424B1 1 d673207d424b1.htm 424B1 424B1
Table of Contents

Filed pursuant to Rule 424(b)(1)
Registration No. 333-195769

PROSPECTUS

 

 

 

LOGO   

Viper Energy Partners LP

 

5,000,000 Common Units

Representing Limited Partner Interests

 

 

This is the initial public offering of our common units representing limited partner interests. We are offering 5,000,000 common units. Prior to this offering, there has been no public market for our common units. We have been approved to list our common units on the NASDAQ Global Select Market under the symbol “VNOM.”

Investing in our common units involves risks. Please read “Risk Factors” beginning on page 17.

These risks include the following:

 

 

We may not have sufficient available cash to pay any quarterly distribution on our common units.

 

The amount of our quarterly cash distributions, if any, may vary significantly both quarterly and annually and will be directly dependent on the performance of our business. We will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time.

 

The volatility of oil and natural gas prices due to factors beyond our control greatly affects our financial condition, results of operations and cash available for distribution.

 

We depend on two operators for substantially all of the development and production on the properties underlying our mineral interests. Substantially all of our revenue is derived from royalty payments made by these operators. A reduction in the expected number of wells to be drilled on our acreage by these operators or the failure of either operator to adequately and efficiently develop and operate our acreage could have an adverse effect on our expected growth and our results of operations.

 

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 unitholders.

 

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

 

Holders of our common units will have limited voting rights and are not entitled to elect our general partner or its directors.

 

Unitholders will incur immediate and substantial dilution in net tangible book value per common unit.

 

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service were to treat us as a corporation for federal income tax purposes or we were to become subject to entity-level taxation for state tax purposes, then our cash available for distribution to you could be substantially reduced.

 

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

In addition, we qualify as an “emerging growth company” as defined in Section 2(a)(19) of the Securities Act of 1933 and, as such, are allowed to provide in this prospectus more limited disclosures than an issuer that would not so qualify. Furthermore, for so long as we remain an emerging growth company, we will qualify for certain limited exceptions from investor protection laws such as the Sarbanes Oxley Act of 2002 and the Investor Protection and Securities Reform Act of 2010. Please read “Summary—Emerging Growth Company Status.”

Diamondback may be deemed to be an “underwriter” within the meaning of the Securities Act with respect to this offering.

 

     Per Common Unit      Total  

Public Offering Price

   $ 26.00       $ 130,000,000   

Underwriting Discount(1)

   $ 1.69       $ 8,450,000   

Proceeds to Viper Energy Partners LP (before expenses)

   $ 24.31       $ 121,550,000   

 

(1) Excludes an aggregate structuring fee equal to 0.50% of the gross proceeds of this offering payable to Barclays Capital Inc. Please read “Underwriting” for a description of all underwriting compensation payable in connection with this offering.

The underwriters may purchase up to an additional 750,000 common units from us at the public offering price, less the underwriting discount and structuring fee, 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 to purchasers on or about June 23, 2014 through the book-entry facilities of The Depository Trust Company.

 

 

Joint Book-Running Managers

 

Barclays   Credit Suisse   Wells Fargo Securities

Senior Co-Managers

 

Baird   Raymond James  

Scotiabank / Howard Weil

Simmons & Company  

Stifel

  Tudor, Pickering, Holt & Co.
            International    

Co-Managers

 

Northland Capital Markets

  Sterne Agee   Wunderlich Securities

Prospectus dated June 17, 2014


Table of Contents

LOGO


Table of Contents

TABLE OF CONTENTS

 

SUMMARY

     1   

Overview

     1   

Our Properties

     2   

Our Relationship with Diamondback

     3   

Business Strategies

     3   

Competitive Strengths

     4   

Risk Factors

     6   

Management

     6   

Conflicts of Interest and Fiduciary Duties

     6   

Emerging Growth Company Status

     7   

Formation Transactions and Structure

     7   

Principal Executive Offices

     9   

The Offering

     10   

Summary Historical Financial Data

     14   

Non-GAAP Financial Measure

     15   

Summary Reserve Data

     16   

RISK FACTORS

     17   

Risks Related to Our Business

     17   

Risks Related to Operators and Other Working Interest Owners

     25   

Risks Inherent in an Investment in Us

     37   

Tax Risks to Common Unitholders

     46   

USE OF PROCEEDS

     50   

CAPITALIZATION

     51   

DILUTION

     52   

CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

     53   

General

     53   

Estimated Cash Available for Distribution for the Twelve Months Ending June 30, 2015

     55   

HOW WE MAKE DISTRIBUTIONS

     62   

General

     62   

Method of Distributions

     62   

Common Units

     62   

General Partner Interest

     62   

SELECTED HISTORICAL FINANCIAL DATA

     63   

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

     64   

Overview

     64   

Operating Results Overview

     64   

Reserves and Pricing

     64   

Sources of Our Revenue

     65   

Principal Components of Our Cost Structure

     65   

Factors Affecting the Comparability of Our Results to the Historical Financial Results of Our Predecessor

     66   

Results of Operations

     67   

Liquidity and Capital Resources

     68   

Contractual Obligations

     69   

Internal Controls and Procedures

     69   

 

i


Table of Contents

New and Revised Financial Accounting Standards

     69   

Critical Accounting Policies

     70   

Inflation

     71   

Off-Balance Sheet Arrangements

     71   

Quantitative and Qualitative Disclosure about Market Risk

     72   

BUSINESS

     73   

Overview

     73   

Our Properties

     73   

Our Relationship with Diamondback

     74   

Business Strategies

     75   

Competitive Strengths

     76   

Oil and Natural Gas Data

     77   

Oil and Natural Gas Production Prices and Production Costs

     81   

Competition

     82   

Seasonal Nature of Business

     82   

Regulation

     83   

Employees

     90   

Facilities

     90   

Legal Proceedings

     90   

MANAGEMENT

     91   

Management of Viper Energy Partners LP

     91   

Executive Officers and Directors of Our General Partner

     92   

Director Independence

     94   

Committees of the Board of Directors

     94   

Indemnification Agreements

     95   

EXECUTIVE COMPENSATION AND OTHER INFORMATION

     96   

Compensation Discussion and Analysis

     96   

Long-Term Incentive Plan

     97   

Director Compensation

     100   

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     102   

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

     105   

Distributions and Payments to Diamondback and Its Affiliates

     105   

Agreements and Transactions with Affiliates in Connection with this Offering

     106   

Other Transactions with Related Persons

     107   

Procedures for Review, Approval and Ratification of Transactions with Related Persons

     107   

CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

     108   

Conflicts of Interest

     108   

Fiduciary Duties

     112   

DESCRIPTION OF OUR COMMON UNITS

     115   

Our Common Units

     115   

Transfer Agent and Registrar

     115   

Transfer of Common Units

     115   

Listing

     116   

THE PARTNERSHIP AGREEMENT

     117   

Organization and Duration

     117   

Purpose

     117   

Capital Contributions

     117   

Adjustments to Capital Accounts Upon Issuance of Additional Common Units

     117   

Voting Rights

     117   

 

ii


Table of Contents

Applicable Law; Forum, Venue and Jurisdiction

     119   

Limited Liability

     119   

Issuance of Additional Partnership Interests

     120   

Amendment of the Partnership Agreement

     121   

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

     123   

Dissolution

     123   

Liquidation and Distribution of Proceeds

     124   

Withdrawal or Removal of Our General Partner

     124   

Transfer of General Partner Interest

     125   

Transfer of Ownership Interests in the General Partner

     125   

Change of Management Provisions

     125   

Limited Call Right

     125   

Non-Taxpaying Holders; Redemption

     126   

Non-Citizen Assignees; Redemption

     126   

Meetings; Voting

     126   

Status as Limited Partner

     127   

Indemnification

     127   

Reimbursement of Expenses

     128   

Books and Reports

     128   

Right to Inspect Our Books and Records

     128   

Registration Rights

     129   

UNITS ELIGIBLE FOR FUTURE SALE

     130   

MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES

     132   

Taxation of the Partnership

     132   

Tax Consequences of Unit Ownership

     134   

Tax Treatment of Operations

     138   

Disposition of Units

     140   

Uniformity of Units

     142   

Tax-Exempt Organizations and Other Investors

     143   

Administrative Matters

     144   

FATCA Withholding Requirements

     145   

State, Local and Other Tax Considerations

     146   

INVESTMENT IN VIPER ENERGY PARTNERS LP BY EMPLOYEE BENEFIT PLANS

     147   

UNDERWRITING

     148   

Commissions and Expenses

     148   

Option to Purchase Additional Common Units

     149   

Lock-Up Agreements

     149   

Offering Price Determination

     149   

Indemnification

     150   

Stabilization, Short Positions and Penalty Bids

     150   

Directed Unit Program

     150   

Purchase by Related Party

     151   

Electronic Distribution

     151   

Listing on the NASDAQ

     151   

Discretionary Sales

     151   

Stamp Taxes

     151   

Other Relationships

     151   

Direct Participation Program Requirements

     152   

Selling Restrictions

     152   

LEGAL MATTERS

     155   

 

iii


Table of Contents

EXPERTS

     155   

WHERE YOU CAN FIND MORE INFORMATION

     155   

FORWARD-LOOKING STATEMENTS

     156   

INDEX TO FINANCIAL STATEMENTS

     F-1   

APPENDIX A—FORM OF FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF VIPER ENERGY PARTNERS LP

     A-1   

APPENDIX B—GLOSSARY OF SELECTED TERMS

     B-1   

 

 

You should rely only on the information contained in this prospectus, any free writing prospectus prepared by or on behalf of us or any other information to which we have referred you in connection with this offering. We have not, and the underwriters have not, authorized any other person to provide you with information different from that contained in this prospectus. 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. This prospectus is not an offer to sell or solicitation of an offer to buy our common units in any circumstances under which the offer or solicitation is unlawful.

INDUSTRY AND MARKET DATA

This prospectus includes industry data and forecasts that we obtained from internal company surveys, publicly available information and industry publications and surveys. Our internal research and forecasts are based on management’s understanding of industry conditions, and such information has not been verified by independent sources. Industry publications and surveys generally state that the information contained therein has been obtained from sources believed to be reliable.

 

iv


Table of Contents

SUMMARY

This summary highlights 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 read the entire prospectus carefully, including the historical financial statements and the notes to those financial statements, before investing in our common units. The information presented in this prospectus assumes, unless otherwise indicated, that the underwriters’ option to purchase additional common units is not exercised. You should read “Risk Factors” for information about important risks that you should consider before buying our common units.

References in this prospectus to “Viper Energy Partners LP Predecessor,” “our predecessor,” “we,” “our,” “us” or like terms when used in a historical context refer to Viper Energy Partners LLC, which Diamondback Energy, Inc. (NasdaqGS: FANG) is contributing to Viper Energy Partners LP in connection with this offering. When used in the present tense or prospectively, “we,” “our,” “us” or like terms refer to Viper Energy Partners LP and its subsidiaries. Except where expressly noted otherwise, references in this prospectus to “Diamondback” refer to Diamondback Energy, Inc. and its subsidiaries other than Viper Energy Partners LP and its subsidiaries. References in this prospectus to “our general partner” refer to Viper Energy Partners GP LLC, a wholly owned subsidiary of Diamondback Energy, Inc. References in this prospectus to “Wexford” refer to Wexford Capital LP, which is a Greenwich, Connecticut-based SEC-registered investment advisor with approximately $4.0 billion under management as of March 31, 2014. References in this prospectus to “our executive officers” and “our directors” refer to the executive officers and directors of our general partner, respectively. We include a glossary of some of the terms used in this prospectus as Appendix B.

Viper Energy Partners LP

Overview

We are a Delaware limited partnership formed by Diamondback to own, acquire and exploit oil and natural gas properties in North America. Our primary business objective is to provide an attractive return to unitholders by focusing on business results, maximizing distributions through organic growth and pursuing accretive growth opportunities through acquisitions of mineral interests from Diamondback and from third parties. Our initial assets consist of mineral interests in oil and natural gas properties in the Permian Basin in West Texas, substantially all of which are leased to working interest owners who bear the costs of operation and development. Diamondback will contribute these assets, which it acquired in September 2013 from a third party for cash, to us upon the closing of this offering.

Like Diamondback, we expect our initial focus will concentrate on the Permian Basin, which is one of the oldest and most prolific producing basins in North America. The Permian Basin, which consists of approximately 85,000 square miles centered around Midland, Texas, has been a significant source of oil production since the 1920s. The Permian Basin is known to have a number of zones of oil and natural gas bearing rock throughout. However, because of the nature of the rock in many of the potentially productive zones, historically it was not economic to exploit these zones. As a result, exploration and development was limited until recently when higher oil prices and more advanced completion techniques, including hydraulic fracturing, changed the economics of drilling and development of these zones and greatly increased the oil and natural gas industry’s interest in the Permian Basin. Oil production in the Permian Basin has grown from 850,000 barrels per day in 2008 to 1.3 million barrels per day in 2013. Based on public statements made by a number of publicly traded oil and natural gas companies, and the successful horizontal well results of the industry, we believe that drilling activity in the Permian Basin is likely to continue to grow at least for several more years.

 

 

1


Table of Contents

Diamondback is a publicly traded independent oil and natural gas company currently focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin. Upon the completion of this offering, Diamondback will own and control our general partner, and will own approximately 93% of our outstanding common units. Diamondback’s total net acreage position in the Permian Basin (including the acreage underlying our mineral interests with respect to which it is operator) was approximately 72,000 net acres at March 31, 2014, and it serves as the operator of approximately 99% of its leased acreage. As of December 31, 2013, Diamondback had estimated proved oil and natural gas reserves of 63,586 MBOE (including the estimated proved reserves associated with our mineral interests) based on a reserve report prepared by Ryder Scott Company, L.P. (“Ryder Scott”). Of these reserves, approximately 45% were classified as proved developed producing (“PDP”) reserves and approximately 67% were oil, 17% were natural gas liquids and 16% were natural gas. Proved undeveloped (“PUD”) reserves included in this estimate are from 206 vertical gross (151 net) well locations on 40-acre spacing and 43 gross (31 net) horizontal well locations. We believe that the properties held by Diamondback include properties that have, or with additional development will have, production and reserves characteristics that could make them attractive for inclusion in our partnership. We believe Diamondback’s significant ownership interest in us will motivate it to offer additional mineral and other interests in oil and natural gas properties to us in the future, although Diamondback has no obligation to do so. Please read “— Our Relationship with Diamondback.”

Our Properties

Our initial assets consisted of mineral interests underlying approximately 14,804 gross acres in Midland County, Texas in the Permian Basin, approximately 50% of which are operated by Diamondback. Diamondback acquired the mineral interests for $440 million on September 19, 2013. The mineral interests entitle us to receive an average 21.4% royalty interest on all production from this acreage with no additional future capital or operating expense required. As of March 31, 2014, there were 210 vertical wells and 22 horizontal wells producing on this acreage, and average net production was approximately 2,197 net BOE/d during March 2014. In addition, there were six vertical wells and 14 horizontal wells in various stages of completion. For the three months ended March 31, 2014 and the period from our inception (September 18, 2013) to December 31, 2013, royalty revenue generated from these mineral interests was $15.9 million and $15.0 million, respectively.

The estimated proved oil and natural gas reserves of our initial assets, as of December 31, 2013, were 10,270 MBOE based on a reserve report prepared by Ryder Scott, our independent reserve engineer. Of these reserves, approximately 48% were classified as PDP reserves. PUD reserves included in this estimate were from 106 vertical gross well locations on 40-acre spacing and 24 gross horizontal well locations. As of December 31, 2013, our proved reserves were approximately 70% oil, 11% natural gas liquids and 18% natural gas.

Based on Diamondback’s evaluation of applicable geologic and engineering data as of March 31, 2014, with respect to the approximate 50% of our mineral interests for which it is the operator, Diamondback had 73 identified potential vertical drilling locations on 40-acre spacing and an additional 184 identified potential vertical drilling locations based on 20-acre downspacing. As of such date, Diamondback had also identified 322 potential horizontal drilling locations in multiple horizons on our acreage. We do not have potential drilling location information with respect to the portion of our properties not operated by Diamondback, although we believe that such portion has very similar production characteristics to the portion operated by Diamondback. The operator of a majority of our properties not operated by Diamondback is RSP Permian, Inc. (NYSE: RSPP), an unaffiliated entity (“RSP Permian”). Diamondback has advised us that it believes it has a good relationship with RSP Permian and that it shares, on occasion, drilling and production information with RSP Permian in order to encourage further development of our properties. Additionally, Diamondback has participated with RSP Permian in the drilling and completion of five horizontal wells on shared acreage subject to our mineral interests.

The gross estimated ultimate recoveries (“EURs”) from the future PUD vertical wells included in our reserve report on 40-acre spacing, as estimated by Ryder Scott as of December 31, 2013, range from 104 MBOE

 

 

2


Table of Contents

per well, consisting of 80 MBbls of oil and 148 MMcf of natural gas, to 146 MBOE per well, consisting of 112 MBbls of oil and 208 MMcf of natural gas, with an average EUR per well of 134 MBOE, consisting of 102 MBbls of oil and 193 MMcf of natural gas. Diamondback currently anticipates a reduction of approximately 20% in EURs from vertical wells drilled on 20-acre spacing.

Our Relationship with Diamondback

Upon the completion of this offering, Diamondback will own and control our general partner and will own approximately 93% of our outstanding common units. We believe that the properties held by Diamondback include properties that have, or with additional development will have, production and reserves characteristics that could make them attractive for inclusion in our partnership. We believe Diamondback’s significant ownership in us will motivate it to offer additional mineral and other interests in oil and natural gas properties to us in the future, although Diamondback has no obligation to do so and may elect to dispose of mineral and other interests in such properties without offering us the opportunities to acquire them.

We believe Diamondback views our partnership as part of its growth strategy, and we believe that Diamondback will be incentivized to pursue acquisitions jointly with us in the future. However, Diamondback will regularly evaluate acquisitions and may elect to acquire properties without offering us the opportunity to participate in such transactions. Moreover, Diamondback may not be successful in identifying potential acquisitions. After this offering, Diamondback will continue to be free to act in a manner that is beneficial to its interests without regard to ours, which may include electing not to present us with acquisition or disposition opportunities. Please read “Conflicts of Interest and Fiduciary Duties.”

In addition, neither we nor our subsidiaries nor our general partner will have any employees. Diamondback will provide management, operating and administrative services to us and our general partner. Please read “Management” and “Certain Relationships and Related Party Transactions.”

Diamondback may be deemed to be an “underwriter” within the meaning of the Securities Act with respect to this offering.

Prior to October 11, 2012, Wexford beneficially owned 100% of the equity interests in Diamondback. Upon completion of Diamondback’s initial public offering, Wexford beneficially owned approximately 44.4% of its common stock. As a result of the issuance of additional shares of common stock by Diamondback and sales of its common stock by affiliates of Wexford, as of April 1, 2014, Wexford beneficially owned approximately 18.4% of the common stock of Diamondback.

Business Strategies

Our primary business objective is to provide an attractive return to unitholders by focusing on business results, maximizing distributions through organic growth and pursuing accretive growth opportunities through acquisitions of mineral interests from Diamondback and from third parties. We intend to accomplish this objective by executing the following strategies:

 

   

Capitalize on the development of the properties underlying our mineral interests to grow our distributions. As of the closing of this offering, our initial assets will consist of mineral interests in the Permian Basin in West Texas. We expect the production from our mineral interest will increase as Diamondback and our other operators continue to actively drill and develop our acreage. We expect to capitalize on this development, cost-free to us, and believe the resulting increase in our aggregate royalty payments will enable us to grow our distributions.

 

 

3


Table of Contents
   

Leverage our relationship with Diamondback to participate with it in acquisitions of mineral or other interests in producing properties from third parties and to increase the size and scope of our potential third-party acquisition targets. We intend to make opportunistic acquisitions of mineral interests that have substantial oil-weighted resource potential and organic growth potential. Diamondback was formed in part to acquire and develop oil and natural gas properties, some of which will likely meet our acquisition criteria. In addition, Diamondback’s executives have long histories of evaluating, pursuing and consummating oil and natural gas property acquisitions in North America. Through our relationships with Diamondback and its affiliates, we have access to their significant pool of management talent and industry relationships, which we believe provide us with a competitive advantage in pursuing potential third-party acquisition opportunities. We may have additional opportunities to work jointly with Diamondback to pursue certain acquisitions of mineral or other interests in oil and natural gas properties from third parties. For example, we and Diamondback may jointly pursue an acquisition where we would acquire mineral or other interests in properties and Diamondback would acquire the remaining working and revenue interests in such properties. We believe this arrangement may give us access to third-party acquisition opportunities that we would not otherwise be in a position to pursue.

 

   

Seek to acquire from Diamondback, from time to time, mineral or other interests in producing oil and natural gas properties that meet our acquisition criteria. We may have additional opportunities to acquire mineral or other interests in producing oil and natural gas properties directly from Diamondback or third parties from time to time in the future. We believe Diamondback may be incentivized to sell properties to us, as doing so may enhance Diamondback’s economic returns by monetizing long-lived producing properties while potentially retaining a portion of the resulting cash flow through distributions on Diamondback’s limited partner interests in us. However, none of Diamondback or any of its affiliates is contractually obligated to offer or sell any interests in properties to us.

Competitive Strengths

We believe that the following competitive strengths will allow us to successfully execute our business strategies and achieve our primary business objective:

 

   

Oil rich resource base in one of North America’s leading resource plays. All of the acreage underlying our mineral interests is located in one of the most prolific oil plays in North America, the Permian Basin in West Texas. The majority of our current properties are well positioned in the core of the Wolfberry play. Production on our properties for the three months ended March 31, 2014 was approximately 79% oil, 12% natural gas liquids and 9% natural gas. As of December 31, 2013, our estimated net proved reserves were comprised of approximately 70% oil and 11% natural gas liquids, which allows us to benefit from the currently more favorable pricing of oil and natural gas liquids as compared to natural gas. We believe that we will have a strong, growing production profile driven by Diamondback, a growth-oriented operator.

 

   

Multi-year drilling inventory in one of North America’s leading oil resource plays. We expect our reserves and cash available for distributions to grow organically as our operators continue to drill new wells on our acreage. Diamondback, as the operator of approximately 50% of our properties, has advised us that it has identified a multi-year inventory of potential drilling locations for our oil-weighted reserves from the acreage underlying our mineral interests. As of March 31, 2014, with respect to the approximate 50% of our properties operated by it, Diamondback had 73 identified potential vertical drilling locations based on 40-acre spacing and an additional 184 identified potential vertical drilling locations based on 20-acre downspacing. Diamondback also believes that there are a significant number of horizontal locations that could be drilled on the acreage. Based on Diamondback’s initial results and those of other operators in the area to date, combined with its interpretation of various geologic and engineering data, Diamondback has identified 322 potential horizontal locations on the acreage operated by Diamondback. These locations

 

4


Table of Contents
 

exist across most of the acreage and in multiple horizons. Of these 322 potential locations, 130 are in the Wolfcamp B or Lower Spraberry horizons, with the remaining locations in the Wolfcamp A, Clearfork, Middle Spraberry or Cline horizons. Diamondback’s current potential horizontal location count is based on 660-foot spacing between wells in the Wolfcamp B and Lower Spraberry horizons in Midland County, 880-foot spacing in the Middle Spraberry horizon and 1,320-foot spacing in other horizons. The ultimate inter-well spacing may be less than these amounts, which would result in a higher location count. Based on horizontal wells drilled to date, Ryder Scott assigned reserves to PUD locations ranging from 374 MBOE for 5,000-foot laterals in the Middle Spraberry to 847 MBOE for 10,000-foot laterals in the Wolfcamp B. When normalized to 7,500-foot laterals, Ryder Scott assigned PUD values of 638 MBOE for the Wolfcamp B horizon, 643 MBOE for the Lower Spraberry horizon and 562 MBOE for the Middle Spraberry horizon. These PUD locations, as assigned by Ryder Scott, are for direct offsets to producing wells. Based on various geologic and engineering parameters, we believe that the estimates assigned to these PUD locations are reasonable estimates for PUD locations on the remaining portion of our acreage. Additionally, we believe that there is similar potential for horizontal development on the portion of our acreage for which Diamondback is not the operator.

 

   

Experienced and proven management team. The members of our executive team have an average of over 25 years of industry experience, most of which were focused on resource play development in the Permian Basin. This team has a proven track record of executing on multi-rig development drilling programs and extensive experience in the Permian Basin. In addition, our executive team has significant experience with property acquisitions. We expect to benefit from the industry relationships fostered by the team’s decades of experience in the Permian Basin. Prior to joining Diamondback, the Chief Executive Officer of our general partner held management positions at Apache Corporation, Laredo Petroleum Holdings, Inc. and Burlington Resources. The Chief Financial Officer of our general partner previously served as the Controller/Tax Director at Hiland Partners, a publicly traded master limited partnership, and has over eight years of accounting experience at other public companies. We believe the experience of our management team is essential for us to grow from our initial property base.

 

   

Favorable and stable operating environment. We will focus our growth in the Permian Basin, one of the oldest hydrocarbon basins in the United States, with a long and well-established production history and developed infrastructure. With approximately 380,000 wells drilled in the Permian Basin since the 1940s, we believe that the geological and regulatory environment is more stable and predictable, and that we are faced with fewer operational risks, in the Permian Basin as compared to emerging hydrocarbon basins. We believe that the impact of the proven application of new technology, combined with the substantial geological information available about the Permian Basin, also reduces the risk of development and exploration activities as compared to emerging hydrocarbon basins.

 

   

Financial flexibility to fund expansion. We will seek to maintain financial flexibility to allow us to opportunistically purchase accretive mineral and other interests. Upon the completion of this offering, we will have no debt and will possess the financial capacity to grow the partnership. Subsequent to the closing of this offering, we also expect to enter into a revolving credit facility to be used for general partnership purposes. We further believe that we have a unique distribution profile with initial distributions exclusively supported by mineral interests. We also expect to produce peer-leading margins unburdened by lease operating expenses.

 

 

5


Table of Contents

Risk Factors

An investment in our common units involves risks. You should carefully consider the risks described in “Risk Factors” and the other information in this prospectus, before deciding whether to invest in our common units. If any of these risks were to occur, our financial condition, results of our operations, cash flows and ability to make distributions to our unitholders would be adversely affected, and you could lose all or part of your investment. For more information regarding the known material risks that could impact our business, please read “Risk Factors.”

Management

We are managed and operated by the board of directors and executive officers of our general partner, Viper Energy Partners GP LLC, a wholly owned subsidiary of Diamondback. As a result of owning our general partner, Diamondback will have the right to appoint all members of the board of directors of our general partner, including at least three directors meeting the independence standards established by The NASDAQ Stock Market LLC (“NASDAQ”). At least one of our independent directors will be appointed by the time our common units are first listed for trading on the NASDAQ Global Select Market. Our unitholders will not be entitled to elect our general partner or its directors or otherwise directly participate in our management or operations. In addition, neither we nor our subsidiaries nor our general partner will have any employees. Diamondback will provide management, operating and administrative services to us and our general partner. Wexford will provide general financial and strategic advisory services to us and our general partner pursuant to an advisory services agreement. The executive officers and some of the directors of our general partner currently serve as executive officers and directors of Diamondback. Please read “Management” and “Certain Relationships and Related Party Transactions.”

Conflicts of Interest and Fiduciary Duties

Although our relationship with Diamondback may provide significant benefits to us, it may also become a source of potential conflicts. For example, Diamondback or its affiliates, including Wexford, are not restricted from competing with us. In addition, the executive officers and certain of the directors of our general partner also serve as officers or directors of Diamondback, and these officers and directors face conflicts of interest, including conflicts of interest regarding the allocation of their time between us and Diamondback.

Our general partner has a contractual duty to manage us in a manner that it believes is not adverse to our interest. However, the executive officers and directors of our general partner have fiduciary duties to manage our general partner in a manner beneficial to Diamondback, the owner of our general partner. As a result, conflicts of interest may arise in the future between us or our unitholders, on the one hand, and Diamondback and our general partner, on the other hand.

Our partnership agreement limits the liability of and replaces the fiduciary duties owed by our general partner to our unitholders. Our partnership agreement also restricts the remedies available to our unitholders for actions that might otherwise constitute a breach of duties by our general partner or its directors or executive officers. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement, and each unitholder is treated as having consented to various actions and potential conflicts of interest contemplated in the partnership agreement that might otherwise be considered a breach of fiduciary or other duties under Delaware law.

For a more detailed description of the conflicts of interest and duties of our general partner and its directors and executive officers, please read “Conflicts of Interest and Fiduciary Duties.” For a description of other relationships with our affiliates, please read “Certain Relationships and Related Party Transactions.”

 

 

6


Table of Contents

Emerging Growth Company Status

We are an “emerging growth company” as defined in the Jumpstart Our Business Startups Act (“JOBS Act”). For as long as we are an emerging growth company, we may take advantage of specified exemptions from reporting and other regulatory requirements that are otherwise applicable generally to other public companies. These exemptions include:

 

   

an exemption from providing 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;

 

   

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

 

   

an exemption from compliance with any other new auditing standards adopted by the PCAOB after April 5, 2012, unless the SEC determines otherwise; and

 

   

reduced disclosure of executive compensation.

In addition, Section 107 of the JOBS Act also provides that an emerging growth company can use the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. This permits an emerging growth company to delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. However, we are choosing to “opt out” of such extended transition period and, as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for non-emerging growth companies. Our decision to opt out of the extended transition period for complying with new or revised accounting standards is irrevocable.

We will cease to be an “emerging growth company” upon the earliest of (i) when we have $1.0 billion or more in annual revenues, (ii) when we have at least $700 million in market value of our common units held by non-affiliates, (iii) when we issue more than $1.0 billion of non-convertible debt over a three-year period or (iv) the last day of the fiscal year following the fifth anniversary of our initial public offering.

Formation Transactions and Structure

At or prior to the closing of this offering, the following transactions will occur:

 

   

we will distribute all cash and cash equivalents and the royalty income receivable on hand to Diamondback;

 

   

Diamondback will contribute Viper Energy Partners LLC to us in exchange for 71,200,000 common units;

 

   

our general partner will maintain its non-economic general partner interest;

 

   

we will issue and sell 5,000,000 common units to the public in this offering and pay the related underwriting discount and structuring fee and offering expenses; and

 

   

we will use the net proceeds from this offering in the manner described under “Use of Proceeds.”

We refer to these transactions collectively as the “formation transactions.”

We have granted the underwriters a 30-day option to purchase up to an aggregate of 750,000 additional common units. Any net proceeds received from the exercise of this option will be distributed to Diamondback. If the underwriters do not exercise this option in full or at all, the common units that would have been sold to the

 

 

7


Table of Contents

underwriters had they exercised the option in full will be issued to Diamondback for no additional consideration at the expiration of the option period. Accordingly, the exercise of the underwriters’ option will not affect the total number of common units outstanding.

The following chart illustrates our organizational structure after giving effect to this offering and the other formation transactions described above:

 

LOGO

 

Public Common Units

     5,000,000         7

Interests of Diamondback:

     

Common Units

     71,200,000         93

Non-Economic General Partner Interest

     —           0 %(1) 
  

 

 

    

 

 

 

Total

     76,200,000         100
  

 

 

    

 

 

 

 

(1) Our general partner owns a non-economic general partner interest in us. Please read “How We Make Distributions—General Partner Interest.”

 

 

8


Table of Contents

Principal Executive Offices

Our principal executive offices are located at 500 West Texas Avenue, Suite 1200, Midland, Texas, and our telephone number is (432) 221-7400. Our website address will be www.viperenergy.com. We intend to make our periodic reports and other information filed with or furnished to the SEC available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

 

 

9


Table of Contents

The Offering

 

Common units offered to the public

5,000,000 common units or 5,750,000 common units if the underwriters exercise in full their option to purchase additional common units from us.

 

Units outstanding after this offering

76,200,000 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 any exercise will be sold to the public. Any common units not purchased by the underwriters pursuant to their exercise of the option will be issued to Diamondback at the expiration of the option period for no additional consideration. Accordingly, the exercise of the underwriters’ option will not affect the total number of common units outstanding.

 

Use of proceeds

We intend to use the estimated net proceeds of approximately $119.4 million from this offering, after deducting the estimated underwriting discount and structuring fee and offering expenses payable by us, to make a distribution to Diamondback. Affiliates of certain of the underwriters are lenders under Diamondback’s revolving credit facility. Diamondback may, but is not required to, apply the distribution that it receives from us to repay amounts outstanding under its revolving credit facility. Accordingly, affiliates of certain of the underwriters may indirectly receive a portion of the proceeds from this offering in the form of repayment of debt by Diamondback.

 

  The net proceeds from any exercise of the underwriters’ option to purchase additional common units (approximately $18.1 million after deducting the estimated underwriting discount and structuring fee, if exercised in full) will be used to make a distribution to Diamondback. Please read “Use of Proceeds.”

 

Cash distributions

Within 60 days after the end of each quarter, beginning with the quarter ending September 30, 2014, we expect to make distributions to unitholders of record on the applicable record date. We expect our first distribution will consist of available cash (as described below) for the period from the closing of this offering through September 30, 2014.

 

  In connection with the closing of this offering, the board of directors of our general partner will adopt a policy pursuant to which distributions for each quarter will be in an amount equal to the available cash we generate in such quarter. Available cash for each quarter will be determined by the board of directors of our general partner following the end of such quarter. We expect that available cash for each quarter will generally equal our Adjusted EBITDA for the quarter, less cash needed for debt service and other contractual obligations and fixed charges and reserves for future operating or capital needs that the board of directors may determine is appropriate.

 

 

10


Table of Contents
  Unlike a number of other master limited partnerships, we do not expect to initially retain cash from our operations for replacement capital expenditures primarily due to our expectation that existing development and the discovery of new pay horizons will lead to inclining production and revenues for at least the next several years. Replacement capital expenditures are those expenditures necessary to replace our existing oil and gas reserves or otherwise maintain our asset base over the long term. We expect to seek additional acquisitions of reserves and may restrict distributions to acquire or fund such acquisitions in whole or in part. If we do not retain cash for replacement capital expenditures in amounts necessary to maintain our asset base, eventually our cash available for distribution will decrease. The board of directors of our general partner may in the future decide to withhold replacement capital expenditures from cash available for distribution which may have an adverse impact on the cash available for distribution in the quarter(s) in which any such amounts are withheld. To the extent that we do not withhold replacement capital expenditures in the future, a portion of our future cash available for distribution will represent a return of your capital.

 

  We do not intend to maintain excess distribution coverage for the purpose of maintaining stability or growth in our quarterly distribution or to otherwise reserve cash for distributions, and we do not intend to incur debt to pay quarterly distributions. Further, it is our intent, subject to market conditions, to finance growth capital externally, and not to reserve cash for unspecified potential future needs.

 

  Because our policy will be to distribute an amount equal to all available cash we generate each quarter, our unitholders will have direct exposure to fluctuations in the amount of cash generated by our business. We expect that the amount of our quarterly distributions, if any, will vary based on our earnings during each quarter. As a result, our quarterly distributions, if any, will not be stable and will vary from quarter to quarter as a direct result of variations in, among other factors, (i) the performance of our operators, (ii) earnings caused by, among other things, fluctuations in the price of oil and natural gas, changes to working capital or capital expenditures and (iii) cash reserves deemed appropriate by the board of directors of our general partner. Such variations in the amount of our quarterly distributions may be significant and could result in no distribution for any quarter. We will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time. The board of directors of our general partner may change our distribution policy at any time. Our partnership agreement does not require us to pay distributions to our unitholders on a quarterly or other basis.

 

 

Based upon our forecast for the twelve months ending June 30, 2015, and assuming the board of directors of our general partner declares

 

 

11


Table of Contents
 

distributions in accordance with our cash distribution policy, we expect that our aggregate distributions for the twelve months ending June 30, 2015 will be approximately $83.8 million, or $1.10 per common unit. Please read “Cash Distribution Policy and Restrictions on Distributions—Estimated Cash Available for Distribution for the Twelve Months Ending June 30, 2015.” Unanticipated events may occur which could materially adversely affect the actual results we achieve during the forecast period. Consequently, our actual results of operations, reserve requirements and financial condition during the forecast period may vary from the forecast, and such variations may be material. Prospective investors are cautioned not to place undue reliance on our forecast and should make their own independent assessment of our future results of operations and financial condition. In addition, the board of directors of our general partner may be required to, or may elect to, eliminate our distributions during periods of reduced prices or demand for oil and natural gas, among other reasons. Please read “Risk Factors.”

 

 

Subordinated units

None.

 

Incentive distribution rights

None.

 

Issuance of additional units

Our partnership agreement authorizes us to issue an unlimited number of additional units without the approval of our unitholders. Please read “Units Eligible for Future Sale” and “The Partnership Agreement—Issuance of Additional 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 unitholders holding 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. Upon the consummation of this offering, Diamondback will own an aggregate of 93% of our common units (or 92% of our common units, if the underwriters exercise their option to purchase additional common units in full). This will effectively give Diamondback the ability to prevent the removal of our general partner. Please read “The Partnership Agreement—Voting Rights.”

 

Limited call right

If at any time our general partner and its affiliates (including Diamondback) own more than 97% of the outstanding common units, our general partner will have the right, but not the obligation, to purchase all of the remaining common units at a price equal to the greater of (1) 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 (2) the highest

 

 

12


Table of Contents
 

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 our general partner and its affiliates (including Diamondback) reduce their ownership to below 75% of the outstanding common units, the ownership threshold to exercise the call right will be permanently reduced to 80%. Please read “The Partnership Agreement—Limited Call Right.”

 

Estimated ratio of taxable income to distributions

We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending December 31, 2017, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be approximately 60% of the cash expected to be distributed to you with respect to that period. Because of the nature of our business and the expected variability of our quarterly distributions, however, the ratio of our taxable income to distributions may vary significantly from one year to another. Please read “Material U.S. Federal Income Tax Consequences—Tax Consequences of Unit Ownership” for the basis of this estimate.

 

Material federal income tax consequences

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

 

Directed unit program

The underwriters have reserved for sale at the initial public offering price up to 10% of the common units being offered by this prospectus for sale to persons who are directors, officers or employees of our general partner and its affiliates and certain other persons with relationships with us and our affiliates. We do not know if these persons will choose to purchase all or any portion of these reserved common units, but any purchases they do make will reduce the number of common units available to the general public. Please read “Underwriting—Directed Unit Program.”

 

Exchange listing

We have been approved to list our common units on the NASDAQ Global Select Market under the symbol “VNOM.”

 

 

13


Table of Contents

Summary Historical Financial Data

Viper Energy Partners LP was formed in February 2014 and does not have historical financial statements. Therefore, in this prospectus we present the historical financial statements of Viper Energy Partners, LLC, the subsidiary of Diamondback that will be contributed to Viper Energy Partners LP upon the closing of this offering. We refer to this entity as “Viper Energy Partners LP Predecessor.” The following table presents summary historical financial data of Viper Energy Partners LP Predecessor as of the dates and for the periods indicated. Diamondback acquired the assets owned by Viper Energy Partners LP Predecessor on September 19, 2013.

The summary historical financial data of Viper Energy Partners LP Predecessor presented as of the dates and for the periods indicated are derived from the audited historical financial statements and unaudited historical financial statements of Viper Energy Partners LP Predecessor included elsewhere in this prospectus.

For a detailed discussion of the summary historical financial data contained in the following table, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The following table should also be read in conjunction with “Use of Proceeds” and the audited historical financial statements and unaudited historical financial statements of Viper Energy Partners LP Predecessor included elsewhere in this prospectus. Among other things, the historical financial statements include more detailed information regarding the basis of presentation for the information in the following table.

 

     Viper Energy Partners  LP
Predecessor Historical
 
     Three Months Ended
March 31,
2014
    Period From Inception
(September 18, 2013)
Through
December 31, 2013
 
     (unaudited)        
     (in thousands)  

Statement of Operations Data:

    

Royalty income

   $ 15,853      $ 14,987   

Expenditures:

    

Production and ad valorem taxes

     921        972   

Depletion

     5,567        5,199   

General and administrative expenses

     66        —     

General and administrative expenses—related party

     78        87   

Interest expense—related party, net of capitalized interest

     5,368        5,741   
  

 

 

   

 

 

 

Total expenditures

     12,000        11,999   
  

 

 

   

 

 

 

Net income

   $         3,853      $         2,988   
  

 

 

   

 

 

 

Statement of Cash Flow Data:

    

Net cash provided by (used in):

    

Operating activities

   $ 6,543      $ 4,845   

Investing activities

     (6,878     (4,083

Financing activities

     (28     —     

Other Financial Data:

    

Adjusted EBITDA(1)

   $ 14,788      $ 13,928   

Balance Sheet Data (at period end):

    

Cash and cash equivalents

   $ 399      $ 762   

Total assets

     447,253        453,023   

Total liabilities

     440,412        450,035   

Members’ equity

     6,841        2,988   

 

(1) For more information, please read “—Non-GAAP Financial Measure” below.

 

 

 

14


Table of Contents

Non-GAAP Financial Measure

Adjusted EBITDA

Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies.

We define Adjusted EBITDA as net income (loss) before income taxes, gain/loss on derivative instruments, interest expense, depreciation, depletion and amortization, impairment of oil and gas properties, non-cash equity based compensation and asset retirement obligation accretion expense. Adjusted EBITDA is not a measure of net income (loss) as determined by United States’ generally accepted accounting principles (“GAAP”). We believe Adjusted EBITDA is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.

The following table presents a reconciliation of Adjusted EBITDA to the most directly comparable GAAP financial measure for the periods indicated.

 

     Viper Energy Partners  LP
Predecessor Historical
 
     Three Months Ended
March 31,
2014
     Period From Inception
(September 18, 2013)
Through
December 31, 2013
 
     (unaudited)         
     (in thousands)  

Net income

   $         3,853       $         2,988   

Interest expense—related party, net of capitalized interest

     5,368         5,741   

Depletion

     5,567         5,199   
  

 

 

    

 

 

 

Adjusted EBITDA

   $ 14,788       $ 13,928   
  

 

 

    

 

 

 

 

 

15


Table of Contents

Summary Reserve Data

The following table sets forth estimates of our net proved oil and natural gas reserves as of December 31, 2013 based on a reserve report prepared by Ryder Scott. The reserve report was prepared in accordance with the rules and regulations of the SEC. You should refer to “Risk Factors,” “Business—Oil and Natural Gas Data—Proved Reserves,” “Business—Oil and Natural Gas Production Prices and Production Costs—Production and Price History,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our audited financial statements and notes thereto included herein in evaluating the material presented below.

 

    

As of

December 31,

 
     2013  

Estimated proved developed reserves:

  

Oil (Bbls)

     3,692,207   

Natural gas (Mcf)

     6,280,409   

Natural gas liquids (Bbls)

     609,303   

Total (BOE)

     5,348,245   

Estimated proved undeveloped reserves:

  

Oil (Bbls)

     3,525,873   

Natural gas (Mcf)

     4,981,176   

Natural gas liquids (Bbls)

     565,820   

Total (BOE)

     4,921,889   

Estimated Net Proved Reserves:

  

Oil (Bbls)

     7,218,080   

Natural gas (Mcf)

     11,261,585   

Natural gas liquids (Bbls)

     1,175,123   

Total (BOE)(1)

     10,270,135   

Percent proved developed

     52.1

 

(1) Estimates of reserves as of December 31, 2013 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the year ended December 31, 2013, in accordance with revised SEC guidelines applicable to reserve estimates as of the end of such periods. The unweighted arithmetic average first day of the month prices were $92.64 per Bbl for oil, $38.45 per Bbl for NGLs and $5.03 per Mcf for natural gas at December 31, 2013. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

 

 

16


Table of Contents

RISK FACTORS

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

If any of the following risks were to occur, our business, financial condition, results of operations and cash available for distribution could be materially adversely affected. In that case, we might not be able to make 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 may not have sufficient available cash to pay any quarterly distribution on our common units.

We may not have sufficient available 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. Our expected aggregate annual distribution amount for the twelve months ending June 30, 2015 is based on the price assumptions set forth in “Cash Distribution Policy and Restrictions on Distributions—Assumptions and Considerations.” If our price assumptions prove to be inaccurate, our actual distributions for the twelve months ending June 30, 2015 may be significantly lower than our forecasted distributions, or we may not be able to pay a distribution at all. The amount of cash we have to distribute each quarter principally depends upon the amount of royalty revenues we generate, which are dependent upon the prices that our operators realize from the sale of oil and natural gas. In addition, the actual amount of cash we will have to distribute each quarter under the cash distribution policy that the board of directors of our general partner will adopt will be reduced by replacement capital expenditures, payments in respect of debt service and other contractual obligations and fixed charges and increases in reserves for future operating or capital needs that the board of directors may determine is appropriate.

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

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

The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods in which we record net losses for financial accounting purposes and may be unable to make cash distributions during periods in which we record net income.

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

Viper Energy Partners LP was formed in February 2014. Our predecessor acquired the mineral interests to be contributed to us upon the consummation of this initial public offering in September 2013. Moreover, we do not have historical financial statements with respect to the mineral interests for periods prior to their acquisition by Diamondback in September 2013. As a result, there is only limited historical financial and operating information available upon which to base your evaluation of our performance.

The amount of our quarterly cash distributions, if any, may vary significantly both quarterly and annually and will be directly dependent on the performance of our business. We will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time and could make no distribution with respect to any particular quarter.

Investors who are looking for an investment that will pay regular and predictable quarterly distributions should not invest in our common units. Our future business performance may be volatile, and our cash

 

17


Table of Contents

flows may be unstable. Please read “—The volatility of oil and natural gas prices due to factors beyond our control greatly affects our financial condition, results of operations and cash available for distribution.” We will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time. Because our quarterly distributions will significantly correlate to the cash we generate each quarter after payment of our fixed and variable expenses, future quarterly distributions paid to our unitholders will vary significantly from quarter to quarter and may be zero.

The board of directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion, including in such a manner that would result in an elimination of cash distributions regardless of the amount of available cash we generate. Our partnership agreement does not require us to make any distributions at all.

The board of directors of our general partner will adopt a cash distribution policy pursuant to which we will distribute all of the available cash we generate each quarter to unitholders of record on a pro rata basis. However, the board may change such policy at any time at its discretion and could elect not to make distributions for one or more quarters regardless of the amount of available cash we generate. Our partnership agreement does not require us to make any distributions at all. Accordingly, investors are cautioned not to place undue reliance on the permanence of such a policy in making an investment decision. Any modification or revocation of our cash distribution policy could substantially reduce or eliminate the amounts of distributions to our unitholders.

The assumptions underlying the forecast of cash available for distribution that we include in “Cash Distribution Policy and Restrictions on Distributions” may prove inaccurate and are subject to significant risks and uncertainties, which could cause actual results to differ materially from our forecasted results.

The forecast of cash available for distribution set forth in “Cash Distribution Policy and Restrictions on Distributions” includes our forecast of our results of operations, Adjusted EBITDA and cash available for distribution for the twelve months ending June 30, 2015. The assumptions underlying the forecast may prove inaccurate and are subject to significant risks and uncertainties that could cause actual results to differ materially from our forecasted results. If our actual results are significantly below forecasted results, or if our expenses are greater than forecasted, we may not be able to pay the forecasted annual distribution, which may cause the market price of our common units to decline materially.

The volatility of oil and natural gas prices due to factors beyond our control greatly affects our financial condition, results of operations and cash available for distribution.

Our revenues, operating results, cash available for distribution and the carrying value of our oil and natural gas properties depend significantly upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including:

 

   

the domestic and foreign supply of oil and natural gas;

 

   

the level of prices and expectations about future prices of oil and natural gas;

 

   

the level of global oil and natural gas exploration and production;

 

   

the cost of exploring for, developing, producing and delivering oil and natural gas;

 

   

the price and quantity of foreign imports;

 

   

political and economic conditions in oil producing countries, including the Middle East, Africa, South America and Russia;

 

   

the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

 

18


Table of Contents
   

speculative trading in crude oil and natural gas derivative contracts;

 

   

the level of consumer product demand;

 

   

weather conditions and other natural disasters;

 

   

risks associated with operating drilling rigs;

 

   

technological advances affecting energy consumption;

 

   

domestic and foreign governmental regulations and taxes;

 

   

the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East;

 

   

the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation facilities;

 

   

the price and availability of alternative fuels; and

 

   

overall domestic and global economic conditions.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. For example, during the past five years, the posted price for West Texas Intermediate light sweet crude oil, which we refer to as West Texas Intermediate or WTI, has ranged from a low of $34.03 per barrel, or Bbl, in February 2009 to a high of $113.39 per Bbl in April 2011. The Henry Hub spot market price of natural gas has ranged from a low of $1.82 per million British thermal units, or MMBtu, in April 2012 to a high of $7.51 per MMBtu in January 2010. During 2013, West Texas Intermediate prices ranged from $86.65 to $110.62 per Bbl and the Henry Hub spot market price of natural gas ranged from $3.08 to $4.52 per MMBtu. On December 31, 2013, the West Texas Intermediate posted price for crude oil was $98.17 per Bbl and the Henry Hub spot market price of natural gas was $4.31 per MMBtu. On March 31, 2014, the West Texas Intermediate posted price for crude oil was $101.57 per Bbl and the Henry Hub spot market price of natural gas was $4.48 per MMBtu. Any substantial decline in the price of oil and natural gas will likely have a material adverse effect on our financial condition, results of operations and cash available for distribution.

In addition, lower oil and natural gas prices may also reduce the amount of oil and natural gas that can be produced economically by our operators. This may result in having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if production estimates change or exploration or development results deteriorate, full cost accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. Our operators could also determine during periods of low commodity prices to shut in or curtail production from wells on our properties. In addition, they could determine during periods of low commodity prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Specifically, they may abandon any well if they reasonably believe that the well can no longer produce oil or natural gas in commercially paying quantities.

We do not enter into hedging arrangements with respect to the oil and natural gas production from our properties, and we will be exposed to the impact of decreases in the price of oil and natural gas.

We have not entered into hedging arrangements to establish, in advance, a price for the sale of the oil and natural gas produced from our properties, and we do not intend to enter into such arrangements in the future. As a result, we may realize the benefit of any short-term increase in the price of oil and natural gas, but we will not be protected against decreases in price, and if the price of oil and natural gas decreases significantly, our business, results of operation and cash available for distribution may be materially adversely affected.

 

19


Table of Contents

We depend on two operators for substantially all of the development and production on the properties underlying our mineral interests. Substantially all of our revenue is derived from royalty payments made by these operators. A reduction in the expected number of wells to be drilled on our acreage by these operators or the failure of either operator to adequately and efficiently develop and operate our acreage could have an adverse effect on our expected growth and our results of operations.

Our sole assets at the closing of this offering will be mineral interests from which we derive royalty income. For the three months ended March 31, 2014, we received approximately 78% and 20% of our royalty revenue from Diamondback and RSP Permian, respectively. The failure of Diamondback or RSP Permian to adequately or efficiently perform operations or an operator’s failure to act in ways that are in our best interests could reduce production and revenues. Further, none of the operators of our properties are obligated to undertake any development activities, so any development and production activities will be subject to their reasonable discretion. Either or both of Diamondback and RSP Permian could determine to drill and complete fewer wells on our acreage than is currently expected. The success and timing of drilling and development activities on our properties, and whether the operators elect to drill any additional wells on our acreage, depends on a number of factors that will be largely outside of our control, including:

 

   

the timing and amount of capital expenditures by our operators, which could be significantly more than anticipated;

 

   

the ability of our operators to access capital;

 

   

the availability of suitable drilling equipment, production and transportation infrastructure and qualified operating personnel;

 

   

the operators’ expertise, operating efficiency and financial resources;

 

   

approval of other participants in drilling wells;

 

   

the operators’ expected return on investment in wells drilled on our acreage as compared to opportunities in other areas;

 

   

the selection of technology;

 

   

the selection of counterparties for the sale of production; and

 

   

the rate of production of the reserves.

The operators may elect not to undertake development activities, or may undertake such activities in an unanticipated fashion, which may result in significant fluctuations in our royalty revenues and cash available for distribution to our unitholders. If reductions in production by the operators are implemented on our properties and sustained, our revenues may also be substantially affected. Additionally, if an operator were to experience financial difficulty, the operator might not be able to pay its royalty payments or continue its operations, which could have a material adverse impact on us.

The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.

Approximately 47.9% of our total estimated proved reserves as of December 31, 2013 were proved undeveloped reserves and may not be ultimately developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data included in the reserve report of our independent petroleum engineer assume that substantial capital expenditures are required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves.

 

20


Table of Contents

We may not be able to terminate our leases if any of our operators declare bankruptcy, and we may experience delays and be unable to replace operators that do not make royalty payments.

A failure on the part of the operators to make royalty payments gives us the right to terminate the lease, repossess the property and enforce payment obligations under the lease. If we repossessed any of our properties, we would seek a replacement operator. However, we might not be able to find a replacement operator and, if we did, we might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, the outgoing operator could be subject to bankruptcy proceedings that could prevent the execution of a new lease or the assignment of the existing lease to another operator. In addition, if we enter into a new lease, the replacement operator may not achieve the same levels of production or sell oil or natural gas at the same price as the operator it replaced.

Our producing properties are located in the Permian Basin of West Texas, making us vulnerable to risks associated with operating in a single geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing horizons within this area.

All of our producing properties are geographically concentrated in the Permian Basin of West Texas. As a result of this concentration, we may 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, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services market limitations or interruption of the processing or transportation of crude oil, natural gas or natural gas liquids. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our properties, they could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition, results of operations and cash available for distribution.

In addition to the geographic concentration of our producing properties described above, as of March 31, 2014, all of our proved reserves were attributable to the Wolfberry play. This concentration of assets within a small number of producing horizons exposes us to additional risks, such as changes in field-wide rules and regulations that could cause our operators to permanently or temporarily shut-in all wells within a field.

Our future success depends on finding, developing or acquiring additional reserves.

Our future success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that successful exploration or development activities are conducted on our properties or we acquire properties containing proved reserves, or both. To increase reserves and production, we would need to undertake development, exploration and other replacement activities or use third parties to accomplish these activities. Substantial capital expenditures will be necessary for the development, production, exploration and acquisition of oil and natural gas reserves. Neither we nor our third-party operators may have sufficient resources to acquire additional reserves or to undertake exploration, development, production or other replacement activities, such activities may not result in significant additional reserves and efforts to drill productive wells at low finding and development costs may be unsuccessful. In addition, we do not expect to initially retain cash from our operations for replacement capital expenditures. See “Cash Distribution Policy and Restrictions on Distributions—Capital Expenditures.” Furthermore, although our revenues and cash available for distribution may increase if prevailing oil and natural gas prices increase significantly, finding costs for additional reserves could also increase.

 

21


Table of Contents

Our failure to successfully identify, complete and integrate acquisitions of properties or businesses could slow our growth and adversely affect our results of operations and cash available for distribution.

There is intense competition for acquisition opportunities in our industry. The successful acquisition of producing properties requires an assessment of several factors, including:

 

   

recoverable reserves;

 

   

future oil and natural gas prices and their applicable differentials;

 

   

operating costs; and

 

   

potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain and we may not be able to identify attractive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. Unless our operators further develop our existing properties, we will depend on acquisitions to grow our reserves, production and cash flow.

Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Further, these acquisitions may be in geographic regions in which we do not currently hold properties, which could result in unforeseen operating difficulties. In addition, if we enter into new geographic markets, we may be subject to additional and unfamiliar legal and regulatory requirements. Compliance with regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. Further, the success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions.

No assurance can be given that we will be able to identify suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition, results of operations and cash available for distribution. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our growth, results of operations and cash available for distribution.

Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties that we acquire or obtain protection from sellers against such liabilities.

Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with the assessments, we

 

22


Table of Contents

perform a review of the subject properties, but such a review will not necessarily reveal all existing or potential problems. In the course of our due diligence, we may not inspect every well or pipeline. We cannot necessarily observe structural and environmental problems, such as pipe corrosion, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

Project areas on our properties, which are in various stages of development, may not yield oil or natural gas in commercially viable quantities.

Project areas on our properties are in various stages of development, ranging from project areas with current drilling or production activity to project areas that have limited drilling or production history. During the three months ended March 31, 2014, Diamondback, which is the operator for 50% of the acreage associated with our properties, drilled a total of 17 gross wells and participated in one additional gross non-operated well, of which three wells were completed as producing wells and 15 wells were in various stages of completion. If the wells in the process of being completed do not produce sufficient revenues or if dry holes are drilled, our financial condition, results of operations and cash available for distribution may be materially affected.

Our method of accounting for investments in oil and natural gas properties may result in impairment of asset value.

We account for oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. All general and administrative corporate costs unrelated to drilling activities are expensed as incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs plus estimated future development costs are amortized over total proved reserves. The average depletion rate per barrel equivalent unit of production was $28.49 and $27.53 for the three months ended March 31, 2014 and for the period from inception (September 18, 2013) through December 31, 2013, respectively.

The net capitalized costs of proved oil and natural gas properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment, exceed the discounted future net revenues of proved oil and natural gas reserves, the excess capitalized costs are charged to expense. We use the unweighted arithmetic average first day of the month price for oil and natural gas for the 12-month period preceding the calculation date in estimating discounted future net revenues.

No impairment on proved oil and natural gas properties was recorded for the three months ended March 31, 2014 and for the period from inception (September 18, 2013) through December 31, 2013. We may, however, experience ceiling test write downs in the future. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—Method of Accounting for Oil and Natural Gas Properties.”

Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

Oil and natural gas reserve engineering is not an exact science and requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices,

 

23


Table of Contents

production levels, ultimate recoveries and operating and development costs. As a result, estimated quantities of proved reserves, projections of future production rates and the timing of development expenditures may be incorrect. Our historical estimates of proved reserves and related valuations as of December 31, 2013, were prepared by Ryder Scott, an independent petroleum engineering firm, which conducted a well-by-well review of all our properties for the period covered by its reserve report using information provided by us. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling, testing and production. Also, certain assumptions regarding future oil and natural gas prices, production levels and operating and development costs may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of future net cash flows. A substantial portion of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil and natural gas that are ultimately recovered being different from our reserve estimates.

The estimates of reserves as of December 31, 2013 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the year ended December 31, 2013, in accordance with the revised SEC guidelines applicable to reserve estimates for such period. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for unproved undeveloped acreage.

SEC rules could limit our ability to book additional proved undeveloped reserves in the future.

SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional proved undeveloped reserves as our operators pursue their drilling programs. Moreover, we may be required to write down our proved undeveloped reserves if those wells are not drilled within the required five-year timeframe.

Declining general economic, business or industry conditions may have a material adverse effect on our results of operations, financial condition and cash available for distribution.

Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, the European debt crisis, the United States mortgage market and a weak real estate market in the United States have contributed to increased economic uncertainty and diminished expectations for the global economy. These factors, combined with volatile prices of oil, natural gas and natural gas liquids, declining business and consumer confidence and increased unemployment, have precipitated an economic slowdown and a recession. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the economies of the United States and other countries. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates further, worldwide demand for petroleum products could diminish, which could impact the price at which oil, natural gas and natural gas liquids from our properties are sold, affect the ability of vendors, suppliers and customers associated with our properties to continue operations and ultimately adversely impact our results of operations, financial condition and cash available for distribution.

Conservation measures and technological advances could reduce demand for oil and natural gas.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand

 

24


Table of Contents

for oil and natural gas. The impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash available for distribution.

We rely on a few key individuals whose absence or loss could adversely affect our business.

Many key responsibilities within our business have been assigned to a small number of individuals. The loss of their services could adversely affect our business. In particular, the loss of the services of one or more members of our executive team, including the Chief Executive Officer of our general partner, Travis D. Stice, could disrupt our business. Diamondback has employment agreements with Travis D. Stice and Teresa L. Dick, the Chief Financial Officer of our general partner, which contain restrictions on competition with the business or operations of Diamondback and its subsidiaries until the later of the termination of their employment with or other affiliation with such entities and for a period of six months thereafter. However, as a practical matter, such employment agreements may not assure the retention of Diamondback’s employees. Further, we do not maintain “key person” life insurance policies on any of our executive team or other key personnel. As a result, we are not insured against any losses resulting from the death of these key individuals.

Competition in the oil and natural gas industry is intense, which may adversely affect our ability to succeed.

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

Loss of our information and computer systems could adversely affect our business.

We are dependent on our information systems and computer based programs. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.

Risks Related to Operators and Other Working Interest Owners

The following risks describe risks that may directly affect our business and operations to the extent we elect in the future to engage in the exploration, development and production of oil and natural gas properties. In addition, any operators of our properties, including our current operators, are subject to the risks and uncertainties described below, and, as the owner of mineral interests, we are indirectly exposed to the same risks and uncertainties. For purposes of this section, where applicable, references to “we,” “us” and “our” refer to Viper Energy Partners LP to the extent the partnership were to acquire working interests in the future, as well as to any operators of our properties, including the current operators.

 

25


Table of Contents

If a significant portion of any future net leasehold acreage is undeveloped, and that acreage is not ultimately developed or does not become commercially productive, we could lose rights under these leases, and any such events could have a material adverse effect on our oil and natural gas reserves and future production and, therefore, our financial condition, results of operations and cash available for distribution.

To the extent we acquire working interests in the future, or acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage contains proved reserves, we could lose our rights under those leases if we do not timely develop such acreage. In addition, if we are required under any such oil and natural gas leases to drill wells that are commercially productive and we are unsuccessful in drilling such wells, we could lose our rights under such leases. Our future oil and natural gas reserves and production and, therefore, our financial condition, results of operations and cash available for distribution may be highly dependent on successfully developing our undeveloped leasehold acreage.

Development and exploration operations require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a loss of properties and a decline in our oil and natural gas reserves.

The oil and natural gas industry is capital intensive. To the extent we acquire working interests in the future, we will not be able to assure you that our operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures. Further, our actual capital expenditures could exceed our capital expenditure budget. In the event our capital expenditure requirements at any time are greater than the amount of capital we have available, we could be required to seek additional sources of capital, which may include traditional reserve base borrowings, debt financing, joint venture partnerships, production payment financings, sales of assets, offerings of debt or equity securities or other means. We cannot assure you that we will be able to obtain debt or equity financing on terms favorable to us, or at all.

If we acquire working interests in the future and we are unable to fund our capital requirements, we may be required to curtail operations relating to the exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our oil and natural gas reserves, or we may be otherwise unable to implement our development plan, complete acquisitions or take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, results of operations and cash available for distribution. In addition, a delay in or the failure to complete proposed or future infrastructure projects could delay or eliminate potential efficiencies and related cost savings.

We may incur losses as a result of title defects in the properties in which we invest.

If we acquire working interests in the future, when acquiring oil and natural gas leases, we may not elect to incur the expense of retaining lawyers to examine the title to the mineral interest. Rather, we may rely upon the judgment 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 and can adversely affect our results of operations, financial condition and cash available for distribution.

Prior to the drilling of an oil or natural gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase production and reserves. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in the assignment of leasehold rights in properties in which we hold an interest, our business, results of operations and cash available for distribution may be adversely affected.

 

26


Table of Contents

Identified potential drilling locations are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

To the extent we acquire working interests in the future, our ability to drill and develop identified potential drilling locations will depend on a number of uncertainties, including the availability of capital, construction of infrastructure, inclement weather, regulatory changes and approvals, oil and natural gas prices, costs, drilling results and the availability of water. Further, identified potential drilling locations are typically in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation. We will not be able to predict in advance of drilling and testing whether any particular drilling location will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable or whether wells drilled on 20-acre downspacing will produce at the same rates as those on 40-acre spacing. The use of technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. If we drill wells that we identify as dry holes in current and future drilling locations, our drilling success rate may decline and materially harm our business.

We will not be able to assure you that the analogies drawn from available data from wells drilled, more fully explored locations or producing fields will be applicable to our drilling locations. Further, initial production rates reported by us or other operators in the Permian Basin may not be indicative of future or long-term production rates. Because of these uncertainties, we do not know if the potential drilling locations we identify will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those identified, which could adversely affect our business.

For information on Diamondback’s identified potential drilling locations, please read “Business.”

Acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. In a highly competitive market for acreage, failure to drill sufficient wells to hold acreage may result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities.

Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres. To the extent we acquire working interests in the future, the cost to renew our leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. Any reduction in our drilling program, either through a reduction in capital expenditures or the unavailability of drilling rigs, could result in the loss of acreage through lease expirations. Any such losses of leases could materially and adversely affect the growth of our financial condition, results of operations and cash available for distribution.

The inability of one or more of our customers to meet their obligations may adversely affect our financial condition, results of operations and cash available for distribution.

To the extent we acquire working interests in the future, we may have exposure to credit risk through receivables from joint interest owners on properties we operate and receivables from purchasers of our oil and natural gas production.

Joint interest receivables will arise from billing entities that own partial interests in any wells we operate. These entities will typically participate in our wells primarily based on their ownership in leases on which we wish to drill. We will generally be unable to control which co-owners participate in our wells.

 

27


Table of Contents

We also may be subject to credit risk due to the concentration of oil and natural gas receivables with several significant customers. This concentration of customers may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Current economic circumstances may further increase these risks. Generally, customers are not required to post collateral. The inability or failure of our significant customers or joint working interest owners to meet their obligations to us or their insolvency or liquidation may materially adversely affect our financial condition, results of operations and cash available for distribution.

To the extent we depend upon certain significant purchasers for the sale of most of our oil and natural gas production, the loss of one or more of these purchasers could, among other factors, limit our access to suitable markets for the oil and natural gas we produce and adversely affect our results of operations and cash available for distribution.

To the extent we acquire working interests in the future, the availability of a ready market for any oil and natural gas we produce will depend on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of natural gas pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of natural gas sold in interstate commerce. In addition, to the extent we depend upon certain significant purchasers for the sale of most of our oil and natural gas production, the loss of one or more of such purchasers, or their failure or inability to meet their obligations to us, could adversely affect our results of operations and cash available for distribution. We cannot assure you that we will have ready access to suitable markets for our oil and natural gas production if we acquire working interests in the future.

The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies, oilfield services or personnel may restrict our operations.

The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs, equipment and supplies increase and demand for, and wage rates of, qualified drilling rig crews also rise with increases in demand. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. To the extent we acquire working interests in the future, in accordance with customary industry practice, we will rely on independent third party service providers to provide most of the services necessary to drill new wells. If we are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of operations could suffer, and we may not be able to drill all of our acreage before our leases expire. In addition, we may not have long-term contracts securing the use of our rigs, and the operator of those rigs may choose to cease providing services to us. Shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies, personnel, trucking services, tubulars, fracking and completion services and production equipment could delay or restrict our exploration and development operations, which in turn could adversely affect our financial condition, results of operations and cash available for distribution.

Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash available for distribution.

Water is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing processes. During the last two 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. To the extent we acquire working interests in the future, if we are unable to obtain water to use in our operations from local sources, or we are unable to effectively utilize flowback water, we may be unable to economically drill for or produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash available for distribution.

 

28


Table of Contents

The results of our exploratory drilling in shale plays will be subject to risks associated with drilling and completion techniques and drilling results may not meet our expectations for reserves or production.

To the extent we acquire working interests in the future, our operations will involve utilizing the latest drilling and completion techniques. Risks that we will face while drilling include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore and being able to run tools and other equipment consistently through the horizontal well bore. Risks that we will face while completing wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well bore during completion operations and successfully cleaning out the well bore after completion of the final fracture stimulation stage. In addition, to the extent we engage in horizontal drilling, those activities may adversely affect our ability to successfully drill in identified vertical drilling locations. Furthermore, certain of the new techniques we may adopt, such as infill drilling and multi-well pad drilling, may cause irregularities or interruptions in production due to, in the case of infill drilling, offset wells being shut in and, in the case of multi-well pad drilling, the time required to drill and complete multiple wells before any such wells begin producing. The results of drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas often have limited or no production history and consequently we will be less able to predict future drilling results in these areas.

Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems, and/or declines in natural gas and oil prices, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline.

The marketability of oil and natural gas production is dependent upon transportation and other facilities, certain of which we do not control. If these facilities are unavailable, our operations could be interrupted and our results of operations and cash available for distribution could be adversely affected.

To the extent we acquire working interests in the future, the marketability of our oil and natural gas production will depend in part upon the availability, proximity and capacity of transportation facilities, including gathering systems, trucks and pipelines, owned by third parties. We may not control these third party transportation facilities and our access to them may be limited or denied. Insufficient production from our wells to support the construction of pipeline facilities by our purchasers or a significant disruption in the availability of our or third party transportation facilities or other production facilities could adversely impact our ability to deliver to market or produce our oil and natural gas and thereby cause a significant interruption in our operations. For example, on certain occasions, our operators have experienced high line pressure at their tank batteries with occasional flaring due to the inability of the gas gathering systems to support the increased production of natural gas in the Permian Basin. If we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production related difficulties, we may be required to shut in or curtail production. In addition, the amount of oil and natural gas that can be produced and sold may be subject to curtailment in certain other circumstances outside of our control, such as pipeline interruptions due to maintenance, excessive pressure, ability of downstream processing facilities to accept unprocessed gas, physical damage to the gathering or transportation system or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months, and in many cases, we are provided with limited, if any, notice as to when these circumstances will arise and their duration. Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from our fields, could adversely affect our financial condition, results of operations and cash available for distribution.

 

29


Table of Contents

Our operations will be subject to various governmental laws and regulations which require compliance that can be burdensome and expensive and could expose us to significant liabilities, which could adversely affect our cash available for distribution.

To the extent we acquire working interests in the future, our oil and natural gas operations will be subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of oil and gas. In addition, the production, handling, storage, transportation, remediation, emission and disposal of oil and natural gas, by-products thereof and other substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state and local laws and regulations primarily relating to protection of human health and the environment. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, permit revocations, requirements for additional pollution controls and injunctions limiting or prohibiting some or all of our operations. Moreover, these laws and regulations have continually imposed increasingly strict requirements for water and air pollution control and solid waste management.

Laws and regulations governing exploration and production may also affect production levels. To the extent we acquire working interests in the future, we will be required to comply with federal and state laws and regulations governing conservation matters, including: provisions related to the unitization or pooling of the oil and natural gas properties; the establishment of maximum rates of production from wells; the spacing of wells; the plugging and abandonment of wells; and the removal of related production equipment. Additionally, state and federal regulatory authorities may expand or alter applicable pipeline safety laws and regulations, compliance with which may require increase capital costs on the part of operators and third party downstream natural gas transporters.

If we acquire working interests in the future, we will also be required to comply with laws and regulations prohibiting fraud and market manipulations in energy markets. To the extent the operators of our properties are shippers on interstate pipelines, they must comply with the tariffs of such pipelines and with federal policies related to the use of interstate capacity.

Significant expenditures may be required to comply with the governmental laws and regulations described above. We believe the trend of more expansive and stricter environmental legislation and regulations will continue. Please read “Business—Regulation” for a description of the laws and regulations that affect our operators and that, to the extent we acquire working interests in the future, will affect us. These and other potential regulations could increase our operating costs, reduce our liquidity, delay our operations or otherwise alter the way we conduct our business, any of which could have a material adverse effect on the amount of cash available for distribution to our unitholders.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

To the extent we acquire working interests in the future, we expect to engage in hydraulic fracturing. Moreover, our current operators engage in hydraulic fracturing. Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal Safe Drinking Water Act (“SDWA”) regulates the underground injection of substances through the Underground Injection Control (“UIC”) program. Hydraulic fracturing is generally exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and natural gas commissions. The Environmental Protection Agency (“EPA”), however, has recently taken the position that hydraulic fracturing with fluids containing diesel fuel is

 

30


Table of Contents

subject to regulation under the UIC program, specifically as “Class II” UIC wells. In addition, on May 9, 2014, the EPA issued an Advanced Notice of Proposed Rulemaking seeking comment on the development of regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. Moreover, the EPA announced on October 20, 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such wastewater must meet before being transported to a treatment plant. Hydraulic fracturing stimulation requires the use of a significant volume of water with some resulting “flowback,” as well as “produced water.” If adopted, the new pretreatment rules will require operators to pretreat wastewater before transferring it to a treatment facility that discharges to surface water. As part of these studies, the EPA has requested that certain companies provide them with information concerning the chemicals used in the hydraulic fracturing process. These studies, depending on their results, could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise.

Legislation to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress.

On August 16, 2012, the EPA published final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”), and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule seeks to achieve a 95% reduction in VOCs emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. The EPA intends to issue revised rules that are likely responsive to some of these requests. For example, on September 23, 2013, the EPA published an amendment extending compliance dates for certain storage vessels. At this point, we cannot predict the final regulatory requirements or the cost to comply with such requirements with any certainty. In addition, the U.S. Department of the Interior published a revised proposed rule on May 24, 2013 that would update existing regulation of hydraulic fracturing activities on federal lands, including requirements for disclosure, well bore integrity and handling of flowback water.

There are also certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. These ongoing or proposed studies, depending on their degree of pursuit and whether any meaningful results are obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities. The EPA is currently evaluating the potential impacts of hydraulic fracturing on drinking water resources. The White House Council on Environmental Quality is conducting an administration-wide review of hydraulic fracturing practices. The U.S. Department of Energy has conducted an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic-fracturing completion methods. Additionally, certain members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the SEC to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shale formations by means of hydraulic fracturing, and the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates.

Several states, including Texas, have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of

 

31


Table of Contents

hydraulic fracturing fluids. The Texas Railroad Commission recently adopted rules and regulations requiring that well operators disclose the list of chemical ingredients subject to the requirements of the federal Occupational Safety and Health Act to state regulators and on a public internet website. To the extent we acquire working interests, we expect to use hydraulic fracturing extensively in connection with the development and production of our oil and natural gas properties and any increased federal, state, local, foreign or international regulation of hydraulic fracturing could reduce the volumes of oil and natural gas that we can economically recover, which could materially and adversely affect our revenues and results of operations. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. In the event state, local, or municipal legal restrictions are adopted in areas where we conduct operations, we may incur substantial costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling of wells.

There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations are adopted that significantly restrict hydraulic fracturing, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause operators to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us, to the extent we acquire working interests in the future, or our operators could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.

Our operations may be exposed to significant delays, costs and liabilities as a result of environmental, health and safety requirements applicable to our business activities.

To the extent we acquire working interests in the future, we may incur significant delays, costs and liabilities as a result of federal, state and local environmental, health and safety requirements applicable to our exploration, development and production activities. These laws and regulations may, among other things: (i) require us to obtain a variety of permits or other authorizations governing our air emissions, water discharges, waste disposal or other environmental impacts associated with drilling, producing and other operations; (ii) regulate the sourcing and disposal of water used in the drilling, fracturing and completion processes; (iii) limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas; (iv) require remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; and/or (v) impose substantial liabilities for spills, pollution or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of oil or natural gas production. These laws and regulations are complex, change frequently and have tended to become increasingly stringent over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations. Under certain environmental laws that impose strict as well as joint and several liability, we may be required to remediate contaminated properties operated by us or facilities of third parties that received waste generated by our operations 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

 

32


Table of Contents

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. In addition, the risk of accidental and/or unpermitted spills or releases from our operations could expose us to significant liabilities, penalties and other sanctions under applicable laws. Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, financial condition, results of operations and cash available for distribution could be materially adversely affected.

Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in some of the areas where we operate.

To the extent we acquire working interests in the future, our operations may be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce our reserves.

If we acquire working interests in the future, the adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the oil and natural gas we produce.

In December 2009, the EPA issued an Endangerment Finding that determined that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment because, according to the EPA, emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allowed the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act, including the stationary source rule, also known as the “Tailoring Rule,” which regulates emissions of GHGs from certain large stationary sources of emissions such as power plants or industrial facilities. The EPA adopted the Tailoring Rule in May 2010, and it became effective in January 2011. On October 15, 2013, however, the U.S. Supreme Court announced it will review aspects of the Tailoring Rule in 2014. Additionally, in September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010.

In addition, in August 2012, the EPA established new source performance standards (“NSPS”) for volatile organic compounds and sulfur dioxide and an air toxic standard for oil and natural gas production, transmission, and storage. The rules include the first federal air standards for natural gas wells that are hydraulically fractured, or refractured, as well as requirements for several other sources, such as storage tanks and other equipment, and limits methane emissions from these sources in an effort to reduce GHG emissions.

The EPA has continued to adopt GHG regulations of other industries, such as the September 2013 proposed GHG rule that, if finalized, would set new source performance standards for new coal-fired and natural gas-fired power plants, which could have an adverse effect on our financial condition, results of operation and cash available for distribution to the extent we acquire working interests in the future. The EPA is also considering additional regulation of greenhouse gases as “air pollutants.” As a result of this continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility. In addition, the U.S. Congress has from time to

 

33


Table of Contents

time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. The U.S. Congress has not adopted such legislation at this time, but it may do so in the future, and many states continue to pursue regulations to reduce greenhouse gas emissions. 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. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce.

Restrictions on emissions of methane or carbon dioxide that may be imposed in various states, as well as state and local climate change initiatives, could adversely affect the oil and natural gas industry, and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

In addition, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornados and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations.

Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that may adversely affect our business, financial condition, results of operations and cash available for distribution.

If we acquire working interests in the future, our drilling activities will be subject to many risks. For example, we will not be able to assure you that wells drilled by us will be productive or that we will recover all or any portion of our investment in such wells. Drilling for oil and natural gas often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient oil or natural gas to return a profit at then realized prices after deducting drilling, operating and other costs. The seismic data and other technologies used do not provide conclusive knowledge prior to drilling a well that oil or natural gas is present or that it can be produced economically. The costs of exploration, exploitation and development activities are subject to numerous uncertainties beyond our control, and increases in those costs can adversely affect the economics of a project. Further, our drilling and producing operations may be curtailed, delayed, canceled or otherwise negatively impacted as a result of other factors, including:

 

   

unusual or unexpected geological formations;

 

   

loss of drilling fluid circulation;

 

   

title problems;

 

   

facility or equipment malfunctions;

 

   

unexpected operational events;

 

   

shortages or delivery delays of equipment and services;

 

   

compliance with environmental and other governmental requirements; and

 

   

adverse weather conditions.

Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells

 

34


Table of Contents

and other regulatory penalties. In the event that planned operations, including the drilling of development wells, are delayed or cancelled, or existing wells or development wells have lower than anticipated production due to one or more of the factors above or for any other reason, our financial condition, results of operations and cash available for distribution to our unitholders may be adversely affected.

Operating hazards and uninsured risks may result in substantial losses and could adversely affect our results of operations and cash available for distribution.

To the extent we acquire working interests in the future, our operations will be subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as oil spills, gas leaks and ruptures or discharges of toxic gases. In addition, our operations will be subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. The occurrence of any of these events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties, suspension of operations and repairs required to resume operations.

We would endeavor to contractually allocate potential liabilities and risks between us and the parties that provide us with services and goods, which include pressure pumping and hydraulic fracturing, drilling and cementing services and tubular goods for surface, intermediate and production casing. Under agreements with our vendors, to the extent responsibility for environmental liability is allocated between the parties, (i) our vendors would generally assume all responsibility for control and removal of pollution or contamination which originates above the surface of the land and is directly associated with such vendors’ equipment while in their control and (ii) we would generally assume the responsibility for control and removal of all other pollution or contamination which may occur during our operations, including pre-existing pollution and pollution which may result from fire, blowout, cratering, seepage or any other uncontrolled flow of oil, gas or other substances, as well as the use or disposition of all drilling fluids. In addition, we may agree to indemnify our vendors for loss or destruction of vendor-owned property that occurs in the well hole (except for damage that occurs when a vendor is performing work on a footage, rather than day work, basis) or as a result of the use of equipment, certain corrosive fluids, additives, chemicals or proppants. However, despite this general allocation of risk, we might not succeed in enforcing such contractual allocation, might incur an unforeseen liability falling outside the scope of such allocation or may be required to enter into contractual arrangements with terms that vary from the above allocations of risk. As a result, we may incur substantial losses which could materially and adversely affect our financial condition, results of operation and cash available for distribution.

In accordance with what we believe to be customary industry practice, we would expect to maintain insurance against some, but not all, of our business risks. Our insurance may not be adequate to cover any losses or liabilities we may suffer. Also, insurance may no longer be available to us or, if it is, its availability may be at premium levels that do not justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations or cash available for distribution. In addition, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. We may also be liable for environmental damage caused by previous owners of properties purchased by us, which liabilities may not be covered by insurance.

We may not have coverage if we are unaware of a sudden and accidental pollution event and unable to report the “occurrence” to our insurance company within the time frame required under our insurance policy. We do not have, and do not intend to have, coverage for gradual, long-term pollution events. In addition, these

 

35


Table of Contents

policies do not provide coverage for all liabilities, and we cannot assure you that the insurance coverage will be adequate to cover claims that may arise, or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash available for distribution.

If we acquire working interests in the future, we may operate in areas of high industry activity, which may make it difficult to hire, train or retain qualified personnel needed to manage and operate our assets.

If we acquire working interests in the future, our operations and drilling activity will likely be concentrated in the Permian Basin, an area in which industry activity has increased rapidly. As a result, demand for qualified personnel in this area, and the cost to attract and retain such personnel, has increased over the past few years due to competition and may increase substantially in the future. Moreover, our competitors may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer.

Any delay or inability to secure the personnel necessary to continue or complete development activities could lead to a reduction in production volumes. Any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on our business, financial condition, results of operations and cash available for distribution.

Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.

To the extent we acquire working interests in the future, we will rely on 2-D and 3-D seismic data. Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical.

We may not be able to keep pace with technological developments in our industry.

The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. To the extent we acquire working interests in the future, as others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and that may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use were to become obsolete, our business, financial condition, results of operations and cash available for distribution could be materially and adversely affected.

Increased costs of capital could adversely affect our business.

Our business and operating results could be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in our credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

 

36


Table of Contents

A terrorist attack or armed conflict could harm our business.

Terrorist activities, 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 oil and natural gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Oil and natural gas related facilities could be direct targets of terrorist attacks, and, to the extent we acquire working interests in the future, our operations could be adversely impacted if infrastructure integral to our customers’ 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.

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 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 beneficial to Diamondback. Therefore, conflicts of interest may arise between Diamondback or any of its affiliates, including our general partner, on the one hand, and us or any of our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our 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 80% of the common units.

 

37


Table of Contents
   

Our general partner controls the enforcement of obligations that it and its affiliates owe to us.

 

   

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

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

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 pay any distributions at all.

In connection with the closing of this offering, the board of directors of our general partner will adopt a cash distribution policy pursuant to which we will distribute an amount equal to the available cash we generate each quarter to our unitholders. However, the board of directors of our general partner may change such policy at any time at its discretion and could elect not to pay distributions for one or more quarters. Please read “Cash Distribution Policy and Restrictions on Distributions.”

In addition, our partnership agreement does not require us to pay any distributions at all. Accordingly, investors are cautioned not to place undue reliance on the permanence of such a policy in making an investment decision. Any modification or revocation of our cash distribution policy could substantially reduce or eliminate the amounts of distributions to our 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 unitholders, which may permit it to favor its own interests or the interests of Diamondback to the detriment of our common unitholders.

The board of directors of our general partner will adopt a policy to distribute an amount equal to the available cash we generate each quarter, which could limit our ability to grow and make acquisitions.

As a result of our cash distribution policy, we will have limited cash available to reinvest in our business or to fund acquisitions, and we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and growth capital expenditures. As such, to the extent we are unable to finance growth externally, our distribution policy will significantly impair our ability to grow.

To the extent we issue additional units in connection with any acquisitions or growth capital expenditures or as in-kind distributions, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, would reduce the available cash that we have to distribute to our unitholders. Please read “Cash Distribution Policy and Restrictions on Distributions.”

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

Neither we nor our general partner have any employees and we will rely solely on Diamondback to operate our assets and perform other management, administrative and operating services for us and our general partner. Diamondback will provide similar activities with respect to its own assets and operations. Because Diamondback will be providing services to us that are similar to those performed for itself, Diamondback may not have sufficient human, technical and other resources to provide those services at a level that Diamondback would be

 

38


Table of Contents

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 unitholders may be reduced.

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

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

 

   

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—Fiduciary Duties.”

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

Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:

 

   

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:

 

  (1) 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

 

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

 

39


Table of Contents

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

Diamondback and other affiliates of our general partner, including Wexford, 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 and Wexford, are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. In addition, Diamondback or Wexford may compete with us for investment opportunities and may own an interest in entities that compete with us. Further, Diamondback and its affiliates, including Wexford, may acquire, develop or dispose of additional oil and natural gas 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 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, Diamondback and Wexford. 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 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, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will 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 unitholders. Please read “Management—Management of Viper Energy Partners LP” and “Certain Relationships and Related Party Transactions.” Unlike publicly traded corporations, we will not conduct annual meetings of our 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 the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

 

40


Table of Contents

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

If our unitholders are dissatisfied with the performance of our general partner, they will have limited ability to remove our general partner. Unitholders initially 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 common units is required to remove our general partner. Following the closing of this offering, Diamondback will own 93% of our common units (or 92% of our common units, if the underwriters exercise their option to purchase additional common units in full).

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common 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 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 due to our general partner and its affiliates for services provided to us or on our behalf will reduce cash available for distribution to our unitholders. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. The amount and timing of such reimbursements will be determined by our general partner.

Prior to making any distribution on the common units, we will reimburse our general partner and its affiliates for all expenses they incur and payments they make on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of cash available for distribution to our unitholders. Please read “Cash Distribution Policy and Restrictions on Distributions.”

At the closing of this offering, we and our general partner will also enter into an advisory services agreement with Wexford pursuant to which Wexford will provide general finance and advisory services in exchange for a fee and certain expense reimbursement. This fee will reduce the amount of cash available for distribution to our unitholders. In addition, 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 Affiliates in Connection with the Transactions.”

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

Our general partner may transfer its general partner interest to a third party without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the owner of our general partner to transfer its membership interests in our general partner to a third party. After any such transfer, the new member or members of our general partner would then be in a position to replace the board of directors and

 

41


Table of Contents

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 executive officers of our general partner. This effectively permits a “change of control” without the vote or consent of the unitholders.

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

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”), we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. 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 “The Partnership Agreement—Limited Liability.”

Unitholders will incur immediate and substantial dilution in net tangible book value per common unit.

The initial public offering price of $26.00 per common unit exceeds our pro forma net tangible book value of $5.78 per common unit. Based on the initial public offering price of $26.00 per common unit, unitholders will incur immediate and substantial dilution of $20.22 per common unit. This dilution results primarily because the assets contributed to us by affiliates of our general partner are recorded at their historical cost in accordance with GAAP, and not their fair value. Please read “Dilution.”

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 the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price equal to the greater of (1) 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 (2) 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 our general partner and its affiliates (including Diamondback) reduce their ownership to below 75% of the outstanding common units, 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 Securities Exchange Act of 1934 (the “Exchange Act”). Upon consummation of this offering, and assuming no exercise of the underwriters’ option to purchase additional common units, Diamondback will own 93% of our common units. For additional information about the limited call right, please read “The Partnership Agreement—Limited Call Right.”

 

42


Table of Contents

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 unitholders in us immediately prior to the issuance will decrease;

 

   

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

 

   

the ratio of our taxable income to distributions may increase;

 

   

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 “The Partnership Agreement—Issuance of Additional Partnership Interests.”

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 this offering, we will have 76,200,000 common units outstanding, including the 5,000,000 common units that we are selling in this offering that may be resold in the public market immediately. All of the common units that are issued to Diamondback will be subject to resale restrictions under a 180-day lock-up agreement with the underwriters. Each of the lock-up agreements with the underwriters may be waived in the discretion of certain of the underwriters. Sales by holders of a substantial number of our common units in the public markets following this offering, 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 registration rights to Diamondback. Under our partnership agreement, our general partner and its affiliates have registration rights relating to the offer and sale of any units that they hold. Please read “Units Eligible for Future Sale.”

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 unitholders could lose all or part of their investment.

Prior to this offering, there has been no public market for the common units. After this offering, there will be only 5,000,000 publicly traded common units. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. Unitholders may not be able to resell their 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 our common units will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that

 

43


Table of Contents

will prevail in the trading market. The market price of our common units may decline below the initial public offering price. The market price of our common units may also be influenced by many factors, some of which are beyond our control, including:

 

   

changes in commodity prices;

 

   

public reaction to our press releases, announcements and filings with the SEC;

 

   

fluctuations in broader securities market prices and volumes, particularly among securities of oil and natural gas companies and securities of publicly traded limited partnerships and limited liability companies;

 

   

changes in market valuations of similar companies;

 

   

departures of key personnel;

 

   

commencement of or involvement in litigation;

 

   

variations in our quarterly results of operations or those of other oil and natural gas companies;

 

   

changes in general economic conditions, financial markets or the oil and natural gas industry;

 

   

announcements by us or our competitors of significant acquisitions or other transactions;

 

   

variations in the amount of our quarterly cash distributions to our unitholders;

 

   

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

 

   

the failure of securities analysts to cover our common units after this offering or changes in their recommendations and estimates of our financial performance;

 

   

future sales of our common units; and

 

   

the other factors described in these “Risk Factors.”

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 and the Dodd-Frank Act of 2010, as well as rules implemented by the SEC and NASDAQ, require, or will require, publicly traded entities to adopt various corporate governance practices that will further increase our costs. Before we are able to make distributions to our unitholders, we must first pay our expenses, including the costs of being a publicly traded partnership and other operating expenses. As a result, the amount of cash we have available for distribution to our unitholders will be affected by our expenses, including the costs associated with being a publicly traded partnership.

Following this offering, we will become subject to the public reporting requirements of the Exchange Act. We expect these requirements will increase certain of our legal and financial compliance costs and make compliance 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 and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal control over financial reporting.

We estimate that we will incur approximately $2.5 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.

 

44


Table of Contents

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, (1) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act of 2002, (2) comply with any new requirements adopted by the PCAOB 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, (3) comply with any new audit rules adopted by the PCAOB after April 5, 2012 unless the SEC determines otherwise or (4) provide certain disclosure regarding executive compensation required of larger public companies.

If we fail to 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 unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our 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. We must comply with Section 404 (except for the requirement for an auditor’s attestation report) beginning with our fiscal year ending December 31, 2015. 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 partnership like us to comply with certain of its corporate governance requirements.

We have been approved to list our common units on the NASDAQ Global Select Market. Because we will be a publicly traded 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. Accordingly, unitholders will not have the same protections afforded to stockholders of certain corporations that are subject to all of NASDAQ’s corporate governance requirements. Please read “Management.”

 

45


Table of Contents

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 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. Please read “The Partnership Agreement—Applicable Law; Forum, Venue and Jurisdiction.” 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. If a dispute were to arise between a limited partner and us or our officers, directors or employees, the limited partner may be required to pursue its legal remedies in Delaware which may be an inconvenient or distant location and which is considered to be a more corporate-friendly environment.

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 U.S. federal income tax status and/or 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 tax status has or is reasonably likely to have a material adverse effect on the maximum applicable rates chargeable to our customers, (ii) whose nationality, citizenship or related status creates substantial risk of cancellation or forfeiture of any of our property and/or (iii) 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 “The Partnership Agreement—Non-Taxpaying Holders; Redemption” and “The Partnership Agreement—Non-Citizen Assignees; Redemption.”

Tax Risks to Common Unitholders

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

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service were to treat us as a corporation for federal income tax purposes or we were to become subject to entity-level taxation for state tax purposes, then our cash available for distribution to you could be substantially reduced.

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

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

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%. Distributions to you would

 

46


Table of Contents

generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. In addition, changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution to you. Therefore, treatment of us as a corporation or the assessment of a material amount of entity-level taxation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

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

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

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

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

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

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

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

If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our

 

47


Table of Contents

net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis in those units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation and depletion recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if you sell your common units, you may incur a tax liability in excess of the amount of cash you receive from the sale. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Units—Recognition of Gain or Loss” for a further discussion of the foregoing.

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

Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, a portion of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, may be unrelated business taxable income and may be taxable to them. Distributions to non-U.S. persons will be subject to withholding taxes imposed at the highest effective tax rate applicable to such non-U.S. persons, and each non-U.S. person may be required to file United States federal tax returns and pay tax on their share of our taxable income if it is treated as effectively connected income. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units. Please read “Material U.S. Federal Income Tax Consequences—Tax Exempt Organizations and Other Investors.”

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

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

We will prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We will prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. The U.S. Treasury Department has issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly-traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Units—Allocations Between Transferors and Transferees.”

 

48


Table of Contents

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

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

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

We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Immediately following this offering, affiliates of Diamondback will directly and indirectly own more than 93% of the total interests in our capital and profits. Therefore, a transfer by affiliates of Diamondback of all or a portion of their interests in us could result in a termination of our partnership for federal income tax purposes. Our termination would, among other things, result in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than the calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, after our termination we would be treated as a new partnership for federal income tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Units—Constructive Termination” for a discussion of the consequences of our termination for federal income tax purposes.

You may be subject to state and local taxes and return filing requirements in states where you do not live as a result of investing in our common units.

In addition to federal income taxes, you may be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if you do not live in any of those jurisdictions. We will initially own assets and conduct business in Texas, which currently imposes income taxes on corporations and other entities but does not impose a personal income tax. As we make acquisitions or expand our business, we may own assets or conduct business in additional states or foreign jurisdictions that impose a personal income tax. You may be required to file state and local income tax returns and pay state and local income taxes in these jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. It is your responsibility to file all U.S. federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the foreign, state or local tax consequences of an investment in our common units.

 

49


Table of Contents

USE OF PROCEEDS

We intend to use the estimated net proceeds of approximately $119.4 million from this offering, after deducting the estimated underwriting discount and structuring fee and offering expenses payable by us, to make a distribution to Diamondback. Affiliates of certain of the underwriters are lenders under Diamondback’s revolving credit facility. Diamondback may, but is not required to, apply the distribution that it receives from us to repay amounts outstanding under its revolving credit facility. Accordingly, affiliates of certain of the underwriters may indirectly receive a portion of the proceeds from this offering in the form of repayment of debt by Diamondback.

The net proceeds from any exercise of the underwriters’ option to purchase additional common units (approximately $18.1 million after deducting the estimated underwriting discount and structuring fee, if exercised in full) will be used to make a distribution to Diamondback. If the underwriters do not exercise their option to purchase additional common units in full, we will issue the remaining additional common units to Diamondback at the expiration of the option period for no additional consideration. If and to the extent the underwriters exercise their option to purchase additional common units, the number of units purchased by the underwriters pursuant to such exercise will be issued to the public and the remainder, if any, will be issued to Diamondback. Accordingly, the exercise of the underwriters’ option will not affect the total number of units outstanding. Please read “Underwriting.”

 

50


Table of Contents

CAPITALIZATION

The following table shows our cash and cash equivalents and capitalization as of March 31, 2014:

 

   

on an actual basis for our predecessor; and

 

   

on a pro forma basis to reflect the offering and the other formation transactions described under “Summary—Formation Transactions and Structure” and the application of the net proceeds from this offering as described under “Use of Proceeds.”

This table is derived from, and should be read together with, the audited historical financial statements and accompanying notes and the unaudited historical financial statements and accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Summary—Formation Transactions and Structure,” “Use of Proceeds” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

     As of March 31, 2014  
     Actual      Pro Forma  
     (in thousands)  

Cash and cash equivalents(1)

   $ 399       $ —     

Royalty income receivable(1)

   $ 6,631       $ —     
  

 

 

    

 

 

 

Long-term debt(2)

   $ 440,000         —     
  

 

 

    

 

 

 

Members’ equity/Partners’ capital:

     

Members’ equity

   $ 6,841       $ —     

Common unitholders:

     

Public

     —           119,351   

Sponsor(1)

     —           320,460   
  

 

 

    

 

 

 

Total members’ equity/partners’ capital

   $ 6,841       $ 439,811   
  

 

 

    

 

 

 

Total capitalization

   $ 446,841       $ 439,811   
  

 

 

    

 

 

 

 

(1) Prior to the closing of this offering, our predecessor will distribute all cash and cash equivalents and the royalty income receivable on hand to Diamondback.
(2) Effective September 19, 2013, our predecessor issued a subordinated note to Diamondback for the principal sum of $440 million. In connection with the closing of this offering, Diamondback will contribute all of the equity interests in Viper Energy Partners LLC to us. Upon such contribution, the subordinated note held by Diamondback will be converted to equity.

 

51


Table of Contents

DILUTION

Purchasers of common units offered by this prospectus will suffer immediate and substantial dilution in net tangible book value per unit. Dilution in net tangible book value per unit represents the difference between the amount per unit paid by purchasers of our common units in this offering and the pro forma net tangible book value per unit immediately after this offering. After giving effect to the sale of 5,000,000 common units in this offering at an initial public offering price of $26.00 per common unit, and after deduction of the estimated underwriting discount and structuring fee and estimated offering expenses payable by us, our pro forma net tangible book value as of March 31, 2014 would have been approximately $440 million, or $6.18 per unit. This represents an immediate decrease in net tangible book value of $0.40 per unit to our existing unitholders and an immediate pro forma dilution of $5.78 per unit to purchasers of common units in this offering. The following table illustrates this dilution on a per unit basis:

 

Initial public offering price per common unit

     $ 26.00   

Pro forma net tangible book value per common unit before the offering(1)

   $ 6.18     

Decrease in net tangible book value per common unit attributable to purchasers in the offering

     (0.40  
  

 

 

   

 

 

 

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

       5.78   
    

 

 

 

Immediate dilution in net tangible book value per common unit to purchasers in the offering

     $ 20.22   
    

 

 

 

 

(1) Determined by dividing the pro forma net tangible book value of the contributed assets and liabilities by the number of common units to be issued to Diamondback for its contribution of assets and liabilities to us.
(2) Determined by dividing our pro forma net tangible book value, after giving effect to the use of the net proceeds of the offering, by the total number of common units outstanding after this offering.

The following table sets forth the number of units that we will issue and the total consideration contributed to us by Diamondback and by the purchasers of our common units in this offering upon consummation of the transactions contemplated by this prospectus ($ in thousands).

 

     Units     Total Consideration  
      Number      Percent     Amount     Percent  

Diamondback(1)

     71,200,000         93   $ 440,000        78.7

New investors

     5,000,000         7     119,351 (2)      21.3
  

 

 

    

 

 

   

 

 

   

 

 

 

Total

     76,200,000         100   $ 559,351        100
  

 

 

    

 

 

   

 

 

   

 

 

 

 

(1) Reflects the value of the assets to be contributed to us by Diamondback recorded at historical cost.
(2) Reflects the net proceeds of this offering after deducting the underwriting discount and structuring fee and estimated offering expenses payable by us.

 

52


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 Cash Available for Distribution for the Twelve Months Ending June 30, 2015—Assumptions and Considerations” below. In addition, you should read “Forward-Looking Statements” and “Risk Factors” for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.

For additional information regarding our historical results of operations, you should refer to Viper Energy Partners LP Predecessor’s audited historical financial statements as of December 31, 2013 and for the period from inception (September 18, 2013) to December 31, 2013 and unaudited historical financial statements as of and for the three months ended March 31, 2014 included elsewhere in this prospectus.

General

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 distribute all of the available cash we generate each quarter, beginning with the quarter ending September 30, 2014. Our first distribution, however, will include available cash for the period from the closing of this offering through September 30, 2014. Available cash for each quarter will be determined by the board of directors of our general partner following the end of such quarter. We expect that available cash for each quarter will generally equal our Adjusted EBITDA for the quarter, less cash needed for debt service and other contractual obligations and fixed charges and reserves for future operating or capital needs that the board of directors may determine is appropriate. We do not intend to maintain excess distribution coverage for the purpose of maintaining stability or growth in our quarterly distribution or otherwise to reserve cash for distributions, nor do we intend to incur debt to pay quarterly distributions. Further, it is our intent, subject to market conditions, to finance growth capital externally. The board of directors of our general partner may change the foregoing distribution policy at any time and from time to time. Our partnership agreement does not require us to pay cash distributions 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 pay any distributions at all.”

Unlike a number of other master limited partnerships, we do not expect to initially retain cash from our operations for replacement capital expenditures primarily due to our expectation that existing development and the discovery of new pay horizons will lead to inclining production and revenues for at least the next several years. Replacement capital expenditures are those expenditures necessary to replace our existing oil and gas reserves or otherwise maintain our asset base over the long term. We expect to seek additional acquisitions of reserves and may restrict distributions to acquire or fund such acquisitions in whole or in part. If we do not retain cash for replacement capital expenditures in amounts necessary to maintain our asset base, eventually our cash available for distribution will decrease. The board of directors of our general partner may in the future decide to withhold replacement capital expenditures from cash available for distribution which may have an adverse impact on the cash available for distribution in the quarter(s) in which any such amounts are withheld. To the extent that we do not withhold replacement capital expenditures in the future, a portion of our future cash available for distribution will represent a return of your capital.

Because our policy will be to distribute all available cash we generate each quarter, without reserving cash for future distributions or borrowing to pay distributions during periods of low revenue, our unitholders will have direct exposure to fluctuations in the amount of cash generated by our business. Our quarterly cash distributions, if any, will not be stable and will vary from quarter to quarter as a direct result of variations in the performance of our operators and revenue caused by fluctuations in the prices of oil and natural gas. Such variations may be significant.

 

53


Table of Contents

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

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

 

   

Our unitholders have no contractual or other legal right to receive cash distributions from us on a quarterly or other basis. The board of directors of our general partner will adopt a policy pursuant to which we will distribute to our unitholders each quarter all of the available cash we generate each quarter, as determined quarterly by the board of directors, but it 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, subsequent to the closing of this offering, we expect to enter into a revolving credit facility to be used for general partnership purposes. We anticipate that any future debt agreements will contain certain financial tests and covenants that we would have to satisfy. 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 flows may be less stable, than the business performance and cash flows of most publicly traded partnerships. As a result, our quarterly cash distributions may be volatile and may vary quarterly and annually.

 

   

We will not have a minimum quarterly distribution or employ structures intended to maintain or increase quarterly distributions over time. Furthermore, none of our limited partner interests, including those held by Diamondback, will be subordinate in right of distribution payment to the common units sold in this offering.

 

   

Our general partner will have the authority to establish cash reserves for the prudent conduct of our business, and the establishment of, or increase in, those reserves could result in a reduction in cash distributions to our unitholders. Our partnership agreement does not set a limit on the amount of cash reserves that our general partner may establish. Any decision to establish cash reserves made by our general partner will be binding on our unitholders.

 

   

Prior to making any distributions on our units, we will reimburse our general partner and its affiliates for all direct and indirect expenses they incur on our behalf. Our partnership 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 to pay distributions to our unitholders.

 

   

Under Section 17-607 of the Delaware Act, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets.

 

   

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

We expect to generally distribute a significant percentage of our cash from operations to our unitholders on a quarterly basis, after, among other things, the establishment of cash reserves and payment of our expenses. To fund growth, we will eventually need capital in excess of the amounts we may retain in our business, but we expect that our growth will depend at least initially on our operators’ ability to access external expansion capital. As a result, our growth will depend initially on our operators’ ability, and perhaps our ability in the future, to raise debt and equity capital from third parties in sufficient amounts and on favorable terms when needed. To the extent efforts to access capital externally are unsuccessful, our ability to grow will be significantly impaired.

We expect to pay our distributions within 60 days of the end of each quarter. Our first distribution will include available cash for the period from the closing of this offering through September 30, 2014.

 

54


Table of Contents

Estimated Cash Available for Distribution for the Twelve Months Ending June 30, 2015

During the twelve months ending June 30, 2015, we estimate that we will generate $83.8 million of available cash. In “—Assumptions and Considerations” below, we discuss the major assumptions underlying this estimate. The available cash discussed in the forecast should not be viewed as management’s projection of the actual available cash that we will generate during the twelve months ending June 30, 2015. We can give you no assurance that our assumptions will be realized or that we will generate any available cash, in which event we will not be able to pay quarterly cash distributions on our common units.

When considering our ability to generate available cash and how we calculate forecasted available cash, please keep in mind all the risk factors and other cautionary statements under the headings “Risk Factors” and “Forward-Looking Statements,” which discuss factors that could cause our results of operations and available cash to vary significantly from our estimates.

Management has prepared the prospective financial information set forth in the table below to present our expectations regarding our ability to generate $83.8 million of available cash for the twelve months ending June 30, 2015. The accompanying prospective financial information was not prepared with a view toward public disclosure or complying with the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the expected course of action and 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 this prospective financial information.

The assumptions and estimates underlying the prospective financial information are inherently uncertain and, though considered reasonable by the management team of our general partner as of the date of its preparation, 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 prospective financial information. Accordingly, there can be no assurance that the prospective results are indicative of our future performance or that actual results will not differ materially from those presented in the prospective financial information. Inclusion of the prospective financial information in this prospectus should not be regarded as a representation by any person that the results contained in the prospective financial information will be achieved.

We do not undertake any obligation to release publicly the results of any future revisions we may make to the financial forecast or to update this financial forecast to reflect events or circumstances after the date of this prospectus. In light of the above, the statement that we believe that we will have sufficient available cash to allow us to pay the forecasted quarterly distributions on all of our outstanding common units for the twelve months ending June 30, 2015 should not be regarded as a representation by us or the underwriters or any other person that we will make such distributions. Therefore, you are cautioned not to place undue reliance on this information.

The following table shows how we calculate estimated available cash for the twelve months ending June 30, 2015. The assumptions that we believe are relevant to particular line items in the table below are explained in the corresponding footnotes and in “—Assumptions and Considerations.”

Neither our independent registered public accounting firm nor any other independent registered public accounting firm has compiled, examined or performed any procedures with respect to the forecasted financial information contained herein, nor has it expressed any opinion or given any other form of assurance on such information or its achievability, and it assumes no responsibility for such forecasted financial information. Our independent registered public accounting firm’s reports included elsewhere in this prospectus relate to our audited historical financial statements. These reports do not extend to the table and the related forecasted information contained in this section and should not be read to do so.

 

55


Table of Contents

The following table illustrates the amount of cash that we estimate that we will generate for the twelve months ending June 30, 2015 and for each quarter during that twelve-month period that would be available for distribution to our unitholders. All of the amounts for the twelve months ending June 30, 2015 in the table below are estimates.

 

    Three Months
Ending
September 30,
2014
    Three Months
Ending
December 31,
2014
    Three Months
Ending
March 31,

2015
    Three Months
Ending
June 30,

2015
    Twelve Months
Ending
June  30,

2015
 
    (in thousands, except per unit data) (unaudited)  

Royalty income

  $ 19,240      $ 22,666      $ 25,079      $ 26,826      $ 93,811   

Forecasted realized prices:

         

Oil price per Bbl

          $ 94.21   

Natural gas price per MMBtu

          $ 4.37   

Natural gas liquids price per Bbl

          $ 35.02   

Expenditures:

         

Production and ad valorem taxes

    (1,443     (1,700     (1,881     (2,012     (7,036

Depletion

    (6,457     (7,563     (8,349     (8,927     (31,296

General and administrative expenses

    (750     (750     (750     (750     (3,000
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income

  $ 10,590      $ 12,653      $ 14,099      $ 15,137      $ 52,479   

Adjustments to reconcile net income to Adjusted EBITDA:

         

Add:

         

Depletion

  $ 6,457      $ 7,563      $ 8,349      $ 8,927      $ 31,296   

Interest expense

    —          —          —          —          —     
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA(1)

    17,047        20,216        22,448        24,064        83,775   

Less:

         

Cash interest expense

    —          —          —          —          —     

Maintenance capital expenditures

    —          —          —          —          —     
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Estimated cash available for distribution

  $ 17,047      $ 20,216      $ 22,448      $ 24,064      $ 83,775   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Estimated cash distributions:

         

Distribution per unit

  $ 0.2237      $ 0.2653      $ 0.2946      $ 0.3158      $ 1.0994   

Estimated aggregate distributions to:

         

Common units held by the public

    1,119        1,327        1,473        1,579        5,497   

Common units held by the sponsor

    15,928        18,889        20,976        22,485        78,278   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total distributions

  $ 17,047      $ 20,216      $ 22,448      $ 24,064      $ 83,775   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) For more information, please read “Summary—Summary Historical Financial Data—Non-GAAP Financial Measure.”

Assumptions and Considerations

Based upon the specific assumptions outlined below, we expect to generate available cash in an amount sufficient to allow us to pay $1.10 per common unit on all of our outstanding units for the twelve months ending June 30, 2015.

While we believe that these assumptions are reasonable in light of our management’s current expectations concerning future events, the estimates underlying these assumptions are inherently uncertain and are subject to significant business, economic, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate. If our assumptions are not correct, the amount of actual cash available to pay distributions could be substantially less than the amount we currently estimate and

 

56


Table of Contents

could, therefore, be insufficient to allow us to pay the forecasted cash distribution, or any amount, on our outstanding common units, in which event the market price of our common units may decline substantially. When reading this section, you should keep in mind the risk factors and other cautionary statements under the headings “Risk Factors” and “Forward-Looking Statements.” Any of the risks discussed in this prospectus could cause our actual results to vary significantly from our estimates.

Operations and Revenue

Royalty Income. Our revenues are a function of oil, natural gas and natural gas liquids production volumes sold and average prices received for those volumes. The mineral interests to be contributed to us upon the closing of this offering entitle us to receive an average 21.4% royalty interest on all production from the associated acreage with no additional future capital or operating expense required. Based on the production and pricing information included below, we estimate that our royalty income for the twelve months ending June 30, 2015 will be $93.8 million. For information on the effect of changes in prices and productions volumes, please read “—Sensitivity Analysis.”

Production. The following table sets forth information regarding production on our properties for the twelve months ending June 30, 2015:

 

Forecasted annual production:

 

Oil (Bbls)

    915,106   

Natural gas (Mcf)

    643,946   

Natural gas liquids (Bbls)

    136,687   

Combined volumes (BOE)

    1,159,117   

Forecasted average daily production:

 

Oil (Bbl/d)

    2,507   

Natural gas (Mcf/d)

    1,764   

Natural gas liquids (Bbl/d)

    374   

Combined volumes (BOE/d)

    3,176   

We estimate that oil and natural gas production from our properties for the twelve months ending June 30, 2015 will be 1,159 MBOE.

As of March 31, 2014, our operators were running five rigs and we anticipate that our operators will continue at this rate through June 30, 2015. We estimate that our operators will drill approximately 47 gross horizontal wells and 36 gross vertical wells in our acreage in the twelve months ending June 30, 2015.

Prices. The table below illustrates the relationship between average oil and natural gas realized sales prices and the average Brent and NYMEX prices on a forecasted basis for the twelve months ending June 30, 2015:

 

Forecasted average oil sales prices:

  

Brent oil price per Bbl

   $ 105.01   

Differential to Brent oil per Bbl(1)

   $ (10.80

Realized oil sales price per Bbl

   $ 94.21   

Forecasted average natural gas liquids sales prices:

  

NYMEX-WTI oil price per Bbl

   $ 94.64   

Differential to NYMEX-WTI oil per Bbl(1)

   $ (59.62

Realized natural gas liquids sales price per Bbl

   $ 35.02   

Forecasted average natural gas sales prices:

  

NYMEX-Henry Hub price per MMBtu

   $ 4.62   

Differential to NYMEX-Henry Hub natural gas(1)

   $ (0.25

Realized natural gas sales price per Mcf

   $ 4.37   

Total combined price (per BOE)

   $ 80.93   

 

57


Table of Contents

 

(1) Differentials between published oil and natural gas prices and the prices actually received for the oil and natural gas production may vary significantly due to market conditions, transportation, gathering and processing costs, quality of production and other factors. The differentials to published oil and natural gas prices are based upon our analysis of the historic price differentials for production from the mineral interests with consideration given to gravity, quality and transportation and marketing costs that may affect these differentials. There is no assurance that these assumed differentials will occur.

Expenditures

Production and ad valorem taxes. The following table summarizes production and ad valorem taxes (in thousands) on a forecast basis for the twelve months ending June 30, 2015:

 

Production taxes

   $ 4,691   

Ad valorem taxes

   $ 2,345   

Total production and ad valorem taxes

   $ 7,036   

Production and ad valorem taxes as a percentage of revenue

     7.5%   

Our production taxes are calculated as a percentage of our oil, natural gas and NGL revenues. In general, as prices and volumes increase, our production taxes increase. As prices and volumes decrease, our production taxes decrease. Ad valorem taxes are generally tied to the valuation of the oil and natural gas properties; such valuation is reasonably correlated to revenues.

Depletion. We estimate that our depletion expense for the twelve months ending June 30, 2015 will be $31.3 million. The forecasted depletion of our oil and natural gas properties is based on the production estimates in our reserve reports. The per BOE depletion rate is $27.00.

General and administrative expenses. We estimate that our general and administrative expenses for the twelve months ending June 30, 2015 will be $3.0 million, which includes an annual fee of $500,000 pursuant to an advisory services agreement that we expect to enter into with Wexford at the closing of this offering and $2.5 million of general and administrative expenses we expect to incur as a result of becoming a publicly traded partnership. Please read “Certain Relationships and Related Party Transactions—Agreements and Transactions with Affiliates in Connection with this Offering.” Our estimate of general and administrative expenses for the forecast period does not include any compensation expense that may be incurred in connection with the grant of unit options pursuant to the long-term incentive plan in connection with this offering. Any charge associated with this grant of unit options will be a non-cash expense. Please read “Executive Compensation and Other Information.”

Interest expense. We estimate that we will not have any long-term debt and related interest expense for the twelve months ending June 30, 2015. Subsequent to the closing of this offering, we expect to enter into a revolving credit facility to be used for general partnership purposes. Interest expense incurred prior to the closing of this offering is in connection with a subordinated note held by Diamondback, which will be converted to equity at the closing of this offering.

Capital Expenditures

Unlike a number of other master limited partnerships, we do not expect to initially retain cash from our operations for replacement capital expenditures primarily due to our expectation that existing development and the discovery of new pay horizons will lead to inclining production and revenues for at least the next several years. Replacement capital expenditures are those expenditures necessary to replace our existing oil and gas reserves or otherwise maintain our asset base over the long term. We expect to seek additional acquisitions of reserves and may restrict distributions to acquire or fund such acquisitions in whole or in part. If we do not retain cash for replacement capital expenditures in amounts necessary to maintain our asset base, eventually our cash available for distribution will decrease. The board of directors of our general partner may in the future decide to

 

58


Table of Contents

withhold replacement capital expenditures from cash available for distribution which may have an adverse impact on the cash available for distribution in the quarter(s) in which any such amounts are withheld. To the extent that we do not withhold replacement capital expenditures in the future, a portion of our future cash available for distribution will represent a return of your capital.

Regulatory, Industry and Economic Factors

Our forecast for the twelve months ending June 30, 2015 is based on the following significant assumptions related to regulatory, industry and economic factors:

 

   

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

 

   

There will not be any major adverse change in commodity prices or the energy industry in general;

 

   

Market, insurance and overall economic conditions will not change substantially; and

 

   

We will not undertake any extraordinary transactions that would materially affect our cash flow.

Forecasted Distributions

We expect that aggregate quarterly distributions of available cash on our common units for the twelve months ending June 30, 2015 will be approximately $83.8 million. While we believe that the assumptions we have used in preparing the estimates set forth above are reasonable based upon management’s current expectations concerning future events, they are inherently uncertain and are subject to significant business, economic regulatory and competitive risks and uncertainties, including those described in “Risk Factors,” that could cause actual results to differ materially from those we anticipate. If our assumptions are not realized, the actual available cash that we generate could be substantially less than the amount we currently estimate and could, therefore, be insufficient to permit us to pay any amount of distributions on all our outstanding common units in respect of the four calendar quarters ending June 30, 2015 or thereafter, in which event the market price of the common units may decline materially.

Sensitivity Analysis

Our ability to generate sufficient cash from operations to pay distributions to our unitholders is a function of two primary variables: (i) production volumes and (ii) commodity prices. In the paragraphs below, we demonstrate the impact that changes in either of these variables, while holding all other variables constant, would have on our ability to generate sufficient cash from our operations to pay quarterly distributions on our common units for the twelve months ending June 30, 2015.

 

59


Table of Contents

Production Volume Changes

The following table shows estimated cash available for distribution under production levels of 90%, 100% and 110% of the production level we have forecasted for the twelve months ending June 30, 2015.

 

    Percentage of Forecasted Annual
Production
 
    90%     100%     110%  

Forecasted annual production:

     

Oil (Bbls)

    823,595        915,106        1,006,616   

Natural gas (Mcf)

    579,552        643,946        708,341   

Natural gas liquids (Bbls)

    123,018        136,687        150,355   

Combined volumes (BOE)

    1,043,205        1,159,117        1,275,028   

Forecasted average daily production:

     

Oil (Bbl/d)

    2,256        2,507        2,758   

Natural gas (Mcf/d)

    1,588        1,764        1,941   

Natural gas liquids (Bbl/d)

    337        374        412   

Combined volumes (BOE/d)

    2,858        3,176        3,493   

Forecasted average sales prices:

     

Brent oil price per Bbl

  $ 105.01      $ 105.01      $ 105.01   

Realized oil sales price per Bbl

  $ 94.21      $ 94.21      $ 94.21   

NYMEX-WTI oil price per Bbl

  $ 94.64      $ 94.64      $ 94.64   

Realized natural gas liquids sales price per Bbl

  $ 35.02      $ 35.02      $ 35.02   

NYMEX-Henry Hub price per MMBtu

  $ 4.62      $ 4.62      $ 4.62   

Realized natural gas sales price per Mcf

  $ 4.37      $ 4.37      $ 4.37   

Estimated cash available for distribution (in thousands):

     

Royalty income

  $ 84,430      $ 93,811      $ 103,192   

General and administrative expenses

    (3,000     (3,000     (3,000

Interest expense

    —          —          —     

Production and ad valorem taxes

    (6,332     (7,036     (7,739
 

 

 

   

 

 

   

 

 

 

Estimated cash available for distribution

  $ 75,098      $ 83,775      $ 92,453   
 

 

 

   

 

 

   

 

 

 

 

60


Table of Contents

Commodity Price Changes

The following table shows estimated cash available for distribution under various assumed oil and natural gas prices for the twelve months ending June 30, 2015. The amounts shown below are based on forecasted realized commodity prices that take into account our average NYMEX commodity price differential assumptions. We have assumed no changes in our production based on changes in prices.

 

Forecasted annual production:

      

Oil (Bbls)

     915,106        915,106        915,106   

Natural gas (Mcf)

     643,946        643,946        643,946   

Natural gas liquids (Bbls)

     136,687        136,687        136,687   

Combined volumes (BOE)

     1,159,117        1,159,117        1,159,117   

Forecasted average daily production:

      

Oil (Bbl/d)

     2,507        2,507        2,507   

Natural gas (Mcf/d)

     1,764        1,764        1,764   

Natural gas liquids (Bbl/d)

     374        374        374   

Combined volumes (BOE/d)

     3,176        3,176        3,176   

Forecasted average sales prices:

      

Brent oil price per Bbl

   $ 95.01      $ 105.01      $ 115.01   

Realized oil sales price per Bbl

   $ 84.21      $ 94.21      $ 104.21   

NYMEX-WTI oil price per Bbl

   $ 84.64      $ 94.64      $ 104.64   

Realized natural gas liquids sales price per Bbl

   $ 25.02      $ 35.02      $ 45.02   

NYMEX-Henry Hub price per MMBtu

   $ 4.12      $ 4.62      $ 5.12   

Realized natural gas sales price per Mcf

   $ 3.87      $ 4.37      $ 4.87   

Estimated cash available for distribution:

      

Royalty income

   $ 82,971      $ 93,811      $ 104,651   

General and administrative expenses

     (3,000     (3,000     (3,000

Interest expense

     —          —          —     

Production and ad valorem taxes

     (6,223     (7,036     (7,849
  

 

 

   

 

 

   

 

 

 

Estimated cash available for distribution

   $ 73,748      $ 83,775      $ 93,802   
  

 

 

   

 

 

   

 

 

 

 

61


Table of Contents

HOW WE MAKE DISTRIBUTIONS

General

Within 60 days after the end of each quarter, we expect to make distributions, as determined by the board of directors of our general partner, to unitholders of record on the applicable record date. Our first distribution will include available cash for the period from the closing of this offering through September 30, 2014. We do not have a legal obligation to pay distributions, and the amount of distributions, if any, declared and paid under our distribution policy is determined by the board of directors of our general partner. See “Cash Distribution Policy and Restrictions on Distributions.”

Method of Distributions

We intend to distribute available cash to our unitholders, pro rata. Our partnership agreement permits us to borrow to make distributions, but we are not required to, and do not intend to, borrow to pay quarterly distributions. Accordingly, there is no guarantee that we will pay any distribution on the units in any quarter.

Common Units

At the closing of this offering, we will have 76,200,000 common units outstanding. Each common unit will be entitled to receive cash distributions to the extent we distribute available cash. 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.

General Partner Interest

Upon the closing of this offering, our general partner will own a non-economic general partner interest and therefore will not be entitled to receive cash distributions. However, it may acquire common units and other equity interests in the future and will be entitled to receive pro rata distributions in respect of those equity interests.

 

62


Table of Contents

SELECTED HISTORICAL FINANCIAL DATA

Viper Energy Partners LP was formed in February 2014 and does not have historical financial statements. Therefore, in this prospectus we present the historical financial statements of Viper Energy Partners LLC, the subsidiary of Diamondback that will be contributed to Viper Energy Partners LP upon the closing of this offering. We refer to this entity as “Viper Energy Partners LP Predecessor.” The following table presents selected historical financial data of Viper Energy Partners LP Predecessor as of the dates and for the periods indicated. Diamondback acquired the assets owned by Viper Energy Partners LP Predecessor on September 19, 2013.

The selected historical financial data of Viper Energy Partners LP Predecessor presented as of the dates and for the periods indicated are derived from the audited historical financial statements and unaudited historical financial statements of Viper Energy Partners LP Predecessor included elsewhere in this prospectus.

For a detailed discussion of the selected historical financial data contained in the following table, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The following table should also be read in conjunction with “Use of Proceeds” and the audited historical financial statements and unaudited historical financial statements of Viper Energy Partners LP Predecessor included elsewhere in this prospectus. Among other things, the historical financial statements include more detailed information regarding the basis of presentation for the information in the following table.

 

     Viper Energy Partners  LP
Predecessor Historical
 
     Three Months Ended
March 31,
2014
    Period From  Inception
(September 18, 2013)
Through
December 31, 2013
 
     (unaudited)        
     (in thousands)  

Statement of Operations Data:

    

Royalty income

   $ 15,853      $ 14,987   

Expenditures:

    

Production and ad valorem taxes

     921        972   

Depletion

     5,567        5,199   

General and administrative expenses

     66        —     

General and administrative expenses—related party

     78        87   

Interest expense—related party, net of capitalized interest

     5,368        5,741   
  

 

 

   

 

 

 

Total expenditures

     12,000        11,999   
  

 

 

   

 

 

 

Net income

   $         3,853      $         2,988   
  

 

 

   

 

 

 

Statement of Cash Flow Data:

    

Net cash provided by (used in):

    

Operating activities

   $ 6,543      $ 4,845   

Investing activities

     (6,878     (4,083

Financing activities

     (28     —     

Other Financial Data:

    

Adjusted EBITDA(1)

   $ 14,788      $ 13,928   

Balance Sheet Data (at period end):

    

Cash and cash equivalents

   $ 399      $ 762   

Total assets

     447,253        453,023   

Total liabilities

     440,412        450,035   

Members’ equity

     6,841        2,988   

 

(1) For more information, please read “Summary—Summary Historical Financial Data—Non-GAAP Financial Measure.”

 

63


Table of Contents

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

You should read the following discussion of our historical performance, financial condition and future prospects in conjunction with Viper Energy Partners LP Predecessor’s audited historical financial statements as of December 31, 2013 and for the period from inception (September 18, 2013) to December 31, 2013 and the unaudited historical financial statements as of and for the three months ended March 31, 2014 included elsewhere in this prospectus. The information provided below supplements, but does not form part of, Viper Energy Partners LP Predecessor’s financial statements. This discussion contains forward-looking statements that are based on the views and beliefs of our management, as well as assumptions and estimates made by our management. Actual results could differ materially from such forward-looking statements as a result of various risk factors, including those that may not be in the control of management. For further information on items that could impact our future operating performance or financial condition, see the section entitled “Risk Factors” elsewhere in this prospectus.

Overview

Viper Energy Partners LP is a Delaware limited partnership formed by Diamondback to own, acquire and exploit oil and natural gas properties in North America. On September 19, 2013, Diamondback completed the acquisition of mineral interests underlying approximately 14,804 gross acres in Midland County, Texas in the Permian Basin for $440 million. Diamondback will contribute these interests to us through the contribution of its wholly owned subsidiary, Viper Energy Partners LLC, in connection with the closing of this offering.

As of March 31, 2014, our assets consisted of mineral interests underlying approximately 14,804 gross acres in Midland County, Texas in the Permian Basin. The mineral interests entitle us to receive an average 21.4% royalty interest on all production from this acreage with no additional future capital or operating expense required. As of March 31, 2014, there were 210 vertical wells and 22 horizontal wells producing on this acreage. The average net production on our acreage was approximately 1,919 net BOE/d during December 2013, and for the period from September 18, 2013 to December 31, 2013, royalty revenue generated from these mineral interests was $15.0 million. The average net production on our acreage was approximately 2,197 net BOE/d during March 2014, and royalty revenue generated from these mineral interests was $15.9 million for the three months ended March 31, 2014. Diamondback serves as the operator of approximately 50% of the acreage associated with these mineral interests.

Operating Results Overview

During the three months ended March 31, 2014, the average daily production on our properties was approximately 2,171 BOE/d, consisting of 1,719 Bbls/d of oil, 1,164 Mcf/d of natural gas and 257 Bbls/d of natural gas liquids. During the period from inception (September 18, 2013) through December 31, 2013, the average daily production on our properties was approximately 1,798 BOE/d, consisting of 1,436 Bbls/d of oil, 1,031 Mcf/d of natural gas and 190 Bbls/d of natural gas liquids.

Reserves and Pricing

Ryder Scott prepared estimates of our proved reserves at December 31, 2013. The prices used to estimate proved reserves for all periods did not give effect to derivative transactions, were held constant throughout the life of the properties and have been adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

 

     As of
December 31,
2013
 

Estimated Net Proved Reserves:

  

Oil (Bbls)

     7,218,080   

Natural gas (Mcf)

     11,261,585   

Natural gas liquids (Bbls)

     1,175,123   

Total (BOE)

     10,270,135   

 

64


Table of Contents
     As of
December 31,
2013
 
     Unweighted
Arithmetic Average
First-Day-of-the-
Month Prices
 

Oil (Bbls)

   $ 92.64   

Natural gas (Mcf)

   $ 5.03   

Natural gas liquids (Bbls)

   $ 38.45   

Sources of Our Revenue

Our revenues are derived from royalty payments we receive from our operators based on the sale of oil and natural gas production, as well as the sale of natural gas liquids that are extracted from natural gas during processing. For the period from inception (September 18, 2013) through December 31, 2013, our revenues were derived 93% from oil sales, 5% from natural gas liquid sales and 2% from natural gas sales. For the three months ended March 31, 2014, our revenues were derived from royalty interests generated 92% from oil sales, 5% from natural gas liquid sales and 3% from natural gas sales. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. Oil, natural gas liquids and natural gas prices have historically been volatile. During 2013, West Texas Intermediate posted prices ranged from $86.65 to $110.62 per Bbl and the Henry Hub spot market price of natural gas ranged from $3.08 to $4.52 per MMBtu. On December 31, 2013, the West Texas Intermediate posted price for crude oil was $98.17 per Bbl and the Henry Hub spot market price of natural gas was $4.31 per MMBtu. On March 31, 2014, the West Texas Intermediate posted price for crude oil was $101.57 per Bbl and the Henry Hub spot market price of natural gas was $4.48 per MMBtu.

Principal Components of Our Cost Structure

Production and Ad Valorem Taxes

Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at fixed rates established by federal, state or local taxing authorities. Where available, we benefit from tax credits and exemptions in our various taxing jurisdictions. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and gas properties.

General and Administrative

These are costs incurred for overhead, including the cost of management, operating and administrative services provided under the shared services agreement with Diamondback E&P LLC, a wholly owned subsidiary of Diamondback, audit and other fees for professional services and legal compliance. In connection with the closing of this offering, the shared services agreement with Diamondback E&P LLC will terminate, and we and our general partner will enter into an advisory services agreement with Wexford pursuant to which Wexford will provide general financial and strategic advisory services to us and our general partner in exchange for a fee and certain expense reimbursement. Please read “Certain Relationships and Related Party Transactions—Agreements and Transactions with Affiliates in Connection with this Offering.”

Depreciation, Depletion and Amortization

Under the full cost accounting method, we capitalize costs within a cost center and then systematically expense those costs on a units of production basis based on proved oil and natural gas reserve quantities. We calculate depletion on all capitalized costs, other than the cost of investments in unproved properties and major development projects for which proved reserves cannot yet be assigned, less accumulated amortization.

 

65


Table of Contents

Income Tax Expense

The partnership will be treated as a partnership for federal income tax purposes, with each partner being separately taxed on its share of taxable income; therefore, there will be no federal income tax expense reflected in our financial statements.

We are subject to the Texas margin tax. Any amounts related to operations for 2013 or for the period in 2014 prior to the closing of this offering will be included in Diamondback’s unitary filing for this tax. Diamondback does not expect any Texas margin tax to be due for the three months ended March 31, 2014 or the period from inception (September 18, 2013) through December 31, 2013, so no amount has been provided in the accompanying financial statements of our predecessor. On a stand-alone basis, we would have owed approximately $98,000 for the Texas margin tax in 2013.

Factors Affecting the Comparability of Our Results to the Historical Financial Results of Our Predecessor

Our results of operations and our future results of operations may not be comparable to the historical results of operations of our predecessor for the periods presented, primarily for the reasons described below:

 

   

In connection with the closing of this offering, the subordinated note will be converted to equity; therefore, we will not have any long-term debt and related interest expense as of the closing of this offering. Subsequent to the closing of this offering, we expect to enter into a revolving credit facility to be used for general partnership purposes.

 

   

We anticipate incurring incremental SG&A expenses of approximately $2.5 million annually as a result of being a publicly traded partnership, consisting of expenses associated with SEC reporting requirements, including annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, Sarbanes-Oxley Act compliance, NASDAQ Global Select Market listing, independent auditor fees, legal fees, investor relations activities, registrar and transfer agent fees, director and officer insurance and director compensation.

 

   

In connection with the closing of this offering, the shared services agreement with Diamondback E&P LLC will terminate, and we and our general partner will enter into an advisory services agreement with Wexford pursuant to which Wexford will provide general financial and strategic advisory services to us and our general partner in exchange for a fee and certain expense reimbursement. Please read “Certain Relationships and Related Party Transactions—Agreements and Transactions with Affiliates in Connection with this Offering.”

 

   

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 and Transactions with Affiliates in Connection with this Offering.”

 

66


Table of Contents

Results of Operations

The following table summarizes our revenue and expenses and production data for the periods indicated.

 

     Three Months Ended
March  31,
2014
     Period From Inception
(September 18, 2013)

Through
December 31, 2013
 
     (unaudited)         
     (in thousands)  

Operating Results:

     

Royalty income

   $ 15,853       $ 14,987   

Expenditures:

     

Production and ad valorem taxes

     921         972   

Depletion

     5,567         5,199   

General and administrative expenses

     66         —     

General and administrative expenses—related party

     78         87   

Interest expense—related party, net of capitalized interest

     5,368         5,741   
  

 

 

    

 

 

 

Total expenditures

     12,000         11,999   
  

 

 

    

 

 

 

Net income

   $         3,853       $         2,988   
  

 

 

    

 

 

 

Production Data:

     

Oil (Bbls)

     154,747         150,815   

Natural gas (Mcf)

     104,731         108,264   

Natural gas liquids (Bbls)

     23,171         19,971   

Combined volumes (BOE)

     195,373         188,830   

Daily combined volumes (BOE/d)

     2,171         1,798   

Royalty Income

Our royalty income for the three months ended March 31, 2014 was $15.9 million, an increase of $0.9 million, or 6%, from $15.0 million for the period from inception (September 18, 2013) to December 31, 2013. Our revenues are a function of oil, natural gas liquids and natural gas production volumes sold and average prices received for those volumes. Our operators received an average of $93.76 per Bbl of oil, $36.30 per Bbl of natural gas liquids and $4.80 per Mcf of natural gas for the volumes sold for the three months ended March 31, 2014. Our operators received an average of $92.07 per Bbl of oil, $35.32 per Bbl of natural gas liquids and $3.67 per Mcf of natural gas for the volumes sold for the period from inception (September 18, 2013) to December 31, 2013.

General and Administrative Expense

Effective September 19, 2013, we entered into a shared services agreement with Diamondback E&P LLC, a wholly owned subsidiary of Diamondback. Under this agreement, Diamondback E&P LLC provides consulting and administrative services to us. We incur a monthly charge for the services of $26,000 or other amounts that are otherwise mutually agreed to in writing between Diamondback E&P LLC and us. For the three months ended March 31, 2014 and the period from inception (September 18, 2013) to December 31, 2013, we incurred $78,000 and $87,000, respectively, for services under this agreement. This agreement will terminate at the closing of this offering. For the three months ended March 31, 2014, we also incurred general and administrative expenses from unrelated parties of $66,000.

 

67


Table of Contents

Net Interest Expense

Net interest expense for the three months ended March 31, 2014 and the period from inception (September 18, 2013) through December 31, 2013 was $5.4 million and $5.7 million, respectively, incurred in connection with the subordinated note held by Diamondback. In connection with the closing of this offering, the subordinated note will be converted to equity.

Liquidity and Capital Resources

Overview

Following the completion of this offering, we expect our primary sources of liquidity will be cash flows from operations and equity and debt financings and our primary uses of cash will be for paying distributions to our unitholders and for replacement and growth capital expenditures, including the acquisition, development and exploration of oil and natural gas properties. Subsequent to the closing of this offering, we expect to enter into a revolving credit facility to be used for general partnership purposes.

Our partnership agreement does not require us to distribute any of the cash we generate from operations. We believe, however, that it will be in the best interests of our unitholders if we distribute a substantial portion of the cash we generate from operations. The board of directors of our general partner will adopt a policy to distribute an amount equal to the available cash we generate each quarter to our unitholders. Our first distribution, however, will include available cash for the period from the closing of this offering through September 30, 2014.

Cash Flows

The following table presents our cash flows for the period indicated.

 

     Three Months Ended
March 31,
2014
    Period From Inception
(September 18, 2013)

Through
December 31, 2013
 
     (unaudited)        
     (in thousands)  

Cash Flow Data:

    

Cash flows provided by operating activities

   $         6,543      $         4,845   

Cash flows used in investing activities

     (6,878     (4,083

Cash flows used in financing activities

     (28     —     
  

 

 

   

 

 

 

Net increase (decrease) in cash

   $ (363   $ 762   
  

 

 

   

 

 

 

Operating Activities

Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for oil and natural gas. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict.

Investing Activities

The purchase of oil and natural gas properties accounted for our cash outlays for investing activities. We used cash for investing activities of $6.9 million and $4.0 million during the three months ended March 31, 2014 and the period from inception (September 18, 2013) to December 31, 2013, respectively.

Financing Activities

We used cash for financing activities of $28,000 during the three months ended March 31, 2014 in connection with this offering. We did not use any cash for financing activities during the period from inception (September 18, 2013) to December 31, 2013.

 

68


Table of Contents

Potential Revolving Credit Facility

Subsequent to the closing of this offering, we expect to enter into a credit agreement providing for a revolving credit facility. The facility would be secured by substantially all of our assets. We expect that the credit agreement will contain various affirmative, negative and financial maintenance covenants. These covenants would, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, transactions with affiliates and entering into certain swap agreements and require the maintenance of certain financial ratios. We also expect that the credit agreement will contain customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control.

Contractual Obligations

The following table presents our contractual obligations and other commitments as of December 31, 2013:

 

     Payments Due by Period  
     Total      2014      2015      2016      2017      2018      Thereafter  
     (in thousands)  

Subordinated note(1)

   $ 710,000       $ 33,500       $ 33,500       $ 33,500       $ 33,500       $ 33,500       $ 542,500   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 710,000       $ 33,500       $ 33,500       $ 33,500       $ 33,500       $ 33,500       $ 542,500   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) Effective September 19, 2013, our predecessor issued a subordinated note to Diamondback for the principal sum of $440 million. In connection with the closing of this offering, Diamondback will contribute Viper Energy Partners LLC to us. Upon such contribution, the subordinated note held by Diamondback will be converted to equity. The amounts above represent the scheduled cash payments for interest expense and maturity as of December 31, 2013.

As of December 31, 2013, we do not have any other contractual obligations.

Internal Controls and Procedures

We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes-Oxley Act of 2002, and are therefore not required to make a formal assessment of the effectiveness of our internal controls over financial reporting for that purpose. Upon becoming a public company, we will be required to comply with the SEC’s rules implementing Section 302 of the Sarbanes-Oxley Act of 2002, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal controls over financial reporting. We will not be required to make our first assessment of our internal controls over financial reporting until the year following our first annual report required to be filed with the SEC. To comply with the requirements of being a public company, we will need to implement additional financial and management controls, reporting systems and procedures and hire additional accounting, finance and legal staff.

Further, our independent registered public accounting firm is not yet required to formally attest to the effectiveness of our internal controls over financial reporting, and will not be required to do so for as long as we are an “emerging growth company” pursuant to the provisions of the JOBS Act or as long as we are a non-accelerated filer. See “Summary—Emerging Growth Company Status.” Please also see “Risk Factors—Risks Inherent in an Investment in Us—For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements that apply to other public companies.”

New and Revised Financial Accounting Standards

We qualify as an “emerging growth company” pursuant to the provisions of the JOBS Act, enacted on April 5, 2012. Section 102 of the JOBS Act provides that an “emerging growth company” can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or

 

69


Table of Contents

revised accounting standards. However, we are choosing to “opt out” of such extended transition period, and as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for non-emerging growth companies. Our election to “opt-out” of the extended transition period is irrevocable.

Critical Accounting Policies

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. Below, we have provided expanded discussion of our more significant accounting policies, estimates and judgments. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our financial statements. See the notes to our consolidated financial statements included elsewhere in this prospectus for additional information regarding these accounting policies.

Use of Estimates

Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated by our management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the consolidated financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities and our disclosure of contingent assets and liabilities at the date of the consolidated financial statements. Actual results could differ from those estimates.

We evaluate these estimates on an ongoing basis, using historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include estimates of proved oil and gas reserves and related present value estimates of future net cash flows therefrom and the carrying value of oil and natural gas properties.

Method of Accounting for Oil and Natural Gas Properties

We account for oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change.

Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs plus estimated future development costs are amortized over total proved reserves.

Costs associated with unevaluated properties are excluded from the full cost pool until we have made a determination as to the existence of proved reserves. We assess all items classified as unevaluated property on an annual basis for possible impairment. We assess properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.

 

70


Table of Contents

Oil and Natural Gas Reserve Quantities and Standardized Measure of Future Net Revenue

Our independent engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net revenues. The SEC has defined proved reserves as the estimated quantities of oil and gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The process of estimating oil and gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If such changes are material, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material.

There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

Royalty Interest and Revenue Recognition

Royalty interest represents the right to receive revenues (oil and natural gas sales), less production and operating taxes and post-production costs. Revenue is recorded when title passes to the purchaser.

Royalty interest has no rights or obligations to explore, develop or operate the property and does not incur any of the costs of exploration, development and operation of the property.

Impairment

The net capitalized costs of proved oil and natural gas properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization, impairment and deferred income taxes exceed the discounted future net revenues of proved oil and natural gas reserves, less any related income tax effects, the excess capitalized costs are charged to expense. In calculating future net revenues, prices are calculated as the average oil and gas prices during the preceding 12-month period prior to the end of the current reporting period, determined as the unweighted arithmetic average first-day-of-the-month prices for the prior 12-month period and costs used are those as of the end of the appropriate quarterly period.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on results of operations for the period from inception (September 18, 2013) through December 31, 2013.

Off-Balance Sheet Arrangements

We currently have no off-balance sheet arrangements.

 

71


Table of Contents

Quantitative and Qualitative Disclosure about Market Risk

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to the oil and natural gas production of our operators. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for oil and natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices that our operators receive for production depend on many factors outside of our or their control.

Credit Risk

We are subject to risk resulting from the concentration of royalty interest revenues in producing oil and natural gas properties and receivables with several significant purchasers. For the three months ended March 31, 2014, two purchasers accounted for more than 10% of royalty interest revenue: Shell Trading (72%); and Enterprise Crude Oil LLC (10%). For the period from inception (September 18, 2013) to December 31, 2013, two purchasers accounted for more than 10% of royalty interest revenue: Shell Trading (59%); and Permian Trucking (19%). We do not require collateral and do not believe the loss of any single purchaser would materially impact our operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

 

72


Table of Contents

BUSINESS

Overview

We are a Delaware limited partnership formed by Diamondback to own, acquire and exploit oil and natural gas properties in North America. Our primary business objective is to provide an attractive return to unitholders by focusing on business results, maximizing distributions through organic growth and pursuing accretive growth opportunities through acquisitions of mineral interests from Diamondback and from third parties. Our initial assets consist of mineral interests in oil and natural gas properties in the Permian Basin in West Texas, substantially all of which are leased to working interest owners who bear the costs of operation and development. Diamondback will contribute these assets, which it acquired in September 2013 from a third party for cash, to us upon the closing of this offering.

Like Diamondback, we expect our initial focus will concentrate on the Permian Basin, which is one of the oldest and most prolific producing basins in North America. The Permian Basin, which consists of approximately 85,000 square miles centered around Midland, Texas, has been a significant source of oil production since the 1920s. The Permian Basin is known to have a number of zones of oil and natural gas bearing rock throughout. However, because of the nature of the rock in many of the potentially productive zones, historically it was not economic to exploit these zones. As a result, exploration and development was limited until recently when higher oil prices and more advanced completion techniques, including hydraulic fracturing, changed the economics of drilling and development of these zones and greatly increased the oil and natural gas industry’s interest in the Permian Basin. Oil production in the Permian Basin has grown from 850,000 barrels per day in 2008 to 1.3 million barrels per day in 2013. Based on public statements made by a number of publicly traded oil and natural gas companies, and the successful horizontal well results of the industry, we believe that drilling activity in the Permian Basin is likely to continue to grow at least for several more years.

Diamondback is a publicly traded independent oil and natural gas company currently focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin. Upon the completion of this offering, Diamondback will own and control our general partner, and will own approximately 93% of our outstanding common units. Diamondback’s total net acreage position in the Permian Basin (including the acreage underlying our mineral interests with respect to which it is operator) was approximately 72,000 net acres at March 31, 2014, and it serves as the operator of approximately 99% of its leased acreage. As of December 31, 2013, Diamondback had estimated proved oil and natural gas reserves of 63,586 MBOE (including the estimated proved reserves associated with our mineral interests) based on a reserve report prepared by Ryder Scott. Of these reserves, approximately 45% were classified as PDP reserves and approximately 67% were oil, 17% were natural gas liquids and 16% were natural gas. PUD reserves included in this estimate are from 206 vertical gross (151 net) well locations on 40-acre spacing and 43 gross (31 net) horizontal well locations. We believe that the properties held by Diamondback include properties that have, or with additional development will have, production and reserves characteristics that could make them attractive for inclusion in our partnership. We believe Diamondback’s significant ownership interest in us will motivate it to offer additional mineral and other interests in oil and natural gas properties to us in the future, although Diamondback has no obligation to do so. Please read “—Our Relationship with Diamondback.”

Our Properties

Our initial assets consisted of mineral interests underlying approximately 14,804 gross acres in Midland County, Texas in the Permian Basin, approximately 50% of which are operated by Diamondback. Diamondback acquired the mineral interests for $440 million on September 19, 2013. The mineral interests entitle us to receive an average 21.4% royalty interest on all production from this acreage with no additional future capital or operating expense required. As of March 31, 2014, there were 210 vertical wells and 22 horizontal wells producing on this acreage, and average net production was approximately 2,197 net BOE/d during March 2014. In addition, there were six vertical wells and 14 horizontal wells in various stages of completion. For the three months ended March 31, 2014 and the period from our inception (September 18, 2013) to December 31, 2013, royalty revenue generated from these mineral interests was $15.9 million and $15.0 million, respectively.

 

73


Table of Contents

The estimated proved oil and natural gas reserves of our initial assets, as of December 31, 2013, were 10,270 MBOE based on a reserve report prepared by Ryder Scott, our independent reserve engineer. Of these reserves, approximately 48% were classified as PDP reserves. PUD reserves included in this estimate were from 106 vertical gross well locations on 40-acre spacing and 24 gross horizontal well locations. As of December 31, 2013, our proved reserves were approximately 70% oil, 11% natural gas liquids and 18% natural gas.

Our mineral interests entitle us to receive an average of 21.4% royalty interest on an acreage weighted basis from our approximately 14,804 gross acres. The actual royalty percentage varies by lease and ranges from 7.8% to 25%. The average royalty percentage on a production basis can therefore vary over time depending on the relative amount of production from the various leases. On an acreage weighted basis, our average royalty percentage is 20.6% on the portion of the acreage that Diamondback operates and is 22.3% on the portion of the acreage operated by others. From September 18, 2013 through March 31, 2014, the average royalty percentage was 20.1% owing to some of the lower royalty percentage acreage being more developed at this time. As additional acreage is developed, we anticipate that the average royalty percentage on a production basis will change and likely will increase as more of the higher royalty acreage is developed.

Based on Diamondback’s evaluation of applicable geologic and engineering data as of March 31, 2014, with respect to the approximate 50% of our mineral interests for which it is the operator, Diamondback had 73 identified potential vertical drilling locations on 40-acre spacing and an additional 184 identified potential vertical drilling locations based on 20-acre downspacing. As of such date, Diamondback had also identified 322 potential horizontal drilling locations in multiple horizons on our acreage. We do not have potential (not involving proved reserves) drilling location information with respect to the portion of our properties not operated by Diamondback, although we believe that such portion has very similar production characteristics to the portion operated by Diamondback. The operator of a majority of our properties not operated by Diamondback is RSP Permian. Diamondback has advised us that it believes it has a good relationship with RSP Permian and that it shares, on occasion, drilling and production information with RSP Permian in order to encourage further development of our properties. Additionally, Diamondback has participated with RSP Permian in the drilling and completion of five horizontal wells on shared acreage subject to our mineral interests.

The gross EURs from the future PUD vertical wells included in our reserve report on 40-acre spacing, as estimated by Ryder Scott as of December 31, 2013, range from 104 MBOE per well, consisting of 80 MBbls of oil and 148 MMcf of natural gas, to 146 MBOE per well, consisting of 112 MBbls of oil and 208 MMcf of natural gas, with an average EUR per well of 134 MBOE, consisting of 102 MBbls of oil and 193 MMcf of natural gas. Diamondback currently anticipates a reduction of approximately 20% in EURs from vertical wells drilled on 20-acre spacing.

With respect to 23 horizontal wells drilled by our operators on our acreage for the period from June 2012 through March 2014, the average 30-day initial production (“IP”) rate was 663 BOE/d and the average 24-hour IP rate was 954 BOE/d from lateral lengths averaging 5,739 feet.

Our Relationship with Diamondback

Upon the completion of this offering, Diamondback will own and control our general partner and will own approximately 93% of our outstanding common units. We believe that the properties held by Diamondback include properties that have, or with additional development will have, production and reserves characteristics that could make them attractive for inclusion in our partnership. We believe Diamondback’s significant ownership in us will motivate it to offer additional mineral and other interests in oil and natural gas properties to us in the future, although Diamondback has no obligation to do so and may elect to dispose of such mineral and other interests in properties without offering us the opportunities to acquire them.

We believe Diamondback views our partnership as part of its growth strategy, and we believe that Diamondback will be incentivized to pursue acquisitions jointly with us in the future. However, Diamondback

 

74


Table of Contents

will regularly evaluate acquisitions and may elect to acquire properties without offering us the opportunity to participate in such transactions. Moreover, Diamondback may not be successful in identifying potential acquisitions. After this offering, Diamondback will continue to be free to act in a manner that is beneficial to its interests without regard to ours, which may include electing not to present us with acquisition or disposition opportunities. Please read “Conflicts of Interest and Fiduciary Duties.”

In addition, neither we nor our subsidiaries nor our general partner will have any employees. Diamondback will provide management, operating and administrative services to us and our general partner. Please read “Management” and “Certain Relationships and Related Party Transactions.”

Diamondback may be deemed to be an “underwriter” within the meaning of the Securities Act with respect to this offering.

Prior to October 11, 2012, Wexford beneficially owned 100% of the equity interests in Diamondback. Upon completion of Diamondback’s initial public offering, Wexford beneficially owned approximately 44.4% of its common stock. As a result of the issuance of additional shares of common stock by Diamondback and sales of its common stock by affiliates of Wexford, as of April 1, 2014, Wexford beneficially owned approximately 18.4% of the common stock of Diamondback.

Business Strategies

Our primary business objective is to provide an attractive return to unitholders by focusing on business results, maximizing distributions through organic growth and pursuing accretive growth opportunities through acquisitions of mineral interests from Diamondback and from third parties. We intend to accomplish this objective by executing the following strategies:

 

   

Capitalize on the development of the properties underlying our mineral interests to grow our distributions. As of the closing of this offering, our initial assets will consist of mineral interests in the Permian Basin in West Texas. We expect the production from our mineral interest will increase as Diamondback and our other operators continue to actively drill and develop our acreage. We expect to capitalize on this development, cost-free to us, and believe the resulting increase in our aggregate royalty payments will enable us to grow our distributions.

 

   

Leverage our relationship with Diamondback to participate with it in acquisitions of mineral or other interests in producing properties from third parties and to increase the size and scope of our potential third-party acquisition targets. We intend to make opportunistic acquisitions of mineral interests that have substantial oil-weighted resource potential and organic growth potential. Diamondback was formed in part to acquire and develop oil and natural gas properties, some of which will likely meet our acquisition criteria. In addition, Diamondback’s executives have long histories of evaluating, pursuing and consummating oil and natural gas property acquisitions in North America. Through our relationships with Diamondback and its affiliates, we have access to their significant pool of management talent and industry relationships, which we believe provide us with a competitive advantage in pursuing potential third-party acquisition opportunities. We may have additional opportunities to work jointly with Diamondback to pursue certain acquisitions of mineral or other interests in oil and natural gas properties from third parties. For example, we and Diamondback may jointly pursue an acquisition where we would acquire mineral or other interests in properties and Diamondback would acquire the remaining working and revenue interests in such properties. We believe this arrangement may give us access to third-party acquisition opportunities that we would not otherwise be in a position to pursue.

 

   

Seek to acquire from Diamondback, from time to time, mineral or other interests in producing oil and natural gas properties that meet our acquisition criteria. We may have additional opportunities to acquire mineral or other interests in producing oil and natural gas properties directly from Diamondback or third parties from time to time in the future. We believe Diamondback may be incentivized to sell

 

75


Table of Contents
 

properties to us, as doing so may enhance Diamondback’s economic returns by monetizing long-lived producing properties while potentially retaining a portion of the resulting cash flow through distributions on Diamondback’s limited partner interests in us. However, none of Diamondback or any of its affiliates is contractually obligated to offer or sell interests in any properties to us.

Competitive Strengths

We believe that the following competitive strengths will allow us to successfully execute our business strategies and achieve our objective of growing our business and maximizing total distributions to our unitholders:

 

   

Oil rich resource base in one of North America’s leading resource plays. All of the acreage underlying our mineral interests is located in one of the most prolific oil plays in North America, the Permian Basin in West Texas. The majority of our current properties are well positioned in the core of the Wolfberry play. Production on our properties for the three months ended March 31, 2014 was approximately 79% oil, 12% natural gas liquids and 9% natural gas. As of December 31, 2013, our estimated net proved reserves were comprised of approximately 70% oil and 11% natural gas liquids, which allows us to benefit from the currently more favorable pricing of oil and natural gas liquids as compared to natural gas. We believe that we will have a strong, growing production profile driven by Diamondback, a growth-oriented operator.

 

   

Multi-year drilling inventory in one of North America’s leading oil resource plays. We expect our reserves and cash available for distributions to grow organically as our operators continue to drill new wells on our acreage. Diamondback, as the operator of approximately 50% of our properties, has advised us that it has identified a multi-year inventory of potential drilling locations for our oil-weighted reserves from the acreage underlying our mineral interests. As of March 31, 2014, with respect to the approximate 50% of our properties operated by it, Diamondback had 73 identified potential vertical drilling locations based on 40-acre spacing and an additional 184 identified potential vertical drilling locations based on 20-acre downspacing. Diamondback also believes that there are a significant number of horizontal locations that could be drilled on the acreage. Based on Diamondback’s initial results and those of other operators in the area to date, combined with its interpretation of various geologic and engineering data, Diamondback has identified 322 potential horizontal locations on the acreage operated by Diamondback. These locations exist across most of the acreage and in multiple horizons. Of these 322 potential locations, 130 are in the Wolfcamp B or Lower Spraberry horizons, with the remaining locations in the Wolfcamp A, Clearfork, Middle Spraberry or Cline horizons. Diamondback’s current potential horizontal location count is based on 660-foot spacing between wells in the Wolfcamp B and Lower Spraberry horizons in Midland County, 880-foot spacing in the Middle Spraberry horizon and 1,320-foot spacing in other horizons. The ultimate inter-well spacing may be less than these amounts, which would result in a higher location count. Based on horizontal wells drilled to date, Ryder Scott assigned reserves to PUD locations ranging from 374 MBOE for 5,000-foot laterals in the Middle Spraberry to 847 MBOE for 10,000-foot laterals in the Wolfcamp B. When normalized to 7,500-foot laterals, Ryder Scott assigned PUD values of 638 MBOE for the Wolfcamp B horizon, 643 MBOE for the Lower Spraberry horizon and 562 MBOE for the Middle Spraberry horizon. These PUD locations, as assigned by Ryder Scott, are for direct offsets to producing wells. Based on various geologic and engineering parameters, we believe that the estimates assigned to these PUD locations are reasonable estimates for PUD locations on the remaining portion of our acreage. Additionally, we believe that there is similar potential for horizontal development on the portion of our acreage for which Diamondback is not the operator.

 

   

Experienced and proven management team. The members of our executive team have an average of over 25 years of industry experience, most of which were focused on resource play development in the Permian Basin. This team has a proven track record of executing on multi-rig development drilling programs and extensive experience in the Permian Basin. In addition, our executive team has significant experience with property acquisitions. We expect to benefit from the industry relationships fostered by the team’s decades of experience in the Permian Basin. Prior to joining Diamondback, the Chief

 

76


Table of Contents
 

Executive Officer of our general partner held management positions at Apache Corporation, Laredo Petroleum Holdings, Inc. and Burlington Resources. The Chief Financial Officer of our general partner previously served as the Controller/Tax Director at Hiland Partners, a publicly traded master limited partnership, and has over eight years of accounting experience at other public companies. We believe the experience of our management team is essential for us to grow from our initial property base.

 

   

Favorable and stable operating environment. We will focus our growth in the Permian Basin, one of the oldest hydrocarbon basins in the United States, with a long and well-established production history and developed infrastructure. With approximately 380,000 wells drilled in the Permian Basin since the 1940s, we believe that the geological and regulatory environment is more stable and predictable, and that we are faced with fewer operational risks, in the Permian Basin as compared to emerging hydrocarbon basins. We believe that the impact of the proven application of new technology, combined with the substantial geological information available about the Permian Basin, also reduces the risk of development and exploration activities as compared to emerging hydrocarbon basins.

 

   

Financial flexibility to fund expansion. We have a conservative balance sheet. We will seek to maintain financial flexibility to allow us to opportunistically purchase accretive mineral and other interests. Upon the completion of this offering, we will have no debt and will possess the financial capacity to grow the partnership. Subsequent to the closing of this offering, we also expect to enter into a revolving credit facility to be used for general partnership purposes. We further believe that we have a unique distribution profile with initial distributions exclusively supported by mineral interests. We also expect to produce peer-leading margins unburdened by lease operating expenses.

Oil and Natural Gas Data

Proved Reserves

SEC Rule-Making Activity

In December 2008, the SEC released its final rule for “Modernization of Oil and Gas Reporting.” These rules require disclosure of oil and gas proved reserves by significant geographic area, using the arithmetic 12-month average beginning-of-the-month price for the year, as opposed to year-end prices as had previously been required, unless contractual arrangements designate the price to be used. Other significant amendments included the following:

 

   

Disclosure of unproved reserves: probable and possible reserves may be disclosed separately on a voluntary basis.

 

   

Proved undeveloped reserve guidelines: reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered and they are scheduled to be drilled within the next five years, unless the specific circumstances justify a longer time.

 

   

Reserves estimation using new technologies: reserves may be estimated through the use of reliable technology in addition to flow tests and production history.

 

   

Reserves personnel and estimation process: additional disclosure is required regarding the qualifications of the chief technical person who oversees the reserves estimation process. We are also required to provide a general discussion of our internal controls used to assure the objectivity of the reserves estimate.

 

   

Non-traditional resources: the definition of oil and gas producing activities has expanded and focuses on the marketable product rather than the method of extraction.

We have adopted the rules upon inception.

 

77


Table of Contents

Evaluation and Review of Reserves

Our historical reserve estimates as of December 31, 2013 were prepared by Ryder Scott. A reserve audit is not the same as a financial audit and is less vigorous in nature than an independent reserve report where the independent reserve engineer determines the reserves on its own.

Ryder Scott is an independent petroleum engineering firm. The technical persons responsible for preparing our proved reserve estimates meet the requirements with regards to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Ryder Scott is a third-party engineering firm and does not own an interest in any of our properties and is not employed by us on a contingent basis.

Under SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” All of our proved reserves as of December 31, 2013 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. The proved reserves for our properties were estimated by performance methods, analogy or a combination of both methods. Approximately 90% of the proved producing reserves attributable to producing wells were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis, which utilized extrapolations of available historical production and pressure data. The remaining 10% of the proved producing reserves were estimated by analogy, or a combination of performance and analogy methods. The analogy method was used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate. All proved developed non-producing and undeveloped reserves were estimated by the analogy method.

To estimate economically recoverable proved reserves and related future net cash flows, Ryder Scott considered many factors and assumptions, including the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves included production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, available seismic data and historical well cost and operating expense data.

Our petroleum engineers and geoscience professionals work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves relating to our assets in the Permian Basin. Our internal technical team members met with our independent reserve engineers periodically during the period covered by the reserve report to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to the independent reserve engineers for our properties such as ownership interest, oil and gas production, well test data, commodity prices and operating and development costs. Our Vice President—Reservoir Engineering is primarily responsible for overseeing the

 

78


Table of Contents

preparation of all of our reserve estimates. Our Vice President—Reservoir Engineering is a petroleum engineer with over 30 years of reservoir and operations experience and our geoscience staff has an average of approximately 26 years of industry experience per person. Our technical staff uses historical information for our properties such as ownership interest, oil and gas production, well test data, commodity prices and operating and development costs.

The preparation of our proved reserve estimates are completed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:

 

   

review and verification of historical production data, which data is based on actual production as reported by our operators;

 

   

preparation of reserve estimates by our Vice President—Reservoir Engineering or under his direct supervision;

 

   

review by our Vice President—Reservoir Engineering of all of our reported proved reserves at the close of each quarter, including the review of all significant reserve changes and all new proved undeveloped reserves additions;

 

   

direct reporting responsibilities by our Vice President—Reservoir Engineering to our Chief Executive Officer;

 

   

verification of property ownership by our land department; and

 

   

no employee’s compensation is tied to the amount of reserves booked.

The following table presents our estimated net proved oil and natural gas reserves as of December 31, 2013 based on the reserve report prepared by Ryder Scott. The reserve report has been prepared in accordance with the rules and regulations of the SEC. All of our proved reserves included in the reserve report are located in the continental United States.

 

     As of
December 31,
2013
 

Estimated proved developed reserves:

  

Oil (Bbls)

     3,692,207   

Natural gas (Mcf)

     6,280,409   

Natural gas liquids (Bbls)

     609,303   

Total (BOE)

     5,348,245   

Estimated proved undeveloped reserves:

  

Oil (Bbls)

     3,525,873   

Natural gas (Mcf)

     4,981,176   

Natural gas liquids (Bbls)

     565,820   

Total (BOE)

     4,921,889   

Estimated Net Proved Reserves:

  

Oil (Bbls)

     7,218,080   

Natural gas (Mcf)

     11,261,585   

Natural gas liquids (Bbls)

     1,175,123   

Total (BOE)(1)

     10,270,135   

Percent proved developed

     52.1

 

(1)

Estimates of reserves as of December 31, 2013 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the year ended December 31, 2013, in accordance with revised SEC guidelines applicable to reserve estimates as of the end of such periods. The unweighted arithmetic average first day of

 

79


Table of Contents
  the month prices were $92.64 per Bbl for oil, $38.45 per Bbl for NGLs and $5.03 per Mcf for natural gas at December 31, 2013. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

As of December 31, 2013, our proved developed reserves totaled 3,692 MBbls of oil, 6,280 MMcf of natural gas and 609 MBbls of natural gas liquids, for a total of 5,348 MBOE. Of the total proved developed reserves, 93% were producing and the remaining 7% were from wells that had been stimulated but were not yet producing hydrocarbons. Producing reserves were from 200 vertical wells and 16 horizontal wells, of which Diamondback was the operator of 102 vertical wells and 11 horizontal wells and RSP Permian was the operator of 74 vertical wells and five horizontal wells. The remaining 24 vertical wells were operated by various other companies. Of the total 216 producing wells, Diamondback had a working interest in 133 wells. Non-producing reserves were from three vertical wells and two horizontal wells in various stages of completion and one well that was behind pipe recompletion.

The foregoing reserves are all located within the continental United States. Reserve engineering is a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. See “Risk Factors.” We have not filed any estimates of total, proved net oil or natural gas reserves with any federal authority or agency other than the SEC.

Additional information regarding our proved reserves can be found in the reserve report as of December 31, 2013, which is filed as Exhibit 99.1 to the registration statement of which this prospectus is a part.

Proved Undeveloped Reserves

As of December 31, 2013, our proved undeveloped reserves totaled 3,526 MBbls of oil, 4,981 MMcf of natural gas and 566 MBbls of natural gas liquids, for a total of 4,922 MBOE. PUDs will be converted from undeveloped to developed as the applicable wells begin production. Our undeveloped reserves were from 106 vertical wells and 24 horizontal wells, of which Diamondback was the operator of 69 vertical wells and 15 horizontal wells and RSP Permian was the operator of the remaining 37 vertical wells and nine horizontal wells. Diamondback also had a non-operated working interest in seven of the vertical wells and all of the nine horizontal wells that were operated by RSP Permian. 20 of the horizontal locations were Wolfcamp B wells, two were Lower Spraberry wells and two were Middle Spraberry wells.

All of our PUD drilling locations are scheduled to be drilled prior to the end of 2018. As of December 31, 2013, approximately 3.6% of our total proved reserves were classified as proved developed non-producing.

Changes in PUDs that occurred since the date of our acquisition of reserves through December 31, 2013 were primarily due to:

 

   

additions of 1,743 MBOE, primarily from 20 horizontal well locations, 16 in the Wolfcamp interval and four in Spraberry intervals, attributable to extensions resulting from strategic drilling of wells by us to delineate our acreage position;

 

   

the conversion of approximately 589 MBOE attributable to PUDs into proved developed reserves; and

 

80


Table of Contents
   

negative revisions of approximately 238 MBOE in PUDs primarily due to lowered natural gas and natural gas liquids forecasts associated with recent gas flaring.

Oil and Natural Gas Production Prices and Production Costs

Production and Price History

The following table sets forth information regarding the operators’ net production of oil, natural gas and natural gas liquids, all of which is from the Permian Basin in West Texas, and certain price and cost information for each of the periods indicated:

 

    Three Months Ended
March 31, 2014
    Period from  Inception
(September 18, 2013) to
December 31, 2013
 

Production Data:

   

Oil (Bbls)

    154,747        150,815   

Natural gas (Mcf)

    104,731        108,264   

Natural gas liquids (Bbl)

    23,171        19,971   

Combined volumes (BOE)

    195,373        188,830   

Daily combined volumes (BOE/d)

    2,171        1,798   

Average Prices:

   

Oil (per Bbl)

  $ 93.76      $ 92.07   

Natural gas (per Mcf)

    4.80        3.67   

Natural gas liquids (per Bbl)

    36.30        35.32   

Combined (per BOE)

    81.14        79.37   

Productive Wells

As of March 31, 2014, our operators owned a working interest in 232 productive wells located on the acreage in which we have a mineral interest. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities.

Acreage

The following table sets forth information as of March 31, 2014 relating to our gross acreage:

 

Basin

   Developed
Acreage(1)
     Undeveloped
Acreage(2)
     Total
Acreage
 

Permian

     8,400         6,404         14,804   

 

(1) Developed acres are acres spaced or assigned to productive wells and do not include undrilled acreage held by production under the terms of the lease. The value provided is for vertical wells only and are based on 40 acres per well for wells drilled as of March 31, 2014.
(2) Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.

 

81


Table of Contents

Drilling Results

The following table sets forth information with respect to the number of wells completed by our operators during the periods indicated. Each of these wells was drilled in Midland County in the Permian Basin of West Texas. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation among the number of productive wells drilled, the quantities of reserves found or the economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of return.

 

     Three Months
Ended
March 31, 2014
 

Development:

  

Productive

     7   

Dry

     —     

Exploratory:

  

Productive

     4   

Dry

     —     

Total

  

Productive

     11   

Dry

     —     

As of March 31, 2014, our operators had 19 wells in the process of drilling, completing or dewatering or shut in awaiting infrastructure that are not reflected in the above table.

Competition

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties. Further, oil and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal and fuel oils. Changes in the availability or price of oil and natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas.

Seasonal Nature of Business

Generally, demand for oil and natural gas decreases during the summer months and increases during the winter months. Certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Seasonal weather conditions and lease stipulations can limit drilling and producing activities and other oil and natural gas operations in a portion of our operating areas. These seasonal anomalies can pose challenges for our operators in meeting well drilling objectives and can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay operations.

 

82


Table of Contents

Regulation

The following disclosure describes regulation more directly associated with operators of oil and natural gas properties, including our current operators, and other owners of working interests in oil and natural gas properties. To the extent we elect in the future to engage in the exploration, development and production of oil and natural gas properties, we would be directly subject to the same regulations described below. For purposes of this section, where applicable, references to “we,” “us,” and “our” refer to Viper Energy Partners LP to the extent the partnership were to acquire working interests in the future as well as to any operators of our properties, including our current operators.

Oil and natural gas operations are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation affecting the oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases the cost of doing business.

Environmental Matters

Oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety. Numerous federal, state and local governmental agencies, such as the U.S. Environmental Protection Agency (“EPA”), issue regulations that often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing earthen pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from operations. The strict and joint and several liability nature of such laws and regulations could impose liability upon us regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our business and prospects.

Waste Handling

The Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute “solid wastes” that are subject to the less stringent requirements of non-hazardous waste provisions. However, we cannot assure you that the EPA or state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses.

 

83


Table of Contents

Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. Any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase the costs to manage and dispose of wastes.

Remediation of Hazardous Substances

The Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), also known as the “Superfund” law, and analogous state laws, generally imposes strict and joint and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” may be subject to strict and joint and several liability for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, would be subject to CERCLA and comparable state statutes. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such “hazardous substances” have been released.

Water Discharges

The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” the Safe Drinking Water Act (“SDWA”), the Oil Pollution Act (“OPA”), and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. These laws and regulations also prohibit certain activity in wetlands unless authorized by a permit issued by the U.S. Army Corps of Engineers. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. In addition, on October 20, 2011, the EPA announced a schedule to develop pre-treatment standards for wastewater discharges produced by natural gas extraction from shale formations. The EPA stated that it will gather data, consult with stakeholders, including ongoing consultation with industry, and solicit public comment on a proposed rule for shale gas in 2014. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions.

The Oil Pollution Act is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters.

 

84


Table of Contents

Noncompliance with the Clean Water Act or OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations.

Air Emissions

The federal Clean Air Act, as amended, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, on August 16, 2012, the EPA published final regulations under the federal Clean Air Act that establish new emission controls for oil and natural gas production and processing operations, which regulations are discussed in more detail below in “—Regulation of Hydraulic Fracturing.” These laws and regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas projects.

Climate Change

In December 2009, the EPA issued an Endangerment Finding that determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because, according to the EPA, emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allowed the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act, including the Tailoring Rule, which regulates emissions of GHGs from certain large stationary sources of emissions such as power plants or industrial facilities. The EPA adopted the Tailoring Rule in May 2010, and it became effective in January 2011, although on October 15, 2013, the U.S. Supreme Court announced it will review aspects of the Rule in 2014. Additionally, in September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010.

The EPA has continued to adopt GHG regulations of other industries, such as the September 2013 proposed GHG rule that, if finalized, would set new source performance standards for new coal-fired and natural-gas fired power plants, which could have an adverse effect on our financial condition and results of operations. As a result of this continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility. In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Although the U.S. Congress has not adopted such legislation at this time, it may do so in the future and many states continue to pursue regulations to reduce greenhouse gas emissions.

Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect the oil and natural gas industry, and state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

In addition, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornados and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some

 

85


Table of Contents

studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations.

Regulation of Hydraulic Fracturing

Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal SDWA regulates the underground injection of substances through the Underground Injection Control (“UIC”) program. Hydraulic fracturing generally is exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions. The EPA, however, has recently taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program, specifically as “Class II” UIC wells. In addition, on May 9, 2014, the EPA issued an Advanced Notice of Proposed Rulemaking seeking comment on the development of regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. Moreover, the EPA announced on October 20, 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such wastewater must meet before being transported to a treatment plant. As part of these studies, the EPA has requested that certain companies provide them with information concerning the chemicals used in the hydraulic fracturing process. These studies, depending on their results, could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise.

Legislation to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress.

On August 16, 2012, the EPA approved final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, or VOCs, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule seeks to achieve a 95% reduction in VOCs emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. The EPA intends to issue revised rules that are likely responsive to some of these requests. For example, on September 23, 2013, the EPA published an amendment extending compliance dates for certain storage vessels. At this point, we cannot predict the final regulatory requirements or the cost to comply with such requirements with any certainty. In addition, the U.S. Department of the Interior published a revised proposed rule on May 24, 2013 that would update existing regulation for hydraulic fracturing activities on federal lands, including requirements for disclosure, well bore integrity and handling of flowback water.

In addition, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. These ongoing or proposed studies, depending on their degree of pursuit and whether any meaningful results are obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities. The EPA is currently evaluating the potential impacts of hydraulic fracturing on drinking water resources. The White House Council on

 

86


Table of Contents

Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. The U.S. Department of Energy has conducted an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic-fracturing completion methods. Additionally, certain members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the SEC to investigate the natural-gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shale formations by means of hydraulic fracturing, and the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates.

Several states, including Texas, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. The Texas Legislature adopted new legislation requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic fracturing process, effective as of September 1, 2011. The Texas Railroad Commission has adopted rules and regulations implementing this legislation that apply to all wells for which the Railroad Commission issues an initial drilling permit after February 1, 2012. The new law requires that the well operator disclose the list of chemical ingredients subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission.

There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.

Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases the cost of doing business, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation and sale for resale of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). Federal and state regulations govern the

 

87


Table of Contents

price and terms for access to oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.

Although oil and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. We cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of condensate and oil and natural gas liquids are not currently regulated and are made at market prices.

Drilling and Production

The operations of our operators are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which we operate also regulate one or more of the following:

 

   

the location of wells;

 

   

the method of drilling and casing wells;

 

   

the timing of construction or drilling activities, including seasonal wildlife closures;

 

   

the rates of production or “allowables”;

 

   

the surface use and restoration of properties upon which wells are drilled;

 

   

the plugging and abandoning of wells; and

 

   

notice to, and consultation with, surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas that our operators can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells or to limit the number of locations we can drill.

Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where we operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the U.S. Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.

Natural Gas Sales and Transportation

Historically, federal legislation and regulatory controls have affected the price and marketing of natural gas. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price

 

88


Table of Contents

controls for sales of domestic natural gas sold in “first sales.” Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties.

FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which our operators may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that our operators produce, as well as the revenues our operators receive for sales of natural gas and release of natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.

Under FERC’s current regulatory regime, transmission services must be provided on an open-access, nondiscriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. Although its policy is still in flux, FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our operators’ costs of transporting gas to point-of-sale locations.

Oil Sales and Transportation

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

Crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act and intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to our operators to the same extent as to our or their competitors.

State Regulation

Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on the market value of oil production and a 7.5% severance tax on the market value of natural gas

 

89


Table of Contents

production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations our operators can drill.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.

Employees

We are managed and operated by the board of directors and executive officers of our general partner. However, neither we, our subsidiary nor our general partner have any employees. All of the employees that will conduct our business, including our executive officers, will be employed by Diamondback. In connection with the closing of this offering, we and our general partner will enter into an advisory services agreement with Wexford pursuant to which Wexford will provide general financial and strategic advisory services to us and our general partner.

As of March 31, 2014, Diamondback had 79 full-time employees. None of Diamondback’s employees are represented by labor unions or covered by any collective bargaining agreements. Diamondback also hires independent contractors and consultants involved in land, technical, regulatory and other disciplines to assist its full time employees. Please read “Management” and “Certain Relationships and Related Party Transactions.”

Facilities

Diamondback leases office space for our principal executive offices in Midland, Texas. We believe that these facilities are adequate for our current operations.

Legal Proceedings

Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities. In the opinion of our management, none of the pending litigation, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations.

 

90


Table of Contents

MANAGEMENT

Management of Viper Energy Partners LP

We are managed and operated by the board of directors and executive officers of our general partner, the latter of whom will be employed by Diamondback.

Diamondback owns all the membership interests in our general partner. As a result of owning our general partner, Diamondback will have the right to appoint all members of the board of directors of our general partner, including the independent directors. Our unitholders will not be entitled to elect our general partner or its directors or otherwise directly participate in our management or operation. Our general partner owes certain duties to our unitholders as well as a fiduciary duty to its owner.

Upon the closing of this offering, we expect that our general partner will have five directors, one of whom will be independent as defined under the independence standards established by NASDAQ and the Exchange Act. W. Wesley Perry will serve as the initial independent member of the board of directors of our general partner. In accordance with the rules of NASDAQ, Diamondback will appoint one additional independent member within 90 days of the effective date of the registration statement of which this prospectus forms a part and one additional independent member within one year of such effective date, bringing the total number of directors on the board of directors of our general partner to seven. NASDAQ does not require a listed publicly traded partnership, such as ours, to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating and corporate governance committee. However, our general partner is required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by NASDAQ and the Exchange Act, subject to the transitional relief during the one-year period following completion of this offering.

The executive officers of our general partner will manage the day-to-day affairs of our business. All of the executive officers of our general partner also serve as executive officers of Diamondback. Our executive officers listed below will allocate their time between managing our business and the business of Diamondback. Our executive officers intend, however, to devote as much time as is necessary for the proper conduct of our business.

Our partnership agreement requires us to reimburse our general partner and its affiliates, including Diamondback, for all expenses they incur and payments they make on our behalf in connection with operating our business. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us. In addition, in connection with the closing of this offering, we and our general partner will enter into an advisory services agreement with Wexford pursuant to which Wexford will provide general finance and advisory services in exchange for a fee and certain expense reimbursement. Please read “Certain Relationships and Related Party Transactions—Agreements and Transactions with Affiliates in Connection with this Offering.”

 

91


Table of Contents

Executive Officers and Directors of Our General Partner

The following table shows information for the executive officers and directors of our general partner upon the consummation of this offering. Directors hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Executive officers serve at the discretion of the board. There are no family relationships among any of our directors or executive officers.

 

Name

  

Age

(as of March 31,
2014)

    

Position With Our General Partner

Travis D. Stice

     52       Chief Executive Officer, Director

Teresa L. Dick

     44       Chief Financial Officer, Senior Vice President and Assistant Secretary

Russell Pantermuehl

     54       Vice President—Reservoir Engineering

Randall J. Holder

     60       Vice President, General Counsel and Secretary

Steven E. West

     53       Executive Chairman, Director

W. Wesley Perry

     57       Director Nominee

Michael L. Hollis

     38       Director Nominee

James L. Rubin

     29       Director Nominee

Travis D. Stice. Mr. Stice has served as Chief Executive Officer and a director of our general partner since February 2014. He has served as Chief Executive Officer of Diamondback since January 2012 and as a director since November 2012. Prior to his current position with Diamondback, Mr. Stice served as its President and Chief Operating Officer from April 2011 to January 2012. Mr. Stice has also served on the board of managers of MidMar Gas LLC, or MidMar, an entity that owns a gas gathering system and processing plant, since 2011 and as Vice President and Secretary of MidMar since April 2012. From November 2010 to April 2011, Mr. Stice served as a Production Manager of Apache Corporation, an oil and gas exploration company. Mr. Stice served as a Vice President of Laredo Petroleum Holdings, Inc, an oil and gas exploration company, from September 2008 to September 2010 and as a Development Manager of ConocoPhillips/Burlington Resources Mid-Continent Business Unit, an oil and gas exploration company, from April 2006 until August 2008. Prior to that, Mr. Stice held a series of positions at Burlington Resources, an oil and gas exploration company, most recently as a General Manager, Engineering, Operations and Business Reporting of its Mid Continent Division from January 2001 until Burlington Resources’ acquisition by ConocoPhillips in March 2006. Mr. Stice has over 26 years of experience in production operations, reservoir engineering, production engineering and unconventional oil and gas exploration and over 18 years of management experience. Mr. Stice graduated from Texas A&M University with a Bachelor of Science degree in Petroleum Engineering. He is a registered engineer in the State of Texas, and is a 25-year member of the Society of Petroleum Engineers.

We believe Mr. Stice’s expertise and extensive industry and executive management experience, including at Diamondback, make him a valuable asset to the board of directors of our general partner.

Teresa L. Dick. Ms. Dick has served as Chief Financial Officer, Senior Vice President and Assistant Secretary of our general partner since February 2014. She has also served as Diamondback’s Chief Financial Officer and Senior Vice President since November 2009 and as its Corporate Controller from November 2007 until November 2009. From June 2006 to November 2007, Ms. Dick held a key management position as the Controller/Tax Director at Hiland Partners, a publicly traded midstream energy master limited partnership. Ms. Dick has over 19 years of accounting experience, including over eight years of public company experience in both audit and tax areas. Ms. Dick received her Bachelor of Business Administration degree in Accounting from the University of Northern Colorado. She is a certified public accountant and a member of the American Institute of CPAs and the Council of Petroleum Accountants Societies.

Russell Pantermuehl. Mr. Pantermuehl has served as Vice President—Reservoir Engineering of our general partner since February 2014. He has also served as Diamondback’s Vice President—Reservoir Engineering since

 

92


Table of Contents

August 2011, and, prior to his current position at Diamondback, Mr. Pantermuehl served as a reservoir engineering supervisor for Concho Resources Inc., an oil and gas exploration company, from March 2010 to August 2011. Mr. Pantermuehl worked for ConocoPhillips Company as a reservoir engineering advisor from January 2005 to March 2010. Mr. Pantermuehl also worked as an independent consultant in the oil and gas industry from March 2000 to December 2004. He received a Bachelor of Science degree in Petroleum Engineering from Texas A&M University.

Randall J. Holder. Mr. Holder has served as Vice President, General Counsel and Secretary of our general partner since February 2014. Mr. Holder joined Diamondback in November 2011 as General Counsel and Vice President responsible for legal and human resources and currently also serves as Secretary. Prior to joining Diamondback, Mr. Holder served as General Counsel and Vice President for Great White Energy Services LLC, an oilfield services company, from November 2008 to November 2011. He served as Executive Vice President and General Counsel for R.L. Hudson and Company, a supplier of molded rubber and plastic components, from February 2007 to October 2008. He was in private practice of law and a member of Holder Betz LLC from February 2005 to February 2007. Mr. Holder served as Vice President and Assistant General Counsel for Dollar Thrifty Automotive Group, a vehicle rental company, from January 2003 to February 2005 and as Vice President and General Counsel for Thrifty Rent-A-Car System, Inc., a vehicle rental company, from September 1996 to December 2002. He also served as Vice President and General Counsel for Pentastar Transportation Group, Inc. from November 1992 to September 1996, which was wholly-owned by Chrysler Corporation. Mr. Holder started his legal career with Tenneco Oil Company where he served as a Division Attorney providing legal services to the company’s mid-continent division for ten years. He received a Juris Doctorate degree from Oklahoma City University.

Steven E. West. Mr. West has served as a director and Executive Chairman of our general partner since February 2014. Mr. West has also served as a director of Diamondback since December 2011 and as its Chairman of the Board since October 2012. He served as Diamondback’s Chief Executive Officer from January 1, 2009 to December 31, 2011. Since January 2011, Mr. West has been a partner at Wexford Capital LP, focusing on Wexford’s private equity energy investments. From August 2006 until December 2010, Mr. West served as senior portfolio advisor at Wexford. From August 2003 until August 2006, he was the chief financial officer of Sunterra Corporation, a former Wexford portfolio company. From December 1993 until July 2003, Mr. West held senior financial positions at Coast Asset Management and IndyMac Bank. Prior to that, he worked at First Nationwide Bank, Lehman Brothers and Peat Marwick Mitchell & Co., the predecessor of KPMG LLP. Mr. West holds a Bachelor of Science degree in Accounting from California State University, Chico.

We believe that Mr. West’s background in finance, accounting and private equity energy investments, as well as his executive management skills developed as part of his career with Wexford, its portfolio companies and other financial institutions qualify him to serve on the board of directors of our general partner.

W. Wesley Perry. Mr. Perry is a nominee for the board of directors of our general partner. He served as President of EGL Resources, Inc., an oil and gas operations company based in Texas and New Mexico, from January 1994 until July 2008, before becoming the Chief Executive Officer. He has also served as manager of PBEX, LLC since July 2012. Mr. Perry has served as a director of Genie Energy, Ltd. from September 2009 and is chairman of the audit committee. He also serves as Chairman of Genie Energy International Corporation. He served as a director of UTG, Inc. from July 2005 to June 2013. He served as a director of American Capital Insurance Company and Texas Imperial Life Insurance Company from 2006 to 2009 and as a director of Western National Bank from 2005 to 2009. Mr. Perry has owned and operated SES Investments, Ltd., an oil and gas investment company, since 1980. He served as the Mayor of Midland, Texas, from January 2008 through January 2014. He also served on the Midland City Council as an at-large councilperson from 2002 to 2008. Mr. Perry holds a Bachelor of Science degree in Engineering from the University of Oklahoma.

We believe that Mr. Perry’s extensive experience in the oil and gas industry and his strong financial background qualify him to serve on the board of directors of our general partner. His appointment to the board of directors of our general partner will become effective as of the time that our common units are first listed on the NASDAQ Global Select Market.

 

93


Table of Contents

Michael L. Hollis. Mr. Hollis is a nominee for the board of directors of our general partner. He has served as Vice President—Drilling of Diamondback since September 2011. Prior to his current position with Diamondback, Mr. Hollis served in various roles, most recently as drilling manager at Chesapeake Energy Corporation, an oil and gas exploration company, from June 2006 to September 2011. He worked for ConocoPhillips Company as a senior drilling engineer from January 2002 to June 2006 and as a process engineer from 2001 to 2003. Mr. Hollis also worked as a production engineer for Burlington Resources from 1998 to 2001 as well as from June 2003 to January 2004. Mr. Hollis received his Bachelor of Science degree in Chemical Engineering from Louisiana State University.

We believe that Mr. Hollis’ extensive experience in the oil and gas industry, including at Diamondback, qualifies him to serve on the board of directors of our general partner. His appointment to the board of directors of our general partner will become effective as of the time that our common units are first listed on the NASDAQ Global Select Market.

James L. Rubin. Mr. Rubin is a nominee for the board of directors of our general partner. He has served as a partner at Wexford since 2012 and currently serves as Portfolio Manager and Co-Head of Equities and as a member of Wexford’s hedge fund investment committee. From 2006 to 2012, he served as an analyst and later as Vice President, focusing on Wexford’s public and private energy investments. Mr. Rubin graduated cum laude from Yale University with a Bachelor of Arts degree with honors in political science and economics.

We believe that Mr. Rubin’s strong financial background qualifies him to serve on the board of directors of our general partner. His appointment to the board of directors of our general partner will become effective as of the time that our common units are first listed on the NASDAQ Global Select Market.

Director Independence

In accordance with the rules of NASDAQ, Diamondback must appoint at least one independent director by the time our common units are first listed on NASDAQ Global Select Market, one additional independent member within 90 days of the effective date of the registration statement of which this prospectus forms a part, and one additional independent member within one year of the effective date of the registration statement.

Committees of the Board of Directors

The board of directors of our general partner will have an audit committee and a conflicts committee. We do not expect that we will have a compensation committee, but rather that the board of directors of our general partner will have authority over compensation matters.

Audit Committee

We are required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by NASDAQ and Rule 10A-3 promulgated under the Exchange Act, subject to certain transitional relief during the one-year period following consummation of this offering as described above. W. Wesley Perry will serve as the initial member of the audit committee. The audit committee will assist the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee will have the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm, and pre-approve any non-audit services and tax services to be rendered by our independent registered public accounting firm. The audit committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to the audit committee and our management, as necessary.

 

94


Table of Contents

Conflicts Committee

We expect that at least one independent member of the board of directors of our general partner will serve on a conflicts committee to review specific matters that the board believes may involve conflicts of interest and determines to submit to the conflicts committee for review. The conflicts committee will determine if the resolution of the conflict of interest is in our best interest. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, including Diamondback, and must meet the independence standards established by NASDAQ and the Exchange Act to serve on an audit committee of a board of directors, along with other requirements in our partnership agreement. Any matters approved by the conflicts committee will be conclusively deemed to be approved by us and all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders.

Indemnification Agreements

We and our general partner will enter into indemnification agreements with each of the current directors and executive officers of our general partner effective upon the closing of this offering. These agreements will require us to indemnify these individuals to the fullest extent permitted by law against expenses incurred as a result of any proceeding in which they are involved by reason of their service to us and, if requested, to advance expenses incurred as a result of any such proceeding. We also intend to enter into indemnification agreements with future directors and executive officers of our general partner.

 

95


Table of Contents

EXECUTIVE COMPENSATION AND OTHER INFORMATION

Compensation Discussion and Analysis

We are a new subsidiary of Diamondback, formed in February 2014, consisting of certain assets that Diamondback is contributing to us in connection with this offering. Accordingly, neither we nor our general partner incurred any cost or liability with respect to management compensation or retirement benefits for directors or executive officers for any periods prior to our formation date. As a result, we have no historical compensation information to present. We currently do not have a compensation committee.

Our general partner has the sole responsibility for conducting our business and for managing our operations, and its board of directors and executive officers make decisions on our behalf. We do not and will not directly employ any of the persons responsible for managing our business. Our executive officers will be employed and compensated by Diamondback or a subsidiary of Diamondback. All of the initial executive officers that will be responsible for managing our day-to-day affairs are also current executive officers of Diamondback.

All of the executive officers of our general partner will have responsibilities to both us and Diamondback, and we expect that our executive officers will allocate their time between managing our business and managing the business of Diamondback. Since all of our executive officers will be employed by Diamondback or one of its subsidiaries, the responsibility and authority for compensation-related decisions for our executive officers will reside with the Diamondback compensation committee. Diamondback has the ultimate decision-making authority with respect to the total compensation of the executive officers that are employed by Diamondback including, subject to the terms of the partnership agreement, the portion of that compensation that is allocated to us pursuant to Diamondback’s allocation methodology. Any such compensation decisions will not be subject to any approvals by the board of directors of our general partner or any committees thereof. However, all determinations with respect to awards that may be made to our executive officers, key employees, and independent directors under any long-term incentive plan we adopt will be made by the board of directors of our general partner or a committee thereof that may be established for such purpose. Please see the description of the long-term incentive plan we intend to adopt prior to the completion of this offering below under the heading “Long-Term Incentive Plan.”

The executive officers of our general partner, as well as the employees of Diamondback who provide services to us, may participate in employee benefit plans and arrangements sponsored by Diamondback, including plans that may be established in the future. Certain of our general partner’s executive officers and employees and certain employees of Diamondback who provide services to us currently hold grants under Diamondback’s equity incentive plans and will retain these grants after the completion of this offering. Except with respect to any awards that may be granted under the long-term incentive plan we intend to adopt prior to the completion of this offering, our executive officers will not receive separate amounts of compensation in relation to the services they provide to us. In accordance with the terms of our partnership agreement, we will reimburse Diamondback for compensation related expenses attributable to the portion of the executive’s time dedicated to providing services to us. Please read “The Partnership Agreement—Reimbursement of Expenses.” Although we will bear an allocated portion of Diamondback’s costs of providing compensation and benefits to employees who serve as executive officers of our general partner, we will have no control over such costs and will not establish or direct the compensation policies or practices of Diamondback. Except with respect to any awards granted under the long-term incentive plan we intend to adopt prior to the completion of this offering, we expect that compensation paid or awarded by us in 2014 will consist only of the portion of compensation paid by Diamondback that is allocated to us and our general partner pursuant to Diamondback’s allocation methodology and subject to the terms of the partnership agreement.

At the closing of this offering, we intend to grant awards of an aggregate of 2,000,000 unit options under the long-term incentive plan to our executive officers. Each unit option entitles the recipient to purchase one of our

 

96


Table of Contents

common units. It is expected that the exercise price of the unit options will equal the fair market value of our common units on the date of grant. Subject to accelerated vesting upon certain specified events, a third of the unit options will vest each year, and the options will be automatically exercised, to the extent vested, on the earlier to occur of the three year anniversary of the date of grant or the occurrence of a change in control.

We expect that future compensation for our executive officers will be structured in a manner similar to that currently used by Diamondback to compensate its named executive officers. If additional details regarding the terms of future compensatory arrangements for our executive officers are known prior to the effective date of this offering, such details will be outlined in further detail herein. In the future, as Diamondback and our general partner formulate and implement the compensation programs for our executive officers, Diamondback, our general partner or both may provide different or additional compensation components, benefits or perquisites to our executive officers, to ensure they are provided with a balanced, comprehensive and competitive compensation structure.

Long-Term Incentive Plan

In order to incentivize our management and directors following the completion of this offering to continue to grow our business, the board of directors of our general partner intends to adopt a long-term incentive plan, or the LTIP, for employees, officers, consultants and directors of our general partner and any of its affiliates, including Diamondback, who perform services for us. Our general partner intends to implement the LTIP prior to the completion of this offering to provide maximum flexibility with respect to the design of compensatory arrangements for individuals providing services to us; however, at this time, neither we nor our general partner has made any decisions regarding any specific grants under the LTIP in conjunction with this offering or in the near term, other than grants in connection with the appointment of non-employee directors

The description of the LTIP set forth below is a summary of the material features of the LTIP that our general partner intends to adopt. This summary, however, does not purport to be a complete description of all the provisions of the LTIP that will be adopted and represents only the general partner’s current expectations regarding the LTIP. This summary is qualified in its entirety by reference to the LTIP, the form of which is filed as an exhibit to this registration statement. The purpose of the LTIP is to provide a means to attract and retain individuals who are essential to our growth and profitability and to encourage them to devote their best efforts to advancing our business by affording such individuals a means to acquire and maintain ownership of awards, the value of which is tied to the performance of our common units. We expect that the LTIP will provide for the grant of unit options, unit appreciation rights, restricted units, unit awards, phantom units, distribution equivalent rights, cash awards, performance awards, other unit-based awards and substitute awards (collectively, “awards”). These awards are intended to align the interests of employees, officers, consultants and directors with those of our unitholders and to give such individuals the opportunity to share in our long-term performance. Any awards that are made under the LTIP will be approved by the board of directors of our general partner or a committee thereof that may be established for such purpose. We will be responsible for the cost of awards granted under the LTIP.

Administration

The LTIP will be administered by the board of directors of our general partner or an alternative committee appointed by the board of directors of our general partner, which we refer to together as the “committee” for purposes of this summary. The committee will administer the LTIP pursuant to its terms and all applicable state, federal, or other rules or laws. The committee will have the power to determine to whom and when awards will be granted, determine the amount of awards (measured in cash or in shares of our common units), proscribe and interpret the terms and provisions of each award agreement (the terms of which may vary), accelerate the vesting provisions associated with an award, delegate duties under the LTIP and execute all other responsibilities

 

97


Table of Contents

permitted or required under the LTIP. In the event that the committee is not comprised of “nonemployee directors” within the meaning of Rule 16b-3 under the Exchange Act, the full board of directors or a subcommittee of two or more nonemployee directors will administer all awards granted to individuals that are subject to Section 16 of the Exchange Act.

Securities to be Offered

The maximum aggregate number of common units that may be issued pursuant to any and all awards under the LTIP shall not exceed 9,144,000 common units, subject to adjustment due to recapitalization or reorganization, or related to forfeitures or expiration of awards, as provided under the LTIP.

If any common units subject to any award are not issued or transferred, or cease to be issuable or transferable for any reason, including (but not exclusively) because units are withheld or surrendered in payment of taxes or any exercise or purchase price relating to an award or because an award is forfeited, terminated, expires unexercised, is settled in cash in lieu of common units, or is otherwise terminated without a delivery of units, those common units will again be available for issue, transfer, or exercise pursuant to awards under the LTIP, to the extent allowable by law. Common units to be delivered pursuant to awards under our LTIP may be common units acquired by our general partner in the open market, from any other person, directly from us, or any combination of the foregoing.

Awards

Unit Options

We may grant unit options to eligible persons. Unit options are rights to acquire common units at a specified price. The exercise price of each unit option granted under the LTIP will be stated in the unit option agreement and may vary; provided, however, that, the exercise price for an unit option must not be less than 100% of the fair market value per common unit as of the date of grant of the unit option unless that unit option is intended to otherwise comply with the requirements of Section 409A of the Internal Revenue Code of 1986, as amended, or the Code. Unit options may be exercised in the manner and at such times as the committee determines for each unit option, unless that unit option is determined to be subject to Section 409A of the Code, in which case the unit option will be subject to any necessary timing restrictions imposed by the Code or federal regulations. The committee will determine the methods and form of payment for the exercise price of a unit option and the methods and forms in which common units will be delivered to a participant.

Unit Appreciation Rights

A unit appreciation right is the right to receive, in cash or in common units, as determined by the committee, an amount equal to the excess of the fair market value of one common unit on the date of exercise over the grant price of the unit appreciation right. The committee will be able to make grants of unit appreciation rights and will determine the time or times at which a unit appreciation right may be exercised in whole or in part. The exercise price of each unit appreciation right granted under the LTIP will be stated in the unit appreciation right agreement and may vary; provided, however, that, the exercise price must not be less than 100% of the fair market value per common unit as of the date of grant of the unit appreciation right, unless that unit appreciation right is intended to otherwise comply with the requirements of Section 409A of the Code.

Restricted Units

A restricted unit is a grant of a common unit subject to a risk of forfeiture, performance conditions, restrictions on transferability and any other restrictions imposed by the committee in its discretion. Restrictions may lapse at such times and under such circumstances as determined by the committee. The committee shall provide, in the restricted unit agreement, whether the restricted unit will be forfeited upon certain terminations of employment. Unless otherwise determined by the committee, a common unit distributed in connection with a unit split or unit dividend, and other property distributed as a dividend, will generally be subject to restrictions and a risk of forfeiture to the same extent as the restricted unit with respect to which such common unit or other property has been distributed.

 

98


Table of Contents

Unit Awards

The committee will be authorized to grant common units that are not subject to restrictions. The committee may grant unit awards to any eligible person in such amounts as the committee, in its sole discretion, may select.

Phantom Units

Phantom units are rights to receive common units, cash or a combination of both at the end of a specified period. The committee may subject phantom units to restrictions (which may include a risk of forfeiture) to be specified in the phantom unit agreement that may lapse at such times determined by the committee. Phantom units may be satisfied by delivery of common units, cash equal to the fair market value of the specified number of common units covered by the phantom unit or any combination thereof determined by the committee. Except as otherwise provided by the committee in the phantom unit agreement or otherwise, phantom units subject to forfeiture restrictions may be forfeited upon termination of a participant’s employment prior to the end of the specified period. Cash distribution equivalents may be paid during or after the vesting period with respect to a phantom unit, as determined by the committee.

Distribution Equivalent Rights

The committee will be able to grant distribution equivalent rights in tandem with awards under the LTIP (other than unit awards or an award of restricted units), or distribution equivalent rights may be granted alone. Distribution equivalent rights entitle the participant to receive cash equal to the amount of any cash distributions made by us during the period the distribution equivalent right is outstanding. Payment of cash distributions pursuant to a distribution equivalent right issued in connection with another award may be subject to the same vesting terms as the award to which it relates or different vesting terms, in the discretion of the committee.

Cash Awards

The LTIP will permit the grant of awards denominated in and settled in cash. Cash awards may be based, in whole or in part, on the value or performance of a common unit.

Performance Awards

The committee may condition the right to exercise or receive an award under the LTIP, or may increase or decrease the amount payable with respect to an award, based on the attainment of one or more performance conditions deemed appropriate by the committee.

Other Unit-Based Awards

The LTIP will permit the grant of other unit-based awards, which are awards that may be based, in whole or in part, on the value or performance of a common unit or are denominated or payable in common units. Upon settlement, these other unit-based awards may be paid in common units, cash or a combination thereof, as provided in the award agreement.

Substitute Awards

The LTIP will permit the grant of awards in substitution for similar awards held by individuals who become employees, consultants or directors as a result of a merger, consolidation, or acquisition by or involving us, an affiliate of another entity, or the assets of another entity. Such substitute awards that are unit options or unit appreciation rights may have exercise prices less than 100% of the fair market value per common unit on the date of the substitution if such substitution complies with Section 409A of the Code and its regulations and other applicable laws and exchange rules.

 

99


Table of Contents

Miscellaneous

Tax Withholding

At our discretion, and subject to conditions that the committee may impose, a participant’s minimum statutory tax withholding with respect to an award may be satisfied by withholding from any payment related to an award or by the withholding of common units issuable pursuant to the award based on the fair market value of the common units.

Anti-Dilution Adjustments

If any “equity restructuring” event occurs that could result in an additional compensation expense under Financial Accounting Standards Board Accounting Standards Codification Topic 718 (“FASB ASC Topic 718”) if adjustments to awards with respect to such event were discretionary, the committee will equitably adjust the number and type of units covered by each outstanding award and the terms and conditions of each such award to equitably reflect the restructuring event. With respect to a similar event that would not result in a FASB ASC Topic 718 accounting charge if adjustment to awards were discretionary, the committee shall have complete discretion to adjust awards in the manner it deems appropriate. In the event the committee makes any adjustment in accordance with the foregoing provisions, a corresponding and proportionate adjustment shall be made with respect to the maximum number of units available under the LTIP and the kind of units or other securities available for grant under the LTIP. Furthermore, in the case of (i) a subdivision or consolidation of the common units (by reclassification, split or reverse split or otherwise), (ii) a recapitalization, reclassification, or other change in our capital structure or (iii) any other reorganization, merger, combination, exchange, or other relevant change in capitalization of our equity, then a corresponding and proportionate adjustment shall be made in accordance with the terms of the LTIP, as appropriate, with respect to the maximum number of units available under the LTIP, the number of units that may be acquired with respect to an award, and, if applicable, the exercise price of an award, in order to prevent dilution or enlargement of awards as a result of such events.

Change in Control

Upon a “change in control” (as defined in the LTIP), the committee may, in its discretion, (i) remove any forfeiture restrictions applicable to an award, (ii) accelerate the time of exercisability or vesting of an award, (iii) require awards to be surrendered in exchange for a cash payment, (iv) cancel unvested awards without payment or (v) make adjustments to awards as the committee deems appropriate to reflect the change in control.

Termination of Employment or Service

The consequences of the termination of a participant’s employment, consulting arrangement or membership on the board of directors will be determined by the committee in the terms of the relevant award agreement.

Director Compensation

We and our general partner were formed in February 2014 and, as such, have not accrued or paid any obligations with respect to compensation for directors for any periods prior to our formation date.

The executive officers or employees of our general partner or of Diamondback who also serve as directors of our general partner will not receive additional compensation for their service as a director of our general partner. Directors of our general partner who are not executive officers or employees of our general partner or of Diamondback will receive compensation as “non-employee directors” as set by our general partner’s board of directors.

Effective as of the closing of this offering, each non-employee director will receive a compensation package that will consist of an annual cash retainer of $47,500 plus an additional annual payment of $15,000 for the chairperson and $10,000 for each other member of the audit committee and $10,000 for the chairperson and

 

100


Table of Contents

$5,000 for each other member of each other committee. Our directors will also receive a fee of $1,000 for attending each in-person meeting of the board of directors or its committees and $500 for attending each telephone meeting. In addition, our directors will be reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or its committees. Each non-employee director may receive grants of equity-based awards under the long-term incentive plan we intend to adopt prior to the completion of this offering from time to time for so long as he or she serves as a director.

Each member of the board of directors of our general partner will be indemnified for his actions associated with being a director to the fullest extent permitted under Delaware law.

 

101


Table of Contents

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table presents information regarding the beneficial ownership of our common units following this offering and the other formation transactions by:

 

   

our general partner;

 

   

each of our general partner’s directors, director nominees and executive officers;

 

   

each unitholder known by us to beneficially hold 5% or more of our common units; and

 

   

all of our general partner’s directors and executive officers as a group.

Beneficial ownership is determined under the rules of the SEC and generally includes voting or investment power with respect to securities. Unless otherwise noted, the address for each beneficial owner listed below is 500 West Texas Avenue, Suite 1200, Midland, Texas 79701.

The following table does not include any awards granted under the long-term incentive plan in connection with this offering or any units that may be purchased pursuant to our directed unit program. Please read “Executive Compensation and Other Information” and “Underwriting—Directed Unit Program.”

 

Name of Beneficial Owner

   Common Units
Beneficially
Owned
     Percentage of
Common Units
Beneficially
Owned
 

Diamondback(1)

     71,200,000         93

Viper Energy Partners GP LLC

     —           —     

Travis D. Stice

     —           —     

Teresa L. Dick

     —           —     

Russell Pantermuehl

     —           —     

Randall J. Holder

     —           —     

Steven E. West

     —           —     

W. Wesley Perry

     —           —     

Michael L. Hollis

     —           —     

James L. Rubin

     —           —     

All directors and executive officers as a group (5 persons)

     —           —     

 

(1) Diamondback Energy, Inc. is a publicly traded company. The directors of Diamondback are Travis D. Stice, Steven E. West, Michael P. Cross, David L. Houston and Mark L. Plaumann. The units owned by Diamondback, as reflected in the table, are common units. The table assumes the underwriters do not exercise their option to purchase 750,000 additional common units and such units are therefore issued to Diamondback upon the option’s expiration. If such option is exercised in full, Diamondback will beneficially own 70,450,000 common units, or 92% of total common units outstanding.

The following table sets forth, as of April 1, 2014, the number of shares of common stock of Diamondback beneficially owned by Wexford and each of the directors, director nominees and executive officers of our general partner and all directors and executive officers of our general partner as a group.

 

     Shares of Diamondback
Common Stock Beneficially Owned(1)
 

Name of Beneficial Owner

   Amount and
Nature of
Beneficial
    Ownership    
     Percentage of
Class
 

DB Energy Holdings LLC(2)

     9,310,128         18.4

Travis D. Stice(3)

     178,990         *   

Teresa L. Dick(4)

     17,698         *   

Russell Pantermuehl(5)

     11,625         *   

Randall J. Holder(6)

    
—  
  
     —     

Steven E. West

     —           —     

W. Wesley Perry

     —           —     

Michael L. Hollis(7)

     5,970         *   

James L. Rubin

     —           —     

All directors and executive officers as a group (5 persons)

     208,313         *   

 

102


Table of Contents

 

* Less than 1%
(1) Beneficial ownership is determined in accordance with SEC rules. In computing percentage ownership of each person, shares of common stock subject to options held by that person that are exercisable as of April 1, 2014, or exercisable within 60 days of April 1, 2014, are deemed to be beneficially owned. These shares, however, are not deemed outstanding for the purpose of computing the percentage ownership of each other person. The percentage of shares beneficially owned is based on 50,700,099 shares of common stock outstanding as of April 1, 2014. Unless otherwise indicated, all amounts exclude shares issuable upon the exercise of outstanding options and vesting of restricted stock units that are not exercisable and/or vested as of April 1, 2014 or within 60 days of April 1, 2014.

 

(2) Based solely on Schedule 13D/A filed with the SEC on March 26, 2014 by DB Energy Holdings LLC (“DB Holdings”), Wexford Spectrum Fund, L.P. (“WSF”), Wexford Catalyst Fund, L.P. (“WCF”), Spectrum Intermediate Fund Limited (“SIF”), Catalyst Intermediate Fund Limited (“CIF,” and together with DB Holdings, WSF, WCF and SIF, the “Funds”), Wexford, Wexford GP LLC (“Wexford GP”), Charles E. Davidson (“Mr. Davidson”), and Joseph M. Jacobs (“Mr. Jacobs”). DB Holdings is a holding company managed by Wexford. WSF, WCF, SIF and CIF are investment funds managed by Wexford. Wexford is an investment advisor registered with the SEC, and manages a series of investment funds. Wexford GP is the general partner of Wexford. Mr. Davidson and Mr. Jacobs are the managing members of Wexford GP. DB has shared voting and dispositive power over 9,310,128 shares. WSF has shared voting and dispositive power over 111,074 shares. WCF has shared voting and dispositive power over 17,553 shares. SIF has shared voting and dispositive power over 374,331 shares. CIF has shared voting and dispositive power over 73,824 shares. Wexford, Wexford GP, Mr. Davidson and Mr. Jacobs have shared voting and dispositive power over 9,893,576 shares. Wexford may, by reason of its status as manager or investment manager of the Funds, be deemed to own beneficially the securities of which the Funds possess beneficial ownership. Wexford GP may, as the General Partner of Wexford, be deemed to own beneficially the securities of which the Funds possess beneficial ownership. Each of Mr. Davidson and Mr. Jacobs may, by reason of his status as a controlling person of Wexford GP, be deemed to own beneficially the securities of which the Funds possess beneficial ownership. Each of Wexford, Wexford GP, Mr. Davidson and Mr. Jacobs disclaims beneficial ownership of the securities owned by the Funds except, in the case of Mr. Davidson and Mr. Jacobs, to the extent of their respective interests in the Funds.

 

(3) Includes shares issuable upon exercise of options to purchase 150,000 shares of Diamondback common stock, all of which have either vested or will vest within 60 days of April 1, 2014, shares issuable upon vesting of 14,285 restricted stock units within 60 days of April 1, 2014 and 14,705 shares of Diamondback common stock held by Mr. Stice. Excludes options to purchase 75,000 shares of Diamondback common stock, which will vest on April 18, 2015, and 30,953 restricted stock units, of which 14,286 will vest on April 18, 2015 and 16,667 will vest in two remaining approximately equal annual installments beginning on January 2, 2015. Also excludes 25,000 performance-based restricted stock units awarded to Mr. Stice on February 27, 2014, which awards are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group.

 

(4) Includes shares issuable upon exercise of options to purchase 16,910 shares of Diamondback common stock, all of which have vested, and 788 shares of Diamondback common stock held by Ms. Dick. Excludes options to purchase 25,000 shares of common stock, which will vest in two equal annual installments beginning on September 1, 2014, and 13,291 restricted stock units, of which 8,571 will vest in two approximately equal annual installments beginning on September 1, 2014 and 4,720 will vest in two equal annual installments beginning on January 2, 2015. Also excludes 7,080 performance-based restricted stock units awarded to Ms. Dick on February 27, 2014, which awards are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group.

 

(5)

Includes shares issuable upon exercise of options to purchase 6,700 shares of Diamondback common stock, all of which have vested, and 4,925 shares of Diamondback common stock held by Mr. Pantermuehl. Excludes options to purchase 50,000 shares of common stock, which will vest in two

 

103


Table of Contents
  equal annual installments beginning on August 15, 2014, and 22,994 restricted stock units, of which 17,143 will vest in two equal annual installments beginning on August 15, 2014 and 5,850 will vest in two equal annual installments beginning on January 2, 2015. Also excludes 8,775 performance-based restricted stock units awarded to Mr. Pantermuehl on February 27, 2014, which awards are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group.

 

(6) Excludes options to purchase 25,000 shares of common stock, which will vest in two equal annual installments beginning on November 18, 2014, and 13,132 restricted stock units, of which 8,572 will vest in two equal annual installments beginning on November 18, 2014 and 4,560 will vest in two equal annual installments beginning on January 2, 2015. Also excludes 6,840 performance-based restricted stock units awarded to Mr. Holder on February 27, 2014, which awards are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group.

 

(7) Includes shares issuable upon exercise of options to purchase 3,045 shares of Diamondback common stock, all of which have vested, and 2,925 shares of Diamondback common stock held by Mr. Hollis. Excludes options to purchase 50,000 shares of Diamondback common stock, which will vest in two equal annual installments beginning on September 12, 2014, and 22,994 restricted stock units, of which 17,143 will vest in two equal annual installments beginning on September 12, 2014 and 5,850 will vest in two equal annual installments beginning on January 2, 2015. Also excludes 8,775 performance-based restricted stock units awarded to Mr. Hollis on February 27, 2014, which awards are subject to the satisfaction of certain stockholder return performance conditions relative to the Diamondback’s peer group.

 

104


Table of Contents

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

After this offering, Diamondback will own 71,200,000 common units, representing approximately 93% of our outstanding units (approximately 92% if the underwriters exercise their option to purchase additional common units in full), and our general partner, which will own a non-economic general partner interest in us that does not entitle it to receive distributions.

The terms of the transactions and agreements disclosed in this section were determined by and among affiliated entities and, consequently, are not the result of arm’s length negotiations. These terms are not necessarily at least as favorable to the parties to these transactions and agreements as the terms that could have been obtained from unaffiliated third parties.

Distributions and Payments to Diamondback and Its Affiliates

The following table summarizes the distributions and payments made or to be made by us to Diamondback and its affiliates (including our general partner) in connection with the formation, ongoing operation and any liquidation of Diamondback.

Formation Stage

 

The consideration received by Diamondback for the contribution of its interests in Viper Energy Partners LLC

Ÿ 71,200,000 common units; and

 

  Ÿ approximately $119.4 million of the net proceeds of this offering.

Operational Stage

 

Payments to our general partner and its affiliates

We will reimburse our general partner and its affiliates for all expenses incurred on our behalf. At the closing of this offering, we and our general partner will enter into an advisory services agreement with Wexford pursuant to which Wexford will provide general finance and advisory services in exchange for a fee and certain expense reimbursement.

 

Cash distributions to Diamondback and its affiliates

We will generally make cash distributions 100% to our unitholders, including affiliates of our general partner, pro rata.

 

Withdrawal or removal of our general partner

If our general partner withdraws or is removed, its non-economic general partner interest will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of the interest. Please read “The Partnership Agreement—Withdrawal or Removal of Our General Partner.”

Liquidation Stage

 

Liquidation

Upon our liquidation, our unitholders will be entitled to receive liquidating distributions according to their respective capital account balances.

 

105


Table of Contents

Agreements and Transactions with Affiliates in Connection with this Offering

In connection with this offering, we will enter into certain agreements and transactions with Diamondback and its affiliates, as described in more detail below.

Contribution Agreement

In connection with the closing of this offering, we will enter into a contribution agreement that will effect the transactions, including the transfer of the ownership interests in Viper Energy Partners LLC to us, and the use of the net proceeds of this offering. While we believe this agreement is on terms no less favorable to any party than those that could have been negotiated with an unaffiliated third party, it will not be the result of arm’s-length negotiations. All of the transaction expenses incurred in connection with these transactions will be paid from the proceeds of this offering.

Registration Rights Agreement

In connection with this offering, we expect to enter into a registration rights agreement with Diamondback. Pursuant to the registration rights agreement, we will be required to file a registration statement to register the common units issued to Diamondback. The registration rights agreement also includes provisions dealing with holdback agreements, indemnification and contribution and allocation of expenses. These registration rights are transferable to affiliates and, in certain circumstances, to third parties. Please read “Units Eligible for Future Sale.”

Advisory Services Agreement

In connection with the closing of this offering, we will enter into an advisory services agreement with Wexford under which Wexford will provide us and our general partner with general financial and strategic advisory services related to our business in return for an annual fee of $500,000, plus reimbursement of reasonable out-of-pocket expenses. This annual fee does not cover any advisory services related to acquisitions, divestitures, financings or other transactions in which we may be involved in the future. In addition, under this agreement, we will pay Wexford to-be-negotiated market-based fees approved by the conflicts committee of the board of directors of our general partner for such services as may be provided by Wexford at our request in connection with future acquisitions and divestitures, financings or other transactions in which we may be involved. This agreement has a term of two years commencing on the completion of this offering. The agreement will continue for additional one-year periods unless terminated in writing by either party at least ten days prior to the expiration of the then current term. The agreement may be terminated at any time by either party upon 30 days’ prior written notice. In the event we terminate the agreement, we will be obligated to pay all amounts due through the remaining term of the agreement. The services provided by Wexford under the advisory services agreement will not extend to our day-to-day business or operations. In this agreement, we will indemnify Wexford and its affiliates from any and all losses arising out of or in connection with the agreement except for losses resulting from Wexford’s or its affiliates’ gross negligence or willful misconduct. In the event we are dissatisfied with the services provided by Wexford, our only remedy against Wexford is to terminate the agreement.

Tax Sharing Agreement

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. The amount of any such reimbursement will be limited to the tax that we would have paid had we not been included in a combined group with Diamondback. Diamondback may use its tax attributes to cause its combined or consolidated group, of which we may be a member for this purpose, to owe no tax. However, we would nevertheless reimburse Diamondback for the tax we would have owed had the attributes not been available or used for our benefit, even though Diamondback had no cash expense for that period.

 

106


Table of Contents

Other Transactions with Related Persons

On September 18, 2013, Diamondback completed an offering of $450 million in aggregate principal amount of 7.625% senior unsecured notes due 2021, in connection with which Viper Energy Partners LLC is a subsidiary guarantor. In connection with the closing of this offering, Viper Energy Partners LLC will be released from this guarantee.

Effective September 19, 2013, we issued a subordinated note to Diamondback for the principal sum of $440 million for the acquisition of our mineral interests. The note bears interest at 7.625% per annum. Interest is due and payable monthly in arrears on the first business day of each calendar month. The unpaid principal balance and all accrued interest on the note are due and payable in full on October 1, 2021. Any indebtedness evidenced by this note is subordinate in the right of payment to any indebtedness outstanding under Diamondback’s revolving credit facility. As of March 31, 2014 and December 31, 2013, there was $440 million outstanding under this note. During the three months ended March 31, 2014 and the period from inception (September 18, 2013) to December 31, 2013, we incurred approximately $5.4 million and $5.7 million of net interest expense, respectively. We owed no amounts and $9.7 million of accrued interest as of March 31, 2014 and December 31, 2013, respectively. In connection with this offering, the subordinated note will be converted into equity.

Effective September 19, 2013, we entered into a shared services agreement with Diamondback E&P LLC, a wholly owned subsidiary of Diamondback. Under this agreement, Diamondback E&P LLC provides consulting and administrative services to us. We incur a monthly charge for the services of $26,000 or other amounts that are otherwise mutually agreed to in writing between Diamondback E&P LLC and us. For the three months ended March 31, 2014 and the period from inception (September 18, 2013) to December 31, 2013, we incurred $78,000 and $87,000, respectively, for services under this agreement. At March 31, 2014 and December 31, 2013, we owed Diamondback E&P LLC no amounts and $87,000, respectively. This agreement will terminate at the closing of this offering.

Procedures for Review, Approval and Ratification of Transactions with Related Persons

We expect that the board of directors of our general partner will adopt policies for the review, approval and ratification of transactions with related persons. We anticipate the board will adopt a written code of business conduct and ethics, under which a director would be expected to bring to the attention of the chief executive officer or the board any conflict or potential conflict of interest that may arise between the director or any affiliate of the director, on the one hand, and us or our general partner on the other. The resolution of any such conflict or potential conflict should, at the discretion of the board in light of the circumstances, be determined by a majority of the disinterested directors.

If a conflict or potential conflict of interest arises between our general partner or its affiliates, on the one hand, and us or our unitholders, on the other hand, the resolution of any such conflict or potential conflict should be addressed by the board of directors of our general partner in accordance with the provisions of our partnership agreement. At the discretion of the board in light of the circumstances, the resolution may be determined by the board in its entirety or by a conflicts committee meeting the definitional requirements for such a committee under our partnership agreement.

Upon our adoption of our code of business conduct and ethics, we would expect that any executive officer will be required to avoid conflicts of interest unless approved by the board of directors of our general partner.

Please read “Conflicts of Interest and Fiduciary Duties—Conflicts of Interest” for additional information regarding the relevant provisions of our partnership agreement.

The code of business conduct and ethics described above will be adopted in connection with the closing of this offering, and as a result, the transactions described above were not reviewed according to such procedures.

 

107


Table of Contents

CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

The Delaware Revised Uniform Limited Partnership Act, which we refer to as the Delaware Act, provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to the limited partners and the partnership. 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. Our partnership agreement also specifically defines the remedies available to unitholders for actions taken that, without these defined liability standards, might constitute breaches of fiduciary duty under applicable Delaware law.

When our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith,” meaning it must not act in a manner that it believes is adverse to our interest. This duty to act in good faith is the default standard set forth under our partnership agreement and our general partner will not be subject to any higher standard.

Our partnership agreement specifies decisions that our general partner may make in its individual capacity, and permits our general partner to make these decisions free of any contractual or other duty to us or our unitholders. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its call right, its voting rights with respect to any units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation or amendment of the partnership agreement.

When the directors and officers of our general partner cause our general partner to manage and operate our business, the directors and officers must cause our general partner to act in a manner consistent with our general partner’s applicable duties. However, the directors and officers of our general partner have fiduciary duties to manage our general partner, including when it is acting in its capacity as our general partner, in a manner beneficial to Diamondback.

Conflicts may arise as a result of the duties of our general partner and its directors and officers to act for the benefit of its owners, which may conflict with our interests and the interests of our public unitholders. Where the directors and officers of our general partner are causing our general partner to act in its capacity as our general partner, the directors and officers must cause the general partner to act in good faith, meaning they cannot cause the general partner to take an action that they believe is adverse to our interest. However, where a decision by our general partner in its capacity as our general partner is not clearly not adverse to our interest, the directors of our general partner may determine to submit the determination to the conflicts committee for review or to seek approval by the unitholders, as described below.

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its directors, executive officers and owners (including Diamondback), on the one hand, and us and our limited partners, on the other hand.

Whenever a conflict arises between our general partner or its owners, on the one hand, and us or our limited partners, on the other hand, the resolution, course of action or transaction in respect of such conflict of interest shall be conclusively deemed approved by us and all our limited partners and shall not constitute a breach of our partnership agreement, of any agreement contemplated thereby or of any duty, if the resolution or course of action or transaction in respect of such conflict of interest is:

 

   

approved by the conflicts committee of our general partner; or

 

   

approved by the holders of a majority of the outstanding common units, excluding any such units owned by our general partner or any of its affiliates.

 

108


Table of Contents

Our general partner may, but is not required to, seek the approval of such resolutions or courses of action from the conflicts committee of its board of directors or from the holders of a majority of the outstanding common units as described above. If our general partner does not seek approval from the conflicts committee or from holders of common units as described above and the board of directors of our general partner approves the resolution or course of action taken with respect to the conflict of interest, then it will be presumed that, in making its decision, the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of us or any of our unitholders, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption and proving that such decision was not in good faith. Unless the resolution of a conflict is specifically provided for in our partnership agreement, the board of directors of our general partner or the conflicts committee of the board of directors of our general partner may consider any factors they determine in good faith to consider when resolving a conflict. An independent third party is not required to evaluate the resolution. Under our partnership agreement, all determinations, other actions or failures to act by our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) will be presumed to be “in good faith,” and in any proceeding brought by or on behalf of us or any of our unitholders, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption and proving that such decision was not in good faith. Please read “Management—Committees of the Board of Directors—Conflicts Committee” for information about the conflicts committee of our general partner’s board of directors.

Conflicts of interest could arise in the situations described below, among others:

Actions taken by our general partner may affect the amount of cash available to pay distributions to unitholders.

The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:

 

   

amount and timing of asset purchases and sales;

 

   

cash expenditures;

 

   

borrowings;

 

   

entry into and repayment of current and future indebtedness;

 

   

issuance of additional units; and

 

   

the creation, reduction or increase of reserves.

Our partnership agreement permits us to borrow funds to make a distribution, and further provides that we and our subsidiaries may borrow funds from our general partner and its affiliates.

The directors and executive officers