and Fresh Water Services Industry

     96  

Market Fundamentals

     97  

Permian Overview

     104  

BUSINESS

     108  

Overview

     108  

Our Assets

     109  

Diamondback Energy, Inc.

     114  

Our Acreage Dedication

     117  

Our Commercial Agreements with Diamondback

     118  

Title to Our Properties

     120  

Competition

     120  

Regulation of Operations

     121  

Environmental Matters

     124  

Employees

     132  

Insurance

     132  

Facilities

     132  

Legal Proceedings

     132  

 

i


Table of Contents
     Page  

MANAGEMENT

     133  

Management of Rattler Midstream Partners LP

     133  

Executive Officers and Directors of Our General Partner

     134  

Director Independence

     135  

Committees of the Board of Directors

     135  

Indemnification Agreements

     136  

EXECUTIVE COMPENSATION AND OTHER INFORMATION

     137  

Long-Term Incentive Plan

     138  

Director Compensation

     142  

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     143  

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

     145  

Distributions and Payments to Our General Partner and Its Affiliates

     145  

Agreements with our Affiliates in Connection with the Transactions

     146  

Procedures for Review, Approval and Ratification of Related Person Transactions

     149  

CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

     150  

Conflicts of Interest

     150  

Fiduciary Duties

     154  

DESCRIPTION OF OUR UNITS

     157  

Common Units and Class B Units

     157  

Transfer Agent and Registrar

     157  

Resignation or Removal

     157  

Transfer of Common Units and Class B Units

     158  

Exchange Listing

     158  

OUR PARTNERSHIP AGREEMENT

     159  

Organization and Duration

     159  

Purpose

     159  

Capital Contributions

     159  

Voting Rights

     159  

Class B Units

     160  

Limited Liability

     161  

Issuance of Additional Partnership Interests

     162  

Amendment of the Partnership Agreement

     162  

Prohibited Amendments

     162  

Opinion of Counsel and Unitholder Approval

     164  

Merger, Consolidation, Conversion, Sale or Other Disposition of Assets

     164  

Dissolution

     165  

Liquidation and Distribution of Proceeds

     165  

Withdrawal or Removal of Our General Partner

     165  

Transfer of General Partner Interest

     166  

Transfer of Ownership Interests in the General Partner

     166  

Change of Management Provisions

     166  

Limited Call Right

     167  

Non-Taxpaying Holders; Redemption

     167  

Non-Citizen Assignees; Redemption

     167  

Meetings; Voting

     168  

Status as Limited Partner

     168  

Indemnification

     169  

Reimbursement of Expenses

     169  

Books and Reports

     169  

Right to Inspect Our Books and Records

     170  

Registration Rights

     170  

Applicable Law; Forum, Venue and Jurisdiction

     170  

RATTLER LLC LIMITED LIABILITY COMPANY AGREEMENT

     172  

Organization and Duration

     172  

Purpose

     172  

Capital Contributions

     172  

Management; Voting Rights

     172  

Limited Liability

     172  

Applicable Law; Forum, Venue and Jurisdiction

     173  

Issuance of Additional Membership Interests

     173  

Transfer of Rattler LLC Units

     174  

Distributions and Allocations

     174  

Amendment of the Limited Liability Company Agreement

     174  

Dissolution

     174  

Liquidation and Distribution of Proceeds

     175  

Withdrawal or Removal of the Managing Member

     175  

Indemnification

     175  

Books and Reports

     175  

 

ii


Table of Contents
     Page  

UNITS ELIGIBLE FOR FUTURE SALE

     176  

Rule 144

     176  

Our Partnership Agreement

     176  

Registration Rights Agreement

     176  

Lock-Up Agreements

     177  

Registration Statement on Form S-8

     177  

UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS

     178  

Corporate Status

     179  

Consequences to U.S. Holders

     179  

Consequences to Non-U.S. Holders

     180  

Distributions

     180  

Gain on Disposition of Common Units

     181  

Backup Withholding and Information Reporting

     182  

Additional Withholding Requirements under FATCA

     182  

INVESTMENT IN RATTLER MIDSTREAM PARTNERS LP BY EMPLOYEE BENEFIT PLANS

     184  

UNDERWRITING

     188  

Directed Unit Program

     190  

Conflicts of Interest

     191  

Selling Restrictions

     191  

LEGAL MATTERS

     194  

EXPERTS

     194  

WHERE YOU CAN FIND ADDITIONAL INFORMATION

     195  

CAUTIONARY STATEMENT REGARDING FORWARD -LOOKING STATEMENTS

     196  

INDEX TO FINANCIAL STATEMENTS

     F-1  

APPENDIX A—FORM OF AGREEMENT OF LIMITED PARTNERSHIP OF RATTLER MIDSTREAM PARTNERS LP

     A-1  

APPENDIX B—FORM OF AGREEMENT OF LIMITED LIABILITY COMPANY OF RATTLER MIDSTREAM 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


Table of Contents

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 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 Partners LP and its subsidiaries (including Rattler LLC). References in this prospectus to the “Rattler LLC” refer to 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 a 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 Partners LP

Overview

We are a growth-oriented Delaware limited partnership formed 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 operator. 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. The assets Diamondback has contributed to us include 528 miles of pipeline across the Midland and Delaware Basins with approximately 216,000 Bbl/d of crude oil gathering capacity, 589,000 Bbl/d of saltwater disposal, or SWD, capacity, 740,700 Bbl/d of fresh water gathering capacity, 36,000 Mcf/d of natural gas compression capability and 150,000 Mcf/d of natural gas gathering capacity. In addition to the midstream infrastructure assets that Diamondback contributed to us, we also have an option, subject to certain conditions, to acquire equity in a long-haul crude oil pipeline, which 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

 

1


Table of Contents

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 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 a 15-year acreage dedication, or Acreage Dedication, from Diamondback spanning approximately 209,000 gross acres on Diamondback’s core leasehold in the Permian (approximately 80,000 gross acres in the Midland Basin and approximately 129,000 gross acres in the Delaware Basin). In this prospectus, we refer to the acreage subject to the Acreage Dedication as the Dedicated Acreage. We entered into commercial agreements with Diamondback in June 2018, effective as of January 1, 2018, that have initial terms ending in 2034. The fees charged under these agreements are based on market prevailing rates at the time of their execution 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. We also have an option, subject to certain conditions, to acquire up to a 10% equity interest in the EPIC Crude Oil Pipeline, which we refer to as EPIC or the EPIC project. Once operational, our equity interest in the EPIC project, upon exercise of our option, is expected to provide us with a steady, oil-weighted cash flow stream and will also provide Diamondback with long-term long-haul transportation capacity for the majority of its 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 105,000 net acres. 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 substantially all 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 March 31, 2018, only 84 of Diamondback’s approximately 1,700 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. As of March 31, 2018, Diamondback was running five rigs in the Delaware Basin and has publicly stated that it plans to run eight rigs while operating within cash flow in the coming years, which we believe will be a significant driver of our future growth.

 

2


Table of Contents

Our midstream infrastructure systems have been designed and built 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 currently have the ability to transport approximately 216,000 Bbl/d of crude oil, 589,000 Bbl/d of produced water, 740,700 Bbl/d of fresh water and 150,000 Mcf/d of natural gas, as well as provide 36,000 Mcf/d of natural gas compression. 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 minimal 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 project will provide Diamondback critical access to a vital long-haul takeaway solution for its planned development on its existing acreage in the Permian. Once operational, our equity interest in the EPIC project, upon exercise of our option, is 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 $13 billion as of July 31, 2018.

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 and as of March 31, 2018, Diamondback’s total position in the Permian was approximately 204,000 net acres. In addition, Diamondback, along with its subsidiary Viper, owns mineral interests underlying approximately 13,865 net royalty acres primarily in the Midland and Delaware Basins of which approximately 46% are operated by Diamondback. Diamondback owns Viper Energy Partners GP LLC, the general partner of Viper, and approximately 64% 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 2017, Diamondback’s and Viper’s production increased by a compound annual growth rate, or CAGR, of 81% and 52%, respectively, and proved reserves increased by a CAGR of 52% and 20%, respectively. Despite low commodity prices over the last two years (average crude oil price of approximately $43 per barrel in 2016 and approximately $51 per barrel in 2017), Diamondback grew its year-over-year production by 30% in 2016 and 84% in 2017 within annual operating cash flow due to its peer leading operating metrics as evidenced by its cash operating costs of $8.52 per Boe over the same two-year period.

 

3


Table of Contents

Acquisition Track Record (2012 – March 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 March 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.

Diamondback has identified approximately 3,800 gross economic potential horizontal drilling locations at $60 per barrel of oil, and the table below shows that the significant majority of those locations 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

 

4


Table of Contents

advanced drilling and completion techniques. Approximately 85% of Diamondback’s gross identified economic potential horizontal drilling locations have lateral lengths in excess of 7,500 feet and drilling locations are split approximately 2,100 and 1,700 between the Midland and Delaware Basins, respectively.

Diamondback’s Horizontal Drilling Locations at Various Crude Oil Prices

 

     Assumed crude oil price ($ / Bbl)(1)  

Gross well count

   $ 40.00      $ 50.00      $ 55.00      $ 60.00      $ 70.00  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Midland

     1,553        1,720        1,948        2,096        2,177  

Delaware

     935        1,239        1,499        1,710        1,884  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     2,488        2,959        3,447        3,806        4,061  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Implied rig years(2)

     14        16        19        21        23  

 

(1)

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

(2)

Assuming Diamondback completes 180 gross wells per year while running approximately 11 rigs as expected in 2018.

As of December 31, 2017, Diamondback’s estimated U.S. Securities and Exchange Commission, or SEC, proved crude oil and natural gas reserves were 335,352 MBoe (approximately 62% proved developed producing), based on a reserve report prepared by Diamondback’s independent reserve engineer. As of December 31, 2017, Diamondback’s estimated proved reserves were approximately 70% oil, 14% natural gas and 16% natural gas liquids, all in the Permian.

Diamondback produced, on average on a consolidated basis, 102.6 MBoe/d, in the Permian during the quarter ended March 31, 2018, with 74% 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 organically from acquisitions from an average of 0.307 net MBoe/d for the year ended December 31, 2016 to 19.202 net MBoe/d for the quarter ended March 31, 2018, an increase of 6,147%.

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

 

    

 

Year Ended December 31,

     Three
Months
Ended
March 31,

2018
 
 
     2015      2016      2017  

Midland Basin

           

Number of wells completed

     65        63        104        29  

Approximate average lateral feet per horizontal well

     6,938        8,386        9,328        9,025  

Production (MBoe/d)

     27.7        33.6        53.1        66.3  

Delaware Basin

           

Number of wells completed

     —          —          19        6  

Approximate average lateral feet per horizontal well

     —          —          7,306        8,879  

Operated production (MBoe/d)

     —          0.3        11.7        19.2  

Total Permian (Midland and Delaware Basins)

           

Number of wells completed

     65        63        123        35  

Approximate average lateral feet per horizontal well

     6,938        8,386        8,977        9,000  

Operated production (MBoe/d)

     27.7        33.9        64.8        85.5  

Viper production (MBoe/d)

     5.4        6.4        11.0        14.1  

Nonoperated/other production (MBoe/d)

     —          2.7        3.4        3.0  

Consolidated production (MBoe/d)

     33.1        43.0        79.2        102.6  

 

5


Table of Contents

Diamondback has been an operational and cost leader in the Permian with a track record of achieving robust production growth within cash flow and, beginning in 2018, returning cash to shareholders through dividends. Diamondback is targeting over 40% annual organic production growth in 2018 within cash flow and believes its asset base can support growth within cash flow for multiple years at current commodity prices. Diamondback has publicly stated that for the most efficient execution of its development plan across its entire existing acreage position, it anticipates increasing the number of rigs from 11 as of March 31, 2018 to between 16 and 18 in the future as operating cash flow allows.

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) 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,” and “Risk Factors—Risks Inherent in an Investment in Us” and “Conflicts of Interest and Fiduciary Duties.”

Our Assets

We own and operate 528 miles of crude oil gathering pipelines, natural gas gathering pipelines and a fully integrated water system on acreage that overlays Diamondback’s six 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 have an option, subject to certain conditions, to acquire equity interest in a long-haul crude oil pipeline under development that we expect, upon exercise of our option, will provide us with a steady, oil-weighted cash flow stream and will also provide Diamondback with long-term long-haul transportation capacity for the majority of its Midland Basin crude oil production. This pipeline will provide Diamondback a total takeaway capacity of 100,000 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 216,000 Bbl/d of crude oil gathering capacity (14% utilized), 150,000 Mcf/d of natural gas gathering capacity (20% utilized), 36,000 Mcf/d of natural gas compression capability (84% utilized), 589,000 Bbl/d of saltwater gathering capacity (34% utilized) and 740,700 Bbl/d of fresh water gathering capacity (32% utilized) as of March 31, 2018.

Crude oil and natural gas gathering and transportation assets

Our crude oil and natural gas gathering system covers approximately 201 miles. We have 74 miles of crude oil pipelines, 216,000 Bbl/d of crude oil throughput capacity, 79,000 Bbl of crude oil storage, 127 miles of

 

6


Table of Contents

natural gas pipelines, 150,000 Mcf/d of natural gas gathering capacity and 36,000 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 28.2 MBoe/d for the quarter ended December 31, 2017. For the quarter ended March 31, 2018, our crude oil and natural gas gathered volumes averaged approximately 35 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. We own strategically located produced water gathering pipeline systems spanning a total of 250 miles that connect 992 crude oil and natural gas producing wells to our SWD well sites. We have a total of 25 SWD wells with an aggregate capacity of 589,000 Bbl/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 16,000 and 24,000 Bbl/d per completion crew operating in each field, as Diamondback traditionally uses 80,000 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 37.1 MMBbl, 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. Our fresh water storage facilities can store approximately 37.1 MMBbl of fresh water. 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 500,000 barrels of water are required in the Midland Basin and approximately 850,000 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.

 

7


Table of Contents

The following table provides information regarding our gathering, compression and transportation system as of March 31, 2018.

Pipeline Infrastructure Assets

 

(miles)

   Delaware Basin      Midland Basin      Permian Total  

Crude oil

     58        16        74  

Natural gas

     127        —          127  

SWD

     125        125        250  

Fresh water

     26        51        77  
  

 

 

    

 

 

    

 

 

 

Total

     336        192        528  
  

 

 

    

 

 

    

 

 

 

 

(capacity/capability)

   Delaware Basin      Midland
Basin
     Permian
Total
     Utilization  

Crude oil (Bbl/d)

     176,000        40,000        216,000        14

Natural gas compression (Mcf/d)

     36,000        —          36,000        84

Natural gas pipeline (Mcf/d)

     150,000        —          150,000        20

SWD (Bbl/d)

     256,000        333,000        589,000        34

Fresh water (Bbl/d)

     369,500        371,200        740,700        32

Investment in a long-haul crude oil pipeline

We also have an option, subject to certain conditions, to acquire up to a 10% equity interest in the EPIC project, a long-haul crude oil pipeline that, upon completion, will be capable of transporting 550,000 Bbl/d from Midland, Texas, to Corpus Christi, Texas. EPIC is expected to be operational in the second half of 2019. Once operational, our equity interest in the EPIC project, upon exercise of our option, is expected to provide us with a steady cash flow stream from oil-weighted long-haul crude oil transportation. In addition, for the next ten years, Diamondback has committed to 100 MBbl/d of firm takeaway capacity on the pipeline encompassing the majority of its estimated Midland Basin production. Diamondback’s transportation contract includes a take-or-pay component for half of its contracted volumes with the balance committed through an acreage dedication.

This long-haul crude oil pipeline 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 $15.75 per barrel differential relative to WTI in July 2018. In addition, Diamondback has secured end-use sales through contracts with downstream customers and the ability to export through reserved dock space.

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 million Bbl/d to three million Bbl/d over the last ten years, with forecasted growth to over five million Bbl/d by the end of 2022.

 

8


Table of Contents

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 August 3, 2018, 56% (426 out of 756 total) of active onshore U.S. horizontal oil rigs were operating in the Permian according to Baker Hughes.

 

9


Table of Contents

Permian Basin 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.

 

10


Table of Contents

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 last five years in its contribution to total crude oil production in the Permian.

Permian Basin Total Daily Production (2012 – 2017)

 

 

LOGO

Crude oil production in the Permian increased at a 20% CAGR over the last five years 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 $15.75 per barrel in July 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 long-haul crude oil pipeline will help insulate it from future pricing dynamics in the local Midland, Texas market and, once operational, our equity investment, upon exercise of our option, in this pipeline 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 up to 589,000 Bbl/d of produced water, allowing Diamondback to more efficiently develop its acreage and grow production on our Dedicated Acreage.

 

11


Table of Contents

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 completions 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 in excess of 850,000 barrels of water per well, compared to approximately 500,000 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:

 

   

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 of 209,000 gross acres across 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 project, in which we have an option to acquire equity interests, will facilitate the execution of Diamondback’s high-growth development program.

 

   

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, Diamondback and Viper have outpaced guidance and peer performance on a per share basis, growing production by 368% and 55% and reserves by 128% and 11%, 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 92% 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.

 

12


Table of Contents
   

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 operator. We have 528 miles of pipelines across the Midland and Delaware Basins with 216,000 Bbl/d of crude oil gathering capacity, 36,000 Mcf/d of natural gas compression capability, 150,000 Mcf/d of natural gas gathering capacity, 589,000 Bbl/d of saltwater disposal gathering capacity and 740,700 Bbl/d of fresh water gathering capacity located in what we believe is the core of the Midland and Delaware Basins of the Permian and overlaying Diamondback’s six 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 2017, Diamondback has grown its production and reserves by CAGRs of 81% and 52%, 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, as of March 31, 2018, with 204,000 net acres (100,000 net acres in the Midland Basin and 104,000 net acres in the Delaware Basin) and exposure to approximately 3,800 gross identified potential horizontal drilling locations 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 2018 year-over-year production by more than 40% within cash flow and that it believes that its asset base can support growth within cash flow for multiple years at current commodity prices. 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.

 

   

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 approximately        % 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 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.

 

   

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 include dedications of acreage in the Delaware Basin (approximately 129,000 gross acres) and the Midland Basin (approximately 80,000 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

 

13


Table of Contents
 

exposure to Diamondback’s leading growth profile with no direct commodity price exposure, thus enhancing the predictability of free cash flow and our performance. For the three months ended March 31, 2018 and for the year ended December 31, 2017, we achieved pro forma EBITDA margins of 70% and 71%, respectively. 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 March 31, 2018, only 84 of Diamondback’s approximately 1,700 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.

 

   

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. Upon completion of this offering, we expect to have no outstanding indebtedness and $        million of liquidity, including $        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 minimal 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:

 

   

Grow by leveraging our strategic relationship with Diamondback and through accretive acquisitions. Diamondback, with its strong credit profile and well-capitalized balance sheet, including $888 million of liquidity as of March 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 seven significant acquisitions for a total of nearly $5 billion and expanded its acreage position in the Permian from approximately 51,000 net acres to approximately 204,000 net acres as of March 31, 2018, an increase of over 300%. 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.

 

   

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 three months ended March 31, 2018, the average utilization of our crude oil and natural gas gathering systems was 39%. Diamondback has dedicated approximately 209,000 gross acres through the Acreage Dedication. Pursuant to this dedication, we will continue to provide fresh water sourcing and handling, saltwater gathering and disposal, crude oil transportation and gathering and natural gas gathering and compression services for Diamondback until 2034, when Diamondback has the option to extend the contract expiration date. 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.

 

14


Table of Contents
   

Focus on free cash flow generation to fund our minimal 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, we expect to have low future capital expenditure requirements, which will allow us to self-fund our minimal capital program and make distribution payments to our unitholders. A core component of our strategy is to maximize free cash flow while maintaining low leverage.

 

   

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:

 

   

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

 

   

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

 

   

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

 

   

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

 

   

reduced disclosure about executive compensation arrangements.

We may take advantage of these provisions until we are no longer an emerging growth company, which will occur on the earliest of (i) the last day of the fiscal year following the fifth anniversary of this offering, (ii) the last day of the fiscal year in which we have 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

 

15


Table of Contents

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

 

   

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.

 

   

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

 

   

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.

 

   

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

 

   

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.

 

   

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

 

   

Affiliates of our general partner and Diamondback may compete with us, and do not have any obligation to present business opportunities to us except with respect to the Acreage Dedication contained in our commercial agreements.

 

   

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.

 

   

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

 

   

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

 

   

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.

 

   

Distributions to common unitholders may be taxable as dividends.

 

16


Table of Contents

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 Partners 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:

 

   

Our general partner will contribute $1.0 million in cash to us in respect of its general partner interest;

 

   

Diamondback will contribute $1.0 million in cash to us in respect of its Class B Units;

 

   

we will issue                Class B Units to Diamondback and Rattler LLC will issue an equal number of Rattler LLC Units to Diamondback;

 

   

we will issue                common units (or                common units if the underwriters exercise in full their option to purchase additional common units) pursuant to this offering in exchange for net proceeds of approximately $        million ($        million if the underwriters exercise in full their option to purchase additional common units);

 

   

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;

 

   

Rattler LLC will distribute a portion of those net proceeds 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 an operational services and secondment agreement with Diamondback.

Following completion of this offering, Diamondback will own, through its ownership of Class B Units, a     % 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, a     % 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.

 

17


Table of Contents

Ownership and Organizational Structure

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

 

 

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 Partners LP Rattler LLC Units managing member interest % economic interest Rattler Midstream LLC 100% membership interest Tall City Towers LLC

 

(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.

 

18


Table of Contents
(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 the 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 operational 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 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

 

19


Table of Contents

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 with respect to Acreage Dedication contained in 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.”

 

20


Table of Contents

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, and Rattler LLC will issue an equal number of Rattler LLC Units, will be issued to Diamondback at the expiration of the option period for no additional consideration.

 

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) distribute approximately $        of the net proceeds to Diamondback and (ii) retain approximately $        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

 

21


Table of Contents
 

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                 ,                 , subject to applicable law and our obligations under certain contractual agreements. Our first distribution, however, will be prorated for the period from the closing of this offering through                  ,                . 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.

 

  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.

 

  We expect that our only source of cash will be distributions from Rattler LLC. 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. 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.

 

  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

 

22


Table of Contents
 

these payments before making any distributions in respect of the Rattler LLC Units.

 

  We expect that we will be subject to a U.S. federal income tax rate of 21%. Accordingly, 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 our preferred distributions and our contemplated distributions to our common unitholders. We estimate that cash distributions from Rattler LLC of approximately $        million would be required to support the payment of our preferred distributions and our currently contemplated quarterly distribution for four quarters ($        million, or approximately $        million per quarter) as well as our U.S. federal income tax obligations for those four quarters.

 

  If the underwriters exercise in full their option to purchase additional common units, we estimate that cash distributions from Rattler LLC would be required to support the payment of our preferred distributions and our currently contemplated quarterly distribution for four quarters ($         million, or approximately $         million per quarter) as well as our U.S. federal income tax obligations for those four quarters.

 

  Because we will own a     % membership interest in Rattler LLC at the completion of this offering (     % 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 $         .

 

  On a pro forma basis, assuming we had completed this offering and related transactions on January 1, 2017, Rattler LLC’s unaudited pro forma cash available for distribution for the twelve months ended             , 2018 and for the year ended December 31, 2017 would have been approximately $         million and $         million, respectively. Therefore, Rattler LLC would have had sufficient cash available to pay distributions on the Rattler LLC Units, and we would have had sufficient cash available to pay distributions on our common units, for the twelve months ended             , 2018 or for the year ended December 31, 2017.

 

 

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             , 2019,” 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

 

23


Table of Contents
 

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

 

24


Table of Contents
 

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     % 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 intend to list our common stock on Nasdaq under the trading symbol “RTLR.”

 

25


Table of Contents

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 Partners LP for the periods and as of the dates indicated. The summary historical financial data of our predecessor as of and for the year ended December 31, 2017 is derived from the audited financial statements of our predecessor appearing elsewhere in this prospectus. In addition, the summary historical financial data of our predecessor as of and for the three months ended March 31, 2018 and March 31, 2017 are derived from unaudited condensed consolidated interim financial statements of our predecessor also 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, 2017 and the three months ended March 31, 2018 are derived from the unaudited pro forma combined financial statements included elsewhere in this prospectus. The unaudited pro forma combined balance sheet data as of March 31, 2018 assumes the offering and the related transactions occurred as of March 31, 2018 and the unaudited pro forma combined statements of operations and statement of cash flows data for the year ended December 31, 2017 and the three months March 31, 2018 assume the offering and the transactions occurred as of January 1, 2017. These transactions include, and the unaudited pro forma combined financial statements give effect to, the following:

 

   

the contribution to us by Diamondback and our general partner of $2.0 million in cash;

 

   

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 those net proceeds to Diamondback and retention of a portion of the net proceeds for general company purposes, including to fund future capital expenditures;

 

   

an estimated $1.4 million in incremental general and administrative expenses that we expect to incur annually as a result of being a publicly traded partnership;

 

   

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

 

   

the acquisition of the Fasken Center by Diamondback and contribution to us of all the membership interests in Tall City Towers LLC, or Tall Towers, as if such transactions occurred on January 1, 2017 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).

 

26


Table of Contents
     Rattler Midstream Partners LP
Predecessor Historical
    Rattler Midstream
Partners LP Pro Forma
 
     Year Ended
December 31,
2017
                Year Ended
December 31,
2017
    Three
Months
Ended
March 31,
2018
 
    Three Months Ended
March 31,
 
    2018     2017  
     (in thousands, except per unit data)  

Statement of Operations Data:

          

Revenues

          

Total revenues

   $ 39,295     $ 33,875     $ 5,656     $ 51,532     $ 34,856  

Costs and expenses

          

Operating expenses

     10,557       10,735       660       13,357       10,844  

Depreciation, amortization and accretion

     3,486       5,816       413       3,792       6,112  

General and administrative expenses

     1,265       254       125       3,287       714  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total operating expenses

     15,308       16,805       1,198       20,436       17,670  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

     23,987       17,070       4,458       31,096       17,186  

Other income/expense

          

Interest expense, net of amount capitalized

     —         —         —         —         —    

Income from nonconsolidated investments

     1,366       1,459       153       1,366       1,459  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total other expense

     1,366       1,459       153       1,366       1,459  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income before income taxes

     25,353       18,529       4,611       32,462       18,645  

Provision for income taxes

     4,688       4,133       1,673       7,266       4,159  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income

   $ 20,665     $ 14,396     $ 2,938     $ 25,196     $ 14,486  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income per common unit (basic and diluted)

          

Common units

          

Balance Sheet Data (at period end):

          

Total property, plant and equipment, net

   $ 255,323     $ 352,428     $ 144,537       $ 352,428  

Total assets

     299,605       490,910       156,360         490,730  

Member’s equity / partners’ capital

     292,608       482,104       154,409         481,924  

Statement of Cash Flows Data:

          

Net cash provided by operating activities

   $ 8     $ 2,216     $ —        

Net cash used in investing activities

     —         —         —        

Net cash provided by financing activities

     —         —         —        

Other Data:

          

EBITDA(1)

   $ 28,839     $ 24,345     $ 5,024     $ 36,254     $ 24,757  

EBITDA attributable to Rattler Midstream Partners LP(1)

          

EBITDA margin(1)(2)

     73     72     89     70     71

 

(1)

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

(2)

EBITDA margin is calculated by dividing EBITDA by total revenues.

 

27


Table of Contents

Non-GAAP Financial Measures

We define EBITDA as net income before income taxes, net interest expense, depreciation, amortization and accretion. We define EBITDA margin as EBITDA expressed as a percentage of revenues. EBITDA and EBITDA margin are used as supplemental financial measures 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 and EBITDA margin 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 and EBITDA margin 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 Partners LP
Predecessor Historical
     Rattler Midstream
Partners LP Pro Forma
 
     Year Ended
December 31,
2017
                   Year Ended
December 31,
2017
     Three
Months
Ended
March 31,
2018
 
     Three Months
Ended March 31,
 
     2018      2017  
     (in thousands, except per unit data)  

Reconciliation of net income to EBITDA:

              

Net income

   $ 20,665      $ 14,396      $ 2,938      $ 25,196      $ 14,486  

Provision for income taxes

     4,688        4,133        1,673        7,266        4,159  

Interest expense, net of amount capitalized

     —          —          —          —          —    

Depreciation, amortization and accretion

     3,486        5,816        413        3,792        6,112  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

EBITDA

   $ 28,839      $ 24,345      $ 5,024      $ 36,254      $ 24,757  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Reconciliation of net cash provided by operating activities to EBITDA:

              

Net cash provided by operating activities

   $ 8      $ 2,216      $ —          

Changes in operating assets and liabilities

     28,831        22,129        5,024        

Change in income tax payable

     —          —          —          

Interest expense, net of amount capitalized

     —          —          —          

Stock based compensation and other

     —          —          —          
  

 

 

    

 

 

    

 

 

       

EBITDA

   $ 28,839      $ 24,345      $ 5,024        
  

 

 

    

 

 

    

 

 

       

 

28


Table of Contents

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;

 

29


Table of Contents
   

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 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.

We expect that our only source of cash will be distributions from Rattler LLC. 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 expect that we will be subject to a U.S. federal income tax rate of approximately 21%. Accordingly, 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 our preferred distributions and any contemplated distributions to our common unitholders. We estimate that cash distributions from Rattler LLC of approximately $         million would be required to support the payment of our preferred distributions and our currently contemplated quarterly distribution for four quarters ($         million, or approximately $         million per quarter) as well as our U.S. federal income tax obligations for those four quarters.

Because we will own a    % membership interest in Rattler LLC at the completion of this offering (    % 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 $        .

 

30


Table of Contents

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:

 

   

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;

 

   

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;

 

   

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

 

   

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;

 

   

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

 

   

regulatory action affecting:

 

   

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

 

   

the rates we can charge for our midstream services,

 

   

the rates that EPIC can charge for its transportation and terminal services;

 

   

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

 

   

our existing gathering and other commercial agreements; or

 

   

our operating costs or our operating flexibility;

 

   

the rates we charge for our midstream services;

 

   

the rates that EPIC charges for its transportation and terminal services;

 

   

prevailing economic conditions; and

 

   

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:

 

   

the level and timing of our capital expenditures, including capital calls associated with any investment we make in the EPIC project;

 

   

our debt service requirements and other liabilities;

 

   

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

 

   

fluctuations in our working capital needs;

 

   

restrictions on distributions contained in any of our debt agreements;

 

   

the cost of acquisitions, if any;

 

   

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

 

31


Table of Contents
   

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

 

   

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.

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                 , 2019. 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 initial quarterly distribution or any distribution at all on our common units, in which event the market price of our common units may decline materially.

 

32


Table of Contents

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 project, 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 project. In order to realize any potential revenues associated with such pipeline, we will need to exercise our option to invest in, and contribute future capital to, this pipeline. To fund this investment, 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. Any delay associated with our option exercise or our failure to timely contribute additional capital could result in decreased revenues.

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 Partners 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.

 

33


Table of Contents

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:

 

   

the availability and cost of capital;

 

   

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

 

   

demand for crude oil, natural gas and NGLs;

 

   

levels of reserves;

 

   

geologic considerations;

 

   

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;

 

   

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

 

   

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

 

   

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.

 

34


Table of Contents

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

 

35


Table of Contents

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:

 

   

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

 

   

an inability to successfully integrate the acquired assets or businesses;

 

   

the assumption of unknown liabilities;

 

   

exposure to potential lawsuits;

 

   

limitations on rights to indemnity from the seller;

 

   

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

 

   

unforeseen difficulties operating in new geographic areas; and

 

   

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

 

36


Table of Contents

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

 

37


Table of Contents

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 and reporting by federal regulators, which could adversely affect our revenues.

Rattler LLC will be filing a tariff to gather crude oil in interstate commerce effective September 1, 2018. Pipelines that gather or transport crude oil for third parties in interstate commerce are, among other things, subject to rate regulation by the Federal Energy Regulatory Commission, or 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. The initial rates for gathering service on Rattler LLC may be adversely affected to the extent that such rates are protested and FERC conducts a cost-of-service review of Rattler LLC’s proposed rates.

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

 

38


Table of Contents

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

 

39


Table of Contents

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. Effective April 27, 2017, to account for inflation, those maximum civil penalties were increased to $209,002 per violation per day, with a maximum of $2,090,022 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, 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.

 

40


Table of Contents

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. 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

 

41


Table of Contents

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 that emit GHGs. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards 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. These EPA regulations, 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

 

42


Table of Contents

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, most recently in Oklahoma, alleging that disposal well operations have 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

 

43


Table of Contents

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:

 

   

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;

 

   

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;

 

   

fires, ruptures and explosions; and

 

   

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

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

 

   

injury or loss of life;

 

   

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

 

   

pollution and other environmental damage;

 

   

regulatory investigations and penalties;

 

   

suspension of our operations; and

 

   

repair and remediation costs.

 

44


Table of Contents

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 operational 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

 

45


Table of Contents

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:

 

   

incur or guarantee additional debt;

 

   

redeem or repurchase units or make distributions under certain circumstances;

 

   

make certain investments and acquisitions;

 

   

incur certain liens or permit them to exist;

 

   

enter into certain types of transactions with affiliates;

 

   

merge or consolidate with another company; and

 

   

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:

 

   

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;

 

   

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;

 

   

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

 

   

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

 

46


Table of Contents

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, 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.

 

47


Table of Contents

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:

 

   

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;

 

   

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

 

   

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

 

   

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

 

   

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.

 

48


Table of Contents

Risks Inherent in an Investment in 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.

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:

 

   

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;

 

   

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

 

   

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;

 

   

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

 

   

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;

 

   

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

 

   

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;

 

   

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

 

   

our general partner may exercise its right to call and purchase 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);

 

   

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

 

   

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

 

49


Table of Contents

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:

 

   

how to allocate business opportunities among us and its affiliates;

 

   

whether to exercise its call right;

 

   

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

 

   

whether to exercise its registration rights; and

 

   

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:

 

   

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;

 

   

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

 

   

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:

 

   

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

 

   

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.”

 

50


Table of Contents

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 Partners 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    % 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). 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.

 

51


Table of Contents

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 operational services and secondment agreement, our general partner determines the amount of these expenses. Under our operational 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, we will enter into a tax sharing agreement with Diamondback pursuant to which we will reimburse Diamondback for our share of state and local income and other taxes borne by Diamondback as a result of our 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.”

 

52


Table of Contents

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.”

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.

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.

 

53


Table of Contents

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

 

54


Table of Contents

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:

 

   

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

 

   

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

 

   

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

 

   

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:

 

   

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

 

   

affiliates of the newly admitted general partner may compete with us, and neither that general partner nor such affiliates will have any obligation to present business opportunities to us.

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

 

55


Table of Contents

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.

 

56


Table of Contents

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 intend to apply 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 Partners 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. 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

 

57


Table of Contents

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.

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

 

58


Table of Contents

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.

 

59


Table of Contents

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) distribute approximately $         of the net proceeds to Diamondback and (ii) retain approximately $         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, and a proportionate decrease or increase in the number of Rattler LLC Units issued to Diamondback.

In connection with the closing of this offering, Diamondback will contribute $1.0 million in cash to us in respect of its Class B Units and our general partner will contribute $1.0 million in cash to us in respect of its general partner interest. We will contribute those contributions to Rattler LLC, which will use those contributions for general company 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.

 

60


Table of Contents

CAPITALIZATION

The following table sets forth:

 

   

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

 

   

our pro forma capitalization as of                     , 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 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, and Rattler LLC will issue an equal number of Rattler LLC Units, will be issued 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                     , 2018  
     Historical      Pro
Forma
 
     (in thousands)  

Cash and cash equivalents

   $        $    

Long-term debt:

     

New revolving credit facility(1)

   $ —        $ —    

Member’s equity / partners’ capital:

     

Member’s equity

   $        $    

Common units

     

Class B Units

     

General partner interest

     

Non-controlling interest

     

Total member’s equity / partners’ capital

     
  

 

 

    

 

 

 

Total capitalization

   $                    $                
  

 

 

    

 

 

 

 

(1)

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

 

61


Table of Contents

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                , 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 $         , 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)

   $                   

Decrease in as adjusted net tangible book value per common unit attributable to purchasers in this offering and distributions to Diamondback

     
  

 

 

    

Less: Pro forma net tangible book value per unit after this offering(3)

     
     

 

 

 

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

      $                
     

 

 

 

 

(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 by the number of common units (                ) issuable to Diamondback on a fully diluted basis.

(3)

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, 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.

(4)

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.

(5)

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, as of                , 2018, 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
  

 

 

    

 

 

   

 

 

    

 

 

 

 

62


Table of Contents

 

(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                , 2018 was $                (excludes deferred taxes).

 

63


Table of Contents

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                , 2019” 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 unaudited historical financial statements as of and for the                months ended                      , 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                    ,                    . Our first distribution, however, will be prorated for the period from the closing of this offering through                    ,                     . 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. 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. 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 operational services and secondment agreement and the Rattler LLC limited liability company agreement, Rattler LLC will reimburse our general partner and its affiliates, including

 

64


Table of Contents

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 expect that we will be subject to a U.S. federal income tax rate of 21%. Accordingly, 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 our preferred distributions and our contemplated distributions to our common unitholders. We estimate that cash distributions from Rattler LLC of approximately $        would be required to support the payment of our preferred distributions and our currently contemplated quarterly distribution for four quarters ($        , or approximately $         per quarter) as well as our U.S. federal income tax obligations for those four quarters.

If the underwriters exercise in full their option to purchase additional common units, we estimate that cash distributions from Rattler LLC would be required to support the payment of our preferred distributions and our currently contemplated quarterly distribution for four quarters ($        , or approximately $        per quarter) as well as our U.S. federal income tax obligations for those four quarters.

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

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                ,                , subject to applicable law and our obligations under our and Rattler LLC’s contractual agreements, but the board of directors of our general partner may change this policy at any time.

 

   

We do not have any debt currently outstanding and, therefore, are not subject to any debt covenants. However, 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 on our common 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 operational 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.

 

65


Table of Contents
   

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, 2017 and Twelve Months Ended                       , 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 $         in aggregate to holders of our common units each quarter (or $         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. We expect that we will be subject to a U.S. federal income tax rate of 21%. Accordingly, 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 our preferred distributions and our contemplated distributions to our common unitholders. We estimate that, in order for us to make those distributions on an after-tax basis, Rattler LLC would have to distribute to us approximately $    per quarter (or $         per year). 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 $        in aggregate to the holders of the Rattler LLC Units, of which we would hold    % and Diamondback would hold    %.

On a pro forma basis, assuming we had completed this offering and related transactions as of January 1, 2017, (i) Rattler LLC’s distributable cash flow would have been approximately $         for the twelve months ended December 31, 2017 and, accordingly, (ii) Rattler LLC would have had sufficient cash available to pay distributions on the Rattler LLC Units, and we would have had sufficient cash available to pay distributions on our common units, for the twelve months ended December 31, 2017.

On a pro forma basis, assuming we had completed this offering and related transactions as of January 1, 2017, (i) Rattler LLC’s distributable cash flow would have been approximately $         for the twelve months ended                 , 2018 and, accordingly, (ii) Rattler LLC would have had sufficient cash available to pay distributions on the Rattler LLC Units, and we would have had sufficient cash available to pay distributions on our common units, for the twelve months ended                , 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.

 

66


Table of Contents

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, 2017.

The following table illustrates, on a pro forma basis, for the year ended December 31, 2017 and the twelve months ended                      , 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, 2017. Certain of the adjustments are explained in further detail in the footnotes to such adjustments.

 

67


Table of Contents

Rattler Midstream Partners LP

Unaudited Pro Forma EBITDA and Distributable Cash Flow

 

      Year Ended
December

31, 2017
     Twelve
Months Ended
            , 2018
 

(In thousands)

             

Pro forma revenues of Rattler LLC:

     

Revenues—related party

   $ 38,414      $                

Surface use

     881     

Rental income—related party

     11,128     

Rental income—third party

     1,109     

Other real estate income

     —       
  

 

 

    

 

 

 

Total pro forma revenues

     51,532     
  

 

 

    

 

 

 

Pro forma costs and expenses:

     

Operating expenses

     13,357     

Depreciation, amortization and accretion

     3,792     

General and administrative expenses(1)

     3,287     

Interest expense(2)

     
  

 

 

    

 

 

 

Total pro forma costs and expenses

     20,436     
  

 

 

    

 

 

 

Pro forma income from operations

     31,096     

Other income:

     

Pro forma income from equity investment

     1,366     
  

 

 

    

 

 

 

Total other income

     1,366     
  

 

 

    

 

 

 

Pro forma net income before taxes

     32,462     
  

 

 

    

 

 

 

Provision for income taxes

     7,266     
  

 

 

    

 

 

 

Pro forma net income of Rattler LLC

   $ 25,196      $                
  

 

 

    

 

 

 

Add:

     

Provision for income taxes

     7,266     

Interest expense(2)

     —       

Depreciation, amortization and accretion

     3,792     
  

 

 

    

 

 

 

Pro forma EBITDA of Rattler LLC

     36,254     
  

 

 

    

 

 

 

Less:

     

Cash interest expense(3)

     

Capital expenditures

     
  

 

 

    

 

 

 

Pro forma distributable cash flow of Rattler LLC

   $        $    
  

 

 

    

 

 

 

Distributions to unitholders of Rattler LLC

   $        $    

Excess of pro forma distributable cash flow of Rattler LLC above distributions to unitholders of Rattler LLC

     

Income tax expense of Rattler Midstream Partners LP

     

Distributions to Diamondback

     

Distributions to Rattler Midstream Partners LP

     

Preferred distributions to Diamondback

     

Preferred distributions to our general partner

     
  

 

 

    

 

 

 

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

   $        $    
  

 

 

    

 

 

 

 

(1)

Pro forma general and administrative expenses includes $1.4 million in incremental 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.

 

68


Table of Contents
(2)

Represents amortization of origination fees and commitment fees on the undrawn portion of Rattler LLC’s new revolving credit facility that we expect to have in place at the closing of this offering (assuming no amounts have been drawn on that facility).

(3)

Represents commitment fees on the undrawn portion of Rattler LLC’s new revolving credit facility that we expect to have in place at the closing of this offering (assuming no amounts have been drawn on that facility).

Estimated EBITDA and Distributable Cash Flow for the Twelve Months Ending                  , 2019

We forecast Rattler LLC’s estimated EBITDA and distributable cash flow during the twelve months ending                      , 2019, will be approximately $        million and $        million, respectively. The forecasted amount for the twelve months ending                 , 2019 would be sufficient for Rattler LLC to pay distributions of approximately $         in respect of the Rattler LLC Units owned by us, which would exceed by $         the amount we would need to pay our income tax expense, our preferred distributions and 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                 , 2019 to pay income tax expense, pay our preferred distributions and pay distributions to our common unitholders and (ii) that Rattler LLC will not distribute to us any cash in excess of that needed for such uses.

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 have generated 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                     , 2019. 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                      , 2019. 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                     , 2019. 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

 

69


Table of Contents

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.

 

70


Table of Contents

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

 

     Three
Months
Ending

                ,         
    Three
Months
Ending

                ,         
    Three
Months
Ending

                ,         
    Three
Months
Ending

                ,         
    Twelve
Months
Ending
                ,

2019
 
(In thousands)                              

Revenues of Rattler LLC:

         

Revenues—related party

  $               $               $               $               $            

Surface use

         

Rental income—related party

         

Rental income—third party

         

Other real estate income

         
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

         
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Costs and expenses:

         

Operating expenses

         

Depreciation, amortization and accretion

         

General and administrative expenses

         

Interest expense(1)

         
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total costs and expenses

         
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income from operations

         

Other income:

         

Income from equity investment

         
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total other income

         
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income before taxes

         
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Provision for income taxes

         

Net income of Rattler LLC

  $       $       $       $       $    
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Add:

         

Interest expense(1)

         

Provision for income taxes

         

Depreciation, amortization and accretion

         
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

EBITDA of Rattler LLC

         
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Less:

         

Cash interest expense(2)

         

Capital expenditures

         
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Distributable cash flow of Rattler LLC

  $       $       $       $       $    
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Distributions to unitholders of Rattler LLC

  $       $       $       $       $    

Excess of pro forma distributable cash flow of Rattler LLC above distributions to unitholders of Rattler LLC

         

Distributions to Diamondback

         

Distributions to Rattler Midstream Partners LP

         

Income tax expense of Rattler Midstream Partners LP

         

Preferred distributions to Diamondback

         

Preferred distributions to our general partner

         
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

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

  $       $       $       $       $    
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

71


Table of Contents

 

(1)

Represents non-cash amortization of origination fees and commitment fees on the undrawn portion of Rattler LLC’s new revolving credit facility that we expect to have in place at the closing of this offering (assuming no amounts have been drawn on that facility).

(2)

Represents commitment fees on the undrawn portion of Rattler LLC’s new revolving credit facility that we expect to have in place at the closing of this offering (assuming no amounts have been drawn on that facility).

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 $         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                , 2019, 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                  , 2019. 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, 2017 and the twelve months ended             , 2018, as well as our forecast regarding those same amounts for the twelve months ending                  , 2019.

 

     Pro Forma
Year Ended
December 31,
2017
     Pro Forma
Twelve Months
Ended                  ,
2018
     Forecasted
Twelve Months
Ending                  ,
2019
 

Midstream services:

        

Crude oil gathering volumes (Bbl/d)

     22,800        

Natural gas gathering volumes (MMBtu/d)

     13,500        

Fresh water services volumes (Bbl/d)

     —          

Saltwater services volumes (Bbl/d)

     143,100        

Total midstream services revenues ($ in thousands)

   $ 39,295      $        $    

Real estate revenue ($ in thousands)

   $ 12,237      $        $    

Total revenues ($ in thousands)

   $ 51,532      $        $    

EBITDA ($ in thousands)

   $ 36,254      $                $            

 

72


Table of Contents

Revenue

We estimate that total revenues for the twelve months ending                , 2019 will be approximately $        million compared to approximately $51.5 million for the pro forma year ended December 31, 2017 and the pro forma twelve months ended                 , 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                    , 2019 will be                    MBbl/d of crude oil and                    Mcf/d of natural gas. Our forecasted increase in volumes over the year ended December 31, 2017 and the twelve months ended                 , 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.”

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                      , 2019 will be $        million compared to approximately $13.4 million for the pro forma year ended December 31, 2017 and approximately $        million for the pro forma twelve months ended                     , 2018.

General and Administrative Expenses

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

We expect total general and administrative expenses for the twelve months ending                    , 2019 will be $         million as compared to $3.2 million for the pro forma year ended December 31, 2017 and approximately $        million for the pro forma twelve months ended                     , 2018. 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.

Depreciation, Amortization and Accretion

We estimate that depreciation, amortization and accretion for the twelve months ending                      , 2019 will be $        million as compared to approximately $3.8 million for the pro forma year ended December 31, 2017 and approximately $        million for the pro forma twelve months ended                     , 2018.

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                    , 2019 will be $        million as compared to approximately $177.0 million for the year ended December 31, 2017.

 

73


Table of Contents

Income Tax Expense

We estimate that income tax expense for the twelve months ending                     , 2019 will be $         million compared to approximately $         million for the pro forma year ended December 31, 2017 and approximately $         million for the pro forma twelve months ended                     , 2018.

Regulatory, Industry and Economic Factors

Our forecast of EBITDA and distributable cash flow for the twelve months ending                     , 2019 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.

 

74


Table of Contents

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                ,                . Our first distribution, however, will be prorated for the period from the closing of this offering through                ,              . 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 (                Rattler LLC Units if the underwriters exercise in full their option to purchase additional common units). 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;

 

   

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                 (         %) will be owned by us and                 (         %) will be owned by Diamondback. If the underwriters exercise in full their option to purchase additional common units, then                 (        %) will be owned by us and                 (         %) will be owned by Diamondback. Each Rattler LLC Unit will be entitled to

 

75


Table of Contents

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 (                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 (                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.

 

76


Table of Contents

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 Partners LP for the periods and as of the dates indicated. The selected historical financial data of our predecessor as of and for the year ended December 31, 2017 is derived from the audited financial statements of our predecessor appearing elsewhere in this prospectus. In addition, the selected historical financial data of our predecessor as of and for the three months ended March 31, 2018 and March 31, 2017 are derived from unaudited condensed consolidated interim financial statements of our predecessor also 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, 2017 and the three months ended March 31, 2018 are derived from the unaudited pro forma combined financial statements included elsewhere in this prospectus. The unaudited pro forma combined balance sheet data as of March 31, 2018 assumes the offering and the related transactions occurred as of March 31, 2018 and the unaudited pro forma combined statements of operations and statement of cash flows data for the year ended December 31, 2017 and the three months March 31, 2018 assume the offering and the transactions occurred as of January 1, 2017. These transactions include, and the unaudited pro forma combined financial statements give effect to, the following:

 

   

the contribution to us by Diamondback and our general partner of $2.0 million in cash;

 

   

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 those net proceeds to Diamondback and retention of a portion of the net proceeds for general company purposes, including to fund future capital expenditures;

 

   

an estimated $1.4 million in incremental general and administrative expenses that we expect to incur annually as a result of being a publicly traded partnership;

 

   

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

 

   

the acquisition of the Fasken Center by Diamondback and contribution to us of all the membership interests in Tall Towers, as if such transactions occurred on January 1, 2017 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).

 

77


Table of Contents
     Rattler Midstream Partners LP
Predecessor Historical
    Rattler Midstream
Partners LP Pro Forma
 
     Year
Ended
December 31,
2017
          Year
Ended
December 31,
2017
    Three
Months
Ended
March 31,
2018
 
    Three Months Ended
March 31,
 
    2018     2017  
     (in thousands, except per unit data)  

Statement of Operations Data:

          

Revenues

          

Total revenues

   $ 39,295     $ 33,875     $ 5,656     $ 51,532     $ 34,856  

Costs and expenses

          

Operating expenses

     10,557       10,735       660       13,357       10,844  

Depreciation, amortization and accretion

     3,486       5,816       413       3,792       6,112  

General and administrative expenses

     1,265       254       125       3,287       714  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total operating expenses

     15,308       16,805       1,198       20,436       17,670  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

     23,987       17,070       4,458       31,096       17,186  

Other income/expense

          

Interest expense, net of amount capitalized

     —         —         —         —         —    

Income from nonconsolidated investments

     1,366       1,459       153       1,366       1,459  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total other expense

     1,366       1,459       153       1,366       1,459  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income before income taxes

     25,353       18,529       4,611       32,462       18,645  

Provision for income taxes

     4,688       4,133       1,673       7,266       4,159  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income

   $ 20,665     $ 14,396     $ 2,938     $ 25,196     $ 14,486  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income per common unit (basic and diluted)

          

Common units

          

Balance Sheet Data (at period end):

          

Total property, plant and equipment, net

   $ 255,323     $ 352,428     $ 144,537       $ 352,428  

Total assets

     299,605       490,910       156,360         490,730  

Member’s equity / partners’ capital

     292,608       482,104       154,409         481,924  

Statement of Cash Flows Data:

          

Net cash provided by operating activities

   $ 8     $ 2,216     $ —        

Net cash used in investing activities

     —         —         —        

Net cash provided by financing activities

     —         —         —        

Other Data:

          

EBITDA(1)

   $ 28,839     $ 24,345     $ 5,024     $ 36,254     $ 24,757  

EBITDA attributable to Rattler Midstream Partners LP(1)

          

EBITDA margin(1)(2)

     73     72     89     70     71

 

(1)

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

(2)

EBITDA margin is calculated by dividing EBITDA by total revenues.

 

78


Table of Contents

Non-GAAP Financial Measures

We define EBITDA as net income before income taxes, net interest expense, depreciation, amortization and accretion. We define EBITDA margin as EBITDA expressed as a percentage of revenues. EBITDA and EBITDA margin are used as supplemental financial measures 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 and EBITDA margin 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 and EBITDA margin 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 Partners LP
Predecessor Historical
     Rattler Midstream
Partners LP Pro Forma
 
     Year
Ended
December 31,
2017
                   Year
Ended
December 31,
2017
     Three
Months
Ended
March 31,
2018
 
     Three Months
Ended March 31,
 
     2018      2017  
     (in thousands, except per unit data)  

Reconciliation of net income to EBITDA:

              

Net income

   $ 20,665      $ 14,396      $ 2,938      $ 25,196      $ 14,486  

Provision for income taxes

     4,688        4,133        1,673        7,266        4,159  

Interest expense, net of amount capitalized

     —          —          —          —          —    

Depreciation, amortization and accretion

     3,486        5,816        413        3,792        6,112  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

EBITDA

   $ 28,839      $ 24,345      $ 5,024      $ 36,254      $ 24,757  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Reconciliation of net cash provided by operating activities to EBITDA:

              

Net cash provided by operating activities

   $ 8      $ 2,216      $ —          

Changes in operating assets and liabilities

     28,831        22,129        5,024        

Change in income tax payable

     —          —          —          

Interest expense, net of amount capitalized

     —          —          —          

Stock based compensation and other

     —          —          —          
  

 

 

    

 

 

    

 

 

       

EBITDA

   $ 28,839      $ 24,345      $ 5,024        
  

 

 

    

 

 

    

 

 

       

 

79


Table of Contents

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 Partners LP, or the partnership, in conjunction with the historical audited financial statements as of and for the years ended December 31, 2016 and 2017 and the consolidated unaudited financial statements for the periods ended March 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 a controlling     % managing member interest in Rattler LLC (    % if the underwriters exercise in full their option to purchase additional common units), and Diamondback will own, through its ownership of Class B Units, a     % 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, a     % 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 by Diamondback in July 2018 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 operator. 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. The assets Diamondback has contributed to us include 528 miles of pipeline across the Midland and Delaware Basins with approximately 216,000 Bbl/d of crude oil gathering capacity, 589,000 Bbl/d of SWD capacity, 740,700 Bbl/d of fresh water gathering capacity, 36,000 Mcf/d of natural gas compression capability and 150,000 Mcf/d of natural gas gathering capacity. In addition to the midstream infrastructure assets that Diamondback contributed to us, we also have an option, subject to certain conditions, to acquire equity in a long-haul crude oil pipeline, which 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

 

80


Table of Contents

following this offering, we will have no outstanding indebtedness, and we do not plan on accessing the capital markets to fund our 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 an Acreage Dedication spanning approximately 209,000 gross acres on Diamondback’s core leasehold in the Permian (approximately 80,000 gross acres in the Midland Basin and approximately 129,000 gross acres in the Delaware Basin). We entered into commercial agreements with Diamondback in June 2018, effective as of January 1, 2018, that have initial terms ending in 2034. The fees charged under these agreements are based on market prevailing rates at the time of their execution 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. We also have an option, subject to certain conditions, to acquire up to a 10% equity interest in the EPIC project. Once operational, our equity interest in the EPIC project, upon exercise of our option, is expected to provide us with a steady, oil-weighted cash flow stream and will also provide Diamondback with long-term long-haul transportation capacity for the majority of its 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 105,000 net acres. 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 substantially all 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 March 31, 2018, only 84 of Diamondback’s approximately 1,700 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. As of March 31, 2018, Diamondback was running five rigs in the Delaware Basin and has publicly stated that it plans to run eight rigs while operating within cash flow in the coming years, which we believe will be a significant driver of our future growth.

Our midstream infrastructure systems have been designed and built 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 currently have the ability to transport approximately 216,000 Bbl/d of crude oil, 589,000 Bbl/d of produced water, 740,700 Bbl/d of fresh water and 150,000 Mcf/d of natural gas, as well as provide 36,000 Mcf/d of natural gas compression. 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 minimal 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 project will provide Diamondback critical access to a vital long-haul takeaway solution for its planned development on its existing acreage in the Permian. Our equity interest in the EPIC project, upon exercise of our

 

81


Table of Contents

option, is 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 and natural gas that we gather, fresh water that we deliver and store and produced water that we gather or 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 250 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.

 

82


Table of Contents

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 services, with approximately 146,000 gross dedicated acres, (ii) natural gas gathering and compression services, with approximately 100,000 gross dedicated acres and firm capacity for natural gas attributable to such acreage, (iii) produced water gathering and disposal services, with approximately 209,000 gross dedicated service acres and firm capacity for produced water and flowback water attributable to such acreage, and (iv) fresh water distribution services, with approximately 209,000 gross dedicated service acres. We also have an option, subject to certain conditions, to purchase equity interests in a long-haul crude oil pipeline under development that will provide firm takeaway for the majority of Diamondback’s estimated Midland Basin production. This pipeline will provide a total takeaway capacity of 550,000 Bbl/d of crude oil directly to the Texas Gulf Coast with Diamondback committed volumes representing 100,000 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.

 

83


Table of Contents

EBITDA

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 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 effective January 1, 2016. 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.

 

84


Table of Contents

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 salt water disposal 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.

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 operational 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 expense 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 operational 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 operational services and secondment agreement are not reflected in our historical financial statements.

 

85


Table of Contents

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 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 $         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 above 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.

 

86


Table of Contents

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, 2017 Compared to the Year Ended December 31, 2016

 

     

 

Year Ended December 31,

     Increase /
(Decrease)
from Prior
Year
 
($ in thousands)        2017              2016      

Revenues

        

Total revenues

   $ 39,295      $ 10,607        270

Costs and expenses

        

Direct operating expenses

     10,557        2,514        320

Depreciation and accretion

     3,486        873        299

General and administrative expenses

     1,265        208        508
  

 

 

    

 

 

    

 

 

 

Total operating expenses

     15,308        3,595        326
  

 

 

    

 

 

    

 

 

 

Operating income

     23,987        7,012        242

Other income

        

Income from equity investment

     1,366        676        102
  

 

 

    

 

 

    

 

 

 

Total other income

     1,366        676        102
  

 

 

    

 

 

    

 

 

 

Income before income taxes

     25,353        7,688     

Income tax expense

     4,688        2,760     
  

 

 

    

 

 

    

Net income

   $ 20,665      $ 4,928     
  

 

 

    

 

 

    

Revenues. Revenues increased by $28.7 million for the year ended December 31, 2017 as compared to the year ended December 31, 2016, primarily due to asset contributions from Diamondback totaling $179.2 million resulting in additional throughput and revenues and, secondarily, to the continued development of existing services.

Income from Equity Investment. The $1.4 million in income from investments is due to net income from Rattler LLC’s equity method investment in HMW LLC. The increase of $0.7 million relates to additional volumes due to new assets being placed into service in March 2016. HMW LLC provides water management services to exploration and production companies operating in Midland, Martin and Andrews Counties in West Texas.

Direct Operating Expense Direct operating expense increased $8.0 million for the year ended December 31, 2017 compared to the year ended December 31, 2016, primarily due to the asset contributions from Diamondback resulting in additional operating costs and, secondarily, to continued development of existing services.

 

87


Table of Contents

Depreciation and Accretion. Depreciation and accretion expense increased $2.6 million for the year ended December 31, 2017 as compared to the year ended December 31, 2016, primarily due to the asset contributions from Diamondback and further development of existing gathering, transportation and disposal systems.

General and Administrative Expense. General and administrative expense increased $1.1 million for the year ended December 31, 2017 as compared to the year ended December 31, 2016, primarily due to increased shared service allocations and additional professional service fees due to business growth and the contribution of additional midstream assets.

Three Months Ended March 31, 2018 Compared to the Three Months Ended March 31, 2017

 

      Three Months
Ended March 31,
     Increase /
(Decrease)
from Prior
Period
 
($ in thousands)    2018      2017  

Revenues

        

Midstream revenue

   $ 31,421      $ 5,656        456

Real estate revenue

     2,454        —       
  

 

 

    

 

 

    

 

 

 

Total revenues

   $ 33,875      $ 5,656        499
  

 

 

    

 

 

    

 

 

 

Costs and expenses

        

Direct operating expenses

     5,206        660        689

Cost of goods sold (exclusive of depreciation and amortization shown below)

     5,251        —          —    

Real estate operating expenses

     278        —          —    

Depreciation, amortization and accretion

     5,816        413        1308

General and administrative expenses

     254        125        103
  

 

 

    

 

 

    

 

 

 

Total operating expenses

     16,805        1,198        1303
  

 

 

    

 

 

    

 

 

 

Operating income

     17,070        4,458        283

Other income

        

Income from equity investment

     1,459        153        854
  

 

 

    

 

 

    

 

 

 

Total other income

     1,459        153        854
  

 

 

    

 

 

    

 

 

 

Income before income taxes

     18,529        4,611     

Income tax expense

     4,133        1,673     
  

 

 

    

 

 

    

Net income

   $ 14,396      $ 2,938     
  

 

 

    

 

 

    

Revenues. Revenues increased by $28.2 million for the three months ended March 31, 2018 as compared to the three months ended March 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 $15.7 million in revenue. 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 $2.4 million in revenue during the three months ended March 31, 2018.

Income from Equity Investment. The $1.5 million in income from investments is due to net income from Rattler LLC’s equity method investment in HMW LLC. The increase of $1.3 million relates to additional volumes due to new assets being placed into service in November 2017. HMW LLC provides water management services to exploration and production companies operating in Midland, Martin and Andrews Counties in West Texas.

Direct Operating Expense Direct operating expense increased $4.5 million for the three months ended March 31, 2018 as compared to the three months ended March 31, 2017, primarily due to asset contributions

 

88


Table of Contents

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 $5.3 million in cost of goods sold related to the fresh water we sourced during the three months ended March 31, 2018.

Real Estate Operating Expense. 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 $0.3 million in operating expenses related to these real estate assets during the three months ended March 31, 2018.

Depreciation, Amortization and Accretion. Depreciation, amortization and accretion expense increased $5.4 million for the three months ended March 31, 2018 as compared to the three months ended March 31, 2017, primarily due to asset contributions from Diamondback and further development of existing gathering, transportation and disposal systems.

General and Administrative Expense. General and administrative expense increased $0.1 million for the three months ended March 31, 2018 as compared to the three months ended March 31, 2017, primarily due to increased shared service allocations and additional professional service fees due to business growth and the contribution of additional midstream asset.

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 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                ,                , 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 $         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 the partnership and all wholly-owned material subsidiaries of the partnership.

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

 

89


Table of Contents

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 the borrower and the partnership 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 2016 and 2017 were as follows:

 

     Year Ended
December 31,
 
     2017      2016  
     ($ in thousands)  

Net cash provided by operating activities

   $ 8      $ —    

Net cash provided by investing activities

   $ —        $ —    

Net cash provided by financing activities

   $     —        $     —    

For the year ended December 31, 2017 as compared to the year ended December 31, 2016:

Net cash provided by operating activities increased by $8,000 during the year ended December 31, 2017 compared to the year ended December 31, 2016. The increase was due to Rattler LLC establishing a bank account during the second quarter of 2017 and having cash activity in 2017 which was not all funded by Diamondback though equity contributions.

Net cash provided by operating activities, investing activities and financing activities for the three month periods ended March 31, 2018 and March 31, 2017 were as follows:

 

     Three Months Ended
March 31,
 
             2018                      2017          
     ($ in thousands)  

Net cash provided by operating activities

   $ 2,216      $ —    

Net cash provided by investing activities

   $ —        $ —    

Net cash provided by financing activities

   $ —        $ —    

For the three months ended March 31, 2018 and March 31, 2017:

Net cash provided by operating activities increased by $2.2 million during the three months ended March 31, 2018 compared to the three months ended March 31, 2017. The increase was due to Rattler LLC establishing a bank account during the second quarter of 2017 and having cash activity in late 2017 and 2018 which was not all funded by Diamondback though equity contributions.

Capital Contributions

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.

For the year ended December 31, 2017, the total capital expenditures of our predecessor were $177.0 million, of which $51.5 million were related to SWD assets, $18.6 million were related to land, $44.7 million were related to crude oil gathering assets, $38.4 million were related to natural gas gathering assets and $23.8 million were related to fresh water assets.

 

90


Table of Contents

For the year ended December 31, 2016, the total capital contributions by Diamondback to our predecessor were $83.3 million, of which $27.2 million were related to SWD assets, $50.1 million were related to land, $5.7 million were related to crude oil gathering assets and $0.2 million were related to natural gas gathering assets.

We estimate that total capital expenditures for the twelve months ending December 31, 2018 will be between $100.0 million and $150.0 million related to midstream assets.

Off-Balance Sheet Arrangements

None.

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 and deliver to natural gas to other transmission delivery points, (ii) in the case of oil gathering, the volumes of metered oil that we gather and deliver to other transmission delivery points, (iii) in the case of fresh water services, the quantities of fresh water delivered to our customers for use in their well drilling and completion operations, (iv) in the case of wastewater disposal and treatment services, the quantities of wastewater treated or 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 with Diamondback and 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.

 

91


Table of Contents

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 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.

 

92


Table of Contents

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.

 

93


Table of Contents

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:

 

 

LOGO

 

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.

 

94


Table of Contents

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:

 

 

LOGO

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

 

95


Table of Contents

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.

 

96


Table of Contents

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:

 

 

LOGO

 

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 31% from 2017 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.

 

97


Table of Contents

Crude Oil Supply and Demand

Crude oil is a significant component of energy consumption. The EIA expects global petroleum liquids consumption to grow 24% from 98 MMBbl/d in 2017 to 122 million Bbl/d by 2050. The following chart illustrates expected growth in petroleum and other liquids consumption.

Global Petroleum Liquids Consumption

 

 

LOGO

 

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. Due in large part to hydraulic fracturing and horizontal drilling, the EIA forecasted U.S. crude oil production to surpass the record of 9.6 million Bbl/d in 2018 which occurred earlier this year (May 2018 production was 10.4 MMBbls/d according to the EIA). 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, 98% of the 1.1 MMBbl/d increase in crude oil production from 2018-2023 is projected to be from increases in tight oil production.

 

98


Table of Contents

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

 

 

LOGO

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 2018 to 2023, the EIA expects a 20% increase in Southwest region production, as shown in the graph below.

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

 

 

LOGO

 

99


Table of Contents

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

 

 

LOGO

 

100


Table of Contents

The EIA expects crude prices to rise over the next several years and is currently forecasting average 2023 WTI and Brent prices of $79/Bbl and $83/Bbl, respectively, versus an average of $49/Bbl and $53/Bbl during 2018. 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 of 10% in WTI pricing over the next five years should continue to enable economic unconventional drilling. Second, WTI crude is expected to trade at a $2 to $4 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

 

 

LOGO

 

101


Table of Contents

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 27% of all energy used in the U.S. in 2017 and demand is expected to grow 29%, from 27.6 quadrillion BTU in 2017 to 35.6 quadrillion BTU by 2040. The following chart illustrates this expected growth in U.S. natural gas demand through 2050.

Natural Gas Consumption by Sector

 

LOGO

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 31% from 2017 through 2050, while natural gas production will increase by 58% over this same time period.

 

102


Table of Contents

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

 

 

LOGO

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 2023.

Projected Spot Price for Natural Gas at Henry Hub

 

. LOGO

 

103


Table of Contents

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 Mexic