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SUBMITTED CONFIDENTIALLY TO THE DIVISION OF CORPORATION FINANCE ON OCTOBER 8, 2014

As filed with the Securities and Exchange Commission on                     , 2014

Registration No. 333-            

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

Black Stone Minerals, L.P.

(Exact Name of Registrant as Specified in Its Charter)

 

 

 

Delaware   1311   47-1846692
(State or Other Jurisdiction of
Incorporation or Organization)
  (Primary Standard Industrial
Classification Code Number)
 

(I.R.S. Employer

Identification Number)

1001 Fannin Street

Suite 2020

Houston, Texas 77002

(713) 658-0647

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

 

 

Steve Putman

Senior Vice President, General Counsel, and Secretary

1001 Fannin Street

Suite 2020

Houston, Texas 77002

(713) 658-0647

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

 

 

Copies to:

 

Mike Rosenwasser

Brenda Lenahan

Vinson & Elkins L.L.P.

666 Fifth Avenue, 26th Floor

New York, New York 10103

Tel: (212) 237-0000

Fax: (212) 237-0100

 

G. Michael O’Leary

Jon W. Daly

Andrews Kurth LLP

600 Travis Street, Suite 4200

Houston, Texas 77002

Tel: (713) 220-4200

Fax: (713) 220-4285

 

 

Approximate date of commencement of proposed sale to the public:

As soon as practicable after this registration statement becomes effective.

 

 

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

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

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

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

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

 

 

 


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The information in this preliminary prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission becomes effective. This preliminary prospectus is not an offer to sell these securities, and we are not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

 

Subject to Completion, dated                     , 2014

PROSPECTUS

 

 

 

 

LOGO

Black Stone Minerals, L.P.

Common Units

Representing Limited Partner Interests

 

 

This is the initial public offering of our common units representing limited partner interests in us. We are offering             common units. Prior to this offering, there has been no public market for our common units. We currently expect the initial public offering price to be between $         and $        per common unit. We intend to apply to list our common units on the New York Stock Exchange under the symbol “BSM.”

Investing in our common units involves risks. Please read “Risk Factors” beginning on page 25.

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 and could make no distribution with respect to any particular quarter.

 

 

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 various unaffiliated operators for all of the exploration, development, and production on the properties underlying our mineral and royalty interests and non-operated working interests. Substantially all of our revenue is derived from the sale of oil and gas production from producing wells in which we own a royalty interest or a non-operated working interest. A reduction in the expected number of wells to be drilled on our acreage by these operators or the failure of our operators to adequately and efficiently develop and operate our acreage could have an adverse effect on our results of operations.

 

 

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

 

 

Common unitholders who are not “Eligible Holders” will not be entitled to receive distributions on or allocations of income or loss on their common units, and their common units will be subject to redemption.

 

 

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 unitholders could be substantially reduced.

 

 

Even if a unitholder does not receive any cash distributions from us, a unitholder will be required to pay taxes on its share of our taxable income.

In addition, we qualify as an “emerging growth company” as defined in 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.”

 

     Per Common
Unit
     Total  

Public Offering Price

   $                    $                

Underwriting Discount

   $         $     

Proceeds to Black Stone Minerals, L.P. (before expenses)

   $         $     

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

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

Barclays expects to deliver the common units to purchasers on or about                     , 2014 through the book-entry facilities of The Depository Trust Company.

 

 

Barclays

 

 

Prospectus dated                     , 2014


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[ARTWORK]


Table of Contents

TABLE OF CONTENTS

 

SUMMARY

     1   

Black Stone Minerals, L.P.

     1   

Overview

     1   

Our Assets

     2   

Our Properties

     3   

Business Strategies

     6   

Competitive Strengths

     7   

Management

     9   

Fiduciary Duties

     9   

Emerging Growth Company Status

     9   

Formation Transactions and Structure

     10   

Principal Executive Offices

     13   

Risk Factors

     14   

The Offering

     18   

Summary Historical and Pro Forma Financial Data

     21   

Non-GAAP Financial Measures

     23   

RISK FACTORS

     25   

Risks Related to Our Business

     25   

Risks Inherent in an Investment in Us

     38   

Tax Risks to Common Unitholders

     44   

USE OF PROCEEDS

     48   

CAPITALIZATION

     49   

DILUTION

     50   

CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

     51   

General

     51   

Pro Forma Cash Available for Distribution for the Year Ended December 31, 2013  and the Twelve Months Ended June 30, 2014

     52   

Estimated Cash Available for Distribution for the Year Ending December 31, 2015

     55   

SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA

     63   

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

     65   

Overview

     65   

Business Environment

     65   

How We Evaluate Our Operations

     66   

Factors Affecting the Comparability of Our Financial Results

     68   

Results of Operations

     69   

Liquidity and Capital Resources

     73   

Contractual Obligations

     75   

Off-Balance Sheet Arrangements

     75   

Critical Accounting Policies and Related Estimates

     75   

New and Revised Financial Accounting Standards

     78   

Quantitative and Qualitative Disclosure about Market Risk

     78   

BUSINESS

     80   

Overview

     80   

Our Assets

     80   

 

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Business Strategies

     82   

Competitive Strengths

     84   

Our Properties

     85   

Estimated Proved Reserves

     95   

Oil and Natural Gas Production Prices and Production Costs

     99   

Environmental Matters

     102   

Title to Properties

     106   

Competition

     107   

Seasonal Nature of Business

     107   

Employees

     107   

Facilities

     107   

Legal Proceedings

     107   

MANAGEMENT

     108   

Management

     108   

Executive Officers and Directors of Our General Partner

     109   

Director Independence

     110   

Committees of the Board of Directors

     111   

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

     112   

EXECUTIVE COMPENSATION AND OTHER INFORMATION

     113   

Summary Compensation Table

     113   

Narrative Disclosure to the Summary Compensation Table

     114   

Outstanding Equity Awards at 2013 Fiscal Year-End

     115   

Additional Narrative Disclosure

     116   

Long-Term Incentive Plan

     118   

Director Compensation

     119   

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     121   

FIDUCIARY DUTIES

     122   

DESCRIPTION OF OUR COMMON UNITS

     125   

Our Common Units

     125   

Transfer Agent and Registrar

     125   

Transfer of Common Units

     125   

Listing

     126   

DESCRIPTION OF OUR PREFERRED UNITS

     127   

Our Preferred Units

     127   

Distributions

     127   

Conversion of the Preferred Units

     128   

Redemption of the Preferred Units

     128   

Anti-Dilution Provisions

     129   

Voting; Waiver

     130   

Co-Investment Right

     130   

THE PARTNERSHIP AGREEMENT

     131   

Organization and Duration

     131   

Purpose

     131   

Capital Contributions

     131   

Adjustments to Capital Accounts Upon Issuance of Additional Common Units

     131   

Voting Rights

     131   

Meetings; Voting

     133   

Nomination of Directors

     134   

 

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Applicable Law; Forum, Venue, and Jurisdiction

     135   

Limited Liability

     135   

Issuance of Additional Partnership Interests

     136   

Amendment of the Partnership Agreement

     137   

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

     139   

Dissolution

     139   

Liquidation and Distribution of Proceeds

     140   

Withdrawal or Removal of Our General Partner; Transfer of General Partner Interest

     140   

Change of Management Provisions

     140   

Non-Taxpaying Holders; Redemption

     140   

Non-Citizen Assignees; Redemption

     141   

Non-Eligible Holders; Redemption

     141   

Status as Limited Partner

     142   

Indemnification

     142   

Reimbursement of Expenses

     142   

Books and Reports

     142   

Right to Inspect Our Books and Records

     143   

UNITS ELIGIBLE FOR FUTURE SALE

     144   

MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES

     145   

Taxation of the Partnership

     145   

Tax Consequences of Unit Ownership

     147   

Tax Treatment of Operations

     151   

Disposition of Units

     153   

Uniformity of Units

     156   

Tax-Exempt Organizations and Other Investors

     156   

Administrative Matters

     157   

FATCA Withholding Requirements

     158   

State, Local, and Other Tax Considerations

     159   

INVESTMENT IN BLACK STONE MINERALS, L.P. BY EMPLOYEE BENEFIT PLANS

     160   

General Fiduciary Matters

     160   

Prohibited Transaction Issues

     160   

Plan Asset Issues

     161   

UNDERWRITING

     162   

Commissions and Expenses

     162   

Option to Purchase Additional Common Units

     162   

Lock-Up Agreements

     163   

Offering Price Determination

     163   

Indemnification

     163   

Stabilization, Short Positions, and Penalty Bids

     164   

Electronic Distribution

     164   

New York Stock Exchange

     165   

Discretionary Sales

     165   

Stamp Taxes

     165   

Relationships

     165   

FINRA

     165   

Selling Restrictions

     165   

LEGAL MATTERS

     169   

EXPERTS

     169   

WHERE YOU CAN FIND MORE INFORMATION

     169   

 

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FORWARD-LOOKING STATEMENTS

     170   

INDEX TO FINANCIAL STATEMENTS

     F-1   

APPENDIX A—FORM OF FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF BLACK STONE MINERALS, L.P.

     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, industry publications, and surveys. Our internal research and forecasts are based on management’s understanding of industry conditions, and this 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, but there can be no assurance as to the accuracy or completeness of the included information. While we are not aware of any misstatements regarding industry or similar data presented herein, such data involves risks and uncertainties and is subject to change based on various factors, including those discussed under the headings “Risk Factors” and “Forward-Looking Statements” in this prospectus.

 

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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 and pro forma financial statements and the notes to those financial statements, before investing in our common units. The information presented in this prospectus assumes an initial public offering price of $         per common unit (the mid-point of the price range set forth on the cover page of this prospectus) and, unless otherwise indicated, that the underwriters’ option to purchase additional common units is not exercised and the preferred units have not converted to common units. You should read “Risk Factors” for information about important risks that you should consider before buying our common units.

References in this prospectus to “BSMC,” “Black Stone Minerals, L.P. Predecessor,” “our predecessor,” “we,” “our,” “us,” or like terms when used in a historical context refer to Black Stone Minerals Company, L.P. and its subsidiaries. When used in the present tense or prospectively, “BSM,” “Black Stone Minerals,” “we,” “our,” “us,” “the partnership,” or like terms refer to Black Stone Minerals, L.P. and its subsidiaries, after giving effect to those transactions described in “—Formation Transactions and Structure.” References in this prospectus to “BSNR” and “our general partner” refer to Black Stone Natural Resources, L.L.C., a wholly owned subsidiary and also the general partner of BSM and BSMC. References in this prospectus to “Black Stone Management” refer to Black Stone Natural Resources Management Company. References in this prospectus to “our working interests” refer to non-operated working interests. We include a glossary of some of the terms used in this prospectus as Appendix B.

Black Stone Minerals, L.P.

Overview

We are one of the largest owners of oil and natural gas mineral interests in the United States. Our principal business is maximizing the value of our existing portfolio of mineral and royalty assets through active management and expanding our asset base through acquisitions of additional mineral and royalty interests. We maximize value through the marketing of our mineral assets for lease, creative structuring of those leases to encourage and accelerate drilling activity, and selectively participating alongside our lessees on a working-interest basis. Our primary business objective is to grow our reserves, production, and cash flow while distributing a substantial majority of our cash flow to our common unitholders.

We own mineral interests in approximately 14.5 million acres, with an average 48.2% ownership interest in that acreage. We also own nonparticipating royalty interests in 1.2 million acres and overriding royalty interests in 1.4 million acres. These non-cost-bearing interests, which we refer to collectively as our “mineral and royalty interests,” include ownership in approximately 40,000 producing wells. Our mineral and royalty interests are located in 41 states and in 62 onshore basins in the continental United States. Many of these interests are in active resource plays, including the Bakken/Three Forks play, Eagle Ford Shale, Wolfcamp play, Haynesville/Bossier play, Granite Wash play, and Fayetteville Shale, as well as emerging plays such as the Tuscaloosa Marine Shale and the Canyon Lime play. The combination of the breadth of our asset base and the long-lived, non-cost-bearing nature of our mineral and royalty interests exposes us to potential additional production and reserves from new and existing plays without investing additional capital.

Our history dates back to 1876, when W.T. Carter & Bro., a predecessor of BSMC, was established as a lumber company in Southeast Texas. W.T. Carter & Bro. acquired significant land holdings for timber, and those acquisitions typically included mineral interests. Beginning in the late 1960s, we began to divest the timber and surface rights on our properties but retained the mineral interests. We began developing our prospective oil and natural gas acreage in the 1980s. In 1985, we were involved in the discovery of the Double A Wells Field in East Texas, a natural gas field that has produced over 540 Bcfe to date. In 1992, we made our first third-party

 

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acquisition of mineral interests and, in 1998, shifted our focus from exploration to acquisitions of mineral and royalty interests. In the aggregate, we have invested approximately $1.6 billion in 42 third-party transactions involving mineral and royalty interests and, to a lesser extent, non-operated working interests. We believe that one of our key strengths is our management’s extensive experience in acquiring and managing mineral and royalty interests. Our management team has a long history of creating unitholder value and has developed a scalable business model that has allowed us to integrate significant acquisitions into our existing organizational structure quickly and cost-efficiently. Our average daily production for the six months ended June 30, 2014 was approximately 25.9 MBoe/d, which includes production from our mineral and royalty interests, as well as production attributable to our working-interest participation program, as described below.

Our Assets

Mineral and Royalty Interests

Mineral interests are real-property interests that are typically perpetual and grant ownership of the oil and natural gas under a tract of land and the rights to explore for, drill for, and produce oil and natural gas on that land or to lease those exploration and development rights to a third party. When those rights are leased, usually for a three-year term, we typically receive an upfront cash payment, known as lease bonus, and we retain a mineral royalty, which entitles us to a cost-free percentage (usually ranging from 20% to 25%) of production or production revenue. A lessee can extend the lease beyond the initial lease term with continuous drilling, production, or other operating activities. When production or drilling ceases, the lease terminates, allowing us to lease the exploration and development rights to another party. Mineral interests generate the substantial majority of our revenue and are also the assets that we have the most influence over.

In addition to mineral interests, we also own other types of non-cost-bearing royalty interests, which include:

 

   

nonparticipating royalty interests, or NPRIs, which are royalty interests that are carved out of the mineral estate and represent the right, which is typically perpetual, to receive a fixed, cost-free percentage of production or revenue from production, without an associated right to lease or receive lease bonus; and

 

   

overriding royalty interests, or ORRIs, which are royalty interests that burden working interests and represent the right to receive a fixed, cost-free percentage of production or revenue from production from a lease. ORRIs remain in effect until the associated leases expire.

Our revenue generated from these mineral and royalty interests was $314.2 million and $173.0 million for the year ended December 31, 2013 and the six months ended June 30, 2014, respectively.

Working-Interest Participation Program

We own working interests related to our mineral interests in various plays across our asset base. Many of these working interests were acquired through working-interest participation rights, which we often include in the terms of our leases. This participation right complements our core mineral-and-royalty-interest business because it allows us to realize additional value from our minerals. Under the terms of the relevant leases, we are granted a unit-by-unit or a well-by-well option to participate on a working-interest basis in drilling opportunities on our mineral acreage. This right to participate in a unit or well is exercisable at our sole discretion. We generally only exercise this option when the results from prior drilling and production activities have substantially reduced the economic risk associated with development drilling, and where we believe the probability of achieving attractive economic returns is high.

We also own other working interests, unrelated to our mineral and royalty assets, which were acquired because of the attractive working-interest investment opportunities within the assets. The majority of these assets

 

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are focused in the Anadarko Basin, and to a lesser extent, in the Permian Basin and Powder River Basin. While these assets have been a successful part of our overall working-interest participation program, they represent approximately 10% of our 2014 non-operated working-interest capital expenditure budget and likely will be less in the future.

We collectively refer to these working interests as our “working-interest participation program.” When we participate in non-operated working interest opportunities, we are required to pay our portion of the costs associated with drilling and operating these wells. Our 2014 drilling capital expenditure budget associated with our working-interest participation program is $85.4 million, which is being invested primarily in the Bakken/Three Forks, Haynesville/Bossier, and Granite Wash plays. We historically have participated in approximately 200 new wells per year. As of June 30, 2014, we owned non-operated working interests in approximately 7,800 gross wells. For the year ended December 31, 2013 and the six months ended June 30, 2014, our revenue generated from these working interests was $123.4 million and $62.2 million, respectively.

Our Properties

Material Basins and Producing Regions

The following summarizes our exposure to the U.S. basins and regions we consider most material to our current and future business.

 

     Acreage(1)      Average Daily
Production for
Six Months

Ended June 30,
2014(3) (Boe/d)
 
     Mineral and Royalty Interests      Working Interests     

USGS Petroleum Province(2)

   Mineral
Interests
     NPRIs      ORRIs      Gross      Net     

Louisiana-Mississippi Salt Basins

     5,270,887         111,707         65,610         55,652         7,287         6,834   

Western Gulf (onshore)

     1,543,217         180,901         88,138         117,148         17,659         4,910   

Williston Basin

     1,113,210         60,734         30,965         54,693         7,821         3,207   

Palo Duro Basin

     1,010,374         22,791         1,120                         15   

Permian Basin

     678,105         541,434         61,677         8,791         4,980         843   

Anadarko Basin

     534,967         10,628         182,096         62,799         21,686         2,549   

Appalachian Basin

     490,006         416         3,532                         902   

East Texas Basin

     406,814         36,113         27,982         127,885         32,426         2,172   

Arkoma Basin

     331,168         5,170         36,121         8,158         1,661         2,100   

Bend Arch-Fort Worth Basin

     138,018         52,208         41,072         56,001         13,408         553   

Southwestern Wyoming

     25,490         560         70,607         15,458         2,492         596   

Other

     2,927,480         188,671         789,702         59,980         13,829         1,255   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     14,469,736         1,211,333         1,398,621         566,566         123,251         25,937   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

Note: Numbers may not add up to total amounts due to rounding.

 

(1) We may own more than one type of interest in the same tract of land. For example, where we have acquired working interests through our working-interest participation program in a given tract, our working-interest acreage in that tract will relate to the same tract acres as our mineral-interest acreage in that tract. Consequently, some of the acreage shown for one type of interest above may also be included in the acreage shown for another type of interest. Because of our working-interest participation program, overlap between working-interest acreage and mineral-and-royalty-interest acreage is significant, while overlap between the different types of mineral and royalty interests is not. Working-interest acreage excludes acreage that is not quantifiable due to incomplete seller records.
(2) The basins and regions shown in the table are consistent with U.S. Geological Survey (“USGS”) delineations of petroleum provinces of onshore and state offshore areas in the continental United States. We refer to these petroleum provinces as “basins” or “regions.”

 

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(3) “Btu-equivalent” production volumes are presented on an oil-equivalent basis using a conversion factor of six Mcf of natural gas per barrel of “oil equivalent,” which is based on approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas.

 

   

Louisiana-Mississippi Salt Basins. The Louisiana-Mississippi Salt Basins region ranges from northern Louisiana and southern Arkansas through south central and southern Mississippi, southern Alabama, and the Florida Panhandle. The Haynesville/Bossier play, which has been extensively delineated through drilling, is the most prospective unconventional play for natural gas production and reserves within this region. Approximately half of the Haynesville/Bossier play’s prospective acreage is within the Louisiana-Mississippi Salt Basins region, where we own significant mineral and royalty interests and working interests. The Tuscaloosa Marine Shale play is the basin’s most significant emerging unconventional oil play, extending through southwestern Mississippi and southeastern Louisiana on the eastern end of the play and westward across central Louisiana to the Texas border. The play is in the early stage of development and is actively being drilled and tested by several operators. We have a significant mineral-and-royalty-interest position across the entire basin, with material exposure to the Tuscaloosa Marine Shale. There are a number of additional active conventional and unconventional plays in the basin in which we hold considerable mineral and royalty interests, including the Brown Dense, Cotton Valley, Hosston, Norphlet, Smackover, and Wilcox plays.

 

   

Western Gulf. The Western Gulf region, which ranges from South Texas through southeastern Louisiana, includes a variety of both conventional and unconventional plays. We have extensive exposure to the Eagle Ford Shale in South Texas, where we are experiencing a significant level of development drilling on our mineral interests within the oil and rich-gas condensate areas of the play. We also have significant exposure to the Tuscaloosa Marine Shale in central and southeastern Louisiana, which is one of the most prospective emerging oil shale plays in the basin and is being actively drilled and tested by several operators in the Western Gulf region. In addition to the Eagle Ford Shale and Tuscaloosa Marine Shale plays, there are a number of other active conventional and unconventional plays to which we have exposure to in the region, including the Austin Chalk, Buda, Eaglebine (or Maness) Shale, Frio, Glenrose, Olmos, Woodbine, Vicksburg, Wilcox, and Yegua plays.

 

   

Williston Basin. The Williston Basin stretches through all of North Dakota, the northwest part of South Dakota, and eastern Montana and includes plays such as the Bakken/Three Forks play, where we have significant exposure through our mineral and royalty interests as well as through our working interests. We are also exposed to other well-known plays in the basin, including the Duperow, Mission Canyon, Madison, Ratcliff, Red River, and Spearfish plays.

 

   

Palo Duro Basin. The Palo Duro Basin covers much of the Texas Panhandle but also occupies a small portion of the Oklahoma Panhandle and extends partially into New Mexico to the west. We have a significant acreage position in the Palo Duro Basin, much of which underlies an emerging unconventional oil play in the Canyon Lime. We are also well positioned relative to a number of other active conventional and unconventional plays in the Palo Duro Basin, including the Brown Dolomite, Canyon Wash, Cisco Sand, and Strawn Wash plays.

 

   

Permian Basin. The Permian Basin ranges from southeastern New Mexico into West Texas and is currently one of the most active areas for drilling in the United States. It includes three geologic provinces: the Midland Basin to the east, the Delaware Basin to the west, and the Central Basin in between. Our acreage underlies prospective areas for the Wolfcamp play in the Midland and Delaware Basins, the Spraberry formation in the Midland Basin, and the Bone Springs formation in the Delaware Basin, which are among the plays most actively targeted by drillers within the basin. In addition to these plays, we own mineral and royalty interests that are prospective for a number of other active conventional and unconventional plays in the Permian Basin, including the Atoka, Clearfork, Ellenberger, San Andres, Strawn, and Wichita Albany plays.

 

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Anadarko Basin. The Anadarko Basin encompasses the Texas Panhandle, southeastern Colorado, southwestern Kansas, and western Oklahoma. We own mineral and royalty interests as well as working interests in prospective areas for most of the prolific plays in this basin, including the Granite Wash, Atoka, Cleveland, and Woodford Shale plays. Other active plays in which we hold interests in prospective acreage include the Cottage Grove, Hogshooter, Marmaton, Springer, and Tonkawa plays.

 

   

Appalachian Basin. The Appalachian Basin covers most of Pennsylvania, eastern Ohio, West Virginia, western Maryland, eastern Kentucky, central Tennessee, western Virginia, northwestern Georgia, and northern Alabama. The basin’s most active play in which we have acreage is the Marcellus Shale, which covers most of western Pennsylvania and the northern part of West Virginia. In addition to the Marcellus Shale, there are a number of other active conventional and unconventional plays to which we have material exposure in the Appalachian Basin, including the Berea, Big Injun, Devonian, Huron, Rhinestreet, and Utica plays.

 

   

East Texas Basin. The East Texas Basin ranges from central East Texas to northeast Texas and includes the Haynesville/Bossier play and the Cotton Valley play, which are among the most prolific gas plays in the basin. We own a material acreage position in the Shelby Trough area of the Haynesville/Bossier play located in San Augustine and Nacogdoches Counties, which is one of the most active areas being drilled today for that play in the East Texas Basin. There are other active plays to which we have significant exposure, including the Bossier Sand, Goodland Lime, James Lime, Pettit, Travis Peak, Smackover, and Woodbine plays.

 

   

Arkoma Basin. The Arkoma Basin stretches from southeast Oklahoma through central Arkansas. The Fayetteville Shale play is one of the basin’s most active unconventional gas plays. We own material mineral and royalty interests within the prospective area of the Fayetteville Shale. In addition, we have interests exposed to a number of other active conventional and unconventional plays in the basin, including the Atoka, Cromwell, Dunn, Hale, and Woodford Shale plays.

 

   

Bend Arch-Fort Worth Basin. The Bend Arch-Fort Worth Basin covers much of north central Texas and includes the Barnett Shale play as its most active unconventional play. Through our mineral and royalty interest in this basin, we have significant exposure to the Barnett Shale as well as a number of other active conventional and unconventional plays in the basin, including the Bend Conglomerate, Caddo, Marble Falls, and Mississippian Lime plays.

 

   

Southwestern Wyoming. The Southwestern Wyoming region covers most of southern and western Wyoming. The Pinedale Anticline is one of the basin’s largest producing fields and mainly produces from the Lance formation. We have a meaningful position in the Pinedale Anticline, and we have interests prospective for other active plays as well, including the Mesaverde, Niobrara, and Wasatch plays.

For more detailed information about the basins and regions described above, please read “Business—Our Properties—Material Basins and Producing Regions.”

 

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Material Resource Plays

The following table presents information about our mineral-and-royalty-interest and working-interest acreage by the resource plays we consider most material to our current and future business and contribute approximately 60% of our aggregate production for the six months ended June 30, 2014.

 

     Acreage(1)  

Resource Play(2)

   Mineral and Royalty Interests      Working Interests  
   Mineral Interests      NPRIs      ORRIs      Gross      Net  

Bakken Shale

     318,990         35,261         12,930         49,799         7,075   

Three Forks

     296,689         32,442         12,250         50,000         6,752   

Haynesville Shale

     274,996         7,078         53,191         168,451         38,256   

Marcellus Shale

     253,536                 1,002                   

Canyon Lime

     232,381                                   

Bossier Shale

     213,276         2,096         47,124         144,619         35,002   

Tuscaloosa Marine Shale

     181,560         4,081         22,674                   

Granite Wash

     110,654         4,122         87,920         5,194         1,364   

Fayetteville Shale

     76,539                 12,160                   

Barnett Shale

     62,171         4,644         35,872         48,282         12,440   

Eagle Ford Shale

     47,683         85,063         33,532         235         118   

Wolfcamp-Delaware

     44,855         18,825         1,080         520         89   

Wolfcamp-Midland

     36,909         38,513         14,804         160         4   

 

(1) We may own more than one type of interest in the same tract of land. For example, where we have acquired working interests through our working-interest participation program in a given tract, our working-interest acreage in that tract will relate to the same tract acres as our mineral-interest acreage in that tract. Consequently, some of the acreage shown for one type of interest above may also be included in the acreage shown for another type of interest. Because of our working-interest participation program, overlap between working-interest acreage and mineral-and-royalty-interest acreage is significant, while overlap between the different types of mineral and royalty interests is not. Working-interest acreage excludes acreage that is not quantifiable due to incomplete seller records.
(2) The plays above have been delineated based on information from the U.S. Energy Information Administration (“EIA”), the USGS, state agencies, or according to areas of the most active industry development.

Business Strategies

Our primary business objective is to grow our reserves, production, and cash flow over the long term, while distributing a substantial majority of our cash flow to our common unitholders. We intend to accomplish this objective by continuing to execute the following strategies:

 

   

Actively lease our minerals to third-party operators. We intend to continue actively marketing our mineral interests for lease in order to generate income from lease bonus and ensure that our acreage is drilled as quickly as possible. Our staff actively manages the leasing of our acreage in order to accelerate royalty revenue and maximize our working-interest optionality. While our leasing activity generates significant revenue from lease bonus, the size and frequency of lease bonus vary depending on the oil and natural gas industry’s perception of the prospectivity, risk, and potential economics of a play. During the lease-negotiation process, we consider standard industry lease terms as well as innovative terms that are designed to encourage more exploration. Through our control of large blocks of contiguous acreage throughout the country, we provide exploration and production companies with an extensive acreage inventory from which to generate prospects and search for new opportunities. In addition, our in-house geological and geophysical team uses our extensive seismic library to assist exploration and production companies in the identification of emerging plays and potential drilling locations.

 

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Acquire additional mineral and royalty interests in oil and natural gas properties that meet our acquisition criteria. We intend to continue to acquire mineral and royalty interests that have substantial resource and cost-free, or organic, growth potential. Our management team has a long history of evaluating, pursuing, and consummating acquisitions of oil and natural gas mineral and royalty interests in the United States. We believe that our large network of industry relationships provides us with a competitive advantage in pursuing potential acquisition opportunities. Since 1992, we have invested approximately $1.6 billion in 42 acquisitions. In the future, we expect to focus on relatively large acquisitions but will also continue to pursue smaller mineral packages to complement an existing position or to establish a foothold in an emerging play. We prefer acquisitions that meet the following criteria:

 

   

sufficient current production to create near-term accretion for our unitholders;

 

   

geologic support for future production and reserve growth;

 

   

a geographic footprint that we believe is complementary to our diverse portfolio and maximizes our potential for upside reserve and production growth from undiscovered reserves or new plays; and

 

   

targeted positions in high-growth resource and conventional plays.

 

   

Participate in drilling opportunities in low-risk plays that generate attractive returns. Our ownership of mineral interests affords us the favorable position of negotiating leases that frequently provide us a unit-by-unit or well-by-well option to participate on a working-interest basis in economic, low-risk drilling opportunities. This participation program offers access to drilling opportunities in established producing trends at well-level economics, often unburdened by traditional land and exploration costs associated with acquiring prospective acreage, such as paying lease bonus, acquiring seismic data, and drilling exploratory and delineation wells. We expect to continue to actively participate in these drilling opportunities.

 

   

Maintain a conservative capital structure and prudently manage the business for the long term. We are committed to maintaining a conservative capital structure that will afford us the financial flexibility to execute our business strategies on an ongoing basis. Upon completion of this offering, we will have no outstanding indebtedness. We believe that proceeds from this offering, internally generated cash flows, our $         million borrowing base under our credit facility, and access to the public capital markets will provide us with sufficient liquidity and financial flexibility to grow our production, reserves, and cash flow through the continued development of our existing assets and accretive acquisitions of mineral and royalty interests.

Competitive Strengths

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

 

   

Significant diversified portfolio of mineral and royalty interests in mature producing basins and exposure to prospective exploration opportunities. We have a large-scale, diversified asset base with exposure to active high-quality conventional and unconventional plays. With our mineral and royalty interests spanning over 16.5 million total acres across the continental United States, we have established a strong position with significant growth opportunities and exposure to potentially large new discoveries in the future. In some cases, we have built our positions in anticipation of development in a play, as we did in the Eagle Ford Shale. In other cases, we acquired diversified mineral packages in rich geologic basins with multiple prospective horizons from which subsequent resource plays, including the Bakken/Three Forks play and the Haynesville/Bossier play, have developed. Because our asset base is large and diversified, we are able to make significant focused acquisitions in active areas within well-established resource plays, while maintaining overall diversity. Furthermore, the geographic breadth of our assets

 

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and vast quantity of our property interests expose us to potential production and reserves from new and existing plays without further required investment on our behalf. We believe that we will continue to benefit from these cost-free additions of production and reserves for the foreseeable future as a result of technological advances and continuing interest by third-party producers in exploration and development activities on our acreage.

 

   

Exposure to many of the leading resource plays in the United States. We expect our reserves and cash available for distributions per unit to grow organically for the next several years as our operators continue to drill new wells on the acreage we have leased to them. We believe that we have significant drilling inventory remaining in our interests in multiple resource plays.

 

   

Ability to increase exposure in most economic plays through our working-interest participation program. We frequently negotiate our leases with options to participate in wells on a working-interest basis. This working-interest option allows us to increase our exposure to plays that we find attractive when the results from prior drilling and production have substantially reduced the economic risk associated with development drilling and where we believe the probability of achieving attractive economic returns is high. We intend to continue increasing our exposure to those opportunities.

 

   

Scalable business model. We believe that our size, organizational structure, and capacity give us a relative advantage in growing our business because we are able to add large packages of mineral and royalty interests without significantly increasing our cost structure, allowing us to be more competitive when pursuing acquisition opportunities. Our land, accounting, engineering and geology, information-technology, and business-development departments have developed a scalable business model that allows us to manage our existing assets efficiently and absorb significant acquisitions without material cost increases.

 

   

Exposure to natural gas supply and demand growth. The EIA projects that U.S. natural gas demand from internal consumption is expected to increase from 25.6 trillion cubic feet in 2012 to 31.6 trillion cubic feet in 2040, driven primarily by increased electricity generation and industrial use. International demand for exports of U.S. natural gas, through pipelines and liquefied natural gas, is forecasted to grow to 5.8 trillion cubic feet per year by 2040. The EIA forecasts the total demand for U.S. natural gas to reach 37.4 trillion cubic feet in 2040. As a result of this increase in demand, the EIA projects U.S. natural gas production to increase from 24.1 trillion cubic feet in 2012 to 37.5 trillion cubic feet in 2040, a 56% increase. Almost all of this increase is due to projected growth in natural gas production from resource plays, which is projected to grow from 9.7 trillion cubic feet in 2012 to 19.8 trillion cubic feet in 2040. We have significant exposure to domestic natural gas resource plays, including the Haynesville/Bossier play, the Fayetteville Shale, and the Barnett Shale, and we believe that these assets will provide meaningful upside in production and revenue growth as demand for natural gas increases. Our gas assets throughout the U.S. Gulf Coast are well-positioned geographically to take advantage of the growing liquefied natural gas export market.

 

   

Financial flexibility to fund expansion. Upon the completion of this offering and the application of the net proceeds as set forth under “Use of Proceeds,” we expect to have no indebtedness outstanding, approximately $        million of cash on hand, and $        million of undrawn borrowing capacity under our credit facility. The credit facility, combined with internally generated cash flow and access to the public capital markets, will provide us with the financial capacity and flexibility to grow our business.

 

   

Experienced and proven management team. The members of our executive team have an average of over 25 years of industry experience and have a proven track record of executing accretive acquisitions and maximizing asset development. We expect to benefit from the longstanding relationships fostered by our management team within the industry and the decades-long track record of successful acquisitions of mineral and royalty interests. We believe the experience of our management team in acquiring and managing mineral and royalty interests will allow us to continue to grow our production, reserves, and distributions.

 

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Management

We are managed and operated by the board of directors and executive officers of our general partner, Black Stone Natural Resources, L.L.C., a wholly owned subsidiary of BSMC. In connection with the closing of this offering, we will complete a series of transactions pursuant to which, among other things, BSMC and BSNR will become our wholly owned subsidiaries. Please read “—Formation Transactions and Structure.” Our partnership agreement provides that our limited partners holding common and preferred units have the right to nominate and vote in the election of directors to the board of directors of our general partner. The board of directors of our general partner must have at least three directors who meet the independence standards established by the New York Stock Exchange (the “NYSE”) within one year of the consummation of this offering. At least one independent director will be appointed by the time our common units are first listed for trading on the NYSE.

Our partnership agreement provides that an annual meeting of the limited partners for the election of directors to the board of directors of our general partner will be held at a date and time as may be fixed from time to time by our general partner. At each annual meeting, the limited partners authorized to vote will elect by a plurality of the votes cast at the meeting persons to serve as directors on the board of directors of our general partner who are nominated in accordance with the provisions of our partnership agreement. At all elections of the board of directors of our general partner, each limited partner authorized to vote will be entitled to cumulate his or her votes and give one candidate, or divide among any number of candidates, a number of votes equal to the product of (x) the number of units held by each limited partner, multiplied by (y) the number of directors to be elected at the meeting.

Fiduciary Duties

Our partnership agreement contains provisions that eliminate the fiduciary duties to which our general partner and the directors and executive officers of our general partner would otherwise be held by state fiduciary duty law and imposes contractual standards that our general partner and its directors and executive officers must follow. Our partnership agreement also specifically restricts the situations in which remedies may be available to our unitholders for actions taken that might otherwise constitute breaches of duty under applicable Delaware law or breaches of the contractual obligations in our partnership agreement. 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 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 duties of our general partner and its directors and executive officers, please read “Fiduciary Duties.”

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 generally applicable 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 (the “Sarbanes-Oxley Act”);

 

   

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;

 

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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 this 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 issue more than $1.0 billion of non-convertible debt over a three-year period; (iii) the last day of the fiscal year following the fifth anniversary of our initial public offering; or (iv) when we have qualified as a “large accelerated filer,” which refers to when we (w) will have an aggregate worldwide market value of voting and non-voting common units held by our non-affiliates of $700 million or more, as of the last business day of our most recently completed second fiscal quarter, (x) have been subject to the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), for a period of at least 12 calendar months, (y) have filed at least one annual report pursuant to Section 13(a) or 15(d) of the Exchange Act, and (z) no longer be eligible to use the requirements for “smaller reporting companies,” as defined in the Exchange Act, for our annual and quarterly reports.

Formation Transactions and Structure

In connection with this offering, the following transactions have occurred or will occur:

 

   

BSNR will contribute cash to (i) BSMC in exchange for             common units representing a 1% limited partner interest in BSMC and (ii) the partnership in exchange for             common units representing a 1% limited partner interest in the partnership;

 

   

BSMC will merge with and into a wholly owned subsidiary of the partnership (“Merger Sub”) with BSMC as the surviving entity;

 

   

in connection with the merger, (i) the partnership will redeem the limited partner interest in it held by BSMC, (ii) the common units and the preferred units of BSMC (other than those common units of BSMC that are held by BSNR) will be exchanged for an aggregate of             of the partnership’s common units and             of the partnership’s preferred units, respectively, (iii) the common units of BSMC that are held by BSNR will be exchanged for a 1% limited partner interest in BSMC, (iv) the non-economic general partner interest in the partnership held by BSNR will continue to be outstanding, and (v) the partnership’s 100% equity interest in Merger Sub will be converted into a 99% limited partner interest in BSMC, and the non-economic general partner interest in BSMC held by BSNR will continue to be outstanding;

 

   

immediately following the merger, the limited partnership agreement of BSMC and the limited liability company agreement of BSNR will be amended and restated;

 

   

the partnership will amend and restate its credit facility;

 

   

the partnership will enter into a registration rights agreement under which certain of its affiliates will have the right to cause it to register the offer and sale of any units that they hold under the Securities Act and applicable state securities laws; and

 

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the partnership will issue and sell             common units to the public in this offering and 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             additional common units. Any net proceeds received from the exercise of this option will be used to fund future capital expenditures.

 

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

 

 

LOGO

 

Common units issued in this offering

                

Units issued in the merger:

     

Common units

                

Preferred units

                

Interests held by our general partner:

     

Non-economic general partner interest

        0.0

Common units

                
  

 

  

 

 

 
        100.0
  

 

  

 

 

 

 

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Principal Executive Offices

Our principal executive offices are located at 1001 Fannin Street, Suite 2020, Houston, Texas 77002, and our telephone number is (713) 658-0647. Our website address will be www.                    .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.

 

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Risk Factors

An investment in our common units involves risks. You should carefully consider the following considerations, 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.

Risks Related to Our Business

 

   

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

 

   

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

 

   

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.

 

   

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.

 

   

Natural gas prices have declined substantially from historical highs and are expected to remain depressed for the foreseeable future. Approximately 74.2% of our 2013 production and 71.8% of our production in the first six months of 2014, on an MBoe basis, was natural gas. Any additional decreases in prices of natural gas may adversely affect our cash flow, results of operations, and financial position, perhaps materially.

 

   

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

 

   

Any acquisitions of additional mineral and royalty interests that we complete will be subject to substantial risks.

 

   

Title to the properties in which we have an interest may be impaired by title defects.

 

   

We depend on various unaffiliated operators for all of the exploration, development, and production on the properties underlying our mineral and royalty interests and non-operated working interests. Substantially all of our revenue is derived from the sale of oil and gas production from producing wells in which we own a royalty interest or a non-operated working interest. A reduction in the expected number of wells to be drilled on our acreage by these operators or the failure of our operators to adequately and efficiently develop and operate our acreage could have an adverse effect on our results of operations.

 

   

We may experience delays in the payment of royalties and be unable to replace operators that do not make required royalty payments, and we may not be able to terminate our leases with defaulting lessees if any of the operators on those leases declare bankruptcy.

 

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Acquisitions, funding our working-interest participation program, and our operators’ development activities of our leases will require substantial capital, and we and our operators may be unable to obtain needed capital or financing on satisfactory terms or at all.

 

   

Unless we replace the oil and natural gas produced from our properties, our cash flow from operations and our ability to make distributions to our common unitholders could be adversely affected.

 

   

We either have little or no control over the timing of future drilling with respect to our mineral and royalty interests and non-operated working interests.

 

   

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

 

   

Our operators’ identified potential drilling locations are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

 

   

The unavailability, high cost, or shortages of rigs, equipment, raw materials, supplies, or personnel may restrict or result in increased costs for operators related to developing and operating our properties.

 

   

The marketability of oil and natural gas production is dependent upon transportation, pipelines, and refining facilities, which neither we nor many of our operators control. Any limitation in the availability of those facilities could interfere with our or our operators’ ability to market our or our operators’ production and could harm our business.

 

   

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.

 

   

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

 

   

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

 

   

The results of 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.

 

   

Oil and natural gas operations are subject to various governmental laws and regulations. Compliance with these laws and regulations can be burdensome and expensive, and failure to comply could result in significant liabilities, which could reduce our cash available for distribution.

 

   

Louisiana mineral servitudes are subject to reversion to the surface owner after ten years’ nonuse.

 

   

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

 

   

The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the oil and natural gas that our operators produce.

 

   

Operating hazards and uninsured risks may result in substantial losses to us or our operators, and any losses could adversely affect our results of operations and cash available for distribution.

 

   

Cyber attacks could significantly affect us.

Risks Inherent in an Investment in Us

 

   

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

 

   

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. If we

 

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make distributions, our preferred unitholders have priority with respect to rights to share in those distributions over our common unitholders for so long as our preferred units are outstanding.

 

   

Our partnership agreement eliminates the fiduciary duties that might otherwise be owed to the partnership and its partners by our general partner and its directors and executive officers under Delaware law.

 

   

Our partnership agreement restricts the situations in which remedies may be available to our unitholders for actions taken that might constitute breaches of duty under applicable Delaware law and breaches of the contractual obligations in our partnership agreement.

 

   

Our partnership agreement restricts the voting rights of unitholders owning 15% or more of our common units, subject to certain exceptions.

 

   

We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets, which may affect our ability to make distributions to you.

 

   

Unitholders may not have limited liability if a court finds that unitholder action constitutes participation in control of our business.

 

   

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

 

   

Increases in interest rates may cause the market price of our common units to decline.

 

   

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

 

   

We may issue additional common units and other equity interests without common unitholder approval, which would dilute holders of common units. However, our partnership agreement does not authorize us to issue units ranking senior to or at parity with our preferred units without preferred unitholder approval.

 

   

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.

 

   

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.

 

   

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

 

   

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, disclosure about our executive compensation and internal control auditing requirements that apply to other 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.

 

   

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

 

   

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

 

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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 common unitholders.

 

   

Common unitholders who are not “Eligible Holders” will not be entitled to receive distributions on or allocations of income or loss on their common units, and their common units will be subject to redemption.

Tax Risks to Common Unitholders

 

   

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 (“IRS”) 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 unitholders could be substantially reduced.

 

   

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.

 

   

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

 

   

Even if a unitholder does not receive any cash distributions from us, a unitholder will be required to pay taxes on its share of our taxable income.

 

   

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

 

   

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.

 

   

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.

 

   

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.

 

   

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.

 

   

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.

 

   

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.

 

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The Offering

 

Common units offered to the public

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

 

Units outstanding after this offering

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

 

Use of proceeds

We intend to use the estimated net proceeds of approximately $         million from this offering (based on an assumed initial offering price of $         per common unit, the mid-point of the price range set forth on the cover page of this prospectus), after deducting the estimated underwriting discount and offering expenses payable by us, to repay all of the indebtedness outstanding under our credit facility and to fund future capital expenditures.

 

  The net proceeds from any exercise of the underwriters’ option to purchase additional common units (approximately $         million based on an assumed initial offering price of $         per common unit, the mid-point of the price range set forth on the cover page of this prospectus, after deducting the estimated underwriting discount, if exercised in full) will be used to fund future capital expenditures. Please read “Use of Proceeds.”

 

  Affiliates of certain of our underwriters are lenders under our credit facility and, as such, may receive a portion of the proceeds from this offering. Please read “Underwriting—Relationships.”

 

Cash distributions

Within 60 days after the end of each quarter, beginning with the quarter ending                     , 2015, we expect to make distributions to common unitholders of record on the applicable record date. We expect our first distribution will consist of available cash for the period from the closing of this offering through                     , 2015.

 

  If we make distributions, our preferred unitholders have priority with respect to rights to share in those distributions over our common unitholders for so long as our preferred units are outstanding. When all of our preferred units have been redeemed or converted to common units, all distributions will be made pro rata to our common unitholders.

 

 

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 a substantial majority of the available cash we generate each quarter. Available cash for each quarter will be determined by the board of directors of our general partner following the end of that quarter. Our initial distribution will be $         per common unit on an annualized basis, which we forecast to represent approximately     %

 

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of our available cash for the year ending December 31, 2015. It is our intent, for at least the next several years, to finance most of our acquisition and working-interest capital needs with the retained net proceeds from this offering, borrowings under our credit facility, and, in certain circumstances, proceeds from future equity and debt issuances. We may also borrow to make distributions to our unitholders where, for example, we believe that the distribution level is sustainable over the long term, but short-term factors may cause available cash from operations to be insufficient to pay distributions at the current level. 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. If we make distributions, our preferred unitholders have priority with respect to rights to share in those distributions over our common unitholders for so long as our preferred units are outstanding.”

 

  Replacement capital expenditures are expenditures necessary to replace our existing oil and natural gas reserves or otherwise maintain our asset base over the long term. 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 the development of existing plays and the discovery of new resources on our mineral and royalty interests will add reserves and will lead to increasing revenues for at least the next several years. We also intend to add reserves through acquisitions of mineral and royalty interests and through non-operated working-interest participation. We may restrict distributions to fund acquisitions and participation in working interests in whole or in part. If we do not retain cash for capital expenditures in amounts necessary to maintain our asset base, our cash available for distribution per unit will decrease over time. The board of directors of our general partner may in the future decide to withhold capital expenditures from cash available for distribution, which may have an adverse impact on the cash available for distribution per unit in the quarter in which those amounts are withheld. To the extent that we do not withhold cash for capital expenditures in the future, a portion of our future cash available for distribution will represent a return of your capital.

 

Subordinated units

None.

 

Incentive distribution rights

None.

 

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Issuance of additional units

Our partnership agreement authorizes us to issue an unlimited number of additional units, including units that are senior to the common units, without the approval of our unitholders. However, our partnership agreement does not authorize us to issue securities having preferences or rights with priority over or on a parity with the preferred units with respect to rights to share in distributions, redemption obligations, or redemption rights unless we receive the approval of our preferred unitholders. Please read “Units Eligible for Future Sale,” “The Partnership Agreement—Issuance of Additional Partnership Interests” and “Description of Our Preferred Units.”

 

Estimated ratio of taxable income to distributions

We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending December 31,         , you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be approximately     % 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.”

 

Exchange listing

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

 

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Summary Historical and Pro Forma Financial Data

Black Stone Minerals, L.P. was formed in September 2014 and does not have historical financial statements. Therefore, in this prospectus we present the historical financial statements of BSMC, our predecessor for accounting purposes. We refer to this entity as “Black Stone Minerals, L.P. Predecessor.” The following table presents summary historical financial data of BSMC and summary pro forma financial data of Black Stone Minerals, L.P. as of the dates and for the periods indicated.

The summary historical financial data presented as of and for the years ended December 31, 2013 and 2012 are derived from the audited historical financial statements of BSMC that are included elsewhere in this prospectus. The summary historical financial data presented as of and for the six months ended June 30, 2014 and for the six months ended June 30, 2013 are derived from the unaudited historical financial statements of BSMC included elsewhere in this prospectus.

The summary pro forma financial data presented for the year ended December 31, 2013 and as of and for the six months ended June 30, 2014 are derived from our pro forma financial statements included elsewhere in this prospectus. Our pro forma financial statements give pro forma effect to the issuance and sale of the common units in this offering and the application of the net proceeds therefrom as described under “Use of Proceeds.” The pro forma balance sheet assumes the events described above occurred as of June 30, 2014. The pro forma statements of operations for the year ended December 31, 2013 and the six months ended June 30, 2014 assume the events described above occurred as of January 1, 2013.

We have not given pro forma effect to incremental general and administrative expenses of approximately $         million that we expect to incur annually as a result of operating as a publicly traded partnership, such as 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, NYSE listing, independent-auditor fees, legal fees, investor-relations activities, registrar and transfer agent fees, director-and-officer insurance, and additional compensation.

 

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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 and unaudited historical financial statements of BSMC and our pro forma financial statements 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.

 

    Black Stone Minerals, L.P. Predecessor
Historical
    Black Stone Minerals,
L.P.
Pro Forma
 
    Year Ended
December 31,
    Six Months Ended
June 30,
    Year Ended
December 31,
2013
    Six Months
Ended
June 30,
2014
 
    2012     2013     2013     2014      
                (unaudited)     (unaudited)  
    (in thousands)  

Revenues:

           

Oil and condensate sales

  $ 202,104      $ 252,742      $ 118,615      $ 124,576      $ 252,742      $ 124,576   

Natural gas and natural gas liquids sales

    166,849        184,868        95,335        110,640        184,868        110,640   

Gain (loss) on commodity derivative instruments

    12,275        (5,860     1,522        (8,343     (5,860     (8,343

Lease bonus and other income

    53,918        31,809        7,155        19,476        31,809        19,476   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

  $ 435,146      $ 463,559      $ 222,627      $ 246,349      $ 463,559      $ 246,349   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating Expenses:

           

Lease operating expense and other

  $ 20,527      $ 21,316      $ 10,347      $ 9,674      $ 21,316      $ 9,674   

Production and ad valorem taxes

    36,680        42,813        19,340        21,408        42,813        21,408   

Depreciation, depletion and amortization

    104,059        102,442        51,090        46,993        102,442        46,993   

Impairment of oil and natural gas properties

    62,987        57,109        27,630               57,109          

General and administrative expense

    50,348        59,501        28,940        29,963        59,501        29,963   

Accretion of asset retirement obligations

    608        588        307        295        588        295   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total operating expenses

  $ 275,209      $ 283,769      $ 137,654      $ 108,333      $ 283,769      $ 108,333   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income from operations

  $ 159,937      $ 179,790      $ 84,973      $ 138,016      $ 179,790      $ 138,016   

Other income (expense):

           

Interest and investment income

  $ 209      $ 90      $ 65      $ 24      $ 90      $ 24   

Interest expense(1)

    (9,166     (11,342     (4,747     (6,852     (3,633     (1,835

Gain on sale of assets

    363        18        18               18          

Other income

    467        407        137        807        407        807   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total other income (expense)

    (8,127     (10,827     (4,527     (6,021     (3,118     (1,004
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income

  $ 151,810      $ 168,963      $ 80,446      $ 131,995      $ 176,672      $ 137,012   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Statement of Cash Flow Data:

           

Net cash provided by (used in):

           

Operating activities

  $ 358,002      $ 320,764      $ 142,900      $ 165,860       

Investing activities

    (198,975     (195,631     (123,855     (59,855    

Financing activities

    (138,172     (142,311     (44,441     (123,339    

Other Financial Data:

           

EBITDA(2)

  $ 328,630      $ 340,444      $ 164,220      $ 186,135      $ 340,444      $ 186,135   

Adjusted EBITDA(2)

    346,574        354,576        167,942        197,189        354,576        197,189   

Capital expenditures(3)

    (198,975     (195,631     (123,855     (59,855    

Balance Sheet Data (at period end):

           

Cash and cash equivalents

  $ 47,301      $ 30,123        $ 12,789        $     

Total assets

    1,199,187        1,444,413          1,466,769       

Long-term debt (including current portion)

    363,100        451,000          453,000            

Total liabilities

    711,143        566,618          574,744          121,744   

Total mezzanine equity

    161,381        161,392          161,122       

Total equity

  $ 326,663      $ 716,403        $ 730,903        $     

 

(1) Includes cash expenses of commitment fees and agency fees and non-cash amortization of debt issuance costs.
(2) Please read “—Non-GAAP Financial Measures” below for the definitions of EBITDA and Adjusted EBITDA and a reconciliation of EBITDA and Adjusted EBITDA to our most directly comparable financial measure, calculated and presented in accordance with generally accepted accounting principles in the United States (“GAAP”).
(3) Net of proceeds from the sale of assets of $1.0 million and $0.1 million for the years ended December 31, 2013 and December 31, 2012, respectively, and $0.1 million for the six months ended June 30, 2013.

 

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Non-GAAP Financial Measures

EBITDA and Adjusted EBITDA are non-GAAP supplemental financial measures used by our management and by external users of our financial statements such as investors, commercial banks, research analysts, and others, to assess:

 

   

our ability to make distributions to unitholders;

 

   

the financial performance of our assets without regard to financing methods, capital structure, or historical cost basis;

 

   

the ability of our assets to generate sufficient cash to pay interest costs and support our indebtedness;

 

   

our operating performance and return on capital as compared to those of other companies and partnerships in our industry, without regard to financing or capital structure; and

 

   

the feasibility of acquisitions and other capital expenditures and the overall rates of return on investment opportunities.

We define EBITDA as net income (loss) before interest expense, income taxes, depreciation, depletion and amortization, impairment of oil and natural gas properties, and accretion of asset retirement obligations (“ARO”). We define Adjusted EBITDA as EBITDA further adjusted for unrealized gains/losses on derivative instruments and non-cash equity-based compensation.

EBITDA and Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income, income from operations, cash flows from operating activities, or any other measure of financial performance or liquidity presented in accordance with GAAP as measures of our operating performance or liquidity. EBITDA and Adjusted EBITDA do not include changes in working capital, capital expenditures, and other items that are set forth in a cash flow statement presentation of our operating, investing, and financing activities. Any measures that exclude these elements have material limitations. Our computation of EBITDA and Adjusted EBITDA may differ from computations of similarly titled measures of other companies.

 

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

 

    Black Stone Minerals, L.P. Predecessor
Historical
    Black Stone  Minerals,
L.P.
Pro Forma
 
    Year Ended
December 31,
    Six Months Ended
June 30,
    Year Ended
December 31,
2013
    Six Months
Ended
June 30,
2014
 
    2012     2013     2013     2014      
                (unaudited)     (unaudited)  
    (in thousands)  

Reconciliation of EBITDA and Adjusted EBITDA to net income:

           

Net income

  $ 151,810      $ 168,963      $ 80,446      $ 131,995      $ 176,672      $ 137,012   

Add:

           

Depletion, depreciation and amortization

    104,059        102,442        51,090        46,993        102,442        46,993   

Impairment of oil and natural gas properties

    62,987        57,109        27,630               57,109          

Accretion of asset retirement obligations

    608        588        307        295        588        295   

Interest expense(1)

    9,166        11,342        4,747        6,852        3,633        1,835   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

EBITDA

    328,630        340,444        164,220        186,135        340,444        186,135   

Add:

           

Unrealized loss on commodity derivative instruments

    10,697        7,350        328        5,400        7,350        5,400   

Equity-based compensation expense(2)

    7,247        6,782        3,394        5,654        6,782        5,654   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

  $ 346,574      $ 354,576      $ 167,942      $ 197,189      $ 354,576      $ 197,189   

 

(1) Includes cash expenses of commitment fees and agency fees and non-cash amortization of debt issuance costs.
(2) Represents compensation expense that is settled in common units.

 

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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. Our preferred unitholders have priority with respect to rights to share in distributions over our common unitholders. Furthermore, our partnership agreement does not require us to pay distributions to our common unitholders on a quarterly basis or otherwise. Available cash for each quarter will be determined by the board of directors of our general partner. Our expected aggregate annual distribution amount for the year ending December 31, 2015 is based on the assumptions set forth in “Cash Distribution Policy and Restrictions on Distributions—Estimated Cash Available for Distribution for the Year Ending December 31, 2015—Assumptions and Considerations.” If our assumptions prove to be inaccurate, our actual distributions for the year ending December 31, 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 revenues we generate, which are largely dependent upon the prices that our operators realize from the sale of oil and natural gas. The actual amount of cash we will have to distribute each quarter will be reduced by principal and interest payments on our outstanding debt, working-capital requirements, and other cash needs. In addition, we may restrict distributions, in whole or in part, to fund acquisitions and participation in working interests. If we do not retain cash for replacement capital expenditures in amounts necessary to maintain our asset base, our cash available for distribution will decrease over time. The board of directors of our general partner may in the future decide to withhold from cash available for distribution amounts for our capital expenditures which may have an adverse impact on the cash available for distribution in the quarter in which amounts are withheld.

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” and “Description of Our Preferred Units—Distributions.”

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 year ending December 31, 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.

 

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The amount of cash we have available for distribution to holders of our units depends primarily on our cash flow and not our 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.

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 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 common unitholders will vary significantly from quarter to quarter and may be zero.

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 and demand for oil and natural gas;

 

   

market 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 regions, 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;

 

   

trading in crude oil and natural gas derivative contracts;

 

   

the level of consumer product demand;

 

   

weather conditions and natural disasters;

 

   

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;

 

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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 spot 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 $59.62 per barrel, or Bbl, in 2009 to a high of $113.39 per Bbl in 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 2012 to a high of $8.15 per MMBtu in 2014. 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 June 30, 2013, the West Texas Intermediate spot price for crude oil was $96.36 per Bbl and the Henry Hub spot market price of natural gas was $3.57 per MMBtu. On June 30, 2014, the West Texas Intermediate spot price for crude oil was $106.07 per Bbl and the Henry Hub spot market price of natural gas was $4.39 per MMBtu. Any prolonged 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. We may use various derivative instruments in connection with anticipated oil and gas sales to minimize the impact of commodity price fluctuations. However, we cannot always hedge the entire exposure of our operations from commodity price volatility. To the extent we do not hedge against commodity price volatility, or our hedges are not effective, our results of operations and financial position may be diminished.

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 our having to make substantial downward adjustments to our estimated proved reserves, which could negatively impact our borrowing base and our ability to fund our operations. 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.

Natural gas prices have declined substantially from historical highs and are expected to remain depressed for the foreseeable future. Approximately 74.2% of our 2013 production and 71.8% of our production in the first six months of 2014, on an MBoe basis, was natural gas. Any additional decreases in prices of natural gas may adversely affect our cash flow, results of operations, and financial position, perhaps materially.

Natural gas prices have declined from an average price at Henry Hub of $8.89 per MMBtu in 2008 to $3.73 per MMBtu in 2013. The reduction in prices has been caused by many factors, including increases in gas production and reserves from unconventional (shale) reservoirs, without an offsetting increase in demand. The expected increase in natural gas production, based on reports from the EIA, could cause the prices for natural gas to remain at current levels or fall to lower levels. If prices for natural gas continue to remain depressed for lengthy periods, we may be required to write down the value of our oil and natural gas properties, which may cause some of our undeveloped locations to no longer be economically viable. In addition, sustained low prices for natural gas will reduce the amounts we would otherwise have available to pay expenses, make distributions to our common unitholders and service our indebtedness.

 

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

We depend partly on acquisitions to grow our reserves, production, and cash flow. Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic data, and other information, the results of which are often inconclusive and subject to various interpretations. The successful acquisition of properties requires an assessment of several factors, including:

 

   

recoverable reserves;

 

   

future oil and natural gas prices and their applicable differentials;

 

   

development plans;

 

   

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, if applicable, 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.

There is intense competition for acquisition opportunities in our industry. 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 financing. In addition, 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 additional legal requirements. Further, the success of any completed acquisition will depend on our ability to integrate effectively the acquired assets into our existing operations. The process of integrating acquired assets may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources.

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.

Any acquisitions of additional mineral and royalty interests that we complete will be subject to substantial risks.

Even if we do make acquisitions that we believe will increase our cash available for distribution, these acquisitions may nevertheless result in a decrease in our cash available for distribution. Any acquisition involves potential risks, including, among other things:

 

   

the validity of our assumptions about estimated proved reserves, future production, prices, revenues, capital expenditures, operating expenses, and costs;

 

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a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions;

 

   

a significant increase in our interest expense or financial leverage if we incur debt to finance acquisitions;

 

   

the assumption of unknown liabilities, losses, or costs for which we are not indemnified or for which any indemnity we receive is inadequate;

 

   

mistaken assumptions about the overall cost of equity or debt;

 

   

our ability to obtain satisfactory title to the assets we acquire;

 

   

an inability to hire, train, or retain qualified personnel to manage and operate our growing business and assets; and

 

   

the occurrence of other significant changes, such as impairment of oil and natural gas properties, goodwill or other intangible assets, asset devaluation, or restructuring charges.

Title to the properties in which we have an interest may be impaired by title defects.

No assurance can be given that we will not suffer a monetary loss from title defects or title failure. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.

We depend on various unaffiliated operators for all of the exploration, development, and production on the properties underlying our mineral and royalty interests and non-operated working interests. Substantially all of our revenue is derived from the sale of oil and gas production from producing wells in which we own a royalty interest or a non-operated working interest. A reduction in the expected number of wells to be drilled on our acreage by these operators or the failure of our operators to adequately and efficiently develop and operate our acreage could have an adverse effect on our results of operations.

Our assets consist of mineral and royalty interests and non-operated working interests. For the six months ended June 30, 2014, we received revenue from over 1,400 operators. The failure of our operators 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. Our operators are often not obligated to undertake any development activities other than those required to maintain their leases on our acreage. In the absence of a specific contractual obligation, any development and production activities will be subject to their reasonable discretion. Our operators 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 capital costs required for drilling activities by our operators, which could be significantly more than anticipated;

 

   

the ability of our operators to access capital;

 

   

prevailing commodity prices;

 

   

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;

 

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the selection of counterparties for the marketing and sale of production; and

 

   

the rate of production of the reserves.

The operators may elect not to undertake development activities, or may undertake these activities in an unanticipated fashion, which may result in significant fluctuations in our results of operations and cash available for distribution to our common unitholders. Sustained reductions in production by the operators on our properties may also adversely affect our results of operations and cash available for distribution.

We may experience delays in the payment of royalties and be unable to replace operators that do not make required royalty payments, and we may not be able to terminate our leases with defaulting lessees if any of the operators on those leases declare bankruptcy.

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 a proceeding under title 11 of the United States Code (the “Bankruptcy Code”), in which case our right to enforce or terminate the lease for any defaults, including non-payment, may be substantially delayed or otherwise impaired. In general, in a proceeding under the Bankruptcy Code, the bankrupt operator would have a substantial period of time to decide whether to ultimately reject or assume the lease, which could prevent the execution of a new lease or the assignment of the existing lease to another operator. In the event that the operator rejected the lease, our ability to collect amounts owed would be substantially delayed, and our ultimate recovery may be only a fraction of the amount owed or nothing. In addition, if we are able to enter into a new lease with a new operator, 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.

Acquisitions, funding our working-interest participation program, and our operators’ development activities of our leases will require substantial capital, and we and our operators may be unable to obtain needed capital or financing on satisfactory terms or at all.

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in connection with the acquisition of mineral and royalty interests and participation in our working-interest participation program. To date, we have financed capital expenditures primarily with funding from cash generated by operations, limited borrowings under our credit facility and an issuance of equity securities.

In the future, we may restrict distributions to fund acquisitions and participation in our working interests but eventually we may need capital in excess of the amounts we retain in our business or borrow under our credit facility. We cannot assure you that we will be able to access external capital on terms favorable to us or at all. If we are unable to fund our capital requirements, we may be unable to complete acquisitions, take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our results of operation and cash available for distribution.

Most of our operators are also dependent on the availability of external debt and equity financing sources to maintain their drilling programs. If those financing sources are not available to the operators on favorable terms or at all, then we expect the development of our properties to be adversely affected. If the development of our properties is adversely affected, then revenues from our mineral and royalty interests and non-operated working interests may decline.

 

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Unless we replace the oil and natural gas produced from our properties, our cash flow from operations and our ability to make distributions to our common unitholders could be adversely affected.

Producing oil and natural gas wells are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and our operators’ production thereof and our cash flow and ability to make distributions are highly dependent on the successful development and exploitation of our current reserves. The production decline rates of our properties may be significantly higher than currently estimated if the wells on our properties do not produce as expected. We may also not be able to find, acquire, or develop additional reserves to replace the current and future production of our properties at economically acceptable terms, which would adversely affect our business, financial condition and results of operations, and cash available for distribution to our common unitholders.

We either have little or no control over the timing of future drilling with respect to our mineral and royalty interests and non-operated working interests.

Our proved undeveloped reserves may not be developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations, and the decision to pursue development of a proved undeveloped drilling location will be made by the operator and not by us. The reserve data included in the reserve report of our engineer assume that substantial capital expenditures are required to develop the 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 the development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop our 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.

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. 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 adversely affected.

Our operators’ identified potential drilling locations are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

The ability of our operators to drill and develop identified potential drilling locations depends 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, our operators’ identified potential drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation. The use of technologies and the study of producing fields in the same area will not enable our operators 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, our operators 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 our operators drill additional wells that they identify as dry holes in current and future drilling locations, their drilling success rate may decline and materially harm their business as well as ours.

We cannot assure you that the analogies our operators draw from available data from the wells on our acreage, more fully explored locations or producing fields will be applicable to their drilling locations. Further, initial production rates reported by our or other operators in the areas in which our reserves are located may not be indicative of future or long-term production rates. Because of these uncertainties, we do not know if the

 

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potential drilling locations our operators have identified will ever be drilled or if our operators will be able to produce oil or natural gas from these or any other potential drilling locations. As such, the actual drilling activities of our operators may materially differ from those presently identified, which could adversely affect our business, results of operation, and cash available for distribution.

The unavailability, high cost, or shortages of rigs, equipment, raw materials, supplies, or personnel may restrict or result in increased costs for operators related to developing and operating our properties.

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. In accordance with customary industry practice, our operators rely on independent third-party service providers to provide many of the services and equipment necessary to drill new wells. If our operators are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of operations could suffer. 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 operators’ exploration and development operations, which in turn could have a material adverse effect on our financial condition, results of operations, and cash available for distribution.

The marketability of oil and natural gas production is dependent upon transportation, pipelines, and refining facilities, which neither we nor many of our operators control. Any limitation in the availability of those facilities could interfere with our or our operators’ ability to market our or our operators’ production and could harm our business.

The marketability of our or our operators’ production depends in part on the availability, proximity, and capacity of pipelines, tanker trucks, and other transportation methods, and processing and refining facilities owned by third parties. The amount of oil that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage, or lack of available capacity on these systems, tanker truck availability, and extreme weather conditions. Also, the shipment of our or our operators’ oil and natural gas on third-party pipelines may be curtailed or delayed if it does not meet the quality specifications of the pipeline owners. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we or our operators are provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or transportation, processing, or refining-facility capacity could reduce our or our operators’ ability to market oil production and have a material adverse effect on our financial condition, results of operations, and cash available for distribution. Our or our operators’ access to transportation options and the prices we or our operators receive can also be affected by federal and state regulation—including regulation of oil production and transportation, and pipeline safety—as well by general economic conditions and changes in supply and demand. In addition, the third parties on whom we or our operators rely for transportation services are subject to complex federal, state, tribal, and local laws that could adversely affect the cost, manner, or feasibility of conducting our business.

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, 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 Pressler Petroleum Consultants, Inc. (“Pressler”), a third-party petroleum engineering firm, which

 

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conducted a detailed well-by-well review of all our properties for the period covered by its reserve report using information provided by us as well as publicly available production information. 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 and future net cash flows. 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 SEC guidelines applicable to reserve estimates for those periods. 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.

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 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 could disrupt our business. 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.

The results of 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.

Our operators use the latest drilling and completion techniques in their operations, and these techniques come with inherent risks. When drilling horizontal wells, operators risk not landing the well bore in the desired drilling zone and straying from the desired drilling zone. When drilling horizontally through a formation, operators risk being unable to run casing through the entire length of the well bore and being unable to run tools and other equipment consistently through the horizontal well bore. Risks that our operators face while completing wells include being unable to fracture stimulate the planned number of stages, to run tools the entire length of the well bore during completion operations, and to clean out the well bore after completion of the final fracture stimulation stage. In addition, to the extent our operators engage in horizontal drilling, those activities may adversely affect their ability to successfully drill in identified vertical drilling locations. Furthermore, certain of the new techniques that our operators 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 these 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 our operators 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 operators’ drilling results are weaker than anticipated or they are unable to execute their drilling program on our properties

 

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because of capital constraints, lease expirations, access to gathering systems, or declines in natural gas and oil prices, our operating and financial results in these areas may be lower than 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 and our results of operations and cash available for distribution could be adversely affected.

Oil and natural gas operations are subject to various governmental laws and regulations. Compliance with these laws and regulations can be burdensome and expensive, and failure to comply could result in significant liabilities, which could reduce our cash available for distribution.

Operations on the properties in which we hold interests are 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 drilling operations, production and distribution activities, discharges or releases of pollutants or wastes, plugging and abandonment of wells, maintenance and decommissioning of other facilities, 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 natural 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 safety 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. Our operators must 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 increased capital costs on the part of operators and third-party downstream natural gas transporters.

Our operators must also 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 those pipelines and with federal policies related to the use of interstate capacity.

Our operators may be required to make significant expenditures 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 may affect us. These and other potential regulations could increase the operating costs of our operators and delay production, which could reduce the amount of cash available for distribution to our common unitholders.

 

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Louisiana mineral servitudes are subject to reversion to the surface owner after ten years’ nonuse.

We own mineral servitudes covering several hundred thousand acres in Louisiana. A mineral servitude is created in Louisiana when the mineral rights are separated from the ownership of the surface, whether by sale or reservation. These mineral servitudes, once created, are subject to a ten-year prescription of nonuse. During the ten-year period, the mineral-servitude owner has to conduct good-faith operations on the servitude for the discovery and production of minerals, or the mineral servitude “prescribes,” and the mineral rights associated with that servitude revert to the surface owner. A good-faith operation for the discovery and production of minerals, even one resulting in a dry hole, conducted within the ten-year period will interrupt the prescription of nonuse and restart the running of the ten-year prescriptive period. If the operation results in production, prescription is interrupted as long as the production continues or operations are conducted in good faith to secure or restore production. If any of our mineral servitudes are prescribed by operation of Louisiana law, our operating results may be adversely affected.

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

Our operators engage in hydraulic fracturing. Hydraulic fracturing is a 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 subject to regulation under the UIC program and that these wells are required to obtain “Class II” UIC permits. In addition, on May 9, 2014, the EPA issued an Advanced Notice of Proposed Rulemaking seeking comment on its proposed 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 is developing effluent-limitation guidelines that may impose federal pre-treatment standards on all oil and natural gas operators transporting wastewater associated with hydraulic-fracturing activities to publicly owned treatment works for disposal. The EPA plans to propose these standards within the next year.

Further, in April 2012, the EPA published final rules that subject all oil and natural gas operations (production, processing, transmission, storage, and distribution) to regulation under the New Source Performance Standards (“NSPS”) and the National Emission Standards for Hazardous Air Pollutants (“NESHAPS”) programs. These rules became effective in October 2012 and include NSPS standards for completions of hydraulically fractured gas wells. The standards include the reduced emission completion techniques developed in the EPA’s Natural Gas STAR program along with restrictions on the flaring of gas not sent to the gathering line. The standards are applicable to newly drilled and fractured wells and wells that are refractured on or after January 1, 2015. Other areas related to federal regulation of hydraulic fracturing include the U.S. Department of the Interior’s revised proposed rule, issued in May 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. The results of these studies 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

 

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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 or require the disclosure of the composition of hydraulic-fracturing fluids. For example, the Texas Railroad Commission has 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. We expect our operators to use hydraulic fracturing extensively in connection with the development and production of our oil and natural gas properties, and any increased federal, state, or local regulation of hydraulic fracturing could reduce the volumes of oil and natural gas that our operators 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 or hydraulic fracturing in particular. In the event state, local, or municipal legal restrictions are adopted in areas where our operators conduct operations, our operators may incur substantial costs to comply with these requirements, which 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, those laws could make it more difficult or costly for our operators to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing is further regulated at the federal or state level, fracturing activities on our properties 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. Legislative changes could cause operators to incur substantial compliance costs. 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.

The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the oil and natural gas that our operators produce.

In response to findings that emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, require preconstruction and operating permits for certain large stationary sources. Facilities required to obtain preconstruction permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established on a case-by-case basis. These EPA rulemakings could adversely affect operations on our properties and restrict or delay the ability of our operators to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sources in the United States on an annual basis, which include operations on certain of our properties.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking or reducing GHG emissions by means of cap and trade programs. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. Although it is not possible at this time to predict how legislation or new regulations that may be

 

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adopted to address GHG emissions would impact our business, any future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our operators’ equipment and operations could require them to incur costs to reduce emissions of GHGs associated with their operations. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas produced from our properties. 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 GHG emissions would impact our business. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, and other climatic events; if any of these effects were to occur, they could have a material adverse effect on our properties and operations.

Operating hazards and uninsured risks may result in substantial losses to us or our operators, and any losses could adversely affect our results of operations and cash available for distribution.

We may be secondarily liable for damage to the environment caused by our operators. The operations of our operators 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, their 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 our operators 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.

In accordance with what we believe to be customary industry practice, we 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 obtain, coverage for gradual, long-term pollution events. In addition, these 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.

Cyber attacks could significantly affect us.

Cyber attacks on businesses have escalated in recent years. We rely on electronic systems and networks to control and manage our business and have multiple layers of security to mitigate risks of cyber attack. If, however, we were to experience an attack and our security measures failed, the potential consequences to our businesses and the communities in which we operate could be significant.

 

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Risks Inherent in an Investment in Us

The board of directors of our general partner will adopt a policy to distribute a substantial majority of 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. If we are unable to finance growth externally, our distribution policy will significantly impair our ability to grow.

If 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. Other than limitations restricting our ability to issue units ranking senior or on a parity with our preferred units, there are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units with respect to distributions. If we incur debt to finance our growth, our interest expense will increase, reducing the available cash that we have to distribute to our unitholders. Please read “Cash Distribution Policy and Restrictions on Distributions.”

The board of directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion. Our partnership agreement does not require us to pay any distributions at all. If we make distributions, our preferred unitholders have priority with respect to rights to share in those distributions over our common unitholders for so long as our preferred units are outstanding.

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 a substantial majority of the available cash we generate each quarter to our unitholders of record. However, the board of directors of our general partner may change this 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 on our common units. Accordingly, investors are cautioned not to place undue reliance on the permanence of 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. If we make distributions, our preferred unitholders have priority with respect to rights to share in those distributions over our common unitholders for so long as our preferred units are outstanding. Please read “Description of Our Preferred Units—Distributions.”

Our partnership agreement eliminates the fiduciary duties that might otherwise be owed to the partnership and its partners by our general partner and its directors and executive officers under Delaware law.

Our partnership agreement contains provisions that eliminate the fiduciary duties that might otherwise be owed by our general partner and its directors and executive officers. For example, our partnership agreement provides that our general partner and its directors and executive officers have no duties to the partnership or its partners except as expressly set forth in the partnership agreement. In place of default fiduciary duties, our partnership agreement imposes a contractual standard requiring our general partner and its directors and executive officers to act in good faith, meaning they cannot cause the general partner to take an action that they subjectively believe is adverse to our interests. Such contractual standards allow our general partner and its directors and executive officers to manage and operate our business with greater flexibility and to subject the actions and determinations of our general partner and its directors and executive officers to lesser legal or judicial scrutiny than would be the case if state law fiduciary standards were applicable.

 

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Our partnership agreement restricts the situations in which remedies may be available to our unitholders for actions taken that might constitute breaches of duty under applicable Delaware law and breaches of the contractual obligations in our partnership agreement.

Our partnership agreement restricts the potential liability of our general partner and its directors and executive officers to our unitholders. For example, our partnership agreement provides that our general partner and its directors and executive officers will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in willful misconduct or fraud or, with respect to any criminal conduct, with the knowledge that its conduct was unlawful.

Unitholders are bound by the provisions of our partnership agreement, including the provisions described above. Please read “Fiduciary Duties.”

Our partnership agreement restricts the voting rights of unitholders owning 15% or more of our common units, subject to certain exceptions.

Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person or group that owns 15% or more of any class of units then outstanding, other than the initial limited partners in our predecessor, their transferees and persons who entitled to vote acquired those units with the prior approval of the board of directors of our general partner, may not vote on any matter. In addition, solely with respect to the election of directors, our partnership agreement provides that (x) our general partner and the partnership will not be their units, if any, and (y) if at any time any person or group beneficially owns 15% or more of the outstanding partnership securities of any class then outstanding and otherwise entitled to vote, then none of the partnership securities owned by such person or group of the outstanding partnership securities of the applicable class may be voted, and in each case, the foregoing units will not be counted when calculating the required votes for a matter and will not be deemed to be outstanding for purposes of determining a quorum for a meeting. These common units will not be treated as a separate class of partnership securities for purposes of our partnership agreement or the Delaware Revised Uniform Limited Partnership Act. Notwithstanding the foregoing, the board of directors of our general partner may, by action specifically referencing votes for the election of directors, determine that the limitation set forth in clause (y) above will not apply to a specific person or group. 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.

We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets, which may affect our ability to make distributions to you.

We are a partnership holding company, and our operating subsidiaries conduct all of our operations and own all of our operating assets. We have no significant assets other than the ownership interests in our subsidiaries. As a result, our ability to make distributions to our unitholders depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, the provisions of existing and future indebtedness, applicable state partnership and limited liability company laws, and other laws and regulations.

Unitholders may not have limited liability if a court finds that unitholder action constitutes participation in control of our business.

The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the states in which we do business. You could have unlimited liability for our obligations if a court or government agency determined that:

 

   

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

 

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

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 by Section 17-607 of the Delaware Act.

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.”

Increases in interest rates may cause the market price of our common units to decline.

An increase in interest rates may cause a corresponding decline in demand for equity investments in general, and in particular, for yield-based equity investments such as our common units. Any such increase in interest rates or reduction in demand for our common units resulting from other relatively more attractive investment opportunities may cause the trading price of our common units to decline.

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

The assumed initial public offering price of $         per common unit (the mid-point of the price range set forth on the cover page of this prospectus) exceeds our pro forma net tangible book value of $         per common unit. Based on the assumed initial public offering price of $         per common unit, common unitholders will incur immediate and substantial dilution of $         per common unit. This dilution results primarily because the assets contributed to us by our predecessor are recorded at their historical cost in accordance with GAAP and not their fair value. Please read “Dilution.”

We may issue additional common units and other equity interests without common unitholder approval, which would dilute holders of common units. However, our partnership agreement does not authorize us to issue units ranking senior to or at parity with our preferred units without preferred unitholder approval.

Under our partnership agreement, we are authorized to issue an unlimited number of additional interests, including common units, without a vote of the unitholders other than, in certain instances, approval of holders of our preferred units. Our issuance of additional common units or other equity interests of equal or senior rank will have the following effects:

 

   

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

 

   

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

 

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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.

However, our partnership agreement does not authorize us to issue securities having preferences or rights with priority over or on a parity with the preferred units with respect to rights to share in distributions, redemption obligations or redemption rights without preferred unitholder approval. Please read “The Partnership Agreement—Issuance of Additional Partnership Interests” and “Description of Our Preferred Units.”

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             common units outstanding, including the             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 our directors, executive officers, and other affiliates 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 these sales might occur, could have a material adverse effect on the price of our common units or impair our ability to obtain capital through an offering of equity securities. In addition, we have agreed to provide registration rights to our directors, executive officers and other affiliates. Under our partnership agreement, certain of our 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             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 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 those described elsewhere 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 and the Dodd-Frank Act of 2010, as well as rules implemented by the SEC and the NYSE, 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 reduced by our expenses, including the costs associated with being a publicly traded partnership.

 

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Following this offering, we will become subject to the public reporting requirements of the Exchange Act. We expect these requirements will increase our legal and financial compliance costs. 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 $         million of incremental costs per year associated with being a publicly traded partnership; however, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than we currently estimate.

For as long as we are an emerging growth company, we will not be required to comply with certain disclosure requirements, including those relating to accounting standards, 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, we will not be required to comply with certain requirements that other public companies are required to comply with. Among other things, we will not be required to:

 

   

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

 

   

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; or

 

   

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.

Upon the completion of this offering, we will become subject to the public reporting requirements of the Exchange Act. We prepare our 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. 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, 2016. 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.

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

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

 

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addition, because we are a publicly traded partnership, the NYSE does not require us to obtain unitholder approval prior to certain unit issuances. Accordingly, unitholders will not have the same protections afforded to stockholders of certain corporations that are subject to all of the NYSE’s corporate governance requirements. Please read “Management.”

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

Our partnership agreement is governed by Delaware law. Our partnership agreement includes exclusive forum, venue, and jurisdiction provisions designating Delaware courts as the exclusive venue for all claims, suits, actions, and proceedings arising out of or relating in any way to the partnership agreement, brought in a derivative manner on behalf of the partnership, asserting a claim of breach of a fiduciary or other duty owed by any director, officer, or other employee of the partnership or the general partner, or owed by the general partner to the partnership or the partners, asserting a claim arising pursuant to any provision of the Delaware Act or asserting a claim governed by the internal affairs doctrine. In addition, if any person holding common units brings any of the aforementioned claims, suits, actions, or proceedings and the person does not obtain a judgment on the merits that substantially achieves, in substance and amount, the full remedy sought, then the person shall be obligated to reimburse us and our affiliates for all fees, costs, and expenses of every kind and description, including but not limited to all reasonable attorneys’ fees and other litigation expenses, that the parties may incur in connection with a claim, suit, action, or proceeding. 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 common 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 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 common units held by any person (i) whose nationality, citizenship, or related status creates substantial risk of cancellation or forfeiture of any of our property and/or (ii) who fails to comply with the procedures established to obtain that proof. The redemption price 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.”

Common unitholders who are not “Eligible Holders” will not be entitled to receive distributions on or allocations of income or loss on their common units, and their common units will be subject to redemption.

In order to comply with U.S. laws with respect to the ownership of interests in oil and natural gas leases on federal lands, we will adopt certain requirements regarding those investors who may own our common units. As used herein, an Eligible Holder means a person or entity qualified to hold an interest in oil and natural gas leases on federal lands. As of the date hereof, Eligible Holder means: (1) a citizen of the United States; (2) a corporation organized under the laws of the United States or of any state thereof; or (3) an association of United States citizens, such as a partnership or limited liability company, organized under the laws of the United States or of any state thereof, but only if this association does not have any direct or indirect foreign ownership, other than foreign ownership of stock in a parent corporation organized under the laws of the United States or of any state

 

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thereof. For the avoidance of doubt, onshore mineral leases or any direct or indirect interest therein may be acquired and held by aliens only through stock ownership, holding or control in a corporation organized under the laws of the United States or of any state thereof and only for so long as the alien is not from a country that the United States federal government regards as denying similar privileges to citizens or corporations of the United States. Common unitholders who are not persons or entities who meet the requirements to be an Eligible Holder will not be entitled to receive distributions or allocations of income and loss on their units and they run the risk of having their units redeemed by us at the lower of their purchase price cost or the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.

For the avoidance of doubt, we will not adopt Eligible Holder requirements regarding those investors who own our preferred units.

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 (“IRS”) 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 unitholders 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 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 of those 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

 

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substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. One 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 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 tax purposes, please read “Material U.S. Federal Income Tax Consequences—Taxation of the Partnership—Partnership Status” for a further discussion.

If the IRS were to contest the federal income tax positions we take, it may adversely affect the market for our common units, and the costs of any 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 affect 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 a unitholder does not receive any cash distributions from us, a unitholder will be required to pay taxes on its share of our taxable income.

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

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

If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell your 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.”

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-

 

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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.”

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 this 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.

 

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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. 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 likely will 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 several states, many of which impose a personal income tax and also impose income taxes on corporations and other entities. 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. 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. 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.

 

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USE OF PROCEEDS

We intend to use the estimated net proceeds of approximately $         million from this offering (based on an assumed initial offering price of $         per common unit, the mid-point of the price range set forth on the cover page of this prospectus), after deducting the estimated underwriting discount and offering expenses payable by us, to repay all of the indebtedness outstanding under our credit facility and to fund future capital expenditures.

The net proceeds from any exercise of the underwriters’ option to purchase additional common units (approximately $         million, if exercised in full, based on an assumed initial offering price of $         per common unit, the mid-point of the price range set forth on the cover of this prospectus, after deducting the estimated underwriting discount) will be used to fund future capital expenditures.

Borrowings under our credit facility were primarily made for the acquisition of properties and other general business purposes. As of June 30, 2014, we had borrowings outstanding of $453.0 million under our credit facility. Indebtedness under our credit facility bore interest at an average rate of approximately 2.4% during the six months ended June 30, 2014. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facility.”

Affiliates of certain of our underwriters are lenders under our credit facility and, as such, may receive a portion of the proceeds from this offering. Please read “Underwriting—Relationships.”

 

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CAPITALIZATION

The following table shows our cash and cash equivalents and capitalization as of June 30, 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 historical and pro forma financial statements and the 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 June 30, 2014  
     Black Stone
Minerals, L.P.
Predecessor
     Black Stone
Minerals, L.P.
 
     Actual      Pro Forma  
    

(unaudited)

(in thousands)

 

Cash and cash equivalents

   $ 12,789       $     
  

 

 

    

 

 

 

Long-term debt

   $ 453,000         —     
  

 

 

    

 

 

 

Mezzanine equity:

     

Black Stone Minerals Company, L.P.

     

Preferred Units

     161,122         —     

Black Stone Minerals, L.P.

     

Preferred Units

     —           —     

Equity:

     

Black Stone Minerals Company, L.P.

     

Common units

   $ 726,958       $ —     

Black Stone Minerals, L.P.

     

Common units held by general partner

     —        

Common units held by others

     —        
  

 

 

    

Total common units

     —        
  

 

 

    

 

 

 

Total equity

   $ 726,958       $     
  

 

 

    

 

 

 

Total capitalization

   $ 1,341,080       $                    
  

 

 

    

 

 

 

 

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DILUTION

Dilution in net tangible book value per common unit represents the difference between the amount per common unit paid by purchasers of our common units in this offering and the pro forma net tangible book value per common unit immediately after this offering. Based on an initial public offering price of $         per common unit (the mid-point of the price range set forth on the cover page of this prospectus), and after deduction of the estimated underwriting discount and estimated offering expenses payable by us, our pro forma net tangible book value as of June 30, 2014 would have been approximately $         million, or $         per common unit. This represents an immediate pro forma dilution of $         per common unit to purchasers of common units in this offering. The following table illustrates this dilution on a per common unit basis:

 

Assumed initial public offering price per common unit

      $                

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

   $                   

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

     

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

     
     

 

 

 

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

     
     

 

 

 

 

(1) Determined by dividing the pro forma net tangible book value of the contributed assets and liabilities by the number of our common units to be issued to the existing limited partners of BSMC in exchange for their limited partner interests in BSMC in connection with the merger of BSMC with and into our subsidiary.
(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 common units that we will issue and the total consideration contributed to us by the existing limited partners of BSMC 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  

Limited partners of BSMC prior to this offering(1)

                        

Purchasers in this offering

                        
  

 

  

 

 

   

 

  

 

 

 

Total

        100        100
  

 

  

 

 

   

 

  

 

 

 

 

(1) Reflects the value of the assets to be contributed to us by the existing limited partners of BSMC, recorded at historical cost.
(2) Reflects the net proceeds of this offering, after deducting the underwriting discount and estimated offering expenses payable by us.

 

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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. 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, you should refer to the historical financial statements of BSMC and our pro forma financial statements, 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 a substantial majority of the available cash we generate each quarter. Available cash for each quarter will be determined by the board of directors of our general partner following the end of that quarter. Our initial distribution will be $         per common unit on an annualized basis, which we forecast to represent approximately     % of our available cash for the year ending December 31, 2015. It is our intent, for at least the next several years, to finance most of our acquisition and working-interest capital needs with the retained net proceeds from this offering, borrowings under our credit facility, and, in certain circumstances, proceeds from future equity and debt issuances. We may also borrow to make distributions to our unitholders where, for example, we believe that the distribution level is sustainable over the long term, but short-term factors may cause available cash from operations to be insufficient to pay distributions at the current level. 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. If we make distributions, our preferred unitholders have priority with respect to rights to share in those distributions over our common unitholders for so long as our preferred units are outstanding.”

Replacement capital expenditures are expenditures necessary to replace our existing oil and natural gas reserves or otherwise maintain our asset base over the long term. 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 the development of existing plays and the discovery of new reserves will lead to increasing revenues for at least the next several years. We also intend to add reserves through acquisitions of mineral and royalty interests and through non-operated working-interest participation. We may restrict distributions, in whole or in part, to fund acquisitions and participation in working interests. If we do not retain cash for replacement capital expenditures in amounts necessary to maintain our asset base, our cash available for distribution per unit will decrease over time. The board of directors of our general partner may in the future decide to withhold from cash available for distribution amounts for our capital expenditures which may have an adverse impact on the cash available for distribution per unit in the quarter in which those amounts are withheld. To the extent that we do not withhold cash for capital expenditures in the future, a portion of our future cash available for distribution will represent a return of your capital.

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 common unitholders have no contractual or other legal right to receive cash distributions from us on a quarterly or other basis, and if distributions are paid, common unitholders will receive distributions only to the extent the distribution amount exceeds distributions that are required to be paid to our preferred unitholders. The board of directors of our general partner will adopt a policy pursuant to which

 

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we will distribute to our unitholders each quarter a substantial majority 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.

 

   

Our credit facility contains certain financial tests and covenants that we must satisfy. If we are unable to satisfy the restrictions under our credit facility or any future debt agreements, we could be prohibited from making distributions notwithstanding our stated distribution policy.

 

   

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 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 limit 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.

 

   

The distribution priority of our preferred units over the common units could result in us paying a full quarterly cash distribution on our preferred units and only a portion or none of the quarterly distribution on our outstanding common units if our available cash for such quarter is not sufficient to pay the distribution on all our outstanding units (common and preferred).

 

   

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, 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. To fund our growth, we may eventually need capital in excess of the amounts we may retain in our business or borrow under our credit facility. To the extent efforts to access capital externally are unsuccessful, our ability to grow will be significantly impaired.

We expect to pay our distributions on our common units within 60 days of the end of each quarter. Our first distribution will be for the period from the closing of this offering through                     , 2015.

Pro Forma Cash Available for Distribution for the Year Ended December 31, 2013 and the Twelve Months Ended June 30, 2014

The pro forma financial statements, upon which pro forma cash available for distribution is based, do not purport to present our results of operations had the transactions contemplated in this prospectus actually been completed as of the dates indicated. Furthermore, cash available for distribution is a cash concept, while our pro forma financial statements have been prepared on an accrual basis. We derived the amounts of pro forma cash available for distribution discussed above in the manner described in the table below. As a result, the amounts of pro forma cash available for distribution should only be viewed as a general indication of the amounts of cash available for distribution that we might have generated had we been formed and completed the transactions contemplated in this prospectus in earlier periods.

Following the completion of this offering, we estimate that we will incur $         million of incremental general and administrative expenses per year as a result of operating as a publicly traded partnership, which includes expenses associated with SEC reporting requirements, including annual and quarterly reports to

 

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unitholders, tax return and Schedule K-1 preparation and distribution, Sarbanes-Oxley Act compliance, NYSE listing, independent- auditor fees, legal fees, investor-relations activities, registrar and transfer agent fees, director-and-officer insurance, and additional compensation.

The following table illustrates, on a pro forma basis for the year ended December 31, 2013 and the twelve months ended June 30, 2014, the amount of cash that would have been available for distribution to our common unitholders, assuming that the transactions contemplated in this prospectus had been consummated on January 1, 2013 and July 1, 2013, respectively.

 

     Year Ended
    December 31,    
2013
    Twelve Months
Ended June 30,
2014
 
     (unaudited)  
     (in thousands)  

Revenues:

    

Oil and condensate sales(1)

   $ 252,742      $ 258,703   

Natural gas and natural gas liquids sales(1)

     184,868        200,173   

Gain (loss) on commodity derivative instruments

     (5,860     (15,725

Lease bonus and other income

     31,809        44,130   
  

 

 

   

 

 

 

Total revenues

   $ 463,559      $ 487,281   

Operating expenses:

    

Lease operating expense and other

   $ 21,316      $ 20,643   

Production and ad valorem taxes

     42,813        44,881   

Depreciation, depletion, and amortization

     102,442        98,345   

Impairment of oil and natural gas properties(2)

     57,109        29,479   

General and administrative expense

     59,501        60,524   

Accretion of asset retirement obligations

     588        576   
  

 

 

   

 

 

 

Total operating expenses

   $ 283,769      $ 254,448   

Income from operations

   $ 179,790      $ 232,833   

Other income (expense):

    

Interest and investment income

   $ 90      $ 49   

Interest expense(3)

     (3,633     (3,630

Gain on sale of assets

     18          

Other income

     407        1,077   
  

 

 

   

 

 

 

Total other income (expense)

   $ (3,118   $ (2,504
  

 

 

   

 

 

 

Pro forma net income

   $ 176,672      $ 230,329   
  

 

 

   

 

 

 

Adjustments to reconcile to pro forma Adjusted EBITDA:

    

Add:

    

Depletion, depreciation, and amortization

   $ 102,442      $ 98,345   

Impairment of oil and natural gas properties

     57,109        29,479   

Accretion of asset retirement obligations

     588        576   

Interest expense

     3,633        3,630   
  

 

 

   

 

 

 

Pro forma EBITDA(4)

   $ 340,444      $ 362,359   

Add:

    

Unrealized loss on commodity derivative instruments

     7,350        12,422   

Equity-based compensation expense(5)

     6,782        9,042   
  

 

 

   

 

 

 

Pro forma Adjusted EBITDA(4)

   $ 354,576      $ 383,823   
  

 

 

   

 

 

 

 

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     Year Ended
    December 31,    
2013
     Twelve Months
Ended June 30,
2014
 
     (unaudited)  
     (in thousands, except per unit data)  

Adjustments to reconcile to pro forma cash available for distribution:

     

Add:

     

Net proceeds from this offering to fund future capital expenditures

     

Less:

     

Incremental general and administrative expense(6)

     

Cash interest expense

     2,665         2,665   

Capital expenditures(7)

     195,631         131,631   
  

 

 

    

 

 

 

Pro forma cash available for distribution

   $         $     

Less:

     

Cash paid to noncontrolling interests

     1,146         335   

Preferred unit dividends(8)

     15,742         15,736   
  

 

 

    

 

 

 

Pro forma cash available for distribution on common units

   $         $     

Pro forma cash distribution per common unit

     

Aggregate distributions of pro forma cash available for distribution to:

     

Common units issued in this offering(9)

     

Common units issued in the merger

     
  

 

 

    

 

 

 

Total distributions on common units

     
  

 

 

    

 

 

 

Excess (shortfall)(9)

     
  

 

 

    

 

 

 

 

(1) Includes revenues from our mineral and royalty interests and working interests.
(2) The impairment primarily resulted from decreasing commodity prices and changes in the projections based on the recent historical operating characteristics at the field level. For more information, please read the historical financial statements of BSMC included elsewhere in this prospectus.
(3) Includes cash expenses of commitment fees and agency fees and non-cash amortization of debt issuance costs.
(4) For more information, please read “Summary—Summary Historical and Pro Forma Financial and Data—Non-GAAP Financial Measures.”
(5) Represents compensation expense that is settled in common units and would not reduce the amount of cash available to common units.
(6) Reflects incremental general and administrative expenses that we expect to incur as a result of operating as a publicly traded partnership that are not reflected in our pro forma financial statements.
(7) Represents capital expenditures for acquisitions, working interests, and other corporate expenditures. Capital expenditures incurred for acquisitions were $121.6 million and $69.8 million for the year ended December 31, 2013 and for the twelve months ended June 30, 2014, respectively.
(8) Reflects dividends paid on our preferred units. The preferred coupon is 10% on a nominal amount of preferred units outstanding of $157.4 million for the year ended December 31, 2013. As of January 1, 2014, the nominal amount of preferred units outstanding was $157.2 million. Preferred units may be converted at the conversion rate of 907.3629601 common units per preferred unit at any time prior to the consummation of this offering and at the conversion rate of                              common units per preferred unit at any time subsequent to the consummation of this offering and are mandatorily convertible in annual tranches of 25% beginning January 1, 2015.
(9) Assuming the underwriters’ option to purchase additional common units to cover over-allotments is exercised in full and all of our preferred units converted into                 common units as of the year ended December 31, 2013 and                 common units as of June 30, 2014, the excess (shortfall) for the year ended December 31, 2013 and for the twelve months ended June 30, 2014 would have (decreased) increased to $         and $        , respectively.

 

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Estimated Cash Available for Distribution for the Year Ending December 31, 2015

During the year ending December 31, 2015, we estimate that we will generate $         million of cash available for distribution. 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 year ending December 31, 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 of 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 $         million of available cash for the year ending December 31, 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. 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 year ending December 31, 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.

 

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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 this information or its achievability, and it assumes no responsibility for this 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 set forth below and should not be read to do so.

 

     Year Ending
December 31, 2015
     (in thousands, except per unit data)

Revenues:

  

Oil and condensate sales(1)

  

Natural gas and natural gas liquids sales

  

Gain (loss) on commodity derivative instruments

  

Lease bonus and other income

  
  

 

Total revenues

  

Operating expenses:

  

Lease operating expense and other

  

Production and ad valorem taxes

  

Depreciation, depletion and amortization

  

Impairment of oil and natural gas properties

  

General and administrative expense

  

Accretion of asset retirement obligations

  

Total operating expenses

  

Income from operations

  

Other income (expense):

  

Interest and investment income

  

Interest expense

  

Other income

  

Total other income (expense)

  

Net income

  

Adjustments to reconcile to Adjusted EBITDA:

  

Add:

  

Depletion, depreciation and amortization

  

Impairment of oil and natural gas properties

  

Accretion of asset retirement obligations

  

Interest expense

  

EBITDA(1)

  

Add:

  

Unrealized loss on commodity derivative instruments

  

Equity-based compensation expense(2)

  

Less:

  

Unrealized gain on commodity derivative instruments

  

Adjusted EBITDA(1)

  

Adjustments to reconcile to estimated cash available for distribution:

  

Add:

  

Net proceeds from this offering to fund future capital expenditures

  

Less:

  

Incremental general and administrative expense

  

Cash interest expense

  

Capital expenditures

  

Estimated cash available for distribution

  

Less:

  

Cash paid to noncontrolling interests

  

Preferred unit dividends(3)

  

Estimated cash available for distribution on common units

  

Estimated cash distribution per common unit

  

Estimated aggregate distributions of cash available for distribution to:

  

Common units issued in this offering(4)

  

Common units issued in the merger

  

Total distributions on common units

  

Excess(4)

  

 

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(1) For more information, please read “Summary—Summary Historical and Pro Forma Financial Data—Non-GAAP Financial Measures.”
(2) Represents compensation expense that is settled in common units and would not impact cash available for distribution.
(3) Reflects dividends paid on our preferred units. The preferred coupon is 10% on a nominal amount of preferred units outstanding of $157.4 million for the year ended December 31, 2013. As of January 1, 2014, the nominal amount of preferred units outstanding was $157.2 million. Preferred units may be converted at the conversion rate of 907.3629601 common units per preferred unit at any time prior to the consummation of this offering and at the conversion rate of                  common units per preferred unit at any time subsequent to the consummation of this offering and are mandatorily convertible in annual tranches of 25% beginning January 1, 2015. We assume that 75% of the preferred units are outstanding during 2015, which if converted would equal                 common units.
(4) Assuming the underwriters’ option to purchase additional common units to cover over-allotments is exercised in full and all of our preferred units converted into                 common units as of January 1, 2015, the excess for the year ending December 31, 2015 would have decreased to $        . In addition, assuming the underwriters’ option to purchase additional common units to cover over-allotments is not exercised in full and all of our preferred units converted into common units as of January 1, 2015, the excess for the year ending December 31, 2015 would have decreased to $        .

Assumptions and Considerations

Based upon the specific assumptions outlined below and based on the cash distribution policy we expect our board of directors to adopt, we expect to generate cash available for distribution in an amount sufficient to allow us to pay $         per common unit on all of our outstanding common units for the year ending December 31, 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 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.

Revenues

We own a diversified portfolio of interests in oil and natural gas properties. Substantially all of our revenues are a function of oil and natural gas production volumes sold and average prices received for those volumes.

Our forecasted 2015 production is derived from both our existing wells from our reserve report and from new wells projected to begin producing during the year. For oil and natural gas wells not currently producing, we utilize information from our operators regarding their drilling plans when available. Such information assists us in estimating both mineral-and-royalty-interest production as well as production from working interest wells in which we expect to participate. In addition, we estimate incremental production based on our historical reserve replacement taking into account play-specific trends, rig counts, and other industry information that we believe may be relevant to our forecast.

 

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The following table sets forth information regarding production associated with our mineral and royalty interests and non-operated working interests on a pro forma basis for the year ended December 31, 2013 and the twelve months ended June 30, 2014 and on a forecasted basis for the year ending December 31, 2015:

 

     Year Ended
December 31,
2013
    Twelve Months
Ended June 30,

2014
    Year Ending
December 31,
2015

Aggregate production:

      

Oil and condensate (MBbls)

     2,626        2,716     

Natural gas (MMcf)

     45,400        42,633     
  

 

 

   

 

 

   

Combined volumes (MBoe)

     10,193        9,822     

Average daily production (MBoe/d)

     27.9        26.9     

Percentage attributable to mineral and royalty interests:

      

Oil and condensate

     74     74  

Natural gas

     63     66  

The following table illustrates the relationship between average oil and natural gas realized sales prices and the average WTI and Henry Hub natural gas prices on a pro forma basis for the year ended December 31, 2013 and the twelve months ended June 30, 2014 and on a forecasted basis for the year ending December 31, 2015:

 

     Year Ended
December 31,
2013
     Twelve
Months Ended
June 30,
2014
     Year Ending
December 31,
2015

Average benchmark prices(1):

        

WTI oil price ($/Bbl)

   $ 97.98       $ 101.36      

Henry Hub natural gas price ($/Mcf)

   $ 3.73       $ 4.29      

Realized prices(2):

        

Realized oil and condensate price ($/Bbl)

   $ 96.25       $ 95.24      

Realized natural gas price ($/Mcf)(3)

     4.07         4.70      

 

(1) For historical periods, average prices were calculated using daily spot prices provided by the EIA. For the year ending December 31, 2015, the NYMEX average price curve as of                     , 2014 was used.
(2) Excluding cash settlement on commodity derivative instruments.
(3) Due to the data provided to us as a mineral-and-royalty-interest owner by our operators, we are unable to reliably determine the total volumes associated with NGLs from the production of natural gas on our acreage. As such, the realized prices we receive for natural gas include sales attributable to NGLs.

Any differences between realized prices and NYMEX prices are referred to as differentials. Our realized prices are a function of both quality and location differentials. In estimating our realized prices for the year ending December 31, 2015, we have considered the oil and natural gas NYMEX price curves, our historical realized prices across our asset base, and any forecasted changes in quality or location differentials.

We recognize oil and natural gas revenue from our mineral and royalty and non-operated working interests in producing wells when the oil and natural gas production from the associated acreage is sold. We estimate our oil and natural gas revenue resulting from our mineral and royalty interests for the year ending December 31, 2015 will be $         million, compared to $314.2 million and $333.2 million on a pro forma basis for the year ended December 31, 2013 and for the twelve months ended June 30, 2014, respectively. We estimate our oil and natural gas revenue resulting from our non-operated working interests for the year ending December 31, 2015 will be $         million compared to $123.4 million and $125.7 million on a pro forma basis for the year ended December 31, 2013 and for the twelve months ended June 30, 2014, respectively.

 

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We anticipate growth in our mineral-and-royalty-interest revenues due to increased production from our acreage in the Eagle Ford and Bakken Shales and our geographically diverse mineral-and-royalty-interest acreage. We anticipate growth in our working interest revenues due to increased production from our acreage in the Bakken and Haynesville Shales. For information on the effect of changes in prices and productions volumes, please read “—Sensitivity Analysis.”

Lease Bonus and Other Income. We also generate revenue through receipt of lease bonus. When we lease our mineral interests, we generally receive an upfront cash payment, or a lease bonus. Lease bonus and other income are estimated to be $         million for the year ending December 31, 2015. Approximately 82% of our acreage is unleased, and we believe this acreage, along with renewals of leased acreage, will provide future bonuses in line with historical averages. Lease bonus and other income on a pro forma basis for the year ended December 31, 2013 and the twelve months ended June 30, 2014 were $31.8 million and $44.1 million, respectively.

Operating Expenses

Of our operating expenses, lease operating expense and other and accretion of asset retirement obligations are attributable solely to our non-operated working interests. Production and ad valorem taxes, depletion, depreciation, and amortization and impairment expense are attributable to both our mineral and royalty interests and our non-operated working interests.

Lease Operating Expenses and Other. Lease operating expenses include normally recurring expenses necessary to operate and produce hydrocarbons from our non-operated working interests in oil and natural gas wells, non-recurring well workovers, repair-related expenses, and exploration expenses. We estimate that lease operating expenses and other for the year ending December 31, 2015 will be $         million as compared to $21.3 million and $20.6 million on a pro forma basis for each of the year ended December 31, 2013 and the twelve months ended June 30, 2014, respectively.

Production and Ad Valorem Taxes. Production, or severance, taxes include statutory amounts deducted from our production revenues by various state taxing entities. Depending on the states’ regulations where the production originates, these taxes may be based on a percentage of the realized value or a fixed amount per production unit. This category also includes the costs to process and transport our production to applicable sales points. Ad valorem taxes are jurisdictional taxes levied on the value of oil and natural gas minerals and reserves. Rates, methods of calculating property values, and timing of payments vary between taxing authorities. We estimate that production and ad valorem taxes for the year ending December 31, 2015 will be $         million, compared to $42.8 million and $44.9 million on a pro forma basis for the year ended December 31, 2013 and the twelve months ended June 30, 2014, respectively.

Depletion, Depreciation, and Amortization. Depletion is the amount of cost basis of oil and natural gas properties at the beginning of a period attributable to the volume of hydrocarbons extracted during such period, calculated on a unit-of-production basis. Estimates of proved developed producing reserves are a major component of the calculation of depletion. We have historically adjusted our depletion rates in the fourth quarter of each year based upon the year-end reserve report and other times during the year when circumstances indicate that there has been a significant change in reserves or costs. We estimate that our depletion, depreciation, and amortization for the year ending December 31, 2015 will be $         million, compared to $102.4 million and $98.3 million on a pro forma basis for the year ended December 31, 2013 and the twelve months ended June 30, 2014, respectively.

Impairment of Oil and Natural Gas Properties. Individual categories of oil and natural gas properties are assessed periodically to determine if the recorded value has been impaired. Management periodically conducts an in-depth evaluation of the cost of property acquisitions, successful exploratory wells, development activities, unproved leasehold, and mineral interests to identify impairments. We anticipate no impairment expense for the year ending December 31, 2015 as compared to $57.1 million and $29.5 million on a pro forma basis for the year ended December 31, 2013 and the twelve months ended June 30, 2014, respectively.

 

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General and Administrative Expense. We estimate that our general and administrative expenses for the year ending December 31, 2015 will be $         million, compared to $59.5 million and $60.5 million on a pro forma basis for the year ended December 31, 2013 and the twelve months ended June 30, 2014, respectively. General and administrative expenses for the year ending December 31, 2015 include $         million of compensation expense incurred in connection with our long-term incentive plan, $         million of general and administrative expenses we expect to incur as a result of becoming a publicly traded partnership, $         million of                 , $         million of                 and $         million of other general and administrative expenses. Please read “Executive Compensation and Other Information.”

Accretion of Asset Retirement Obligations. An ARO represents an obligation to perform site reclamation, to dismantle production or processing facilities, or to plug and abandon wells. To determine the current amount of ARO, the estimated future cost to satisfy the abandonment obligation, using current prices that are escalated by an assumed inflation factor up to the estimated settlement date, is discounted back to the date that the abandonment obligation was incurred. After recording this cost, an ARO is accreted to its future estimated value in order to match the timing of expenses with the periods in which they occurred. We estimate that our accretion expense for the year ending December 31, 2015 will be $         million, compared to $0.6 million and $0.6 million on a pro forma basis for the year ended December 31, 2013 and the twelve months ended June 30, 2014, respectively.

Interest Expense. We estimate that interest expense will be $         million for the year ending December 31, 2015 as compared to $3.6 million and $3.6 million on a pro forma basis for the year ended December 31, 2013 and the twelve months ended June 30, 2014, respectively. We do not expect to have borrowings outstanding under our credit facility during the year ending December 31, 2015 and only expect to incur commitment and agency expense or related costs during the forecast period. In connection with amending and restating our credit facility in connection with this offering, we expect to incur costs of $         million for the year ending December 31, 2015. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facility.”

Commodity Derivative Contracts

Our ongoing operations expose us to changes in the market price for oil and natural gas. To mitigate the given commodity price risk associated with its operations, we use derivative instruments. From time to time, such instruments may include fixed price contracts, variable to fixed price swaps, costless collars, and other contractual arrangements. However, we currently utilize only costless collars. We do not enter into derivative instruments for speculative purposes. In addition, we employ a “rolling hedge” strategy whereby we do not execute all of our hedges at the same time but instead execute new trades as older hedges settle or expire. The impact of these derivative instruments could affect the amount of revenue we ultimately record.

Our hedge volumes are limited to projected proved developed producing reserve (“PDP”) production as determined by our then most current reserve report. We have traditionally employed a strategy of hedging a high percentage of our aggregate PDP production for the next twelve months with a lesser degree of production hedged for the subsequent twelve-month period. We have historically limited our hedging to a total period of 24 months, with the percentage hedged each month declining over the period. As we only hedge PDP production, our hedges do not account for new wells that are projected to begin producing in the future. Accordingly, our hedged volumes are considerably lower than our actual production for the year. For example, as of January 1, 2013, we had 50.3% of our 2013 PDP production hedged on a Boe basis, which represented 39.1% of our total actual production for the year. Taking into account new hedges executed throughout 2013, the total volumes hedged as a percentage of total annual production for 2013 was 64.0%.

 

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For purposes of the forecast, we have assumed that we do not enter into additional commodity derivative contracts. Our existing hedges will cover     MBoe/d, or approximately     % of our total forecasted production of MBoe/d for the year ending December 31, 2015. We have assumed that the commodity derivative contracts will consist of zero-cost collars for oil and natural gas. The table below shows the volumes, benchmark price, and prices we have assumed for our commodity derivative contracts for the year ending December 31, 2015:

 

     Volume      % of
Forecasted
Production
    Weighted-
Average Floor
Price
     Weighted-
Average Ceiling
Price
 

Oil and condensate

     Bbl                $         $     

Natural gas

     Mcf                $                    $                

Capital Expenditures

We expect to spend approximately $         million on capital expenditures in connection with our non-operated working interests on a forecasted basis for the year ending December 31, 2015, compared to $73.7 million and $61.5 million on a pro forma basis for the year ended December 31, 2013 and the twelve months ended June 30, 2014, respectively.

Although we may make acquisitions during the year ending December 31, 2015, our forecast does not reflect any acquisitions, as we cannot assure you that we will be able to identify attractive properties or, if identified, that we will be able to negotiate acceptable purchase agreements, or if successful, the timing of the closing(s) of any such acquisitions or the commencement of our receipt of revenues therefrom.

Regulatory, Industry, and Economic Factors

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

 

   

There will not be any new federal, state, or local regulation of 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 year ending December 31, 2015 will be approximately $         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 December 31, 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 common 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 year ending December 31, 2015.

 

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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 year ending December 31, 2015.

 

     Percentage of Forecasted Annual Production  
             90%                      100%                      110%          

Forecasted annual production:

        

Oil and condensate (Bbls)

        

Natural gas (Mcf)

        

Combined volumes (Boe)

        

Forecasted average daily production:

        

Oil and condensate (Bbl/d)

        

Natural gas (Mcf/d)

        

Combined volumes (Boe/d)

        

Forecasted average sales prices:

        

WTI oil price ($/Bbl)

   $                    $                    $                

Realized oil and condensate sales price ($/Bbl)

        

Henry Hub natural gas price ($/Mcf)

   $         $         $     

Realized natural gas sales price ($/Mcf)

        

Estimated cash available for distribution (in thousands):

        

Oil and condensate sales

        

Natural gas and natural gas liquids sales

        

Lease bonus and other income

        

Operating expenses

        

Estimated cash flow available for distribution

        

Commodity Price Changes. The following table shows estimated cash available for distribution under various assumed oil and natural gas prices for the year ending December 31, 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.

 

     Change in Forecasted Commodity Prices  
             90%                      100%                      110%          

Forecasted annual production:

        

Oil and condensate (Bbls)

        

Natural gas (Mcf)

        

Combined volumes (Boe)

        

Forecasted average daily production:

        

Oil and condensate (Bbl/d)

        

Natural gas (Mcf/d)

        

Combined volumes (Boe/d)

        

Forecasted average sales prices:

        

WTI oil and condensate price ($/Bbl)

   $                    $                    $                

Realized oil and condensate sales price ($/Bbl)

        

Henry Hub natural gas price ($/Mcf)

   $         $         $     

Realized natural gas sales price ($/Mcf)

        

Estimated cash available for distribution (in thousands):

        

Oil and condensate sales

        

Natural gas and natural gas liquids sales

        

Lease bonus and other income

        

Operating expenses

        

Estimated cash available for distribution

        

 

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SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA

Black Stone Minerals, L.P. was formed in September 2014 and does not have historical financial statements. Therefore, in this prospectus we present the historical financial statements of BSMC, our predecessor for accounting purposes. We refer to this entity as “Black Stone Minerals, L.P. Predecessor.” The following table presents selected historical financial data of BSMC and selected pro forma financial data of Black Stone Minerals, L.P. as of the dates and for the periods indicated.

The selected historical financial data presented as of and for the years ended December 31, 2013 and 2012 are derived from the audited historical financial statements of BSMC that are included elsewhere in this prospectus. The selected historical financial data presented as of and for the six months ended June 30, 2014 and for the six months ended June 30, 2013 are derived from the unaudited historical financial statements of BSMC included elsewhere in this prospectus.

The selected pro forma financial data presented for the year ended December 31, 2013 and as of and for the six months ended June 30, 2014 are derived from our pro forma financial statements included elsewhere in this prospectus. Our pro forma financial statements give pro forma effect to the issuance and sale of the common units from this offering and the application of the net proceeds therefrom as described under “Use of Proceeds.” The pro forma balance sheet assumes the events described above occurred as of June 30, 2014. The pro forma statements of operations for the year ended December 31, 2013 and the six months ended June 30, 2014 assume the events described above occurred as of January 1, 2013.

We have not given pro forma effect to incremental general and administrative expenses of approximately $         million that we expect to incur annually as a result of operating as a publicly traded partnership, such as 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, NYSE listing, independent-auditor fees, legal fees, investor-relations activities, registrar and transfer agent fees, director-and-officer insurance, and additional compensation.

 

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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 and unaudited historical financial statements of BSMC 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.

 

    Black Stone Minerals, L.P. Predecessor
Historical
    Black Stone Minerals,
L.P.
Pro Forma
 
    Year Ended
December 31,
    Six Months Ended
June 30,
    Year Ended
December 31,
2013
    Six Months
Ended
June 30,
2014
 
    2012     2013     2013     2014      
                (unaudited)     (unaudited)  
    (in thousands)  

Revenues:

           

Oil and condensate sales

  $ 202,104      $ 252,742      $ 118,615      $ 124,576      $ 252,742      $   124,576   

Natural gas and natural gas liquids sales

    166,849        184,868        95,335        110,640        184,868        110,640   

Gain (loss) on commodity derivative instruments

    12,275        (5,860     1,522        (8,343     (5,860     (8,343

Lease bonus and other income

    53,918        31,809        7,155        19,476        31,809        19,476   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

  $ 435,146      $ 463,559      $ 222,627      $ 246,349      $ 463,559      $ 246,349   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating Expenses:

           

Lease operating expense and other

  $ 20,527      $ 21,316      $ 10,347      $ 9,674      $ 21,316      $ 9,674   

Production and ad valorem taxes

    36,680        42,813        19,340        21,408        42,813        21,408   

Depreciation, depletion and amortization

    104,059        102,442        51,090        46,993        102,442        46,993   

Impairment of oil and natural gas properties

    62,987        57,109        27,630               57,109          

General and administrative expense

    50,348        59,501        28,940        29,963        59,501        29,963   

Accretion of asset retirement obligations

    608        588        307        295        588        295   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total operating expenses

  $ 275,209      $ 283,769      $ 137,654      $ 108,333      $ 283,769      $ 108,333   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income from operations

  $ 159,937      $ 179,790      $ 84,973      $ 138,016      $ 179,790      $ 138,016   

Other income (expense):

           

Interest and investment income

  $ 209      $ 90      $ 65      $ 24      $ 90      $ 24   

Interest expense(1)

    (9,166     (11,342     (4,747     (6,852     (3,633     (1,835

Gain on sale of assets

    363        18        18               18          

Other income

    467        407        137        807        407        807   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total other income (expense)

    (8,127     (10,827     (4,527     (6,021     (3,118     (1,004
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income

  $ 151,810      $ 168,963      $ 80,446      $ 131,995      $ 176,672      $ 137,012   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Statement of Cash Flow Data:

           

Net cash provided by (used in):

           

Operating activities

  $ 358,002      $ 320,764      $ 142,900      $ 165,860       

Investing activities

    (198,975     (195,631     (123,855     (59,855    

Financing activities

    (138,172     (142,311     (44,441     (123,339    

Other Financial Data:

           

EBITDA(2)

  $ 328,630      $ 340,444      $ 164,220      $ 186,135      $ 340,444      $ 186,135   

Adjusted EBITDA(2)

    346,574        354,576        167,942        197,189        354,576        197,189   

Capital expenditures(3)

    (198,975     (195,631     (123,855     (59,855    

Balance Sheet Data (at period end):

           

Cash and cash equivalents

  $ 47,301      $ 30,123        $ 12,789        $     

Total assets

    1,199,187        1,444,413          1,466,769       

Long-term debt (including current portion)

    363,100        451,000          453,000            

Total liabilities

    711,143        566,618          574,744          121,744   

Total mezzanine equity

    161,381        161,392          161,122       

Total equity

  $ 326,663      $ 716,403        $ 730,903        $     

 

(1) Includes cash expenses of commitment fees and agency fees and non-cash amortization of debt issuance costs.
(2) Please read “Summary—Summary Historical and Pro Forma Financial Data—Non-GAAP Financial Measures.”
(3) Net of proceeds from the sale of assets of $1.0 million and $0.1 million for the years ended December 31, 2013 and December 31, 2012, respectively, and $0.1 million for the six months ended June 30, 2013.

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read the following discussion and analysis of our financial condition and results of operations in conjunction with historical financial statements of our accounting predecessor for financial reporting purposes, BSMC, included elsewhere in this prospectus. This discussion and analysis contains forward-looking statements that involve risks, uncertainties, and assumptions. Actual results may differ materially from those anticipated in these forward-looking statements as a result of a number of factors, including those set forth under “Risk Factors” and “Forward-Looking Statements,” and elsewhere in this prospectus.

Overview

We are one of the largest owners of oil and natural gas mineral interests in the United States. Our principal business is maximizing the value of our existing portfolio of mineral and royalty assets through active management and expanding our asset base through acquisitions of additional mineral and royalty interests. We maximize value through the marketing of our mineral assets for lease, creative structuring of those leases to encourage and accelerate drilling activity, and selectively participating alongside our lessees on a working-interest basis. Our primary business objective is to grow our reserves, production, and cash flow while distributing a substantial majority of our cash flow to our common unitholders.

Our mineral and royalty interests consist of mineral interests in approximately 14.5 million acres, with an average 48.2% ownership interest in that acreage, NPRIs in 1.2 million acres, and ORRIs in 1.4 million acres. These non-cost-bearing interests include ownership in approximately 40,000 producing wells. We also own non-operated working interests. We recognize oil and natural gas revenue from our mineral and royalty and non-operated working interests in producing wells when the oil and natural gas production from the associated acreage is sold. Our other sources of revenue include mineral lease bonus, shut-in royalties, and delay rentals, which are recognized as revenue according to the terms of the lease agreements, and management fees from our minority interests and two third parties.

Business Environment

The information below is designed to give a broad overview of the oil and natural gas business environment as it affects us.

Rig Count

Since we do not operate wells, drilling on our acreage is dependent upon the exploration and production companies that lease our acreage. In addition to drilling plans that we seek from our operators, we monitor rig counts in an effort to identify existing and future leasing and drilling activity on our acreage.

On a weekly basis, Baker Hughes Incorporated, an oilfield services company, releases a detailed report which provides information on the locations of oil and natural gas drilling rigs across the United States, Canada, and the Gulf of Mexico. The weekly rig count report provides insight into industry-wide trends regarding drilling opportunities in basins across the United States.

The following table shows the rig count at the close of each of the quarters presented:

 

     Second Quarter
2014
     First Quarter
2014
     Fourth Quarter
2013
     Third Quarter
2013
 

Oil

     1,558         1,487         1,382         1,362   

Natural gas

     314         318         374         376   

Other

     1         4         1         6   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     1,873         1,809         1,757         1,744   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

Source: Baker Hughes Incorporated

 

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Natural Gas Storage

The majority of our revenue is derived from sales of oil production attributable to our interests; however, the majority of our production is natural gas. Natural gas prices are significantly influenced by storage levels throughout the year. Accordingly, we monitor the natural gas storage reports regularly in the evaluation of our business and its outlook.

Historically, natural gas supply and demand fluctuates on a seasonal basis. From April to October, when the weather is warmer and natural gas demand is lower, natural gas storage levels generally increase. From November to March, storage levels typically decline as utility companies draw natural gas from storage to meet increased heating demand due to colder weather. In order to maintain sufficient storage levels for increased seasonal demand, a portion of natural gas production during the summer months must be used for storage injection. The portion of production used for storage varies year-to-year depending on the demand from the previous winter and the demand for electricity used for cooling during the summer months.

The following table shows natural gas storage volumes by region for each of the quarters presented:

 

Location

   Second Quarter
2014 (Bcf)
     First Quarter
2014 (Bcf)
     Fourth Quarter
2013 (Bcf)
     Third Quarter
2013 (Bcf)
 

East(1)

     923         310         1,501         1,800   

West(2)

     331         160         412         529   

Producing(3)

     675         352         1,061         1,158   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     1,929         822         2,974         3,487   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

Source: EIA

 

(1) CT, DE, DC, FL, GA, IA, IL, IN, KY, MA, MD, ME, MI, MO, NC, NE, NH, NJ, NY, OH, PA, RI, SC, TN, VT, VA, WI and WV
(2) AZ, CA, CO, ID, MN, MT, NV, ND, OR, SD, WA, WY and UT
(3) AL, AR, KS, LA, MI, NM, OK and TX

How We Evaluate Our Operations

We use a variety of operational and financial measures to assess our performance. Among the measures considered by management are the following:

 

   

volumes of oil and natural gas produced;

 

   

commodity prices; and

 

   

EBITDA and Adjusted EBITDA.

Volumes of Oil and Natural Gas Produced

In order to assess and track performance and to evaluate potential acquisition opportunities, we monitor and analyze production volumes from the various basins and plays that comprise our extensive asset base. We also periodically compare projected volumes to actual reported volumes and investigate unexpected variations.

Commodity Prices

Factors Affecting the Sales Price of Oil and Natural Gas

We do not market our own production due to our diverse geographical presence, extensive volume of wells, and large number of operators. For the substantial majority of our wells, our oil and natural gas production, including associated natural gas liquids, is marketed by our operators. The agreements with these operators

 

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contain provisions for the marketing of production on both short-term (usually one year or less in duration) and long-term bases. The prices received for oil and natural gas generally vary by geographical area. The relative prices of oil and natural gas are determined by the factors impacting global and regional supply and demand dynamics, such as economic conditions, production levels, weather cycles, and other factors. In addition, realized prices are influenced by product quality and location relative to consuming and refining markets. Any differences between realized prices and NYMEX prices are referred to as differentials. All of our production is derived from properties located in the United States. As a result of our geographic diversification, we are not exposed to concentrated differential risks associated with any single play, trend, or basin.

 

   

Oil. The majority of our oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of our control. NYMEX Light Sweet Crude (WTI) is the prevailing domestic oil pricing index. The majority of our oil production is priced on this benchmark with the final realized price affected by both quality and location differentials.

Quality differentials result from the fact that various types of oil differ from one another due to their different chemical composition, which plays an important role in their refining and subsequent sale as petroleum products. Among other things, there are two characteristics that commonly drive quality differentials: the density of the oil, characterized by the API gravity, and the presence and concentration of impurities, such as sulfur. In general, light crude oil, or oil with a higher API gravity, produces a higher percentage of more valuable lighter products when refined, such as gasoline; therefore, light crude oil normally sells at a premium to heavy crude oil. Oil with low sulfur content, or “sweet” crude oil, is less expensive to refine and normally sells at a premium to high sulfur-content oil, or “sour” crude oil.

Location differentials generally result from transportation costs based on the produced oil’s proximity to consuming and refining markets and major trading points.

 

   

Natural Gas. The NYMEX price quoted at Henry Hub is a widely used benchmark for the pricing of natural gas in the United States. The actual prices realized from the sale of natural gas differ from the quoted NYMEX price as a result of quality and location differentials.

Quality differentials result from the heating value of natural gas measured in Btus and the presence of impurities, such as sulfur, carbon dioxide, and nitrogen. Due to the content of NGLs in high Btu gas, this quality of natural gas nets a higher overall price when compared to low Btu gas. Natural gas with a higher concentration of impurities will receive a lower price due to the cost of treating the natural gas to meet pipeline quality specifications.

Natural gas, which currently has a limited global transportation system, is subject to price variances based on local supply and demand conditions and the cost to transport natural gas to end use markets.

Hedging

We enter into derivative instruments to partially mitigate the impact of commodity price volatility on our cash flow from operations. From time to time, such instruments may include fixed price contracts, variable to fixed price swaps, costless collars, and other contractual arrangements. However, we currently utilize only costless collars. In addition, we employ a “rolling hedge” strategy whereby we do not execute all of our hedges at the same time but instead execute new trades as older hedges settle or expire. The impact of these derivative instruments could affect the amount of revenue we ultimately record. For further information, please read “— Quantitative and Qualitative Disclosures About Market Risk.”

EBITDA; Adjusted EBITDA

EBITDA and Adjusted EBITDA are non-GAAP supplemental financial measures used by our management and by external users of our financial statements such as investors, commercial banks, research analysts, and others, to assess:

 

   

our ability to make distributions to unitholders;

 

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the financial performance of our assets without regard to financing methods, capital structure, or historical cost basis;

 

   

the ability of our assets to generate sufficient cash to pay interest costs and support our indebtedness;

 

   

our operating performance and return on capital as compared to those of other companies and partnerships in our industry, without regard to financing or capital structure; and

 

   

the feasibility of acquisitions and other capital expenditures and the overall rates of return on investment opportunities.

We define EBITDA as net income (loss) before interest expense, income taxes, depreciation, depletion and amortization, impairment of oil and natural gas properties, and accretion of AROs. We define Adjusted EBITDA as EBITDA further adjusted for unrealized gains/losses on derivative instruments and non-cash equity-based compensation.

EBITDA and Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income, income from operations, cash flows from operating activities, or any other measure of financial performance or liquidity presented in accordance with GAAP as measures of our operating performance or liquidity. EBITDA and Adjusted EBITDA do not include changes in working capital, capital expenditures, and other items that are set forth in a cash flow statement presentation of our operating, investing, and financing activities. Any measures that exclude these elements have material limitations. Our computation of EBITDA and Adjusted EBITDA may differ from computations of similarly titled measures of other companies.

Factors Affecting the Comparability of Our Financial Results

Our historical financial condition and results of operations for the periods presented may not be comparable, either from period to period or going forward, because we will incur annual incremental general and administrative expenses as a result of operating as a publicly traded partnership, which includes 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, NYSE listing, independent-auditor fees, legal fees, investor-relations activities, registrar and transfer agent fees, director-and-officer insurance, and additional compensation. These direct, incremental general and administrative expenses are not included in our historical results of operations.

 

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Results of Operations

Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013

Revenues

The following table shows our production, pricing, and revenues for the periods presented (in thousands except for realized prices):

 

     Six Months Ended
June 30,
 
     2014     2013  
     (unaudited)  

Production:

    

Oil and condensate (MBbls)

     1,323        1,233   

Natural gas (MMcf)

     20,228        22,996   
  

 

 

   

 

 

 

Equivalents (Boe)(1)

     4,695        5,065   
  

 

 

   

 

 

 

Realized prices:

    

Oil and condensate ($/Bbl)

   $ 94.15      $ 96.21   

Natural gas ($/Mcf)(2)

     5.47        4.15   

Combined equivalents ($/Boe)

   $ 50.10      $ 42.24   

Revenues:

    

Oil and condensate sales

   $ 124,576      $ 118,615   

Natural gas and natural gas liquids sales

     110,640        95,335   

Gain (loss) on commodity derivative instruments

     (8,343     1,522   

Lease bonus and other income

     19,476        7,155   
  

 

 

   

 

 

 

Total revenues

   $ 246,349      $ 222,627   

 

(1) “Btu-equivalent” production volumes are presented on an oil-equivalent basis using a conversion factor of six Mcf of natural gas per barrel of “oil equivalent,” which is based on approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas.
(2) As a mineral-and-royalty-interest owner, we are often provided insufficient and inconsistent data by our operators. As a result, we are unable to reliably determine the total volumes associated with natural gas liquids from the production of natural gas on our acreage. As such, the realized prices we receive for natural gas include sales attributable to natural gas liquids.

Total revenues for the six months ended June 30, 2014 increased $23.7 million, or 10.7%, compared to the six months ended June 30, 2013. The increase was primarily driven by higher realized natural gas prices and higher oil and condensate volumes.

Oil and condensate sales during the period were $6.0 million, or 5.0%, higher than the corresponding period in 2013 primarily due to an increase in production volumes. Our mineral-and-royalty-interest oil volumes accounted for 74.8% and 74.4% of total oil and condensate volumes for the six month period ending June 30, 2014 and the six month period ending June 30, 2013, respectively. The 7.9% increase in mineral-and-royalty-interest oil volumes, period to period, was driven primarily by production increases from new wells in the Eagle Ford Shale. Our working-interest oil volumes increased by 5.6% to 333.5 MBbls during the first half of 2014 versus the first half of 2013 primarily due to new wells in the Bakken/Three Forks play. A 2.1% decrease in realized oil prices partially offset the overall increase in oil and condensate revenue.

Natural gas revenues increased by $15.3 million, or 16.1%, for the six months ended June 30, 2014 as compared to the same period for 2013. A 31.8% increase in the realized natural gas price for the first six months of 2014 versus the same period in 2013 generated the increase. The favorable price variance was partially offset by a decrease in produced volumes. As we expected, natural gas production declined from period to period. The

 

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12.0% decline in both mineral-and-royalty-interest and working-interest volumes was primarily driven by the run-off in production in the Hayneville/Bossier play. In 2008 and 2009, we entered in to lease agreements which covered the majority of our Hayneville/Bossier play acreage in Louisiana and Texas. As operators drilled wells to hold acreage, our natural gas production increased significantly in the play, with the volumes peaking in 2012. With most acreage now held by production, many operators have moved drilling rigs out of the play. Although these wells initially produce at high rates, they tend to decline rapidly, so without consistent drilling activity to replace the high decline rates of the individual wells, the overall production rate from the play has declined. While operators have recently begun to increase the drilling activity on our acreage, the production from these new wells has not yet reached the point of offsetting the declines in the existing wells. Mineral-and-royalty-interest production comprised 68.4% and 61.7% of our natural gas volumes for the first half of 2014 and first half of 2013, respectively.

Lease bonus and delay rental revenue increased $12.3 million, or 172.2%, for the six months ended June 30, 2014 as compared to the same period in 2013. This increase primarily resulted from the successful closing of a significant lease in the Canyon Wash and Canyon Lime plays in Potter County, Texas during the first quarter of 2014.

Operating Expenses

Lease Operating Expenses and Other. Lease operating expenses include normally recurring expenses necessary to operate and produce hydrocarbons from our non-operated working interests in oil and natural gas wells, non-recurring well workovers, repair-related expenses, and exploration expenses. Lease operating expenses decreased by $0.7 million, or 6.5%, for the six months ended June 30, 2014 as compared to the same period in 2013 due to lower production in the Haynesville Shale.

Production and Ad Valorem Taxes. Production, or severance, taxes include statutory amounts deducted from our production revenues by various state taxing entities. Depending on the states’ regulations where the production originates, these taxes may be based on a percentage of the realized value or a fixed amount per production unit. This category also includes the costs to process and transport our production to applicable sales points. Ad valorem taxes are jurisdictional taxes levied on the value of oil and natural gas minerals and reserves. Rates, methods of calculating property values, and timing of payments vary between taxing authorities. For the six months ended June 30, 2014, production and ad valorem taxes increased by $2.1 million, or 10.7%, over the six months ended June 30, 2013, generally as a result of higher oil and natural gas sales.

Depreciation, Depletion, and Amortization Expense. Depletion is the amount of cost basis of oil and natural gas properties at the beginning of a period attributable to the volume of hydrocarbons extracted during such period, calculated on a unit-of-production basis. Estimates of proved developed producing reserves are a major component of the calculation of depletion. We have historically adjusted our depletion rates in the fourth quarter of each year based upon the year-end reserve report and other times during the year when circumstances indicate that there has been a significant change in reserves or costs. Depreciation, depletion, and amortization declined $4.1 million, or 8.0%, primarily due to slightly lower natural gas production volumes during the first six months ended June 30, 2014.

Impairment of Oil and Natural Gas Properties. Individual categories of oil and natural gas properties are assessed periodically to determine if the recorded value has been impaired. Management periodically conducts an in-depth evaluation of the cost of property acquisitions, successful exploratory wells, development activities, unproved leasehold, and mineral interests to identify impairments. Impairments totaled $27.6 million for the six months ended June 30, 2013 primarily due to the impact that changes in price had on the value of our reserve estimates. The primary areas negatively impacted by impairments were the Appalachian Basin and the Haynesville/Bossier and Barnett Shale plays. No impairments were recorded during the six months ended June 30, 2014.

 

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General and Administrative Expense. During the six months ended June 30, 2014, general and administrative expenses increased by $1.0 million, or 3.5% as compared to the same time period in 2013. The increase was due to higher costs associated with our long-term incentive plans. Excluding costs associated with our long-term incentive plans, our general and administrative expense has generally tended to remain consistent between periods.

Accretion of Asset Retirement Obligations. An ARO represents an obligation to perform site reclamation, to dismantle production or processing facilities, or to plug and abandon wells. To determine the current amount of ARO, the estimated future cost to satisfy the abandonment obligation, using current prices that are escalated by an assumed inflation factor up to the estimated settlement date, is discounted back to the date that the abandonment obligation was incurred. After recording this cost, an ARO is accreted to its future estimated value in order to match the timing of expenses with the periods in which they occurred. Accretion expense did not vary significantly between the six months ended June 30, 2014 and the six months ended June 30, 2013.

Interest Expense. Interest expense increased by $2.1 million, or 44.3%, due to additional borrowings under our credit facility. Outstanding borrowings during 2014 were higher than 2013, primarily due to increased expenditures for acquisitions, drilling activity, and funding of common equity repurchases during 2013.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

Revenues

The following table shows our production, pricing, and revenues for the periods presented (in thousands except for realized prices):

 

     Year Ended
December 31,
 
     2013     2012  

Production:

    

Oil and condensate (MBbls)

     2,626        2,173   

Natural gas (MMcf)

     45,400        52,965   
  

 

 

   

 

 

 

Equivalents (MBoe)(1)

     10,193        11,001   
  

 

 

   

 

 

 

Realized Prices:

    

Oil and condensate ($/Bbl)

   $ 96.25      $ 93.00   

Natural gas ($/Mcf)(2)

     4.07        3.15   

Combined equivalents ($/Boe)

   $ 42.93      $ 33.54   

Revenues:

    

Oil and condensate sales

   $ 252,742      $ 202,104   

Natural gas and natural gas liquids sales

     184,868        166,849   

Gain (loss) on commodity derivative instruments

     (5,860     12,275   

Lease bonus and other income

     31,809        53,918   
  

 

 

   

 

 

 

Total revenues

   $ 463,559      $ 435,146   

 

(1) “Btu-equivalent” production volumes are presented on an oil-equivalent basis using a conversion factor of six Mcf of natural gas per barrel of “oil equivalent,” which is based on approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas.
(2) As a mineral-and-royalty-interest owner, we are often provided insufficient and inconsistent data by our operators. As a result, we are unable to reliably determine the total volumes associated with natural gas liquids from the production of natural gas on our acreage. As such, the realized prices we receive for natural gas include sales attributable to natural gas liquids.

 

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Total revenues for the year ended December 31, 2013 increased $28.4 million, or 6.5%, compared to 2012. Revenues from oil production were $50.6 million, or 25.1%, higher than 2012 primarily due to an increase in volumes stemming from the drilling of new wells in the Bakken/Three Forks play, where we own both mineral and royalty interests and working interests, and the Eagle Ford Shale, where we own only mineral and royalty interests. Higher oil prices also contributed to the overall increase in oil and condensate sales. Natural gas and natural gas liquids sales increased by $18.0 million, or 10.8%, year-over-year which was the result of a 29.2% increase in realized natural gas prices (exclusive of any hedging activity). The increase in prices was partially offset by a 14.3% decrease in natural gas production. The decrease in mineral-and-royalty-interest and working-interest natural gas volumes primarily relates to the run-off in production in the Hayneville/Bossier play where reservoir characteristics result in high production decline rates

Lease bonus and delay rental revenue decreased $22.1 million, or 41.0%, for the year ended December 31, 2013 as compared to 2012. During 2013, leasing activity was strong in, among other places, the Austin Chalk, Woodbine, Granite Wash, and Eaglebine plays, all located in Texas. However, 2012 leasing revenue significantly exceeded expectations due to the successful consummation of several large leases in the Brown Dense play and the Tuscaloosa Marine Shale in Mississippi, the Haynesville/Bossier play in Louisiana, and the Woodbine play in Texas.

Operating Expenses

Lease Operating Expenses and Other. Lease operating expenses increased by $0.8 million, or 3.8%, for the year ended December 31, 2013, as compared to the same period in 2012. Our production mix changed from 2012 to 2013 to include higher volumes from oil wells. Lease operating expenses associated with wells which primarily produce oil are typically higher than similar expenses incurred to produce volumes from wells which primarily produce natural gas.

Production and Ad Valorem Taxes. For the year ended December 31, 2013, production and ad valorem taxes increased $6.1 million, or 16.7%, over 2012, as a result of the correlation to higher oil and natural gas sales.

Depreciation, Depletion, and Amortization Expense. DD&A decreased $1.6 million, or 1.6%, for the year ended December 31, 2013 as compared to 2012.

Impairment of Oil and Natural Gas Properties. Impairments totaled $57.1 million for the year ended December 31, 2013, primarily due to the impact changes in prices had on the value of our reserve estimates. The primary areas impacted by impairments were in the Appalachian Basin, the Haynesville/Bossier play, and the Barnett Shale play. Impairments totaled $63.0 million for the year ended December 31, 2012, principally related to properties located in the Appalachian Basin, the Barnett Shale play, and various fields in the Anadarko Basin.

General and Administrative Expense. General and administrative expenses increased $9.2 million, or 18.2%, in 2013 as compared to 2012 primarily as a result of higher costs associated with our long-term incentive plans, contractor costs resulting from land and title work and recording fees associated with assets acquired through the exchange offer. See the notes to our historical financial statements included elsewhere in this prospectus for additional information regarding the exchange offer.

Accretion of Asset Retirement Obligations. Accretion expense did not vary significantly between the year ended December 31, 2013 as compared to 2012.

Interest Expense. Interest expense increased $2.2 million, or 23.7%, due to additional borrowings under our credit facility. Borrowings during the year were higher than 2012 primarily as a result of increased expenditures for acquisitions and repurchases of our common equity.

 

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Liquidity and Capital Resources

Overview

Following the completion of this offering, we expect our primary sources of liquidity to be the net proceeds retained from this offering, cash flows from operations, borrowings under our credit facility, and proceeds from the issuance of equity and debt. We expect our primary uses of cash will be for distributions to our common unitholders and for capital expenditures, including the acquisition of mineral and royalty and working interests and the development of our oil and natural gas properties.

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 a substantial majority of the available cash we generate each quarter. Available cash for each quarter will be determined by the board of directors of our general partner following the end of that quarter. Our initial distribution will be $         per common unit on an annualized basis, which we forecast to represent approximately     % of our available cash for the year ending December 31, 2015. We may borrow to make distributions to our unitholders when, for example, we believe that the distribution level is sustainable over the long-term, but short-term factors may cause available cash from operations to be insufficient to pay the distribution at the then-current level. 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.

It is our intent, for at least the next several years, to finance most of our acquisitions and working-interest capital needs with the retained net proceeds from this offering and borrowings from our credit facility and, in certain circumstances, proceeds from future equity and debt issuances. Replacement capital expenditures are expenditures necessary to replace our existing oil and natural gas reserves or otherwise maintain our asset base over the long-term. 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 the development of existing plays and the discovery of new reserves will lead to increasing revenues for at least the next several years. We intend also to add reserves through acquisitions of mineral and royalty interests and through non-operated working-interest participation. We may restrict distributions to our common unitholders, in whole or in part, to fund acquisitions and participation in working interests.

At the beginning of each calendar year, we establish a capital budget and then review it throughout the year. Our capital budgets are created based upon our estimate of internally generated cash and the ability to borrow and raise additional capital. Actual capital expenditure levels will vary, in part, based on actual internally generated cash, actual wells proposed by our operators for our participation, and the successful closing of acquisitions. The timing, size, and nature of acquisitions are unpredictable.

Cash Flows

The following table shows our cash flows for the periods presented (in thousands):

 

     Year Ended
December 31,
    Six Months Ended
June 30,
 
     2013     2012     2014     2013  
                 (unaudited)  

Cash flows from operating activities

   $ 320,764      $ 358,002      $ 165,860      $ 142,900   

Cash flows used in investing activities

   $ (195,631   $ (198,975   $ (59,855   $ (123,855

Cash flows used in financing activities

   $ (142,311   $ (138,172   $ (123,339   $ (44,441

Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013

Operating Activities. Our operating cash flow is dependent in large part on our production, realized commodity prices, leasing revenues, and operating expenses. For the six months ended June 30, 2014, cash flows from operating activities increased by $23.0 million as compared to the same period in 2013 due to increased realized commodity prices and higher oil