S-1/A
Table of Contents

As filed with the Securities and Exchange Commission on April 22, 2015

Registration No. 333-202875

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

AMENDMENT NO. 2

TO

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   ¨

CALCULATION OF REGISTRATION FEE

 

 

Title of each class of securities to be registered  

Amount to be
registered(1)

  Proposed maximum
aggregate offering
price per unit(2)
  Proposed maximum
aggregate offering
price(1)(2)
  Amount of
registration fee(3)

Common units representing limited partner interests

  25,875,000   $21.00   $543,375,000   $63,141

 

 

 

(1) Estimated pursuant to Rule 457(a) under the Securities Act of 1933, as amended. Includes common units issuable upon exercise of the underwriters’ option to purchase additional common units.
(2) Estimated solely for the purpose of calculating the registration fee.
(3) The Registrant previously paid $11,620 of the total registration fee in connection with the previous filing of this Registration Statement.

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

 

 

 


Table of Contents

The information in this preliminary prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission 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 April 22, 2015

PROSPECTUS

 

 

LOGO

Black Stone Minerals, L.P.

22,500,000 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 22,500,000 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 $19.00 and $21.00 per common unit. We have been approved to list our common units on the New York Stock Exchange under the symbol “BSM,” subject to official notice of issuance.

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

These risks include the following:

 

 

We may not generate sufficient cash from operations after establishment of cash reserves to pay the minimum quarterly distribution on our common and subordinated units. If we make distributions, our preferred unitholders have priority with respect to rights to share in those distributions over our common and subordinated unitholders for so long as our preferred units are outstanding.

 

 

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

 

 

Oil and natural gas prices have declined substantially from historical highs and may remain depressed for the foreseeable future. Any additional decreases in the prices of oil or natural gas may adversely affect our cash generated from operations, results of operations, financial position, and our ability to pay the minimum quarterly distribution on all of our outstanding common and subordinated units, perhaps materially.

 

 

Our minimum quarterly distribution provides the common unitholders a specified priority right to distributions over the subordinated unitholders if we pay distributions. It does not provide the common unitholders the right to require payment of any distributions.

 

 

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 natural 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.

 

 

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

 

 

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 distributions 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(1)

   $         $     

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

   $         $     

 

(1) Excludes an aggregate structuring fee equal to 0.50% of the gross proceeds of this offering payable by us to Barclays Capital Inc. Please read “Underwriting.”

The underwriters may purchase up to an additional 3,375,000 common units from us at the public offering price, less the underwriting discount, within 30 days from the date of this prospectus to cover over-allotments.

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

The underwriters expect to deliver the common units to purchasers on or about                     , 2015 through the book-entry facilities of The Depository Trust Company.

 

 

 

Barclays

   BofA Merrill Lynch   Citigroup
Credit Suisse     Wells Fargo Securities

 

 

 

J.P. Morgan           Morgan Stanley   Raymond James
Scotia Howard Weil     Simmons & Company
International        

Prospectus dated                     , 2015


Table of Contents

LOGO


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

     24   

Non-GAAP Financial Measures

     26   

RISK FACTORS

     27   

Risks Related to Our Business

     27   

Risks Inherent in an Investment in Us

     41   

Tax Risks to Common Unitholders

     47   

USE OF PROCEEDS

     51   

CAPITALIZATION

     52   

DILUTION

     53   

CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

     54   

General

     54   

Pro Forma Cash Generated from Operations for the Year Ended December 31, 2014

     58   

Estimated Cash Generated from Operations for the Twelve Months Ending March 31, 2016

     61   

Historical Asset Production

     75   

HOW WE MAKE DISTRIBUTIONS

     76   

General

     76   

Operating Surplus and Capital Surplus

     76   

Capital Expenditures

     78   

Subordination Period

     80   

Distributions From Operating Surplus During the Subordination Period

     82   

Distributions From Capital Surplus

     82   

Adjustment to the Minimum Quarterly Distribution

     83   

Distributions of Cash Upon Liquidation

     83   

SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA

     84   

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

     86   

Overview

     86   

Business Environment

     86   

How We Evaluate Our Operations

     88   

Factors Affecting the Comparability of Our Financial Results

     90   

Results of Operations

     90   

 

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Liquidity and Capital Resources

     93   

Credit Facility

     94   

Contractual Obligations

     95   

Off-Balance Sheet Arrangements

     95   

Critical Accounting Policies and Related Estimates

     95   

New and Revised Financial Accounting Standards

     99   

Quantitative and Qualitative Disclosure about Market Risk

     99   

BUSINESS

     100   

Overview

     100   

Our Assets

     100   

Business Strategies

     102   

Competitive Strengths

     104   

Our Properties

     105   

Estimated Proved Reserves

     115   

Oil and Natural Gas Production Prices and Production Costs

     120   

Environmental Matters

     123   

Title to Properties

     127   

Competition

     128   

Seasonal Nature of Business

     128   

Employees

     128   

Facilities

     128   

Legal Proceedings

     128   

MANAGEMENT

     129   

Management

     129   

Executive Officers and Directors of Our General Partner

     130   

Director Independence

     135   

Committees of the Board of Directors

     135   

Certain Relationships and Related Party Transactions

     136   

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

     136   

EXECUTIVE COMPENSATION AND OTHER INFORMATION

     137   

Summary Compensation Table

     137   

Narrative Disclosure to the Summary Compensation Table

     138   

Outstanding Equity Awards at 2014 Fiscal Year-End

     139   

Additional Narrative Disclosure

     140   

Long-Term Incentive Plan

     143   

Director Compensation

     145   

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     147   

FIDUCIARY DUTIES

     149   

DESCRIPTION OF OUR COMMON UNITS

     152   

Our Common Units

     152   

Transfer Agent and Registrar

     152   

Transfer of Common Units

     152   

Listing

     153   

DESCRIPTION OF OUR PREFERRED UNITS

     154   

Our Preferred Units

     154   

Distributions

     154   

Conversion of the Preferred Units

     155   

Redemption of the Preferred Units

     155   

 

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Anti-Dilution Provisions

     156   

Voting; Waiver

     157   

THE PARTNERSHIP AGREEMENT

     158   

Organization and Duration

     158   

Purpose

     158   

Capital Contributions

     158   

Adjustments to Capital Accounts Upon Issuance of Additional Common Units

     158   

Voting Rights

     158   

Meetings; Voting

     160   

Nomination of Directors

     161   

Applicable Law; Forum, Venue, and Jurisdiction

     162   

Limited Liability

     162   

Issuance of Additional Partnership Interests

     163   

Amendment of the Partnership Agreement

     164   

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

     166   

Dissolution

     166   

Liquidation and Distribution of Proceeds

     167   

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

     167   

Change of Management Provisions

     167   

Ineligible Holders; Redemption

     167   

Limited Call Right

     168   

Status as Limited Partner

     169   

Indemnification

     169   

Books and Reports

     169   

Right to Inspect Our Books and Records

     170   

UNITS ELIGIBLE FOR FUTURE SALE

     171   

MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES

     172   

Taxation of the Partnership

     172   

Tax Consequences of Unit Ownership

     174   

Tax Treatment of Operations

     178   

Disposition of Units

     180   

Uniformity of Units

     182   

Tax-Exempt Organizations and Other Investors

     183   

Administrative Matters

     184   

FATCA Withholding Requirements

     185   

State, Local, and Other Tax Considerations

     186   

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

     187   

General Fiduciary Matters

     187   

Prohibited Transaction Issues

     187   

Plan Asset Issues

     188   

UNDERWRITING

     189   

Commissions and Expenses

     189   

Option to Purchase Additional Common Units

     190   

Lock-Up Agreements

     190   

Offering Price Determination

     190   

Indemnification

     191   

Stabilization, Short Positions, and Penalty Bids

     191   

Directed Unit Program

     192   

Electronic Distribution

     192   

 

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New York Stock Exchange

     192   

Discretionary Sales

     192   

Stamp Taxes

     192   

Relationships

     192   

FINRA

     193   

Selling Restrictions

     193   

LEGAL MATTERS

     195   

EXPERTS

     195   

CHANGE IN ACCOUNTANTS

     195   

WHERE YOU CAN FIND MORE INFORMATION

     196   

FORWARD-LOOKING STATEMENTS

     197   

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.

 

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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 $20.00 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 and subordinated 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” refer to Black Stone Natural Resources, L.L.C., a wholly owned subsidiary and also the general partner of BSMC. References in this prospectus to “our general partner” or “New GP” refer to Black Stone Minerals GP, L.L.C., a wholly owned subsidiary and also the general partner of BSM. References in this prospectus to “New BSMC GP” refer to BSMC GP, L.L.C., a wholly owned subsidiary and also the general partner of BSMC, after giving effect to those transactions described in “—Formation Transactions and Structure.” 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. References in this prospectus to production or reserves in “Boe” or “MBoe” are presented on a “Btu-equivalent” basis at a conversion ratio of six Mcf (as defined below) of natural gas to one barrel of oil, unless otherwise indicated. 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 generated from operations over the long term, while paying, to the extent practicable, a growing quarterly distribution to our unitholders.

We own mineral interests in approximately 14.5 million acres, with an average 48.1% 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 plays, Eagle Ford Shale, Wolfcamp play, Haynesville/Bossier plays, 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.

 

 

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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 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 year ended December 31, 2014 was approximately 26.7 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, and excludes volumes and payments related to prior period production.

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 revenue from production. 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 (“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 (“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 $340.4 million for the year ended December 31, 2014.

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

 

 

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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 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 2015 non-operated working-interest capital expenditure budget and likely will be a declining portion of our future working-interest capital expenditure budget.

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 2015 drilling capital expenditure budget associated with our working-interest participation program is approximately $40.1 million. Approximately 65% and 14% of our 2015 drilling capital budget will be spent in the Haynesville/Bossier and the Bakken/Three Forks plays, respectively, with the remainder spent in various plays including the Wilcox and Granite Wash plays. We historically have participated in approximately 175 new wells per year. As of December 31, 2014, we owned non-operated working interests in approximately 9,200 gross wells. For the year ended December 31, 2014, our revenue generated from these working interests was $124.4 million.

Our Properties

Material Basins and Producing Regions

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

 

     Acreage as of December 31, 2014(1)      Average Daily
Production for
Year Ended 

December 31,
2014(3)(4) (Boe/d)
 
     Mineral and Royalty Interests      Working Interests     

USGS Petroleum Province(2)

   Mineral
Interests
     NPRIs      ORRIs      Gross      Net     

Louisiana-Mississippi Salt Basins

     5,279,494         111,787         19,373         55,409         7,231         7,040   

Western Gulf (onshore)

     1,543,704         180,901         85,501         117,049         17,694         5,065   

Williston Basin

     1,111,548         61,094         30,645         53,090         7,488         3,493   

Palo Duro Basin

     1,010,374         22,791         1,120                         16   

Permian Basin

     695,605         545,414         59,757         8,433         5,054         840   

Anadarko Basin

     535,767         10,628         181,401         31,667         21,404         2,447   

Appalachian Basin

     490,006         416         3,532                         905   

East Texas Basin

     406,294         40,584         30,610         138,519         35,520         2,460   

Arkoma Basin

     331,168         5,170         36,109         8,953         2,408         2,029   

Bend Arch-Fort Worth Basin

     138,178         52,208         41,072         61,650         11,369         550   

Southwestern Wyoming

     25,490         560         70,607         15,458         2,492         542   

Other

     2,933,898         188,446         793,419         43,574         13,173         1,333   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     14,501,524         1,219,999         1,353,145         533,802         123,834         26,719   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

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

 

 

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  acreage in that tract will relate to the same 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.”
(3) “Btu-equivalent” production volumes are presented on an oil-equivalent basis using a conversion factor of six thousand cubic feet (“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. Please read “Business—Estimated Proved Reserves—Summary of Estimated Proved Reserves.”
(4) Represents actual production plus allocated accrued volumes attributable to the period presented.

 

   

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 plays, which have been extensively delineated through drilling, are the most prospective unconventional plays for natural gas production and reserves within this region. Approximately half of the Haynesville/Bossier plays’ 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 region’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 has been actively drilled and tested recently by several operators. We have a significant mineral-and-royalty-interest position across the entire region, with material exposure to the Tuscaloosa Marine Shale. There are a number of additional active conventional and unconventional plays in the basins in which we hold considerable mineral and royalty interests, including the Brown Dense, Cotton Valley, Hosston, Norphlet, Smackover, and Wilcox plays.

 

   

Western Gulf (onshore). 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 region and has been actively drilled and tested recently 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 plays, 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.

 

 

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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.

 

   

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 plays and the Cotton Valley play, which are among the most prolific natural gas plays in the basin. We own a material acreage position in the Shelby Trough area of the Haynesville/Bossier plays 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 natural gas plays. We own material mineral and royalty interests within the prospective area of the Fayetteville Shale. In addition, we have exposure 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 interests 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 region’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 61% of our aggregate production for the year ended December 31, 2014.

 

     Acreage as of December 31, 2014(1)  

Resource Play(2)

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

Bakken Shale

     304,875         35,621         12,610         48,515         6,852   

Three Forks

     291,697         32,802         11,930         48,717         6,479   

Haynesville Shale

     269,824         7,123         14,842         174,293         40,440   

Marcellus Shale

     249,567         —           1,002         —           —     

Canyon Lime

     219,158         —           —           —           —     

Bossier Shale

     204,742         2,096         8,814         136,964         33,433   

Tuscaloosa Marine Shale

     178,756         4,081         6,489         —           —     

Granite Wash

     100,883         4,042         87,516         5,194         1,364   

Fayetteville Shale

     72,901         —           11,833         —           —     

Barnett Shale

     62,178         4,004         37,837         20,985         7,596   

Eagle Ford Shale

     47,736         85,864         46,927         235         118   

Wolfcamp-Midland

     57,774         46,720         15,609         160         4   

Wolfcamp-Delaware

     33,895         11,785         1,080         642         160   

 

(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 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 generated from operations over the long term, while paying, to the extent practicable, a growing quarterly distribution to our 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 low-risk drilling opportunities in 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 from operations, our $600.0 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 generated from operations 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 16.7 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 and the Haynesville/Bossier plays, have developed. Because our asset base is large and diversified, we are able to make significant focused acquisitions in active areas within well-established

 

 

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resource plays, while maintaining overall diversity. Furthermore, the geographic breadth of our assets 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 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 plays, 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 natural 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 $13.6 million of cash on hand, and $600.0 million of undrawn borrowing capacity under our credit facility. The credit facility, combined with internally generated cash from operations 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

 

 

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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.

Management

We are managed and operated by the board of directors and executive officers of our general partner, Black Stone Minerals GP, L.L.C., our wholly owned subsidiary. 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, subordinated, 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”).

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”);

 

 

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

 

   

an exemption from compliance with any other new auditing standards adopted by the PCAOB after April 5, 2012, unless the Securities and Exchange Commission (“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:

 

   

the partnership formed New GP, a new wholly owned subsidiary to function as the general partner of the partnership, and BSNR transferred its general partner interest in the partnership to New GP in exchange for cash;

 

   

BSNR will contribute cash to BSMC in exchange for 21,939,243 common units representing a 1% limited partner interest in BSMC, and New GP will contribute cash to the partnership in exchange for 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;

 

   

immediately prior to the merger, the limited partnership agreement of the partnership will be amended and restated, and the limited partner interests of BSMC and our general partner in the partnership will be converted into common units and subordinated units of the partnership, as applicable;

 

   

in connection with the merger, (i) the common units of the partnership held by BSMC will be redeemed in exchange for a return of its original capital contribution, (ii) the common units of BSMC (other than common units of BSMC held by BSNR) will be exchanged for an aggregate of 72,633,333 common units of the partnership and 95,133,333 subordinated units of the partnership at a conversion ratio of 12.9465 : 1 for 0.4329 common units and 0.5671 subordinated units, and the preferred units of BSMC will be exchanged for an aggregate of 117,980 preferred units of the partnership at a conversion ratio of

 

 

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one to one, (iii) the common units of BSMC held by BSNR will remain outstanding as limited partner interests in BSMC, and New GP will retain its non-economic general partner interest in the partnership and its units in the partnership, (iv) the partnership’s 100% equity interest in Merger Sub will be converted into a 99% limited partner interest in BSMC, and (v) BSNR will retain its non-economic general partner interest in BSMC;

 

   

(i) the partnership will form New BSMC GP, a new wholly owned subsidiary to function as general partner of BSMC, (ii) the partnership will remove BSNR as general partner of BSMC and appoint New BSMC GP as general partner of BSMC, and (iii) in connection therewith, BSNR will transfer its general partner interest in BSMC to New BSMC GP; and

 

   

the partnership will issue and sell 22,500,000 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 3,375,000 additional common units. Any net proceeds received from the exercise of this option will be used to fund future capital expenditures.

The following chart illustrates our organizational structure prior to this offering and the formation transactions described above:

 

LOGO

 

 

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

LOGO

 

(1) The 117,980 preferred units as of March 31, 2015 are convertible into 3,579,881 common units and 4,688,839 subordinated units.

 

 

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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.blackstoneminerals.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 generated from operations, 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 generate sufficient cash from operations after establishment of cash reserves to pay the minimum quarterly distribution on our common and subordinated units. If we make distributions, our preferred unitholders have priority with respect to rights to share in those distributions over our common and subordinated unitholders for so long as our preferred units are outstanding.

 

   

The assumptions underlying the forecast of our cash generated from operations 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 distribute to holders of our units depends primarily on our cash generated from operations and not our profitability, which may prevent us from making cash distributions during periods when we record net income.

 

   

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

 

   

Oil prices have declined substantially from historical highs and may remain depressed for the foreseeable future. Approximately 55.4% of our 2014 oil and natural gas revenues were derived from oil and condensate sales. Any additional decreases in prices of oil may adversely affect our cash generated from operations, results of operations, financial position, and our ability to pay the minimum quarterly distribution on all of our outstanding common and subordinated units, perhaps materially.

 

   

Natural gas prices have declined substantially from historical highs and are expected to remain depressed for the foreseeable future. Approximately 70.1% of our 2014 total production was natural gas, on a “Btu-equivalent” basis. Any additional decreases in prices of natural gas may adversely affect our cash generated from operations, results of operations, financial position, and our ability to pay the minimum quarterly distribution on all of our outstanding common and subordinated units, perhaps materially.

 

   

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

 

   

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

 

   

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 natural 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 generated from operations and our ability to make distributions to our common and subordinated 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 cash distributions to our unitholders.

 

   

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.

 

   

Our credit facility has substantial restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions.

 

   

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 distributions to unitholders.

 

   

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

 

   

Cyber attacks could significantly affect us.

 

 

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Risks Inherent in an Investment in Us

 

   

We expect to distribute a substantial majority of the cash we generate from operations 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 make distributions, our preferred unitholders have priority with respect to rights to share in those distributions over our common and subordinated unitholders for so long as our preferred units are outstanding.

 

   

Our minimum quarterly distribution provides the common unitholders a specified priority right to distributions over the subordinated unitholders if we pay distributions. It does not provide the common unitholders the right to require payment of any 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 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 units, subject to certain exceptions.

 

   

Actions taken by our general partner may affect the amount of cash generated from operations that is available for distribution to unitholders or accelerate the right to convert subordinated units.

 

   

We have a call right that may require common unitholders to sell their common units at an undesirable time or price.

 

   

Unitholders may have liability to repay distributions.

 

   

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

 

   

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 and subordinated unitholder approval, which would dilute holders of common and subordinated 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, 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.

 

 

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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.

 

   

If you are not an Eligible Holder, your common units may 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 distributions 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 distributions 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

22,500,000 common units (25,875,000 common units if the underwriters exercise in full their option to purchase additional common units from us).

 

Units outstanding after this offering

95,133,333 common units (98,508,333 common units if the underwriters exercise in full their option to purchase additional common units from us), 95,133,333 subordinated units, and 117,980 preferred units. The preferred units are convertible into 3,579,881 common units and 4,688,839 subordinated units.

 

Use of proceeds

We intend to use the estimated net proceeds of approximately $421.9 million from this offering (based on an assumed initial offering price of $20.00 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, structuring fee, and offering expenses payable by us, to repay all of the indebtedness outstanding under our credit facility, which was $389.0 million as of March 31, 2015. We expect that at the time of completion of the offering, the outstanding balance on our credit facility will approximately equal the net proceeds of this offering. If the net proceeds should exceed the outstanding balance, this excess will be used to fund future capital expenditures.

 

  The net proceeds from any exercise of the underwriters’ option to purchase additional common units (approximately $63.6 million based on an assumed initial offering price of $20.00 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 structuring fee, 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

Our partnership agreement generally provides that during the subordination period we will pay any distributions each quarter as follows:

 

   

first, to the holders of preferred units in an amount of approximately $25.00 per preferred unit (the “quarterly preferred distribution amount”);

 

 

   

second, to the holders of common units, until each common unit has received the applicable minimum quarterly distribution in the amounts specified below plus any arrearages from prior quarters; and

 

 

   

third, to the holders of subordinated units, until each subordinated unit has received the applicable minimum quarterly distribution.

 

 

 

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  If the distributions to our common and subordinated unitholders exceed the applicable minimum quarterly distribution per unit, then such excess amounts will be distributed pro rata on the common and subordinated units as if they were a single class. The preferred units have a right to further participate (on an as-converted basis) in quarterly distributions in excess of the quarterly preferred distribution amount under certain circumstances that we do not expect to occur. Even if those additional distributions do occur, considering that the outstanding preferred units are convertible into only a relatively small number of our total outstanding common and subordinated units, we believe these additional distributions payable under those circumstances would not materially adversely affect the per unit distribution rate we would otherwise pay on our common and subordinated units.

 

  We have no legal or contractual obligation to pay the minimum quarterly distribution on our common units and subordinated units, and the board of directors of our general partner can change the amount of the quarterly distributions, if any, at any time. Furthermore, even if we intend to pay distributions on our common units and subordinated units, our ability to pay the applicable minimum quarterly distribution is subject to various restrictions and other factors described in more detail in “Cash Distribution Policy and Restrictions on Distributions.” Therefore, the fact that our partnership agreement includes the concept of a minimum quarterly distribution does not provide any assurance that a distribution will be paid on the common units, nor are we providing or making any forecast beyond the twelve months ending March 31, 2016 as to our ability to pay the minimum quarterly distribution on the common units.

 

  The applicable minimum quarterly distribution for the periods specified below is as follows:  

 

     

Minimum Quarterly Distribution
(per unit)

Four Quarters Ending March 31,

   Per Quarter    Annualized

2016

   $0.2625    $1.05

2017

   $0.2875    $1.15

2018

   $0.3125    $1.25

2019 and thereafter

   $0.3375    $1.35

 

  After March 31, 2019, the minimum quarterly distribution shall be the same as it is for each of the four quarters ending March 31, 2019. Our initial distribution will be $1.05 per common and subordinated unit on an annualized basis (or $0.2625 per common and subordinated unit on a quarterly basis). The minimum quarterly distribution does not provide common unitholders the right to require payment of any distributions. It merely reflects the specified priority right of common unitholders to distributions before the subordinated unitholders receive distributions if distributions are paid.

 

 

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  We believe, based on our financial forecast and related assumptions included in “Cash Distribution Policy and Restrictions on Distributions,” that we will generate sufficient cash from operations to pay, for the twelve months ending March 31, 2016, the required distribution on the preferred units and the applicable minimum quarterly distribution of $0.2625 per unit ($1.05 per unit on an annualized basis) on all the common and subordinated units outstanding.

 

  If we assume that (i) the initial minimum quarterly distribution is $0.3375 per unit, which is the amount applicable after March 31, 2019, (ii) the preferred units are fully converted, (iii) the underwriters’ option to purchase additional common units to cover over-allotments is exercised in full, and (iv) no additional common or subordinated units are issued, we believe that the cash generated from operations during the twelve months ending March 31, 2016 would be sufficient to pay 100% of the aggregate minimum quarterly distribution on all the common units and 74.9% of the aggregate minimum quarterly distribution on the subordinated units.

Any distributions paid on our common and subordinated units with respect to a quarter will be paid within 60 days after the end of such quarter. Our first distribution will be for the period from the closing of this offering through June 30, 2015, and our partnership agreement will prorate the minimum quarterly distribution based on the actual length of the period. Please read “Cash Distribution Policy and Restrictions on Distributions.”

 

Subordinated units

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

 

Conversion of subordinated units

The subordination period will end on the first business day after we have earned and paid an aggregate amount of at least $1.35 (the annualized minimum quarterly distribution applicable for quarterly periods ending March 31, 2019 and thereafter) multiplied by the total number of outstanding common and subordinated units for a period of four consecutive, non-overlapping quarters ending on or after March 31, 2019, and there are no outstanding arrearages on our common units. When the subordination period ends as a result of our having met the test described above, all subordinated units will convert into common units on a one-to-one basis, and common units will thereafter no longer be entitled to arrearages.

 

 

In addition, at any time on or after March 31, 2019, provided there are no arrearages in the payment of the minimum quarterly distribution on

 

 

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the common units, our general partner may decide in its sole discretion to convert each subordinated unit into a number of common units at a ratio that will be less than one to one. If our general partner makes such election, all outstanding subordinated units will be converted into common units, and the conversion ratio will be equal to the distributions paid out with respect to the subordinated units over the previous four-quarter period in relation to the total amount of distributions required to pay the applicable minimum quarterly distribution in full with respect to the subordinated units over the previous four quarters. It should be expected that the general partner will cause this conversion unless it determines that such conversion will be adverse to the subordinated unitholders. If at the time our general partner elects to convert the subordinated units under this provision our forecasted distributions on our subordinated units (as determined by the conflicts committee of our general partner’s board of directors) for the next four quarters are lower than our actual distributions for the previous four-quarter period referred to above, then the conversion ratio will be based on the forecasted distributions instead of the actual distributions.

 

Preferred units

Our preferred units represent limited partner interests in us. Our preferred units will receive priority distributions over our common and subordinated units until the holders of our preferred units have been paid a specified yield on their initial investment. Each preferred unit may be converted at any time at the option of the holder thereof into common units at the then-effective conversion rate. In addition, on January 1 of each year from 2016 to 2018 a number of preferred units will automatically convert into common units and subordinated units at the then-effective conversion rate. The preferred units may also be redeemed, at the option of the holders, for a cash price per preferred unit equal to their initial investment plus a specified yield thereon (the “Holder Redemption Price”) (i) on December 31 of each year from 2015 through 2017 or (ii) if Thomas L. Carter, Jr. is no longer chief executive officer of our general partner or is no longer actively involved in the investment decisions, management, and operations of the partnership. The preferred units will automatically be redeemed at the Holder Redemption Price if there is a change of control of the partnership. Except with respect to certain matters requiring the approval of the holders of preferred units, holders of preferred units are entitled to vote their preferred units as a single class with the holders of common and subordinated units on an “as-converted basis.” For a detailed discussion of our preferred units, please read “Description of Our Preferred Units.”

 

Incentive distribution rights

None.

 

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 and the subordinated units, without the approval of our unitholders. However, our partnership agreement does not authorize us to issue

 

 

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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.”

 

Voting rights

Our limited partners holding common units, subordinated units, or preferred units (the preferred units on an as-converted basis) will vote together as a single class for most matters, including the election of directors to the board of directors of our general partner. Our limited partners will be entitled to cumulate their votes for purposes of electing directors. Please read “The Partnership Agreement—Voting Rights.”

 

Limited call right

If at any point in time prior to the end of the subordination period we have acquired more than 80% of the total number of common units outstanding, we have the right, but not the obligation, to purchase all of the remaining common units at a price equal to the greater of (i) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (ii) the highest per-unit price paid by us for common units during the 90-day period preceding the date such notice is first mailed. This limited call right is not exerciseable as long as any of our preferred units are outstanding or at any time after the subordination period has ended.

 

Eligible Holders and redemption

Only Eligible Holders are entitled to own our units and to receive distributions or be allocated income or loss from us. Eligible Holders are limited partners (i) whose, or whose owners’, federal income tax status does not have or is not reasonably likely to have a material adverse effect on the rates chargeable by us to customers and (ii) whose ownership could not result in our loss of ownership in any material part of our assets, as determined by our general partner with the advice of counsel.

 

  We have the right, but not the obligation, to redeem all of the units of any holder that is an Ineligible Holder or that has failed to certify or has falsely certified that such holder is an Eligible Holder. The purchase price for such redemption would be equal to the then-current market price of the units. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.

 

  Please read “Description of Our Common Units—Transfer of Common Units.”

 

Estimated ratio of taxable income to distributions

We estimate that if you (i) are subject to the passive activity loss limitation and (ii) own the common units you purchase in this offering through the record date for distributions for the period ending

 

 

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December 31, 2018, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be approximately 30% of the aggregate applicable minimum quarterly distribution with respect to that period. Alternatively, if you are not subject to the passive loss limitation, your ratio of taxable income for such period to cash distributions will likely be lower. Thereafter, the ratio of allocable taxable income to cash distributions to you could substantially increase. Please read “Material U.S. Federal Income Tax Consequences—Tax Consequences of Unit Ownership” for the basis of this estimate.

 

Material federal income tax consequences

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

 

Directed unit program

The underwriters have reserved for sale at the initial public offering price up to 5% of the common units being offered by this prospectus for sale to persons who are directors, officers, or employees of our general partner and certain other persons with relationships with us and our affiliates. We do not know if these persons will choose to purchase all or any portion of these reserved common units, but any purchases they do make will reduce the number of common units available to the general public. Please read “Underwriting—Directed Unit Program.”

 

Exchange listing

We have been approved to list our common units on the NYSE under the symbol “BSM,” subject to official notice of issuance.

 

 

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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 consolidated 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 unaudited pro forma financial data of Black Stone Minerals, L.P. as of the dates and for the years indicated.

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

The summary unaudited pro forma financial data presented as of and for the year ended December 31, 2014 is derived from our unaudited pro forma consolidated financial statements included elsewhere in this prospectus. Our unaudited pro forma consolidated financial statements give pro forma effect to the formation transactions, including 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 unaudited pro forma consolidated balance sheet assumes the events described above occurred as of December 31, 2014. The unaudited pro forma consolidated statement of operations for the year ended December 31, 2014 assumes the events described above occurred as of January 1, 2014.

We have not given pro forma effect to incremental general and administrative expenses of approximately $1.5 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 registered public accounting firm 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 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,
    Year Ended
December 31,
2014
 
    2014     2013    
         

(unaudited)

 
   

(in thousands)

 

Statement of Operations Data:

     

Revenue:

     

Oil and condensate sales

  $ 257,390      $ 252,742      $   257,390   

Natural gas and natural gas liquids sales

    207,456        184,868        207,456   

Gain (loss) on commodity derivative instruments

    37,336        (5,860     37,336   

Lease bonus and other income

    46,139        31,809        46,139   
 

 

 

   

 

 

   

 

 

 

Total revenue

    548,321        463,559        548,321   
 

 

 

   

 

 

   

 

 

 

Operating (income) expense:

     

Lease operating expense and other

    23,288        21,316        23,288   

Production and ad valorem taxes

    49,575        42,813        49,575   

Depreciation, depletion, and amortization

    111,962        102,442        111,962   

Impairment of oil and natural gas properties

    117,930        57,109        117,930   

General and administrative

    62,765        59,501        62,765   

Accretion of asset retirement obligations

    1,060        588        1,060   

(Gain) loss on disposal of assets

    32        (18     32   
 

 

 

   

 

 

   

 

 

 

Total operating expense

    366,612        283,751        366,612   
 

 

 

   

 

 

   

 

 

 

Income from operations

    181,709        179,808        181,709   

Other income (expense):

     

Interest and investment income

    28        90        28   

Interest expense(1)

    (13,509     (11,342     (3,630

Other income

    959        407        959   
 

 

 

   

 

 

   

 

 

 

Total other expense

    (12,522     (10,845     (2,643
 

 

 

   

 

 

   

 

 

 

Net income

  $ 169,187      $ 168,963      $ 179,066   
 

 

 

   

 

 

   

 

 

 

Statement of Cash Flow Data:

     

Net cash provided by (used in):

     

Operating activities

  $ 396,125      $ 320,764     

Investing activities

    (101,110     (195,631  

Financing activities

    (310,335     (142,311  

Other Financial Data:

     

EBITDA(2)

  $ 294,658      $ 282,747      $ 294,658   

Adjusted EBITDA(2)

    385,705        354,576        385,705   

Capital expenditures(3)

    (101,110     (195,631  

Balance Sheet Data (at year end):

     

Cash and cash equivalents

  $ 14,803      $ 30,123      $ 42,670   

Total assets

    1,326,782        1,444,413        1,347,062   

Credit facilities

    394,000        451,000        —     

Total liabilities

    512,400        566,618        118,400   

Total mezzanine equity

    161,165        161,392        161,165   

Total equity

    653,217        716,403        1,067,497   

 

(1) Includes cash expenses for 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 $19.5 million and $0.1 million for the years ended December 31, 2014 and December 31, 2013, respectively.

 

 

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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, research analysts, and others, to assess the financial performance of our assets and their ability to sustain distributions over the long term without regard to financing methods, capital structure, or historical cost basis.

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

EBITDA and Adjusted EBITDA do not represent and 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 presented in accordance with GAAP as measures of our financial performance. EBITDA and Adjusted EBITDA have important limitations as analytical tools because they exclude some but not all items that affect net income, the most directly comparable GAAP financial measure. Our computation of EBITDA and Adjusted EBITDA may differ from computations of similarly titled measures of other companies.

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,
    Year Ended
December 31,
2014
 
    2014     2013    
         

(unaudited)

 
   

(in thousands)

 

Reconciliation of EBITDA and Adjusted EBITDA to net income:

     

Net income

    $169,187      $ 168,963      $ 179,066   

Add:

     

Depreciation, depletion, and amortization

    111,962        102,442        111,962   

Interest expense(1)

    13,509        11,342        3,630   
 

 

 

   

 

 

   

 

 

 

EBITDA

    294,658        282,747        294,658   

Add:

     

Impairment of oil and natural gas properties

    117,930        57,109        117,930   

Accretion of asset retirement obligations

    1,060        588        1,060   

Unrealized loss on commodity derivative instruments

           7,350          

Equity-based compensation expense(2)

    11,340        6,782        11,340   

Less:

     

Unrealized gain on commodity derivative instruments

    (39,283            (39,283
 

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

    $385,705      $ 354,576      $ 385,705   
 

 

 

   

 

 

   

 

 

 

 

(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 and subordinated 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 financial condition, results of operations, cash flows, and ability to make distributions 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 generate sufficient cash from operations after establishment of cash reserves to pay the minimum quarterly distribution on our common and subordinated units. If we make distributions, our preferred unitholders have priority with respect to rights to share in those distributions over our common and subordinated unitholders for so long as our preferred units are outstanding.

We may not generate sufficient cash from operations each quarter to pay the full minimum quarterly distribution to our common and subordinated unitholders. Our preferred unitholders have priority with respect to rights to share in distributions over our common and subordinated unitholders. Furthermore, our partnership agreement does not require us to pay distributions to our common and subordinated unitholders on a quarterly basis or otherwise. The amount of cash to be distributed each quarter will be determined by the board of directors of our general partner.

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 replacement capital expenditures, acquisitions, and participation in working interests. If over the long term we do not retain cash for replacement capital expenditures in amounts necessary to maintain our asset base, a portion of future distributions will represent a return of capital and the value of our common units will be adversely affected, which will eventually cause our cash distributions per unit to decrease. Withholding cash for our capital expenditures may have an adverse impact on the cash distributions 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 our cash generated from operations 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 assumptions underlying the forecast of our cash generated from operations for the twelve months ending March 31, 2016 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 distribution, which may cause the market price of our common units to decline materially.

 

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The amount of cash we distribute to holders of our units depends primarily on our cash generated from operations and not our profitability, which may prevent us from making cash distributions during periods when we record net income.

The amount of cash we distribute depends primarily upon our cash generated from operations 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 volatility of oil and natural gas prices due to factors beyond our control greatly affects our financial condition, results of operations, and cash distributions to unitholders.

Our revenues, operating results, cash distributions to unitholders, 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 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;

 

   

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 five years prior to December 31, 2014, the spot price for West Texas Intermediate light sweet crude oil, which we refer to as West Texas Intermediate (“WTI”) has ranged from a high of $113.39 per barrel (“Bbl”) in 2011 to a low of $53.45 per Bbl in 2014. During the same period, the Henry Hub spot market price of natural gas has ranged from a low of $1.82 per million British thermal units (“MMBtu”) in 2012 to a high of $8.15 per MMBtu in 2014. During 2014, the WTI spot price of oil ranged from $53.45 to $107.95 per Bbl and the Henry Hub spot market price of natural gas ranged from $2.74 to $8.15 per MMBtu. On December 31, 2013, the WTI spot price for oil was $98.17 per Bbl and the Henry Hub spot market price of natural gas was $4.31 per MMBtu. On December 31, 2014, the WTI spot price for oil was $53.45 per Bbl, and the Henry Hub spot market price of natural gas was $2.99 per MMBtu. Any

 

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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 distributions to unitholders. We may use various derivative instruments in connection with anticipated oil and natural 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 scenario 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, successful efforts method of accounting principles 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.

Oil prices have declined substantially from historical highs and may remain depressed for the foreseeable future. Approximately 55.4% of our 2014 oil and natural gas revenues were derived from oil and condensate sales. Any additional decreases in prices of oil may adversely affect our cash generated from operations, results of operations, financial position, and our ability to pay the minimum quarterly distribution on all of our outstanding common and subordinated units, perhaps materially.

The spot WTI market price at Cushing, Oklahoma has declined from $98.17 per Bbl on December 31, 2013 to $53.45 per Bbl on December 31, 2014. On March 9, 2015, the WTI oil price at Cushing, Oklahoma was $49.95 per Bbl. The reduction in price has been caused by many factors, including substantial increases in U.S. oil production and reserves from unconventional (shale) reservoirs, without an offsetting increase in demand. The International Energy Agency (“IEA”) forecasts continued U.S. production growth and a slowdown in global demand growth in 2015. This environment could cause the prices for oil to remain at current levels or to fall to lower levels. If prices for oil continue to remain depressed for lengthy periods, we may be required to write down the value of our oil and natural gas properties, and some of our undeveloped locations may no longer be economically viable. In addition, sustained low prices for oil will negatively impact the value of our estimated proved reserves and the amount that we are allowed to borrow under our bank credit facility and reduce the amounts of cash we would otherwise have available to pay expenses, fund capital expenditures, make distributions to our unitholders, and service our indebtedness.

Natural gas prices have declined substantially from historical highs and are expected to remain depressed for the foreseeable future. Approximately 70.1% of our 2014 total production was natural gas, on a “Btu-equivalent” basis. Any additional decreases in prices of natural gas may adversely affect our cash generated from operations, results of operations, financial position, and our ability to pay the minimum quarterly distribution on all of our outstanding common and subordinated units, perhaps materially.

During the seven years prior to December 31, 2014, natural gas prices at Henry Hub have ranged from a high of $13.31 per MMBtu in 2008 to a low of $1.82 per MMBtu in 2012. On December 31, 2014, the Henry Hub spot market price of natural gas was $2.99 per MMBtu. On March 9, 2015, the Henry Hub spot market price was $2.75 per MMBtu. The reduction in prices has been caused by many factors, including increases in natural 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, and some of our undeveloped

 

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locations may no longer be economically viable. In addition, sustained low prices for natural gas will negatively impact the value of our estimated proved reserves and the amount that we are allowed to borrow under our bank credit facility and reduce the amounts of cash we would otherwise have available to pay expenses, make distributions to our unitholders, and service our indebtedness.

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

We depend partly on acquisitions to grow our reserves, production, and cash generated from operations. 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 distributions to unitholders. 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 distributions to unitholders.

 

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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 generated from operations, these acquisitions may nevertheless result in a decrease in our cash distributions per unit. 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;

 

   

a decrease in our liquidity by using a significant portion of our cash generated from operations 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.

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 natural 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 year ended December 31, 2014, we received revenue from over 1,000 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;

 

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

 

   

the selection of technology;

 

   

the selection of counterparties for the 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 distributions to our unitholders. Sustained reductions in production by the operators on our properties may also adversely affect our results of operations and cash distributions to unitholders.

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 distributions to unitholders.

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 generated from operations and our ability to make distributions to our common and subordinated 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 generated from operations 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, results of operations, and cash distributions to our common and subordinated 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 undeveloped 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 distributions to unitholders 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

 

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be indicative of future or long-term production rates. Because of these uncertainties, we do not know if the 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 distributions to unitholders.

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 distributions to unitholders.

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 distributions to unitholders. 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, 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

 

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prepared by Pressler Petroleum Consultants, Inc. (“Pressler”), a third-party petroleum engineering firm, which conducted a detailed 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. Our estimates of proved reserves and related valuations as of December 31, 2014 were prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), a third-party petroleum engineering firm, which conducted a detailed review of all of our properties for the period covered by its reserve report using information provided by us. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling, testing, and production. Also, certain assumptions regarding future oil and natural gas prices, production levels, and operating and development costs may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves and future cash generated from operations. 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, 2014 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, 2014 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 distributions to unitholders.

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.

 

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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 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 distributions to unitholders 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 cash distributions to our unitholders.

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—Environmental Matters” 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 distributions to our 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 programs. These rules became effective in October 2012 and include NSPS standards for completions of hydraulically fractured natural 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 natural 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

 

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members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the SEC to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shale formations by means of hydraulic fracturing, and the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates.

Several states, including Texas, have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances 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.

Our credit facility has substantial restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions.

Our credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion based on their valuation of our proved reserves and their internal criteria. The borrowing base is redetermined at least semi-annually, and the available borrowing amount could be further decreased as a result of such redeterminations. Decreases in the available borrowing amount could result from declines in oil and natural gas prices, operating difficulties or increased costs, declines in reserves, lending requirements, or regulations or certain other circumstances. As of March 31, 2015, we had outstanding borrowings of $389.0 million and the aggregate maximum credit amounts of the lenders were $1.0 billion. As a result of the steep decline in oil and natural gas prices in of the second half of 2014, our borrowing base was decreased by the lenders under our credit facility in April 2015 to $600.0 million. A future decrease in our borrowing base could be substantial and could be to a level below our then-outstanding borrowings. Outstanding borrowings in excess of the borrowing base are required to be repaid in five equal monthly payments, or we are required to pledge other oil and natural gas properties as additional collateral, within 30 days following notice from the administrative agent of the new or adjusted borrowing base. If we do not have sufficient funds on hand for

 

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repayment, we may be required to seek a waiver or amendment from our lenders, refinance our credit facility, or sell assets, debt or common units. We may not be able to obtain such financing or complete such transactions on terms acceptable to us or at all. Failure to make the required repayment could result in a default under our credit facility, which could materially adversely affect our business, financial condition, results of operations, and distributions to our unitholders.

The operating and financial restrictions and covenants in our credit facility restrict, and any future financing agreements likely will restrict, our ability to finance future operations or capital needs, engage, expand, or pursue our business activities, or pay distributions. Our credit facility restricts, and any future credit facility likely will restrict, our ability to:

 

   

incur indebtedness;

 

   

grant liens;

 

   

make certain acquisitions and investments;

 

   

enter into hedging arrangement;

 

   

enter into transactions with our affiliates;

 

   

make distributions to our unitholders; or

 

   

enter into a merger, consolidation, or sale of assets.

Our credit facility restricts our ability to make distributions to unitholders or to repurchase units unless after giving effect to such distribution or repurchase, there is no event of default under our credit facility and our outstanding borrowings are not in excess of our borrowing base. While we currently are not restricted by our credit facility from declaring a distribution, we may be restricted from paying a distribution in the future.

We also are required to comply with certain financial covenants and ratios under the credit facility. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control, such as reduced oil and natural gas prices. If we violate any of the restrictions, covenants, ratios, or tests in our credit facility, a significant portion of our indebtedness may become immediately due and payable, our ability to make distributions will be inhibited and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our credit facility are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our credit facility, the lenders can seek to foreclose on our assets.

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

 

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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 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 distributions to unitholders.

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, natural 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 distributions to unitholders. 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 distributions to unitholders.

 

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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.

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.

Risks Inherent in an Investment in Us

We expect to distribute a substantial majority of the cash we generate from operations each quarter, which could limit our ability to grow and make acquisitions.

We expect to distribute a substantial majority of the cash we generate from operations each quarter. As a result, we will have limited cash generated from operations 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, 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. The incurrence of additional commercial borrowings or other debt to finance our growth would result in increased interest expense and required principal repayments, which, in turn, may reduce the cash that we have available 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 and subordinated unitholders for so long as our preferred units are outstanding.

Our partnership agreement generally provides that, during the subordination period, we will pay any distributions each quarter as follows: (i) first, to the holders of preferred units in an amount of approximately $25.00 per preferred unit, (ii) second, to the holders of common units, until each common unit has received the applicable minimum quarterly distribution plus any arrearages from prior quarters, and (iii) third, to the holders of subordinated units, until each subordinated unit has received the applicable minimum quarterly distribution. If the distributions to our common and subordinated unitholders exceed the applicable minimum quarterly distribution per unit, then such excess amounts will be distributed pro rata on the common and subordinated units as if they were a single class. The preferred units have a right to further participate (on an as-converted basis) in quarterly distributions in excess of the quarterly preferred distribution amount under certain circumstances that we do not expect to occur. Even if those additional distributions do occur, considering that the outstanding preferred units are convertible into only a relatively small number of our total outstanding common and subordinated units, we believe these additional distributions payable under those circumstances would not materially adversely affect the per unit distribution rate we would otherwise pay on our common and subordinated units. Our initial minimum quarterly distribution will be $1.05 per common and subordinated unit on an annualized basis (or $0.2625 per unit on a quarterly basis). We expect that we will distribute a substantial majority of the cash we generate from operations each quarter. However, the board of directors of our general partner could elect not to pay distributions for one or more quarters or at all. Please read “Cash Distribution Policy and Restrictions on Distributions.”

 

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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 any distribution 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 and subordinated unitholders for so long as our preferred units are outstanding. Please read “Description of Our Preferred Units—Distributions.”

Our minimum quarterly distribution provides the common unitholders a specified priority right to distributions over the subordinated unitholders if we pay distributions. It does not provide the common unitholders the right to require payment of any distributions.

Our partnership agreement does not require us to pay any distributions on our common and subordinated units. The provision providing for a minimum quarterly distribution merely provides the common unitholders with a specified priority right to distributions before the subordinated unitholders receive distributions, if distributions are made with respect to the common and subordinated units. In addition, we do not express any belief about our ability to pay distributions on our common and subordinated units with respect to periods after March 31, 2016.

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.

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 or our limited partners 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 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 limited partners in BSMC prior to this offering, their transferees, and persons who acquired such units with the prior approval of the board of directors of our general partner, may not vote on any matter.

 

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Actions taken by our general partner may affect the amount of cash generated from operations that is available for distribution to unitholders or accelerate the right to convert subordinated units.

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

 

   

amount and timing of asset purchases and sales;

 

   

cash expenditures;

 

   

borrowings;

 

   

entry into and repayment of current and future indebtedness;

 

   

issuance of additional units; and

 

   

the creation, reduction, or increase of reserves in any quarter.

In addition, borrowings by us do not constitute a breach of any duty owed by our general partner to our unitholders, including borrowings that have the purpose or effect of:

 

   

enabling holders of subordinated units to receive distributions; or

 

   

hastening the expiration of the subordination period.

In addition, our general partner may use an amount, initially equal to $137.6 million, which would not otherwise constitute cash generated from operations, in order to permit the payment of distributions on subordinated units. All of these actions may affect the amount of cash distributed to our unitholders and may facilitate the conversion of subordinated units into common units. Please read “How We Make Distributions.”

For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and our subordinated units, our partnership agreement permits us to borrow funds, which would enable us to make such distribution on all outstanding units. Please read “How We Make Distributions—Operating Surplus and Capital Surplus—Operating Surplus.”

We have a call right that may require common unitholders to sell their common units at an undesirable time or price.

If at any point in time prior to the end of the subordinated period we have acquired more than 80% of the total number of common units outstanding, we have the right, but not the obligation, to purchase all of the remaining common units at a price equal to the greater of (1) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (2) the highest per-unit price paid by us or any of our affiliates for common units during the 90-day period preceding the date such notice is first mailed. This limited call right is not exerciseable as long as any of our preferred units are outstanding, or at any time after the subordination period has ended.

Unitholders may have liability to repay distributions.

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.

 

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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.

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

The assumed initial public offering price of $20.00 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 $5.71 per common unit. Based on the assumed initial public offering price of $20.00 per common unit, common unitholders will incur immediate and substantial dilution of $14.29 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 and subordinated unitholder approval, which would dilute holders of common and subordinated 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 and subordinated unitholders in us immediately prior to the issuance will decrease;

 

   

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

 

   

the ratio of our taxable income to distributions may increase;

 

   

the relative voting strength of each previously outstanding common and subordinated 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.

Immediately after this offering, we will have 95,133,333 common units and 95,133,333 subordinated units outstanding, including the 22,500,000 common units that we are selling in this offering that may be resold immediately in the public market. All of the subordinated units will convert into common units at the end of the subordination period. All of the common units that are issued to our directors and executive officers will be subject to resale restrictions under a 180-day lock-up agreement with the underwriters. Under the terms of our partnership agreement, the limited partners of BSMC prior to this offering will be restricted from selling any common units they beneficially own, including any common units resulting from the conversion of such limited partners’ preferred units, for 45 days from the date of this prospectus. 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

 

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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. The limited partners of BSMC prior to this offering (including our executive officers and directors) will be restricted from selling with certain limited exceptions any subordinated units they beneficially own until permitted by the board of directors of our general partner in its sole discretion. 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. Immediately after this offering, there will be only 22,500,000 publicly traded common units. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. Unitholders may not be able to resell their common units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units, and limit the number of investors who are able to buy the common units.

The initial public offering price for our common units will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that 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.

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, as well as rules implemented by the SEC and the NYSE, 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 or reserve for our expenses, including the costs of being a publicly traded partnership. As a result, the amount of cash we have available to distribute to our unitholders will be affected by the costs associated with being a publicly traded partnership.

Following this offering, we will become subject to the public reporting requirements of the Exchange Act. We expect these requirements will increase our legal and financial compliance costs. For example, as a result of becoming a publicly traded partnership, we are required to 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 $1.5 million of incremental costs per year associated with being a publicly traded partnership; however, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than we currently estimate.

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, 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;

 

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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 have been approved to list our common units on the NYSE, subject to official notice of issuance. 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 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 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, or 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. 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.

 

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If you are not an Eligible Holder, your common units may be subject to redemption.

We have adopted certain requirements regarding those investors who may own our units. Eligible Holders are limited partners (a) whose, or whose owners’, federal income tax status does not have or is not reasonably likely to have a material adverse effect on the rates chargeable by us to customers and (b) whose ownership could not result in our loss of ownership in any material part of our assets, as determined by our general partner with the advice of counsel. If you are not an Eligible Holder, in certain circumstances as set forth in our partnership agreement, your units may be redeemed by us at 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. Please read “The Partnership Agreement—Ineligible Holders; Redemption.”

Tax Risks to Common Unitholders

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

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the 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 distributions 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 our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, or deductions would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, cash distributions to our unitholders 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 distributions to our unitholders. 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 generated from operations 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, the Obama administration’s budget proposal for fiscal year 2016 recommends that certain publicly traded partnerships earning income from activities related to fossil fuels be taxed as corporations beginning in 2021. From time to time, members of Congress propose and consider such

 

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substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. If successful, the Obama administration’s proposal or other similar proposals could eliminate 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 ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units. Any modification to U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the qualifying income requirement to be treated as a partnership for U.S. federal income tax purposes. For a discussion of the importance of our treatment as a partnership for federal income 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 distributions 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 distributions 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-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

 

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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 $421.9 million from this offering (based on an assumed initial offering price of $20.00 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, structuring fee, and offering expenses payable by us, to repay all of the indebtedness outstanding under our credit facility, which was $389.0 million as of March 31, 2015. We expect that at the time of completion of the offering, the outstanding balance on our credit facility will approximately equal the net proceeds of this offering. If the net proceeds should exceed the outstanding balance, this excess will be used to fund future capital expenditures.

The net proceeds from any exercise of the underwriters’ option to purchase additional common units (approximately $63.6 million, if exercised in full, based on an assumed initial offering price of $20.00 per common unit, the mid-point of the price range set forth on the cover of this prospectus, after deducting the estimated underwriting discount and structuring fee) 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 March 31, 2015, we had borrowings outstanding of $389.0 million under our credit facility. Indebtedness under our credit facility bore interest at a weighted average rate of approximately 2.4% during the year ended December 31, 2014. The maturity date of our credit facility is February 3, 2017. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—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 December 31, 2014:

 

   

on an actual basis for our predecessor; and

 

   

on a pro forma basis to reflect the formation transactions described under “Summary—Formation Transactions and Structure,” including this offering and the application of the net proceeds therefrom 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 December 31, 2014  
     Black Stone
Minerals, L.P.
Predecessor
     Black Stone
Minerals, L.P.
 
     Actual      Pro Forma  
     (unaudited)  
     (in thousands)  

Cash and cash equivalents

   $ 14,803       $ 42,670   
  

 

 

    

 

 

 

Credit facility

   $ 394,000       $ —     
  

 

 

    

 

 

 

Mezzanine equity

     

Black Stone Minerals Company, L.P.

     

Preferred units

     161,165         —     

Black Stone Minerals, L.P.

     

Preferred units

     —           161,165   
  

 

 

    

 

 

 

Total mezzanine equity

     161,165         161,165   
  

 

 

    

 

 

 

Equity

     

Black Stone Minerals Company, L.P.

     

Common units

     650,598         —     
  

 

 

    

 

 

 

Total equity

     650,598         —     

Black Stone Minerals, L.P.

     

General partner

     —           —     

Common units

     —           695,952   

Subordinated units

     —           368,926   
  

 

 

    

 

 

 

Noncontrolling interests

     2,619         2,619   
  

 

 

    

 

 

 

Total equity

     653,217         1,067,497   
  

 

 

    

 

 

 

Total capitalization

   $ 1,208,382       $ 1,228,662   
  

 

 

    

 

 

 

 

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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 unit immediately after this offering. Based on an initial public offering price of $20.00 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, structuring fee, and estimated offering expenses payable by us, our pro forma net tangible book value as of December 31, 2014 would have been approximately $1,067.5 million, or $5.71 per unit. This represents an immediate pro forma dilution of $14.29 per common unit to purchasers of common units in this offering. The following table illustrates this dilution on a per unit basis:

 

Assumed initial public offering price per common unit

      $ 20.00   

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

   $ 3.97      

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

     1.74      

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

        5.71   
  

 

 

    

 

 

 

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

      $ 14.29   
     

 

 

 

 

(1) Determined by dividing the pro forma net tangible book value of the contributed assets and liabilities by the number of our pro forma units to be issued to the limited partners of BSMC prior to this offering in exchange for their limited partner interests in BSMC in connection with the merger of BSMC with and into our subsidiary (71,212,190 common units and 93,271,956 subordinated units).
(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 pro forma units outstanding after this offering (93,712,190 common units and 93,271,956 subordinated units).

The following table sets forth, on the same pro forma basis as of December 31, 2014, the number of common units and subordinated units that we will issue and the total consideration contributed to us by the limited partners of BSMC prior to this offering and by the purchasers of our common units in this offering upon consummation of the transactions contemplated by this prospectus (dollars in thousands).

 

     Units     Total Consideration  
     Number      Percent     Amount     Percent  

Limited partners of BSMC prior to this offering(1)(2)

     164,484,146         88.0   $ 653,217        61.2

Purchasers in this offering

     22,500,000         12.0     414,280 (3)      38.8
  

 

 

    

 

 

   

 

 

   

 

 

 

Total

     186,984,146         100.0   $ 1,067,497        100.0
  

 

 

    

 

 

   

 

 

   

 

 

 

 

(1) Reflects the value of the net assets to be contributed to us by the limited partners of BSMC prior to this offering recorded at historical cost at December 31, 2014.
(2) Upon the completion of the transactions contemplated by this prospectus, the limited partners of BSMC prior to this offering will own all 93,271,956 of our subordinated units.
(3) Reflects the net proceeds of this offering, after deducting the underwriting discount, structuring fee, 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

Our partnership agreement generally provides that we will pay any distributions each quarter during the subordination period in the following manner:

 

   

first, to the holders of preferred units in an amount of approximately $25.00 per preferred unit;

 

   

second, to the holders of common units, until each common unit has received the applicable minimum quarterly distribution in the amounts specified below plus any arrearages from prior quarters; and

 

   

third, to the holders of subordinated units, until each subordinated unit has received the applicable minimum quarterly distribution.

If the distributions to our common and subordinated unitholders exceed the applicable minimum quarterly distribution per unit, then such excess amounts will be distributed pro rata on the common and subordinated units as if they were a single class. The preferred units have a right to further participate (on an as-converted basis) in quarterly distributions in excess of the quarterly preferred distribution amount under certain circumstances that we do not expect to occur. Even if those additional distributions do occur, considering that the outstanding preferred units are convertible into only a relatively small number of our total outstanding common and subordinated units, we believe these additional distributions payable under those circumstances would not materially adversely affect the per unit distribution rate we would otherwise pay on our common and subordinated units. The applicable minimum quarterly distribution for the periods specified below is as follows:

 

Four Quarters Ending March 31,

   Minimum Quarterly Distribution
(per unit)
   Per Quarter    Annualized

2016

   $0.2625    $1.05

2017

   $0.2875    $1.15

2018

   $0.3125    $1.25

2019 and thereafter

   $0.3375    $1.35

After March 31, 2019, the minimum quarterly distribution shall be the same as it is for each of the four quarters ending March 31, 2019. Our initial minimum quarterly distribution will be $1.05 per common and subordinated unit on an annualized basis (or $0.2625 per common and subordinated unit on a quarterly basis). The minimum quarterly distribution does not provide the common unitholders the right to require payment of any distributions. It merely reflects the specified priority right of our common unitholders to distributions before the subordinated unitholders receive distributions, if distributions are paid.

The amount of cash to be distributed each quarter will be determined by the board of directors of our general partner following the end of that quarter after a review of our cash generated from operations for such quarter. We expect that we will distribute a substantial majority of the cash generated from our operations each quarter. The cash generated from operations for each quarter will generally equal our Adjusted EBITDA for the quarter, less cash needed for debt service, other contractual obligations, fixed charges, and reserves for future operating or capital needs that the board of directors may determine are appropriate. For a demonstration of how cash generated from operations available for distribution on common and subordinated units will be determined, please see the tables under “Pro Forma Cash Generated from Operations for the Year Ended December 31, 2014”

 

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and “Estimated Cash Generated from Operations for the Twelve Months Ending March 31, 2016.” It is our intent, for at least the next several years, to finance most of our acquisitions and working-interest capital needs with cash generated from operations, 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 cash generated from operations to be insufficient to pay distributions at the applicable minimum quarterly distribution level on our common and subordinated units. The board of directors of our general partner can change the amount of the quarterly distributions, if any, 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. Therefore, the fact that our partnership agreement includes the concept of a minimum quarterly distribution does not provide any assurance that a distribution will be paid on the common units, nor are we providing or making any forecast beyond the twelve months ending March 31, 2016 as to our ability to pay the applicable minimum quarterly distribution on the common units. If we make distributions, our preferred unitholders have priority with respect to rights to share in those distributions over our common and subordinated unitholders for so long as our preferred units are outstanding.” For a description of the relative rights and privileges of our preferred units to distributions, please read “—Preferred Units.”

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. Like a number of other master limited partnerships, we are required by our partnership agreement to retain cash from our operations in an amount equal to our estimated replacement capital requirements. We believe the level of our initial distribution rate will allow us to retain in our business sufficient cash generated from our operations to satisfy our replacement capital expenditures needs and to fund a portion of our growth capital expenditures. The board of directors of our general partner will be responsible for establishing the amount of our estimated replacement capital expenditures following this offering.

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 by the board of directors of our general partner and is subject to certain restrictions, including the following:

 

   

Our common and subordinated 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 and subordinated unitholders will receive distributions only to the extent the distribution amount exceeds distributions that are required to be paid to our preferred unitholders.

 

   

Our credit facility restricts our distributions if there is a default under our credit facility or if our borrowing base is lower than the outstanding loans under our credit facility. Among other covenants, our credit facility requires we maintain a ratio of total debt to EBITDAX of 3.50:1.00 or less and a current ratio of 1.00:1.00 or greater. If we are unable to comply with these financial covenants or if we breach any other covenant under our credit facility or any future debt agreements, we could be prohibited from making distributions notwithstanding our stated distribution policy.

 

   

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.

 

   

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.

 

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We may lack sufficient cash to pay distributions to our unitholders due to shortfalls in cash generated from operations 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 substantial majority 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.

Any distributions paid on our common and subordinated units with respect to a quarter will be paid within 60 days after the end of such quarter. Our first distribution will be for the period from the closing of this offering through June 30, 2015, and our partnership agreement will prorate the minimum quarterly distribution based on the actual length of the period. Please read “Cash Distribution Policy and Restrictions on Distributions.”

Minimum Quarterly Distribution

Upon completion of this offering, our partnership agreement provides for an initial minimum quarterly distribution of $0.2625 per unit, or $1.05 per unit on an annualized basis, on all of the common and subordinated units outstanding through March 31, 2016. The payment of the full initial minimum quarterly distribution on all of the common units and subordinated units to be outstanding after completion of this offering would require us to have cash generated from operations available for distribution of approximately $202.6 million on an annualized basis. Our ability to make cash distributions at the applicable minimum quarterly distribution rate will be subject to the factors described above under “—General—Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.” The table below sets forth the amount of common units and subordinated units that will be outstanding after this offering, assuming the underwriters do not exercise their option to purchase additional common units, and the cash generated from operations available for distribution needed to pay the aggregate initial minimum quarterly distribution on all of such units for a single fiscal quarter and a four-quarter period (dollars in thousands):

 

     Number of
Units(1)
     Aggregate Minimum Quarterly Distributions for the
Three Months Ending
     Annualized  
        March 31,
2016
     December 31,
2015
     September 30,
2015
     June 30,
2015
    

Common units issued in this offering

     22,500,000       $ 5,907       $ 5,906       $ 5,906       $ 5,906       $ 23,625   

Common units issued or issuable as equity-based compensation(2)

     1,954,939         514         513         513         513         2,053   

Common units issued in the merger(3)

     72,633,333         19,067         19,066         19,066         19,066         76,265   

Subordinated units issued in the merger(4)

     95,133,333         24,974         24,972         24,972         24,972         99,890   

Common units to be issued upon conversion of preferred units as of January 1, 2016

     1,193,294         313         —           —           —           313   

Subordinated units to be issued upon conversion of preferred units as of January 1, 2016

     1,562,946         410         —           —           —           410   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     194,997,845       $ 51,185       $ 50,457       $ 50,457       $ 50,457       $ 202,556   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) Reflects conversion of preferred units into common and subordinated units on January 1, 2016, which will be entitled to the minimum quarterly distribution for the three months ending March 31, 2016 and thereafter.
(2) Includes 60,000 common units, 936,661 restricted common units, and 958,278 common-unit-settled performance units expected to be issued as equity-based compensation after the offering.

 

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(3) Includes 1,190,148 common units to be issued in the merger resulting from the conversion of preferred units into BSMC common units in January 2015 and 230,983 restricted common units (net of withholding for vesting awards) to be issued in the merger resulting from equity-based compensation awards granted in February 2015.
(4) Includes 1,558,826 subordinated units to be issued in the merger resulting from the conversion of preferred units into BSMC common units in January 2015 and 302,536 restricted subordinated units (net of withholding for vesting awards) to be issued in the merger resulting from equity-based compensation awards granted in February 2015.

The preferred units are convertible into common units and subordinated units. If all of our preferred units converted as of March 31, 2015, these units would convert into 3,579,881 common and 4,688,839 subordinated units. If our preferred units fully converted into common and subordinated units as of March 31, 2015, we would need $8.0 million of additional cash to pay the applicable minimum quarterly distribution on all of our common and subordinated units outstanding after this offering, which would be more than offset by the $10.8 million of distributions on the preferred units. If the underwriters exercise their option to purchase additional common units, we will need $3.5 million additional cash to pay the applicable minimum quarterly distribution on our common units outstanding after the offering.

Further, our partnership agreement provides for an increase in the applicable minimum quarterly distribution on each of April 1, 2016, 2017, and 2018. To fund those increases in the minimum quarterly distribution on our outstanding common and subordinated units, our cash generated from operations available for distribution, assuming (i) no change in distribution coverage, (ii) the preferred units fully converted on March 31, 2015, (iii) the underwriters exercise their option to purchase additional common units in full, and (iv) no additional common or subordinated units are issued, would have to increase by $23.2 million, $46.4 million, and $69.6 million for each of the twelve months ending March 31, 2017, 2018, and 2019, respectively, compared to the twelve months ending March 31, 2016.

The table below sets forth the amounts required to pay the minimum quarterly distribution of $0.3375 applicable for the twelve months ending March 31, 2019, assuming (unlike the immediately preceding table) that (i) the preferred units have fully converted and (ii) the underwriters exercised their option to purchase additional units to cover over-allotments in full with respect to this offering (dollars in thousands):

 

     Number of Units      Aggregate Minimum Quarterly Distributions for the
Three Months Ending
     Annualized  
        March 31,
2019
     December 31,
2018
     September 30,
2018
     June 30,
2018
    

Common units issued in this offering

     25,875,000       $ 8,732       $ 8,733       $ 8,733       $ 8,733       $ 34,931   

Common units issued or issuable as equity-based compensation

     1,954,939         659         660         660         660         2,639   

Common units issued in the merger

     72,633,333         24,513         24,514         24,514         24,514         98,055   

Subordinated units issued in the merger

     95,133,333         32,109         32,107         32,107         32,107         128,430   

Common units issuable upon conversion of preferred units

     3,579,881         1,209         1,208         1,208         1,208         4,833   

Subordinated units issuable upon conversion of preferred units

     4,688,839         1,584         1,582         1,582         1,582         6,330   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     203,865,325       $ 68,806       $ 68,804       $ 68,804       $ 68,804       $ 275,218   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

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Subordinated Units

The limited partners of BSMC prior to this offering will initially own all of our subordinated units. The principal difference between our common and subordinated units is that, for any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distribution until the common units have received the applicable minimum quarterly distribution for such quarter plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages. When the subordination period ends, all of the subordinated units will convert into common units on a one-to-one basis.

Our common unitholders are only entitled to arrearages in the payment of the minimum quarterly distribution from prior quarters during the subordination period. To the extent we have cash generated from operations available for distribution in any quarter during the subordination period in excess of the amount necessary to pay the applicable minimum quarterly distribution to holders of our common units, we will use this excess cash to pay any distribution arrearages on the common units related to prior quarters before any cash distribution is made on our subordinated units. Please read “How We Make Distributions—Subordination Period.”

Preferred Units

Prior to our liquidation, and while any of our preferred units remain outstanding, cash or other property of the partnership will be distributed 100% to our preferred unitholders until the aggregate Unpaid Preferred Yield (as defined below) of each preferred unit accrued through the last day of the immediately preceding calendar quarter has been reduced to zero. Under certain limited circumstances, the preferred units have a right to increased priority distributions, and under other limited circumstances, the preferred units also have a right to further participate in distributions. We believe it is unlikely any such distribution will be required, and if they are required, we believe they would not materially adversely affect the per unit distribution rate we would otherwise make on our common and subordinated units.

The terms “Preferred Yield” and “Unpaid Preferred Yield” have the following meanings:

“Preferred Yield” means a yield on the outstanding preferred units equivalent to a 10% per annum interest rate (subject to adjustment following certain events of default by the partnership) on an initial investment of $1,000, calculated based on a 365-day year and compounded quarterly.

“Unpaid Preferred Yield” means, with respect to each preferred unit and as of any date of determination, an amount equal to the excess, if any, of (a) the cumulative Preferred Yield from the closing of this offering through the date established, over (b) the cumulative amount of distributions made as of the date established in respect of the preferred unit.

For more information about our preferred units, please read “Description of Our Preferred Units.”

Pro Forma Cash Generated from Operations for the Year Ended December 31, 2014

The pro forma financial statements, upon which pro forma cash generated from operations 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 generated from operations 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 generated from operations in the manner described in the table below. As a result, the amounts of pro forma cash generated from operations should only be viewed as a general indication of our cash generated from operations had the formation transactions contemplated in this prospectus been consummated in an earlier period.

Following the completion of this offering, we estimate that we will incur $1.5 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 unitholders, tax return and Schedule K-1 preparation and distribution, Sarbanes-Oxley Act compliance, NYSE listing, independent registered public accounting firm fees, legal fees, investor-relations activities, registrar and transfer agent fees, director-and-officer insurance, and additional compensation.

 

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The following table illustrates, on a pro forma basis for the year ended December 31, 2014, the amount of cash generated from operations that would have been available for distribution to our common and subordinated unitholders and reinvestment in our business, assuming that the formation transactions contemplated in this prospectus had been consummated on January 1, 2014.

Black Stone Minerals, L.P.

Pro Forma Cash Generated from Operations

 

     Year Ended
    December 31,    
2014
 
     (unaudited)  
     (in thousands)  

Revenue:

  

Oil and condensate sales(1)

   $ 257,390   

Natural gas and natural gas liquids sales(1)

     207,456   

Gain on commodity derivative instruments

     37,336   

Lease bonus and other income

     46,139   
  

 

 

 

Total revenue

     548,321   
  

 

 

 

Operating (income) expense:

  

Lease operating expense and other

     23,288   

Production and ad valorem taxes

     49,575   

Depreciation, depletion, and amortization

     111,962   

Impairment of oil and natural gas properties(2)

     117,930   

General and administrative

     62,765   

Accretion of asset retirement obligations

     1,060   

Loss on disposal of assets

     32   
  

 

 

 

Total operating expense

     366,612   
  

 

 

 

Income from operations

     181,709   

Other income (expense):

  

Interest and investment income

     28   

Interest expense(3)

     (3,630

Other income

     959   
  

 

 

 

Total other expense

     (2,643
  

 

 

 

Pro forma net income

     179,066   
  

 

 

 

Adjustments to reconcile to pro forma Adjusted EBITDA:

  

Add:

  

Depreciation, depletion, and amortization

     111,962   

Interest expense

     3,630   
  

 

 

 

Pro forma EBITDA(4)

     294,658   

Add:

  

Impairment of oil and natural gas properties

     117,930   

Accretion of asset retirement obligations

     1,060   

Equity-based compensation expense(5)

     11,340   

Less:

  

Unrealized gain on commodity derivative instruments

     (39,283
  

 

 

 

Pro forma Adjusted EBITDA(4)

   $     385,705   

 

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     Year Ended
    December 31,    
2014
 
    

(unaudited)

 
    

(in thousands, except
per unit data)

 

Adjustments to reconcile to pro forma cash generated from operations:

  

Less:

  

Deferred revenue

     (2,589

Incremental general and administrative(6)

     (1,475

Cash interest expense(3)

     (2,665

Capital expenditures(7)

     (101,110
  

 

 

 

Pro forma cash generated from operations

     277,866   

Less:

  

Cash paid to noncontrolling interests(8)

     (294

Preferred unit distributions(9)(10)

     (15,720
  

 

 

 

Pro forma cash generated from operations available for distribution on common and subordinated units and reinvestment in our business

     261,852   

Initial minimum quarterly distribution per common and subordinated unit

     1.05   

Aggregate distributions to:

  

Common units issued in this offering

     23,625   

Common units issued or issuable as equity-based compensation

     2,053   

Common units issued in the merger

     75,015   

Subordinated units issued in the merger

     98,254   
  

 

 

 

Total distributions on common and subordinated units(10)

     198,947   
  

 

 

 

Excess(11)

   $ 62,905   
  

 

 

 

 

(1) Includes revenues from our mineral and royalty interests and working interests.
(2) The impairment primarily resulted from decreasing commodity prices and changes in 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) Interest expense includes cash expenses of commitment fees and agency fees and non-cash amortization of debt issuance costs. Cash interest expense does not include non-cash amortization of debt issuance costs.
(4) For more information, please read “Summary—Summary Historical and Pro Forma Financial Data—Non-GAAP Financial Measures.”
(5) Represents compensation expense that is settled in common and subordinated units and would not reduce the amount of cash generated from operations.
(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. Does not include expected nonrecurring expenses of approximately $1.4 million related to compliance with the Sarbanes-Oxley Act.
(7) Our capital expenditures during 2014 were funded with cash generated from our operations.
(8) Reflects cash distributions made to unaffiliated third-party limited partners in a consolidated, but not wholly owned, partnership. For additional information, please read Note 16 to the consolidated financial statements of BSMC included elsewhere in this prospectus.
(9) Reflects distributions paid on our preferred units assuming no optional conversion. For more information regarding conversion of the preferred units, please read “Description of Our Preferred Units—Conversion of the Preferred Units.” If all outstanding preferred units had been converted to common and subordinated units at the beginning of the period, no preferred unit distributions would have been paid. Pro forma cash generated from operations available for distribution on common and subordinated units would have increased to $277.6 million for the year ended December 31, 2014 and total distributions on common and subordinated units would have increased by $11.6 million.
(10) Does not reflect the conversion of 35,589 preferred units into 1,190,148 common units and 1,558,826 subordinated units on January 1, 2015, which would eliminate $3.9 million in preferred unit distributions, increase the estimated quarterly distributions to common and subordinated units by $2.9 million for the same period, and increase the excess by $1.0 million.
(11) 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 4,770,029 common and 6,247,665 subordinated units as of the year ended December 31, 2014, the excess for the year ended December 31, 2014 would have increased to $63.5 million.

 

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If we do not distribute cash from operations in any quarter sufficient to pay the full applicable minimum quarterly distribution on all common units, then holders of the subordinated units will not be entitled to receive any distribution until the common units have received the applicable minimum quarterly distribution for such quarter plus any arrearages in the payment of the applicable minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages.

The following table illustrates the excess in the amount of cash generated from operations available for distribution on common and subordinated units and reinvestment in our business on a pro forma basis for the year ended December 31, 2014 assuming (i) the minimum quarterly distribution per unit was $0.3375, which is the minimum quarterly distribution applicable after March 31, 2018 and (ii) all preferred units outstanding as of December 31, 2014 have converted into 4,770,029 common units and 6,247,665 subordinated units pursuant to their terms.

 

     Pro Forma
Year Ended
December 31, 2014
 
     (in thousands,
except per unit data)
 

Pro forma cash generated from operations available for distribution on common and subordinated units and reinvestment in our business

   $ 277,572   

Minimum quarterly distribution per common and subordinated unit

     1.35   

Aggregate distributions to:

  

Common units issued in this offering

     30,375   

Common units issued or issuable as equity-based compensation

     2,639   

Common units issued in the merger

     98,055   

Subordinated units issued in the merger

     128,430   

Common units issuable upon conversion of preferred units

     6,440   

Subordinated units issuable upon conversion of preferred units

     8,434   
  

 

 

 

Total distributions on common and subordinated units

     274,373   
  

 

 

 

Excess

   $ 3,199   
  

 

 

 

Based on the immediately preceding table and assuming the underwriters’ option to purchase additional common units to cover over-allotments was exercised in full, we would have had a shortfall of $1.4 million, and we would have been able to pay 100% of the aggregate minimum quarterly distribution on all common units and 99.0% of the aggregate minimum quarterly distribution on all the subordinated units.

Based on our preliminary operating results and assuming the formation transactions occurred as of January 1, 2015, we believe that we will generate sufficient cash from operations to pay the aggregate initial minimum quarterly distributions on all common units and subordinated units outstanding at the completion of this offering for the three months ended March 31, 2015.

Estimated Cash Generated from Operations for the Twelve Months Ending March 31, 2016

For the twelve months ending March 31, 2016, we estimate that we will generate $241.6 million of cash from operations. In “—Assumptions and Considerations” below, we discuss the major assumptions underlying this estimate. The cash generated from operations discussed in the forecast should not be viewed as management’s projection of the actual cash that we will generate during the twelve months ending March 31, 2016. We can give you no assurance that our assumptions will be realized or that we will generate any cash, in which event we will not be able to pay the full initial minimum quarterly cash distribution on all of our common and subordinated units during such period.

When considering our ability to generate cash and how we calculate forecasted cash generated from operations, 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 cash generated from operations to vary significantly from our estimates.

 

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Management has prepared the prospective financial information set forth in the table below to present our expectations regarding our ability to generate $241.6 million of estimated cash generated from operations for the twelve months ending March 31, 2016. 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 or updates we may make to 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 cash generated from operations to allow us to pay the full initial minimum quarterly distribution on all of our outstanding common and subordinated units during the twelve months ending March 31, 2016 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.

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.

 

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The following table illustrates the amount of cash that we estimate that we will generate for the twelve months ending March 31, 2016 that would be available for distribution to our common and subordinated unitholders and reinvestment in our business.

Black Stone Minerals, L.P.

Estimated Cash Generated from Operations

 

     Twelve Months
Ending March 31,

2016
 
     (unaudited)  
     (in thousands, except per unit data)  

Revenue:

  

Oil and condensate sales

   $ 145,272   

Natural gas and natural gas liquids sales

     125,644   

Gain on commodity derivative instruments

     33,587   

Lease bonus and other income

     40,200   
  

 

 

 

Total revenue

     344,703   
  

 

 

 

Operating expense:

  

Lease operating expense and other

     21,058   

Production and ad valorem taxes

     24,377   

Depreciation, depletion, and amortization

     113,684   

General and administrative

     78,007   

Accretion of asset retirement obligations

     1,060   
  

 

 

 

Total operating expense

     238,186   
  

 

 

 

Income from operations

     106,517   

Other expense:

  

Interest expense

     (4,119
  

 

 

 

Total other expense

     (4,119
  

 

 

 

Net income

     102,398   
  

 

 

 

Adjustments to reconcile to Adjusted EBITDA:

  

Add:

  

Depreciation, depletion, and amortization

     113,684   

Interest expense

     4,119   
  

 

 

 

EBITDA(1)

     220,201   

Add:

  

Accretion of asset retirement obligations

     1,060   

Equity-based compensation expense(2)

     24,318   
  

 

 

 

Adjusted EBITDA(1)

     245,579   

Adjustments to reconcile to estimated cash generated from operations:

  

Add:

  

Borrowings to fund future capital expenditures(3)

     47,027   

Less:

  

Deferred revenue(4)

     (863

Cash interest expense

     (3,143

Capital expenditures

     (47,027
  

 

 

 

Estimated cash generated from operations

     241,573   

Less:

  

Cash paid to noncontrolling interests(5)

     (179

Preferred unit distributions(6)(7)

     (10,844
  

 

 

 

Estimated cash generated from operations available for distribution on common and subordinated units and reinvestment in our business

     230,550   

Initial minimum quarterly distribution per common and subordinated unit

     1.05   

Estimated annual distributions to:

  

Common units issued in this offering

     23,625   

Common units issued or issuable as equity-based compensation

    
2,053
  

Common units issued in the merger

     76,265   

Subordinated units issued in the merger

     99,890   

Common units to be issued upon conversion of preferred units as of January 1, 2016(7)

     313   

Subordinated units to be issued upon conversion of preferred units as of January 1, 2016(7)

     410   
  

 

 

 

Total distributions on common and subordinated units

     202,556   
  

 

 

 

Excess(8)

   $ 27,994   
  

 

 

 

 

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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 and subordinated units and would not impact estimated cash generated from operations.
(3) Assumes borrowings under our credit facility are incurred when the capital expenditures are made.
(4) Represents working-interest owners’ recoupment of advance royalty payments, which results in a reduction of cash received from production revenues.
(5) Reflects cash distributions made to unaffiliated third-party limited partners in a consolidated, but not wholly owned, partnership. For additional information, please read Note 16 to the consolidated financial statements of BSMC included elsewhere in this prospectus.
(6) Reflects distributions paid on our preferred units assuming no optional conversion. For more information regarding conversion of the preferred units, please read “Description of Our Preferred Units—Conversion of the Preferred Units.” If all outstanding preferred units had been converted to common and subordinated units at the beginning of the period, no preferred unit distributions would have been paid, estimated cash generated from operations available for distribution on common and subordinated units would have increased to $241.4 million, and total distributions on common and subordinated units would have increased by $8.0 million for the twelve months ending March 31, 2016.
(7) Reflects conversion of 35,684 preferred units into 1,193,294 common units and 1,562,946 subordinated units on January 1, 2016, which eliminates $1.0 million of preferred unit distributions for the quarter ending March 31, 2016, increases the estimated quarterly distributions to common and subordinated units by $0.7 million for the same period, and increases the excess by $0.3 million.
(8) 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 3,579,881 common and 4,688,839 subordinated units as of March 31, 2015, the excess for the twelve months ending March 31, 2016 would have decreased to $27.3 million. In addition, assuming the underwriters’ option to purchase additional common units to cover over-allotments is not exercised and all of our preferred units converted into common and subordinated units as of March 31, 2015, the excess for the twelve months ending March 31, 2016 would have increased to $30.9 million.

If we do not distribute cash from operations in any quarter sufficient to pay the full applicable minimum quarterly distribution on all common units, then holders of the subordinated units will not be entitled to receive any distribution until the common units have received the applicable minimum quarterly distribution for such quarter plus any arrearages in the payment of the applicable minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages.

The following table illustrates the shortfall in our estimated amount of cash generated from operations available for distribution on common and subordinated units and reinvestment in our business for the twelve months ending March 31, 2016 assuming (i) the minimum quarterly distribution per unit was $0.3375, which is the minimum quarterly distribution applicable after March 31, 2018 and (ii) all preferred units outstanding as of March 31, 2015 have converted into 3,579,881 common units and 4,688,839 subordinated units pursuant to their terms.

 

     Estimated
Twelve Months Ending
March 31, 2016
 
     (in thousands,
except per unit data)
 

Estimated cash generated from operations available for distribution on common and subordinated units and reinvestment in our business

   $ 241,394   

Minimum quarterly distribution per common and subordinated unit

     1.35   

Aggregate distributions to:

  

Common units issued in this offering

     30,375   

Common units issued or issuable as equity-based compensation

     2,639   

Common units issued in the merger

     98,055   

Subordinated units issued in the merger

     128,430   

Common units issuable upon conversion of preferred units

     4,833   

Subordinated units issuable upon conversion of preferred units

     6,330   
  

 

 

 

Total distributions on common and subordinated units

     270,662   
  

 

 

 

Shortfall

   $ (29,268
  

 

 

 

Based on the immediately preceding table and assuming the underwriters’ option to purchase additional common units to cover over-allotments was exercised in full, we would have had a shortfall of $33.8 million, and we would have been able to pay 100% of the aggregate minimum quarterly distribution on all common units and 74.9% of the aggregate minimum quarterly distribution on all the subordinated units.

 

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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 estimated cash from operations in an amount sufficient to allow us to pay the full initial minimum quarterly distribution on all of our outstanding common and subordinated units during the twelve months ending March 31, 2016. In addition, we expect that the cash generated from operations in excess of the amount necessary for us to pay the applicable minimum quarterly distribution on our common and subordinated units will be more than enough to allow us to reserve an amount equal to our estimated replacement capital as required by our partnership agreement. The board of directors of our general partner will be responsible for establishing the amount of our estimated replacement capital expenditures following this offering.

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 generated from operations 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 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.

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, 2014 and on a forecasted basis for the twelve months ending March 31, 2016:

 

     Twelve Months
Ending March 31,
2016
    Year Ended
December 31,
2014
 
     (unaudited)  

Aggregate production:

    

Oil and condensate (MBbls)

     2,918        3,005   

Natural gas (MMcf)

     40,264        42,273   
  

 

 

   

 

 

 

Combined volumes (MBoe)

     9,629        10,051   

Average daily production (MBoe/d)

     26.3        27.5   

Percentage attributable to mineral and royalty interests:

    

Oil and condensate

     74     75

Natural gas

     63     65

For additional information on our historical production, please read “—Historical and Forecast Asset Production.”

 

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The following table illustrates the relationship between average oil and natural gas realized prices and the average WTI oil and Henry Hub natural gas prices on a pro forma basis for the year ended December 31, 2014 and on a forecasted basis for the twelve months ending March 31, 2016:

 

     Twelve Months
Ending March 31,
2016
     Year Ended
December 31,
2014
 
     (unaudited)  

Average benchmark prices(1):

     

WTI oil price ($/Bbl)

   $ 54.24       $ 93.16   

Henry Hub natural gas price ($/Mcf)

   $ 2.85       $ 4.37   

Realized prices(2):

     

Realized oil and condensate price ($/Bbl)

   $ 49.78       $ 85.65   

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

   $ 3.12       $ 4.91   

 

(1) For historical periods, average prices were calculated using daily spot prices provided by the EIA. For the twelve months ending March 31, 2016, the NYMEX average price curves as of April 1, 2015 were used.
(2) Excluding cash settlement on commodity derivative instruments.
(3) 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 of natural gas liquids (“NGLs”) associated with the production of natural gas on our acreage. As such, the realized prices for natural gas account for all sales attributable to NGLs. The oil and condensate production volumes and natural gas production volumes do not include NGL volumes.

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 twelve months ending March 31, 2016, 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 twelve months ending March 31, 2016 will be $188.3 million, compared to $340.4 million on a pro forma basis for the year ended December 31, 2014. We estimate our oil and natural gas revenue resulting from our non-operated working interests for the twelve months ending March 31, 2016 will be $82.6 million compared to $124.4 million on a pro forma basis for the year ended December 31, 2014.

We forecast a decline in our mineral-and-royalty-interest and working-interest revenues primarily due to the anticipation of lower realized prices for oil and natural gas for the twelve months ending March 31, 2016. Another contributing factor to the reduction in our mineral-and-royalty interest revenues is slightly lower production from our mineral-and-royalty interest properties stemming from a decline in operator drilling activity on some of our acreage, despite increased forecasted production from our acreage in the Eagle Ford Shale and the Haynesville/Bossier and Wilcox plays. While our working-interest revenues are decreasing, we expect higher overall production from our working-interest properties driven by increases in the Haynesville/Bossier and Wilcox plays. For additional information on the effect of changes in prices and production volumes, please read “—Sensitivity Analysis.”

Lease Bonus and Other Income. When we lease our mineral interests, we generally receive an upfront cash payment, or a lease bonus. Lease bonus and other income is estimated to be $40.2 million for the twelve months ending March 31, 2016. Approximately 83% of our mineral acreage was unleased as of December 31, 2014, 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, 2014 was $46.1 million.

 

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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, depreciation, depletion, 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 twelve months ending March 31, 2016 will be $21.1 million as compared to $23.3 million on a pro forma basis for the year ended December 31, 2014.

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 twelve months ending March 31, 2016 will be $24.4 million, compared to $49.6 million on a pro forma basis for the year ended December 31, 2014. The reduction in production and ad valorem taxes is driven by the decline in expected revenues as a result of the current forecast for oil and natural gas prices.

Depreciation, Depletion, 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 depreciation, depletion, and amortization for the twelve months ending March 31, 2016 will be $113.7 million, compared to $112.0 million on a pro forma basis for the year ended December 31, 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. We do not forecast any impairment expense for the twelve months ending March 31, 2016; however, due to the recent decline in commodity prices and the possibility of future commodity price deterioration, we may have impairment. We recognized $117.9 million of impairment on a pro forma basis for the year ended December 31, 2014. Our impairment analysis is performed during the preparation of our annual financial statements as described in Note 5 to the audited consolidated financial statements.

General and Administrative. We estimate that our general and administrative expenses for the twelve months ending March 31, 2016 will be $78.0 million, compared to $62.8 million on a pro forma basis for the year ended December 31, 2014. General and administrative expenses for the twelve months ending March 31, 2016 include $1.5 million of recurring general and administrative expenses we expect to incur as a result of becoming a publicly traded partnership. They do not include expected nonrecurring expenses of approximately $1.4 million related to compliance with the Sarbanes-Oxley Act. General and administrative expenses for the twelve months ending March 31, 2016 also include $14.5 million of incremental compensation expense we expect to incur in connection with our long-term incentive plan, which comprises $13.8 million of equity-based compensation and $0.7 million of cash compensation. The incremental equity compensation is expected to vest over the next five years and is partially contingent upon meeting certain performance measures related to our growth. Please read “Executive Compensation and Other Information.”

 

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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 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 twelve months ending March 31, 2016 will be $1.1 million, compared to $1.1 million on a pro forma basis for the year ended December 31, 2014.

Interest Expense. We estimate that interest expense, which includes amortization of debt issue costs, commitment fees, and agency fees, will be $4.1 million for the twelve months ending March 31, 2016 as compared to $3.6 million on a pro forma basis for the year ended December 31, 2014. We do not expect to have borrowings outstanding under our credit facility in excess of our capital expenditures during the twelve months ending March 31, 2016. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—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 our 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 costless collars and fixed-price hedges. We do not enter into derivative instruments for speculative purposes. In addition, we currently 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 current hedge volumes are limited to projected proved developed producing reserve (“PDP”) production as determined by our most current reserve report. We have traditionally employed a strategy of hedging a high percentage of our 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 that period. As we currently 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 in any given year. For example, as of January 1, 2014, we had hedges in place for 81.9% of our projected PDP production through December 31, 2014 on a Boe basis, which represented 59.9% of our actual production for the year. Taking into account new hedges executed during 2014, we had hedges in place for 68.5% of our actual production for 2014.

For purposes of this forecast, we have assumed that we do not enter into additional commodity derivative contracts after April 1, 2015. Our existing hedges will cover 18.3 MBoe/d, or approximately 69.4% of our total forecasted production of MBoe/d for the twelve months ending March 31, 2016. We have assumed that the commodity derivative contracts will consist of costless collars and fixed-price hedges for oil and natural gas. The table below shows the volumes, percentage of forecasted production, and prices we have assumed for our commodity derivative contracts for the twelve months ending March 31, 2016:

 

     Costless Collars  
     Hedged
Volumes
     % of
Forecasted
Production
    Weighted-
Average Floor
Price
     Weighted-
Average Ceiling
Price
 
     (unaudited)  

Oil and condensate (MBbls)

     500         17.1   $ 85.28       $ 102.23   

Natural gas (MMcf)

     4,040         10.0   $ 3.73       $ 4.64   

 

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     Fixed-Price Hedges  
     Hedged
Volumes
       % of
Forecasted
Production
       Weighted-
Average Fixed
Price
 
     (unaudited)  

Oil and condensate (MBbls)

     1,454           49.8      $ 58.17   

Natural gas (MMcf)

     24,330           60.4      $ 3.16   

Capital Expenditures

Although we may make acquisitions during the twelve months ending March 31, 2016, 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 closings of any such acquisitions or the commencement of our receipt of revenues therefrom.

Historically we have not distinguished between replacement capital expenditures and growth capital expenditures. We will, however, after this offering, categorize our capital expenditures as either:

 

   

Replacement capital expenditures are those capital expenditures required to maintain our asset base over the long term as it may change as a result of additions or dispositions over time. We expect that the primary component of replacement capital expenditures will be capital expenditures associated with the replacement of oil and natural gas reserves through the acquisition of new oil and natural gas mineral and royalty interests and through development expenditures related to our working interests.

 

   

Growth capital expenditures are those capital expenditures that we expect will increase our existing asset base. Examples of growth capital expenditures include the acquisition of new oil and natural gas mineral and royalty interests and expenditures related to our working interests, to the extent such expenditures are incurred to increase our asset base.

Because our replacement capital expenditures can be irregular, the amount of our actual replacement capital expenditures may differ substantially from period to period, which could cause similar fluctuations in the amounts of cash generated from operations, operating surplus, and adjusted operating surplus if we subtracted actual replacement capital expenditures from cash generated from operations. To address this issue, our partnership agreement will require that an estimate of the average quarterly replacement capital expenditures necessary to maintain our asset base over the long term be subtracted from cash generated from operations each quarter as opposed to the actual amounts spent. The amount of estimated replacement capital expenditures deducted from cash generated from operations will be initially determined by our general partner’s board of directors and is subject to review and change by our general partner’s board of directors at least once a year. The estimate will be made at least annually and whenever an event occurs that is likely to result in a material adjustment to the amount of our replacement capital expenditures, such as a major acquisition. For purposes of calculating cash generated from operations, any adjustment to this estimate will be prospective only.

We spent $74.2 million on a pro forma basis for the year ended December 31, 2014 on capital expenditures in connection with our non-operated working interests.

Regulatory, Industry, and Economic Factors

Our forecast for the twelve months ending March 31, 2016 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 generated from operations.

 

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Forecasted Distributions

We expect that aggregate quarterly distributions on our common and subordinated units for the twelve months ending March 31, 2016 will be approximately $202.6 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 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 March 31, 2016 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 and subordinated unitholders is a function of two primary variables: (i) production volumes and (ii) commodity prices. In the tables 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 minimum quarterly distributions on our common units for the twelve months ending March 31, 2016.

Production Volume Changes. The following table shows estimated cash generated from operations under production levels of 90%, 100%, and 110% of the production level we have forecasted for the twelve months ending March 31, 2016.

 

     Percentage of Forecasted Annual Production  
             90%                      100%                      110%          
     (unaudited)  

Forecasted annual production:

        

Oil and condensate (MBbls)

     2,626         2,918         3,210   

Natural gas (MMcf)

     36,238         40,264         44,290   
  

 

 

    

 

 

    

 

 

 

Combined volumes (MBoe)

     8,666         9,629         10,592   

Forecasted average daily production:

        

Oil and condensate (MBbl/d)

     7.2         8.0         8.8   

Natural gas (MMcf/d)

     99.0         110.0         121.0   
  

 

 

    

 

 

    

 

 

 

Combined volumes (MBoe/d)

     23.7         26.3         28.9   

Forecasted average sales prices:

        

WTI oil price ($/Bbl)

   $ 54.24       $ 54.24       $ 54.24   

Realized oil and condensate sales price ($/Bbl)(1)

   $ 49.78       $ 49.78       $ 49.78   

Henry Hub natural gas price ($/Mcf)

   $ 2.85       $ 2.85       $ 2.85   

Realized natural gas sales price ($/Mcf)(1)

   $ 3.12       $ 3.12       $ 3.12   

Estimated cash generated from operations (in thousands):

        

Oil and condensate sales

   $ 130,744       $ 145,272       $ 159,799   

Natural gas and natural gas liquids sales

     113,080         125,644         138,209   

Gain on commodity derivative instruments(2)

     33,587         33,587         33,587   

Lease bonus and other income

     40,200         40,200         40,200   

Operating expense

     235,748         238,186         240,624   

Estimated cash generated from operations

   $ 216,764       $ 241,573       $ 266,379   

 

(1) Excluding cash settlement on commodity derivative instruments.
(2) Represents cash settlement on commodity derivative instruments maturing in the twelve months ending March 31, 2016.

 

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Commodity Price Changes. The following table shows estimated cash generated from operations under various assumed oil and natural gas prices for the twelve months ending March 31, 2016. 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%          
     (unaudited)  

Forecasted annual production:

        

Oil and condensate (MBbls)

     2,918         2,918         2,918   

Natural gas (MMcf)

     40,264         40,264         40,264   
  

 

 

    

 

 

    

 

 

 

Combined volumes (MBoe)

     9,629         9,629         9,629   

Forecasted average daily production:

        

Oil and condensate (MBbl/d)

     8.0         8.0         8.0   

Natural gas (MMcf/d)

     110.0         110.0         110.0   
  

 

 

    

 

 

    

 

 

 

Combined volumes (MBoe/d)

     26.3         26.3         26.3   

Forecasted average sales prices:

        

WTI oil and condensate price ($/Bbl)

   $ 48.82       $ 54.24       $ 59.67   

Realized oil and condensate sales price ($/Bbl)(1)

   $ 44.45       $ 49.78       $ 55.12   

Henry Hub natural gas price ($/Mcf)

   $ 2.57       $ 2.85       $ 3.14   

Realized natural gas sales price ($/Mcf)(1)

   $ 2.81       $ 3.12       $ 3.43   

Estimated cash generated from operations (in thousands):

        

Oil and condensate sales

   $ 129,697       $ 145,272       $ 160,847   

Natural gas and natural gas liquids sales

     113,080         125,644         138,209   

Gain on commodity derivative instruments(2)

     52,145         33,587         15,030   

Lease bonus and other income

     40,200         40,200         40,200   

Operating expense

     235,637         238,186         240,735   

Estimated cash generated from operations

   $ 234,650       $ 241,573       $ 248,495   

 

(1) Excluding cash settlement on commodity derivative instruments.
(2) Represents cash settlement on commodity derivative instruments maturing in the twelve months ending March 31, 2016.

 

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Quarterly Forecast Information

The following table presents our forecasted cash generated from operations on a quarter-by-quarter basis for the forecast period. The following forecast reflects our judgment as of the date of this prospectus of conditions we expect to exist and the course of action we expect to take for the twelve months ending March 31, 2016. Please see “—Assumptions and Considerations.” The assumptions and considerations underlying the forecast for the twelve months ending March 31, 2016 are inherently uncertain, and estimating the precise quarter in which each revenue and expense will be recognized increases the level of uncertainty of the quarterly forecast information. Accordingly, actual quarter-by-quarter results may differ materially from the quarter-by-quarter forecast information presented below. As an owner of mineral and royalty interests, we are subject to fluctuations in cash generated from operations from quarter to quarter due to uncertainty of timing of collections from our lessees. As a result, we may manage our working-capital requirements through the use of our credit facility. We do not believe that a shortfall caused by these timing-related fluctuations in cash receipts in any given quarter during the forecast period would affect our ability to pay distributions for that quarter.

 

    Three Months Ending  
    March  31,
2016
    December 31,
2015
    September 30,
2015
    June  30,
2015
 
   

(unaudited)

(in thousands)

 

Revenue:

       

Oil and condensate sales

  $ 38,441      $ 36,302      $ 36,926      $ 33,603   

Natural gas and natural gas liquids sales

    35,611        32,055        30,383        27,595   

Gain on commodity derivative instruments

    103        5,116        9,376        18,992   

Lease bonus and other income(1)

    6,050        14,050        12,050        8,050   
 

 

 

   

 

 

   

 

 

   

 

 

 

Total revenue

    80,205        87,523        88,735        88,240   
 

 

 

   

 

 

   

 

 

   

 

 

 

Operating expense:

       

Lease operating expense and other

    5,318        5,304        5,291        5,145   

Production and ad valorem taxes

    6,616        6,162        6,075        5,524   

Depreciation, depletion, and amortization

    28,621        28,478        28,365        28,220   

General and administrative

    19,739        19,377        19,377        19,514   

Accretion of asset retirement obligations

    265        265        265        265   
 

 

 

   

 

 

   

 

 

   

 

 

 

Total operating expense

    60,559        59,586        59,373        58,668   
 

 

 

   

 

 

   

 

 

   

 

 

 

Income from operations

    19,646        27,937        29,362        29,572   

Other expense:

       

Interest expense

    (965     (883     (847     (1,424
 

 

 

   

 

 

   

 

 

   

 

 

 

Total other expense

    (965     (883     (847     (1,424
 

 

 

   

 

 

   

 

 

   

 

 

 

Net income

    18,681        27,054        28,515        28,148   
 

 

 

   

 

 

   

 

 

   

 

 

 

Adjustments to reconcile to Adjusted EBITDA:

       

Add:

       

Depreciation, depletion, and amortization

    28,621        28,478        28,365        28,220   

Interest expense

    965        883        847        1,424   
 

 

 

   

 

 

   

 

 

   

 

 

 

EBITDA

 

 

 

 

48,267

 

  

 

 

 

 

56,415

 

  

 

 

 

 

57,727

 

  

 

 

 

 

57,792

 

  

Add:

       

Accretion of asset retirement obligations

    265        265        265        265   

Equity-based compensation expense

 

 

 

 

 

 

 

 

5,908

 

 

 

  

 

 

 

 

 

 

 

 

5,879

 

 

 

  

 

 

 

 

 

 

 

 

5,879

 

 

 

  

 

 

 

 

 

 

 

 

6,652

 

 

 

  

       
 

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

 

 

 

 

54,440

 

  

 

 

 

 

62,559

 

  

 

 

 

 

63,871

 

  

 

 

 

 

64,709

 

  

 

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    Three Months Ending  
    March  31,
2016
    December 31,
2015
    September 30,
2015
    June  30,
2015
 
   

(unaudited)

(in thousands)

 

Adjustments to reconcile to estimated cash generated from operations:

       

Add:

       

Borrowings to fund future capital expenditures

    11,313        11,336        11,712        12,666   

Less:

       

Deferred revenue

    (266     (259     (258     (80

Cash interest expense

    (718     (638     (606     (1,181

Capital expenditures

    (11,313     (11,336     (11,712     (12,666
 

 

 

   

 

 

   

 

 

   

 

 

 

Estimated cash generated from operations

    53,456        61,662        63,007        63,448   

Less:

       

Cash paid to noncontrolling interests(2)

    (46     (45     (44     (44

Preferred unit distributions(3)

    (1,956     (2,974     (2,974     (2,940
 

 

 

   

 

 

   

 

 

   

 

 

 

Estimated cash generated from operations available for distribution on common and subordinated units and reinvestment in our business

    51,454        58,643        59,989