SUBMITTED CONFIDENTIALLY TO THE DIVISION OF CORPORATION FINANCE ON JANUARY 29, 2015

As filed with the Securities and Exchange Commission on                     , 2015

Registration No. 333-            

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Confidential Draft Submission No. 5

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

Black Stone Minerals, L.P.

(Exact Name of Registrant as Specified in Its Charter)

Delaware	1311	47-1846692
(State or Other Jurisdiction of Incorporation or Organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification Number)

1001 Fannin Street

Suite 2020

Houston, Texas 77002

(713) 658-0647

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

Steve Putman

Senior Vice President, General Counsel, and Secretary

1001 Fannin Street

Suite 2020

Houston, Texas 77002

(713) 658-0647

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

Copies to:

Mike Rosenwasser Brenda Lenahan Vinson & Elkins L.L.P. 666 Fifth Avenue, 26th Floor New York, New York 10103 Tel: (212) 237-0000 Fax: (212) 237-0100 G. Michael O’Leary Jon W. Daly Andrews Kurth LLP 600 Travis Street, Suite 4200 Houston, Texas 77002 Tel: (713) 220-4200 Fax: (713) 220-4285

Approximate date of commencement of proposed sale to the public:

As soon as practicable after this registration statement becomes effective.

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

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

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

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

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

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

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

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                     , 2015

PROSPECTUS

Black Stone Minerals, L.P.

Common Units

Representing Limited Partner Interests

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

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

These risks include the following:

• We may not generate sufficient cash from operations to pay any quarterly distribution on our common units. If we make distributions, our preferred unitholders have priority with respect to rights to share in those distributions over our common unitholders for so long as our preferred units are outstanding.

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

• 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.

• 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.

• Common 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             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

Scotiabank / Howard Weil Simmons & Company International

Prospectus dated                     , 2015

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	14
Risk Factors	15
The Offering	19
Summary Historical and Pro Forma Financial Data	23
Non-GAAP Financial Measures	25
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, 2013  and the Twelve Months Ended September 30, 2014	56
Estimated Cash Generated from Operations for the Year Ending December 31, 2015	59
SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA	71
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	73
Overview	73
Business Environment	73
How We Evaluate Our Operations	74
Factors Affecting the Comparability of Our Financial Results	76
Results of Operations	77
Liquidity and Capital Resources	81
Contractual Obligations	83
Off-Balance Sheet Arrangements	84
Critical Accounting Policies and Related Estimates	84
New and Revised Financial Accounting Standards	86
Quantitative and Qualitative Disclosure about Market Risk	87
BUSINESS	88
Overview	88
Our Assets	88

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Business Strategies	90
Competitive Strengths	92
Our Properties	93
Estimated Proved Reserves	103
Oil and Natural Gas Production Prices and Production Costs	108
Environmental Matters	112
Title to Properties	116
Competition	117
Seasonal Nature of Business	117
Employees	117
Facilities	117
Legal Proceedings	117
MANAGEMENT	118
Management	118
Executive Officers and Directors of Our General Partner	119
Director Independence	123
Committees of the Board of Directors	123
Certain Relationships and Related Party Transactions	124
EXECUTIVE COMPENSATION AND OTHER INFORMATION	125
Summary Compensation Table	125
Narrative Disclosure to the Summary Compensation Table	126
Outstanding Equity Awards at 2013 Fiscal Year-End	127
Additional Narrative Disclosure	128
Long-Term Incentive Plan	130
Director Compensation	132
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT	133
FIDUCIARY DUTIES	135
DESCRIPTION OF OUR COMMON UNITS	138
Our Common Units	138
Transfer Agent and Registrar	138
Transfer of Common Units	138
Listing	139
DESCRIPTION OF OUR PREFERRED UNITS	140
Our Preferred Units	140
Distributions	140
Conversion of the Preferred Units	141
Redemption of the Preferred Units	141
Anti-Dilution Provisions	142
Voting; Waiver	143
THE PARTNERSHIP AGREEMENT	144
Organization and Duration	144
Purpose	144
Capital Contributions	144
Adjustments to Capital Accounts Upon Issuance of Additional Common Units	144
Voting Rights	144
Meetings; Voting	146
Nomination of Directors	147

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Applicable Law; Forum, Venue, and Jurisdiction	148
Limited Liability	148
Issuance of Additional Partnership Interests	149
Amendment of the Partnership Agreement	149
Merger, Consolidation, Conversion, Sale, or Other Disposition of Assets	152
Dissolution	152
Liquidation and Distribution of Proceeds	153
Withdrawal or Removal of Our General Partner; Transfer of General Partner Interest	153
Change of Management Provisions	153
Non-Taxpaying Holders; Redemption	153
Non-Citizen Assignees; Redemption	154
Status as Limited Partner	154
Indemnification	154
Reimbursement of Expenses	154
Books and Reports	155
Right to Inspect Our Books and Records	155
UNITS ELIGIBLE FOR FUTURE SALE	156
MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES	157
Taxation of the Partnership	157
Tax Consequences of Unit Ownership	159
Tax Treatment of Operations	163
Disposition of Units	165
Uniformity of Units	167
Tax-Exempt Organizations and Other Investors	168
Administrative Matters	169
FATCA Withholding Requirements	170
State, Local, and Other Tax Considerations	171
INVESTMENT IN BLACK STONE MINERALS, L.P. BY EMPLOYEE BENEFIT PLANS	172
General Fiduciary Matters	172
Prohibited Transaction Issues	172
Plan Asset Issues	173
UNDERWRITING	174
Commissions and Expenses	174
Option to Purchase Additional Common Units	175
Lock-Up Agreements	175
Offering Price Determination	175
Indemnification	176
Stabilization, Short Positions, and Penalty Bids	176
Directed Unit Program	177
Electronic Distribution	177
New York Stock Exchange	177
Discretionary Sales	177
Stamp Taxes	177
Relationships	177
FINRA	178
Selling Restrictions	178
LEGAL MATTERS	180
EXPERTS	180
CHANGE IN ACCOUNTANTS	180

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WHERE YOU CAN FIND MORE INFORMATION	181
FORWARD-LOOKING STATEMENTS	182
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 $         per common unit (the mid-point of the price range set forth on the cover page of this prospectus) and, unless otherwise indicated, that the underwriters’ option to purchase additional common units is not exercised and the preferred units have not converted to common units. You should read “Risk Factors” for information about important risks that you should consider before buying our common units.

References in this prospectus to “BSMC,” “Black Stone Minerals, L.P. Predecessor,” “our predecessor,” “we,” “our,” “us,” or like terms when used in a historical context refer to Black Stone Minerals Company, L.P. and its subsidiaries. When used in the present tense or prospectively, “BSM,” “Black Stone Minerals,” “we,” “our,” “us,” “the partnership,” or like terms refer to Black Stone Minerals, L.P. and its subsidiaries, after giving effect to those transactions described in “—Formation Transactions and Structure.” References in this prospectus to “BSNR” 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 New 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. 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 while distributing a substantial majority of our cash generated from operations to our common 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 1.3 million acres. These non-cost-bearing interests, which we refer to collectively as our “mineral and royalty interests,” include ownership in approximately 40,000 producing wells. Our mineral and royalty interests are located in 41 states and in 62 onshore basins in the continental United States. Many of these interests are in active resource plays, including the Bakken/Three Forks play, Eagle Ford Shale, Wolfcamp play, Haynesville/Bossier play, Granite Wash play, and Fayetteville Shale, as well as emerging plays such as the Tuscaloosa Marine Shale and the Canyon Lime play. The combination of the breadth of our asset base and the long-lived, non-cost-bearing nature of our mineral and royalty interests exposes us to potential additional production and reserves from new and existing plays without investing additional capital.

Our history dates back to 1876, when W.T. Carter & Bro., a predecessor of BSMC, was established as a lumber company in Southeast Texas. W.T. Carter & Bro. acquired significant land holdings for timber, and those

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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 nine months ended September 30, 2014 was approximately 25.9 MBoe/d, which includes production from our mineral and royalty interests, as well as production attributable to our working-interest participation program, as described below.

Our Assets

Mineral and Royalty Interests

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

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

• nonparticipating royalty interests (“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 $314.2 million and $260.1 million for the year ended December 31, 2013 and the nine months ended September 30, 2014, respectively.

Working-Interest Participation Program

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

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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 2014 non-operated working-interest capital expenditure budget and likely will be less in the future.

We collectively refer to these working interests as our “working-interest participation program.” When we participate in non-operated working-interest opportunities, we are required to pay our portion of the costs associated with drilling and operating these wells. Our 2014 drilling capital expenditure budget associated with our working-interest participation program is approximately $73.0 million. Approximately 41% and 29% of our 2014 drilling capital budget will be spent in the Bakken/Three Forks play and the Haynesville/Bossier play, respectively, with the remainder spent in various plays including the Granite Wash. As of September 30, 2014, the substantial majority of our 2014 drilling and completion budget was either spent or committed. Accordingly, we do not expect that any delays in drilling under this program would have a material impact on our results of operations. We historically have participated in approximately 200 new wells per year. As of September 30, 2014, we owned non-operated working interests in approximately 9,000 gross wells. For the year ended December 31, 2013 and the nine months ended September 30, 2014, our revenue generated from these working interests was $123.4 million and $92.1 million, respectively.

Our Properties

Material Basins and Producing Regions

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

	Acreage as of September 30, 2014(1)										Average Daily Production for Nine Months Ended September 30, 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		5,273,142		111,707		17,140		54,685		6,850		6,777
Western Gulf (onshore)		1,543,417		180,901		82,481		116,933		17,677		4,930
Williston Basin		1,113,650		60,734		30,645		52,770		7,429		3,323
Palo Duro Basin		1,010,374		22,791		1,120		—		—		15
Permian Basin		696,286		544,648		59,033		8,353		5,054		830
Anadarko Basin		535,607		10,628		180,443		28,296		21,404		2,461
Appalachian Basin		490,006		416		3,532		—		—		907
East Texas Basin		406,279		36,191		25,252		126,495		33,673		2,247
Arkoma Basin		331,168		5,170		36,109		8,943		2,408		2,029
Bend Arch-Fort Worth Basin		138,018		52,208		41,038		55,841		13,408		567
Southwestern Wyoming		25,450		560		70,607		15,458		2,492		553
Other		2,933,385		188,606		790,369		43,294		13,159		1,290
Total		14,496,780		1,214,559		1,337,768		511,069		123,554		25,930

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

(1) We may own more than one type of interest in the same tract of land. For example, where we have acquired working interests through our working-interest participation program in a given tract, our working-interest acreage in that tract will relate to the same tract acres as our mineral-interest acreage in that tract.

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

• Western Gulf (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 basin and is being actively drilled and tested by several operators in the Western Gulf region. In addition to the Eagle Ford Shale and Tuscaloosa Marine Shale plays, there are a number of other active conventional and unconventional plays to which we have exposure to in the region, including the Austin Chalk, Buda, Eaglebine (or Maness) Shale, Frio, Glenrose, Olmos, Woodbine, Vicksburg, Wilcox, and Yegua plays.

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

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

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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 play 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 play located in San Augustine and Nacogdoches Counties, which is one of the most active areas being drilled today for that play in the East Texas Basin. There are other active plays to which we have significant exposure, including the Bossier Sand, Goodland Lime, James Lime, Pettit, Travis Peak, Smackover, and Woodbine plays.

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

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

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

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

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Material Resource Plays

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

	Acreage as of September 30, 2014 (1)
Resource Play(2)	Mineral and Royalty Interests						Working Interests
	Mineral Interests		NPRIs		ORRIs		Gross		Net
Bakken Shale		318,909		35,261		12,610		48,195		6,782
Three Forks		296,449		32,442		11,930		48,397		6,420
Haynesville Shale		275,275		6,523		14,468		169,257		39,396
Marcellus Shale		253,536		—		1,002		—		—
Canyon Lime		232,381		—		—		—		—
Bossier Shale		213,539		1,496		8,441		135,208		33,243
Tuscaloosa Marine Shale		181,480		4,081		6,409		—		—
Granite Wash		110,648		4,042		87,516		5,194		1,364
Fayetteville Shale		76,539		—		11,833		—		—
Barnett Shale		62,171		4,004		37,803		20,665		8,322
Eagle Ford Shale		46,396		85,864		44,324		235		118
Wolfcamp-Delaware		44,535		11,785		1,080		642		160
Wolfcamp-Midland		58,498		46,720		14,964		160		4

(1) We may own more than one type of interest in the same tract of land. For example, where we have acquired working interests through our working-interest participation program in a given tract, our working-interest acreage in that tract will relate to the same tract acres as our mineral-interest acreage in that tract. Consequently, some of the acreage shown for one type of interest above may also be included in the acreage shown for another type of interest. Because of our working-interest participation program, overlap between working-interest acreage and mineral-and-royalty-interest acreage is significant, while overlap between the different types of mineral and royalty interests is not. Working-interest acreage excludes acreage that is not quantifiable due to incomplete seller records.

(2) The plays above have been delineated based on information from the U.S. Energy Information Administration (“EIA”), the USGS, state agencies, or according to areas of the most active industry development.

Business Strategies

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

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

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

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

• geologic support for future production and reserve growth;

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

• targeted positions in high-growth resource and conventional plays.

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

• Maintain a conservative capital structure and prudently manage the business for the long term. We are committed to maintaining a conservative capital structure that will afford us the financial flexibility to execute our business strategies on an ongoing basis. Upon completion of this offering, we will have no outstanding indebtedness. We believe that proceeds from this offering, internally generated cash from operations, our $700.0 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 16.5 million total acres across the continental United States, we have established a strong position with significant growth opportunities and exposure to potentially large new discoveries in the future. In some cases, we have built our positions in anticipation of development in a play, as we did in the Eagle Ford Shale. In other cases, we acquired diversified mineral packages in rich geologic basins with multiple prospective horizons from which subsequent resource plays, including the Bakken/Three Forks play and the Haynesville/Bossier play, have developed. Because our asset base is large and diversified, we are able to make significant focused acquisitions in active areas within well-established resource plays, while maintaining overall diversity. Furthermore, the geographic breadth of our assets

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

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

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

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

• Exposure to natural gas supply and demand growth. The EIA projects that U.S. natural gas demand from internal consumption is expected to increase from 25.6 trillion cubic feet in 2012 to 31.6 trillion cubic feet in 2040, driven primarily by increased electricity generation and industrial use. International demand for exports of U.S. natural gas, through pipelines and liquefied natural gas, is forecasted to grow to 5.8 trillion cubic feet per year by 2040. The EIA forecasts the total demand for U.S. natural gas to reach 37.4 trillion cubic feet in 2040. As a result of this increase in demand, the EIA projects U.S. natural gas production to increase from 24.1 trillion cubic feet in 2012 to 37.5 trillion cubic feet in 2040, a 56% increase. Almost all of this increase is due to projected growth in natural gas production from resource plays, which is projected to grow from 9.7 trillion cubic feet in 2012 to 19.8 trillion cubic feet in 2040. We have significant exposure to domestic natural gas resource plays, including the Haynesville/Bossier play, the Fayetteville Shale, and the Barnett Shale, and we believe that these assets will provide meaningful upside in production and revenue growth as demand for natural gas increases. Our 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 $        million of cash on hand, and $        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 and preferred units have the right to nominate and vote in the election of directors to the board of directors of our general partner. The board of directors of our general partner must have at least three directors who meet the independence standards established by the New York Stock Exchange (the “NYSE”) within one year of the consummation of this offering. At least one independent director will be appointed by the time our common units are first listed for trading on the NYSE.

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

Fiduciary Duties

Our partnership agreement contains provisions that eliminate the fiduciary duties to which our general partner and the directors and executive officers of our general partner would otherwise be held by state fiduciary duty law and imposes contractual standards that our general partner and its directors and executive officers must follow. Our partnership agreement also specifically restricts the situations in which remedies may be available to our unitholders for actions taken that might otherwise constitute breaches of duty under applicable Delaware law or breaches of the contractual obligations in our partnership agreement. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement, and each unitholder is treated as having consented to various actions contemplated in the partnership agreement that might otherwise be considered a breach of fiduciary or other duties under Delaware law.

For a more detailed description of the duties of our general partner and its directors and executive officers, please read “Fiduciary Duties.”

Emerging Growth Company Status

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

• an exemption from providing an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”);

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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 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             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 of the partnership;

• in connection with the merger, (i) the common units in 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                     of common units of the partnership at a conversion ratio of                     :1, and the preferred units of BSMC will be

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exchanged for an aggregate of                     of preferred units of the partnership, (iii) the common units of BSMC that are 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 common 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             common units to the public in this offering and use the net proceeds from this offering in the manner described under “Use of Proceeds.”

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

We have granted the underwriters a 30-day option to purchase up to an aggregate of             additional common units. Any net proceeds received from the exercise of this option will be used to fund future capital expenditures.

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

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

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Principal Executive Offices

Our principal executive offices are located at 1001 Fannin Street, Suite 2020, Houston, Texas 77002, and our telephone number is (713) 658-0647. Our website address will be www.                    .com. We intend to make our periodic reports and other information filed with or furnished to the SEC available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

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Risk Factors

An investment in our common units involves risks. You should carefully consider the following considerations, the risks described in “Risk Factors” and the other information in this prospectus, before deciding whether to invest in our common units. If any of these risks were to occur, our financial condition, results of our operations, cash 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 to pay any quarterly distribution on our common units. If we make distributions, our preferred unitholders have priority with respect to rights to share in those distributions over our common unitholders for so long as our preferred units are outstanding.

• 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 amount of our cash distributions, if any, may vary significantly both quarterly and annually and will be directly dependent on the performance of our business. We will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time and could make no distribution with respect to any particular quarter. Furthermore, our partnership agreement does not require us to pay distributions to our common unitholders on a quarterly basis or otherwise.

• 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 54.5% of our 2013 total revenue and 51.6% of our total revenue in the first nine months of 2014 was derived from oil and condensate sales. Any additional decreases in prices of oil may adversely affect our cash generated from operations, results of operations, and financial position, perhaps materially.

• Natural gas prices have declined substantially from historical highs and are expected to remain depressed for the foreseeable future. Approximately 74.2% of our total 2013 production and 71.2% of our total production in the first nine months of 2014, on an MBoe basis, was natural gas. Any additional decreases in prices of natural gas may adversely affect our cash generated from operations, results of operations, and financial position, perhaps materially.

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

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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.

• 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 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 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.

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• Cyber attacks could significantly affect us.

Risks Inherent in an Investment in Us

• The board of directors of our general partner will adopt a policy to distribute a substantial majority of the 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 unitholders for so long as our preferred units are outstanding.

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

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

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

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

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

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

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

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

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

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

• There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. The price of our common units may fluctuate significantly, and unitholders could lose all or part of their investment.

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

• For as long as we are an emerging growth company, we will not be required to comply with certain disclosure requirements, including those relating to accounting standards, 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.

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

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

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

Use of proceeds We intend to use the estimated net proceeds of approximately $         million from this offering (based on an assumed initial offering price of $         per common unit, the mid-point of the price range set forth on the cover page of this prospectus), after deducting the estimated underwriting discount, structuring fee, and offering expenses payable by us, to repay all of the indebtedness outstanding under our credit facility, which was $430.0 million as of September 30, 2014. Any remaining net proceeds, which we estimate will be $         million, based upon the amount outstanding under our credit facility, will be used to fund future capital expenditures.

The net proceeds from any exercise of the underwriters’ option to purchase additional common units (approximately $         million based on an assumed initial offering price of $         per common unit, the mid-point of the price range set forth on the cover page of this prospectus, after deducting the estimated underwriting discount 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 Within 60 days after the end of each quarter, beginning with the quarter ending                 , 2015, we expect to make distributions to common unitholders of record on the applicable record date. We expect our first distribution will consist of cash generated from operations for the period from the closing of this offering through                 , 2015.

If we make distributions, our preferred unitholders have priority with respect to rights to share in those distributions over our common unitholders for so long as our preferred units are outstanding. When all of our preferred units have been redeemed or converted to common units, all distributions will be made pro rata to our common unitholders. For a description of the relative rights and privileges of holders of our preferred units to partnership distributions, please read “Description of Our Preferred Units—Distributions.”

In connection with the closing of this offering, the board of directors of our general partner will adopt a policy pursuant to which we will

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distribute a substantial majority of the cash we generate from operations each quarter, which we expect initially to be approximately         % of our cash generated from operations. Our initial distribution will be $             per common unit on an annualized basis ( or $         per unit on a quarterly basis). 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 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. It is our intention to maintain excess distribution coverage to sustain or increase the amount of in our quarterly distribution. For a demonstration on how this determination will be made, please see the tables under “Pro Forma Cash Generated from Operations for the Year Ended December 31, 2013 and the Twelve Months Ended September 30, 2014” and “Estimated Cash Generated from Operations for Distribution for the Year Ending December 31, 2015.” It is our intent, for at least the next several years, to finance most of our acquisition and working-interest capital needs with cash generated from operations, the retained net proceeds from this offering, borrowings under our credit facility, and, in certain circumstances, proceeds from future equity and debt issuances. We may also borrow to make distributions to our unitholders where, for example, we believe that the distribution level is sustainable over the long term, but short-term factors may cause cash generated from operations to be insufficient to pay distributions at the current level. The board of directors of our general partner may change the foregoing distribution policy at any time and from time to time. Our partnership agreement does not require us to pay cash distributions on a quarterly or other basis. Please read “Risk Factors—Risks Inherent in an Investment in Us—The board of directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion. Our partnership agreement does not require us to pay any distributions at all. If we make distributions, our preferred unitholders have priority with respect to rights to share in those distributions over our common unitholders for so long as our preferred units are outstanding.”

Replacement capital expenditures are expenditures necessary to replace our existing oil and natural gas reserves or otherwise maintain our asset base over the long term. Unlike a number of other master limited partnerships, we are not required by our partnership agreement to retain cash from our operations for replacement capital expenditures. However, we have set our initial distribution rate at a level we believe 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.

Preferred units Our preferred units represent limited partner interests in us. Our preferred units will receive priority distributions over our common

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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 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, each preferred unit is entitled to vote as a single class with the common units on an “as-converted basis.” For a detailed discussion of our preferred units, please read “Description of Our Preferred Units.”

Subordinated units None.

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

Estimated ratio of taxable income to distributions We estimate that if you (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 December 31,         , you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be approximately     % of the cash expected to be distributed to you with respect to that period. Alternatively, if you are not subject to the passive loss limitation, we estimate you will be allocated, on a cumulative basis, an amount of federal taxable income for such period that will be approximately     % of the cash expected to be distributed to you with respect to such period. Because of the nature of our business and the expected variability of our quarterly distributions, however, the ratio of our taxable income to distributions may vary

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significantly from one year to another. Please read “Material U.S. Federal Income Tax Consequences—Tax Consequences of Unit Ownership” for the basis of this estimate.

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

Directed unit program The underwriters have reserved for sale at the initial public offering price up to     % 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 applied to list our common units on the NYSE under the symbol “BSM.”

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Summary Historical and Pro Forma Financial Data

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

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

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

We have not given pro forma effect to incremental general and administrative expenses of approximately $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,” the audited and unaudited historical financial statements of BSMC, and our pro forma financial statements included elsewhere in this prospectus. Among other things, the historical financial statements include more detailed information regarding the basis of presentation for the information in the following table.

	Black Stone Minerals, L.P. Predecessor Historical												Black Stone Minerals, L.P. Pro Forma
	Nine Months Ended September 30,						Year Ended December 31,						Nine Months Ended September 30, 2014			Year Ended December 31, 2013
	2014			2013			2013			2012
	(unaudited)												(unaudited)
	(in thousands)
Revenue:
Oil and condensate sales	$	195,665		$	193,534		$	252,742		$	202,104		$	195,665		$	252,742
Natural gas and natural gas liquids sales		156,554			138,226			184,868			166,849			156,554			184,868
Gain (loss) on commodity derivative instruments		339			(3,441	)		(5,860	)		12,275			339			(5,860	)
Lease bonus and other income		26,586			11,964			31,809			53,918			26,586			31,809
Total revenue		379,144			340,283			463,559			435,146			379,144			463,559
Operating (income) expense:
Lease operating expense and other		16,151			15,952			21,316			20,527			16,151			21,316
Production and ad valorem taxes		33,589			29,910			42,813			36,680			33,589			42,813
Depreciation, depletion, and amortization		84,058			75,213			102,442			104,059			84,058			102,442
Impairment of oil and natural gas properties		—			27,630			57,109			62,987			—			57,109
General and administrative		45,607			45,789			59,501			50,348			45,607			59,501
Accretion of asset retirement obligations		443			461			588			608			443			588
Gain on sale of assets		—			(18	)		(18	)		(363	)		—			(18	)
Total operating expense		179,848			194,937			283,751			274,846			179,848			283,751
Income from operations		199,296			145,346			179,808			160,300			199,296			179,808
Other income (expense):
Interest and investment income		27			79			90			209			27			90
Interest expense(1)		(10,292	)		(7,922	)		(11,342	)		(9,166	)		(2,733	)		(3,633	)
Other income		869			274			407			467			869			407
Total other expense		(9,396	)		(7,569	)		(10,845	)		(8,490	)		(1,837	)		(3,136	)
Net income	$	189,900		$	137,777		$	168,963		$	151,810		$	197,459		$	176,672
Statement of Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	278,398		$	218,305		$	320,764		$	358,002
Investing activities		(92,545	)		(170,446	)		(195,631	)		(198,975	)
Financing activities		(207,984	)		(77,952	)		(142,311	)		(138,172	)
Other Financial Data:
EBITDA(2)	$	284,250		$	220,912		$	282,747		$	265,035		$	284,250		$	282,747
Adjusted EBITDA(2)		288,437			257,252			354,576			346,574			288,437			354,576
Capital expenditures(3)		(92,545	)		(170,446	)		(195,631	)		(198,975	)
Balance Sheet Data (at period end):
Cash and cash equivalents	$	7,992					$	30,123		$	47,301		$
Total assets		1,444,467						1,444,413			1,199,187
Credit facilities		430,000						451,000			363,100			—
Total liabilities		552,992						566,618			711,143			122,992
Total mezzanine equity		161,165						161,392			161,381			161,165
Total equity		730,310						716,403			326,663

(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 $0.1 million and $1.0 million for the years ended December 31, 2013 and December 31, 2012, respectively, and no proceeds for the nine months ended September 30, 2014 and $0.1 million for the nine months ended September 30, 2013.

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Non-GAAP Financial Measures

EBITDA and Adjusted EBITDA are non-GAAP supplemental financial measures used by our management and by external users of our financial statements such as investors, 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 (“ARO”), 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.

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

	Black Stone Minerals, L.P. Predecessor Historical									Black Stone Minerals, L.P. Pro Forma
	Nine Months Ended September 30,					Year Ended December 31,				Nine Months Ended September 30, 2014			Year Ended December 31, 2013
	2014			2013		2013		2012
	(unaudited)									(unaudited)
	(in thousands)
Reconciliation of EBITDA and Adjusted EBITDA to net income:
Net income		$189,900		$	137,777	$	168,963	$	151,810	$	197,459		$	176,672
Add:
Depreciation, depletion, and amortization		84,058			75,213		102,442		104,059		84,058			102,442
Interest expense(1)		10,292			7,922		11,342		9,166		2,733			3,633
EBITDA		284,250			220,912		282,747		265,035		284,250			282,747
Add:
Impairment of oil and natural gas properties		—			27,630		57,109		62,987		—			57,109
Accretion of asset retirement obligations		443			461		588		608		443			588
Unrealized loss on commodity derivative instruments		—			4,957		7,350		10,697		—			7,350
Equity-based compensation expense(2)		7,452			3,292		6,782		7,247		7,452			6,782
Less:
Unrealized gain on commodity derivative instruments		(3,708	)		—		—		—		(3,708	)		—
Adjusted EBITDA		$288,437		$	257,252	$	354,576	$	346,574	$	288,437		$	354,576

(1) Includes cash expenses of commitment fees and agency fees and non-cash amortization of debt issuance costs.

(2) Represents compensation expense that is settled in common units.

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RISK FACTORS

Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should carefully consider the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units. If any of the following risks were to occur, our 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 to pay any quarterly distribution on our common units. If we make distributions, our preferred unitholders have priority with respect to rights to share in those distributions over our common unitholders for so long as our preferred units are outstanding.

We may not generate sufficient cash from operations each quarter to enable us to pay any distributions to our common unitholders. Our preferred unitholders have priority with respect to rights to share in distributions over our common unitholders. Furthermore, our partnership agreement does not require us to pay distributions to our common unitholders on a quarterly basis or otherwise. The amount of cash to be distributed each quarter will be determined by the board of directors of our general partner. Our expected aggregate annual distribution amount for the year ending December 31, 2015 is based on the assumptions set forth in “Cash Distribution Policy and Restrictions on Distributions—Estimated Cash Generated from Operations for Distribution for the Year Ending December 31, 2015—Assumptions and Considerations.” If our assumptions prove to be inaccurate, our actual distributions for the year ending December 31, 2015 may be significantly lower than our forecasted distributions, or we may not be able to pay a distribution at all. The amount of cash we have to distribute each quarter principally depends upon the amount of revenues we generate, which are largely dependent upon the prices that our operators realize from the sale of oil and natural gas. The actual amount of cash we will have to distribute each quarter will be reduced by principal and interest payments on our outstanding debt, working-capital requirements, and other cash needs. In addition, we may restrict distributions, in whole or in part, to fund 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 year ending December 31, 2015 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 amount of our cash distributions, if any, may vary significantly both quarterly and annually and will be directly dependent on the performance of our business. We will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time and could make no distribution with respect to any particular quarter. Furthermore, our partnership agreement does not require us to pay distributions to our common unitholders on a quarterly basis or otherwise.

Investors who are looking for an investment that will pay regular and predictable quarterly distributions should not invest in our common units. Our future business performance may be volatile, and our cash generated from operations may be unstable. Please read “—The volatility of oil and natural gas prices due to factors beyond our control greatly affects our financial condition, results of operations, and cash distributions to unitholders.” We will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time such as the issuance of subordinated units. Because our distributions depend primarily on the cash we generate each quarter after payment of our fixed and variable expenses, distributions paid to our common unitholders may vary significantly both quarterly and annually. Furthermore, our partnership agreement does not require us to pay distributions to our common unitholders on a quarterly basis or otherwise.

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;

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

• the price and availability of alternative fuels; and

• overall domestic and global economic conditions.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. For example, during the 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, 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 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 may result in our having to make substantial downward adjustments to our estimated proved reserves, which could negatively impact our borrowing base and our ability to fund our operations. If this occurs or if production estimates change or exploration or development results deteriorate, full cost accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. Our operators could also determine during periods of low commodity prices to shut in or curtail production from wells on our properties. In addition, they could determine during periods of low commodity prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Specifically, they may abandon any well if they reasonably believe that the well can no longer produce oil or natural gas in commercially paying quantities.

Oil prices have declined substantially from historical highs and may remain depressed for the foreseeable future. Approximately 54.5% of our 2013 total revenue and 51.6% of our total revenue in the first nine months of 2014 was derived from oil and condensate sales. Any additional decreases in prices of oil may adversely affect our cash generated from operations, results of operations, and financial position, perhaps materially.

WTI oil prices at Cushing, Oklahoma have declined from $98.17 per Bbl on December 31, 2013 to $53.45 per Bbl on December 31, 2014. 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, make distributions to our common unitholders, and service our indebtedness.

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Natural gas prices have declined substantially from historical highs and are expected to remain depressed for the foreseeable future. Approximately 74.2% of our 2013 total production and 71.2% of our total production in the first nine months of 2014, on an MBoe basis, was natural gas. Any additional decreases in prices of natural gas may adversely affect our cash generated from operations, results of operations, and financial position, 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. 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 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 common 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.

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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.

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 nine months ended September 30, 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;

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• prevailing commodity prices;

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

• the operators’ expertise, operating efficiency, and financial resources;

• approval of other participants in drilling wells;

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

• the selection of technology;

• 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 common 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.

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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.

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 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 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.

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

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proved reserves, projections of future production rates, and the timing of development expenditures may be incorrect. Our historical estimates of proved reserves and related valuations as of December 31, 2013, were prepared by Pressler Petroleum Consultants, Inc. (“Pressler”), a third-party petroleum engineering firm, which conducted a detailed well-by-well review of all our properties for the period covered by its reserve report using information provided by us as well as publicly available production information. Our historical estimates of proved reserves and related valuations as of September 30, 2014 were prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), a third-party petroleum engineering firm, which also conducted a well-by-well 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, 2013 and September 30, 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, 2013 and in the period from October 1, 2013, through September 30, 2014, respectively, 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

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in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas often have limited or no production history and consequently our operators will be less able to predict future drilling results in these areas.

Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our operators’ drilling results are weaker than anticipated or they are unable to execute their drilling program on our properties 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 our cash distributions to 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

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regulations will continue. Please read “Business—Regulation” for a description of the laws and regulations that affect our operators and that may affect us. These and other potential regulations could increase the operating costs of our operators and delay production, which could reduce the amount of cash distributions to our common unitholders.

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

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

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

Our operators engage in hydraulic fracturing. Hydraulic fracturing is a common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand, and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal Safe Drinking Water Act (“SDWA”) regulates the underground injection of substances through the Underground Injection Control (“UIC”) program. Hydraulic fracturing is generally exempt from regulation under the UIC program, and the hydraulic-fracturing process is typically regulated by state oil and natural gas commissions. The Environmental Protection Agency (“EPA”), however, has recently taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program and that these wells are required to obtain “Class II” UIC permits. In addition, on May 9, 2014, the EPA issued an Advanced Notice of Proposed Rulemaking seeking comment on its proposed development of regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. Moreover, the EPA is developing effluent-limitation guidelines that may impose federal pre-treatment standards on all oil and natural gas operators transporting wastewater associated with hydraulic-fracturing activities to publicly owned treatment works for disposal. The EPA plans to propose these standards within the next year.

Further, in April 2012, the EPA published final rules that subject all oil and natural gas operations (production, processing, transmission, storage, and distribution) to regulation under the New Source Performance Standards (“NSPS”) and the National Emission Standards for Hazardous Air Pollutants (“NESHAPS”) programs. These rules became effective in October 2012 and include NSPS standards for completions of hydraulically fractured 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

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

Several states, including Texas, have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances 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 September 30, 2014, our borrowing base for our credit facility was $700 million, we had outstanding borrowings of $430.0 million, and the aggregate maximum credit amounts of the lenders were $1.0 billion. Our next borrowing base redetermination is scheduled for April 2015. As a result of the steep decline in oil and natural gas prices in of the second half of 2014, our borrowing base will likely be decreased by the lenders under our credit facility in April 2015 if prices do not return to former levels. A future decrease in our borrowing base could be substantial and could be to a level below our then-outstanding

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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 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 or to engage, expand, or pursue our business activities or to 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 common 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

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

As a result of our cash distribution policy, we will have limited cash 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 or as in-kind distributions, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. Other than limitations restricting our ability to issue units ranking senior or on a parity with our preferred units, there are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units with respect to distributions. If we incur debt to finance our growth, our interest expense will increase, reducing cash distributions to unitholders. Please read “Cash Distribution Policy and Restrictions on Distributions.”

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

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

In addition, our partnership agreement does not require us to pay any distributions at all on our common units. Accordingly, investors are cautioned not to place undue reliance on the permanence of a policy in making an investment decision. Any modification or revocation of our cash distribution policy could substantially reduce or eliminate the amounts of distributions to our unitholders. The amount of distributions we make, if any, and the decision to make any distribution at all will be determined by the board of directors of our general partner. If we make distributions, our preferred unitholders have priority with respect to rights to share in those distributions over our common unitholders for so long as our preferred units are outstanding. Please read “Description of Our Preferred Units—Distributions.”

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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, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in willful misconduct or fraud or, with respect to any criminal conduct, with the knowledge that its conduct was unlawful.

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

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

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

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

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

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

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

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

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

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

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”), we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted by Section 17-607 of the Delaware Act.

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

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

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

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

The assumed initial public offering price of $         per common unit (the mid-point of the price range set forth on the cover page of this prospectus) exceeds our pro forma net tangible book value of $         per common unit. Based on the assumed initial public offering price of $         per common unit, common unitholders will

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incur immediate and substantial dilution of $         per common unit. This dilution results primarily because the assets contributed to us by our predecessor are recorded at their historical cost in accordance with GAAP and not their fair value. Please read “Dilution.”

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

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

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

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

• the ratio of our taxable income to distributions may increase;

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

• the market price of the common units may decline.

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

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

After this offering, we will have             common units outstanding, including the             common units that we are selling in this offering that may be resold in the public market immediately. All of the common units that are issued to our directors and executive officers will be subject to resale restrictions under a 180-day lock-up agreement with the underwriters, and, 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 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 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. Please read “Units Eligible for Future Sale.”

There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. The price of our common units may fluctuate significantly, and unitholders could lose all or part of their investment.

Prior to this offering, there has been no public market for the common units. After this offering, there will be only             publicly traded common units. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. Unitholders may not be able to resell their common units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

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

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

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

We have no history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accounting, and other expenses that we did not incur prior to this offering. In addition, the Sarbanes-Oxley Act and the Dodd-Frank Act of 2010, as well as rules implemented by the SEC and the NYSE, require, or will require, publicly traded entities to adopt various corporate governance practices that will further increase our costs. Before we are able to make distributions to our unitholders, we must first pay our expenses, including the costs of being a publicly traded partnership and other operating expenses. As a result, the amount of cash we distribute to our unitholders will be reduced by our expenses, including the costs associated with being a publicly traded partnership.

Following this offering, we will become subject to the public reporting requirements of the Exchange Act. We expect these requirements will increase our legal and financial compliance costs. For example, as a result of becoming a publicly traded partnership, we are required to have at least three independent directors and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal control over financial reporting.

We estimate that we will incur approximately $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;

• 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

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

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

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

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

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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 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

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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.

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.

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

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

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USE OF PROCEEDS

We intend to use the estimated net proceeds of approximately $         million from this offering (based on an assumed initial offering price of $         per common unit, the mid-point of the price range set forth on the cover page of this prospectus), after deducting the estimated underwriting discount, structuring fee, and offering expenses payable by us, to repay all of the indebtedness outstanding under our credit facility, which was $430.0 million as of September 30, 2014. Any remaining net proceeds, which we estimate will be $         million, based upon the amount outstanding under our credit facility as of September 30, 2014, will be used to fund future capital expenditures.

The net proceeds from any exercise of the underwriters’ option to purchase additional common units (approximately $         million, if exercised in full, based on an assumed initial offering price of $         per common unit, the mid-point of the price range set forth on the cover of this prospectus, after deducting the estimated underwriting discount 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 September 30, 2014, we had borrowings outstanding of $430.0 million under our credit facility. Indebtedness under our credit facility bore interest at an average rate of approximately 2.4% during the nine months ended September 30, 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—Liquidity and Capital Resources—Credit Facility.”

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

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CAPITALIZATION

The following table shows our cash and cash equivalents and capitalization as of September 30, 2014:

• on an actual basis for our predecessor; and

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

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

	As of September 30, 2014
	Black Stone Minerals, L.P. Predecessor		Black Stone Minerals, L.P.
	Actual		Pro Forma
	(unaudited) (in thousands)
Cash and cash equivalents	$	7,992	$
Credit facility	$	430,000	$	—
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		726,490		—
Noncontrolling interests		3,820		—
Total equity		730,310		—
Black Stone Minerals, L.P.
General partner’s capital		—		—
Limited partners’ capital		—
Noncontrolling interests		—		3,820
Total equity		—
Total capitalization	$	1,321,475	$

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DILUTION

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

Assumed initial public offering price per common unit	$
Pro forma net tangible book value per common unit before the offering(1)	$
Increase in net tangible book value per common unit attributable to purchasers in the offering
Less: Pro forma net tangible book value per common unit after the offering(2)
Immediate dilution in net tangible book value per common unit to purchasers in the offering

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

(2) Determined by dividing our pro forma net tangible book value, after giving effect to the use of the net proceeds of the offering, by the total number of common units outstanding after this offering.

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

	Units				Total Consideration
	Number	Percent			Amount		Percent
Limited partners of BSMC prior to this offering(1)				%					%
Purchasers in this offering				%		(2)			%
Total			100	%				100	%

(1) Reflects the value of the assets to be contributed to us by the existing limited partners of BSMC, recorded at historical cost.

(2) Reflects the net proceeds of this offering, after deducting the underwriting discount, 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

In connection with the closing of this offering, the board of directors of our general partner will adopt a policy pursuant to which we will distribute a substantial majority of the cash we generate from operations each quarter, which we expect initially to be approximately         % of our cash generated from operations. Our initial distribution will be $         per common unit on an annualized basis (or $         per unit on a quarterly basis). 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 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. It is our intention to maintain excess distribution coverage to sustain or increase that amount of our quarterly distribution. For a demonstration on how this determination will be made, please see the tables under “Pro Forma Cash Generated from Operations for the Year Ended December 31, 2013 and the Twelve Months Ended September 30, 2014” and “Estimated Cash Generated from Operations for Distribution for the Year Ending December 31, 2015.” It is our intent, for at least the next several years, to finance most of our acquisition and working-interest capital needs with cash generated from operations, the retained net proceeds from this offering, borrowings under our credit facility, and, in certain circumstances, proceeds from future equity and debt issuances. We may also borrow to make distributions to our unitholders where, for example, we believe that the distribution level is sustainable over the long term, but short-term factors may cause cash generated from operations to be insufficient to pay distributions at the current level. The board of directors of our general partner may change the foregoing distribution policy at any time and from time to time. Our partnership agreement does not require us to pay cash distributions on a quarterly or other basis. Please read “Risk Factors—Risks Inherent in an Investment in Us—The board of directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion. Our partnership agreement does not require us to pay any distributions at all. If we make distributions, our preferred unitholders have priority with respect to rights to share in those distributions over our common unitholders for so long as our preferred units are outstanding.” For a description of the relative rights and privileges of holders of our preferred units to partnership distributions, please read “—Preferred Unit Distributions.”

Replacement capital expenditures are expenditures necessary to replace our existing oil and natural gas reserves or otherwise maintain our asset base over the long term. Unlike a number of other master limited partnerships, we are not required by our partnership agreement to retain cash from our operations for replacement capital expenditures. However, we have set our initial distribution rate at a level we believe 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.

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

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

• Our common unitholders have no contractual or other legal right to receive cash distributions from us on a quarterly or other basis, and if distributions are paid, common unitholders will receive distributions

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only to the extent the distribution amount exceeds distributions that are required to be paid to our preferred unitholders. The board of directors of our general partner will adopt a policy pursuant to which we will distribute to our unitholders each quarter a substantial majority of the cash we generate from operations each quarter, as determined quarterly by the board of directors, but it may change this policy at any time.

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

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

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

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

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

• We may lack sufficient cash to pay distributions to our unitholders due to 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.

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

Preferred Unit Distributions

Prior to our liquidation, and while any of our preferred units remain outstanding, cash or other property of the partnership will be distributed to our limited partners in the following order and priority at times and in amounts as our general partner determines in its sole discretion:

(1) First, 100% to our preferred unitholders pro rata, until the aggregate Unpaid Preferred Yield of each preferred unit accrued through the last day of the immediately preceding calendar quarter has been reduced to zero; then

(2) Second, in respect of each calendar year, 100% to our common unitholders pro rata, until there has been distributed pursuant to this paragraph an aggregate amount in respect of such calendar year equal to 10% of the aggregate Interest Fair Market Value of the outstanding common units as of the first day of each calendar year; and

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(3) Finally, 100% to our common unitholders and our preferred unitholders pro rata in accordance with their interests in us, determined on an “as converted” basis.

The terms “Interest Fair Market Value,” “Preferred Yield,” and “Unpaid Preferred Yield” have the following meanings:

“Interest Fair Market Value” means, as of any date, the amount which would be received by the holder of a common unit if (a) all of the then outstanding preferred units and any other outstanding convertible securities issued by us were converted into or exchanged for common units, and (b) an amount equal to the fair market value of our assets minus our liabilities (adjusted to reflect any increases in our equity value resulting from the deemed conversion of our then outstanding preferred units and other convertible securities) were distributed to our partners.

“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, 2013 and the Twelve Months Ended September 30, 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 discussed above 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 we been formed and completed the transactions contemplated in this prospectus in earlier periods.

Following the completion of this offering, we estimate that we will incur $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, 2013 and the twelve months ended September 30, 2014, the amount of cash generated from operations that would have been available for distribution to our common unitholders, assuming that the transactions contemplated in this prospectus had been consummated on January 1, 2013 and October 1, 2013, respectively.

	Twelve Months Ended September 30, 2014			Year Ended     December 31,     2013
	(unaudited)
	(in thousands)
Revenue:
Oil and condensate sales(1)	$	254,873		$	252,742
Natural gas and natural gas liquids sales(1)		203,196			184,868
Loss on commodity derivative instruments		(2,080	)		(5,860	)
Lease bonus and other income		46,431			31,809
Total revenue	$	502,420		$	463,559
Operating (income) expense:
Lease operating expense and other		21,515			21,316
Production and ad valorem taxes		46,492			42,813
Depreciation, depletion, and amortization		111,287			102,442
Impairment of oil and natural gas properties(2)		29,479			57,109
General and administrative		59,319			59,501
Accretion of asset retirement obligations		570			588
Gain on sale of assets		—			(18	)
Total operating expense		268,662			283,751
Income from operations		233,758			179,808
Other income (expense):
Interest and investment income		38			90
Interest expense(3)		(3,631	)		(3,633	)
Other income		1,002			407
Total other expense		(2,591	)		(3,136	)
Pro forma net income		231,167			176,672
Adjustments to reconcile to pro forma Adjusted EBITDA:
Add:
Depreciation, depletion, and amortization		111,287			102,442
Interest expense		3,631			3,633
Pro forma EBITDA(4)		346,085			282,747
Add:
Impairment of oil and natural gas properties		29,479			57,109
Accretion of asset retirement obligations		570			588
Unrealized loss on commodity derivative instruments		1,315			7,350
Equity-based compensation expense(5)		10,942			6,782
Less:
Unrealized gain on commodity derivative instruments		—			—
Pro forma Adjusted EBITDA(4)	$	388,391		$	354,576

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	Twelve Months Ended September 30, 2014			Year Ended     December 31,     2013
	(unaudited)
	(in thousands, except per unit data)
Adjustments to reconcile to pro forma cash generated from operations:
Add:
Net proceeds from this offering to fund capital expenditures(6)
Less:
Deferred revenue		—			—
Incremental general and administrative(7)		(1,475	)		(1,475	)
Cash interest expense(3)		(2,665	)		(2,665	)
Capital expenditures(8)		(117,730	)		(195,631	)
Pro forma cash generated from operations	$			$
Less:
Cash paid to noncontrolling interests(9)		(327	)		(1,146	)
Preferred unit dividends(10)		(15,731	)		(15,742	)
Pro forma cash generated from operations available for distribution on common units	$			$
Pro forma cash distribution per common unit
Aggregate distributions to:
Common units issued in this offering(11)
Common units issued in the merger
Total distributions on common units
Excess (shortfall)(11)	$			$

(1) Includes revenues from our mineral and royalty interests and working interests.

(2) The impairment primarily resulted from decreasing commodity prices and changes in the projections based on the recent historical operating characteristics at the field level. For more information, please read the historical financial statements of BSMC included elsewhere in this prospectus.

(3) 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 and Data—Non-GAAP Financial Measures.”

(5) Represents compensation expense that is settled in common units and would not reduce the amount of cash generated from operations.

(6) Estimated net proceeds from this offering (based on an assumed initial offering price of $         per common unit) remaining after full repayment of our credit facility with the net proceeds from this offering. Please read “Use of Proceeds.”

(7) 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 $1.5 million related to regulatory compliance.

(8) Represents capital expenditures for acquisitions, working interests, and other corporate expenditures. Capital expenditures incurred for acquisitions were $121.6 million and $49.1 million for the year ended December 31, 2013 and for the twelve months ended September 30, 2014, respectively.

(9) Reflects cash distributions made to unaffiliated third-party limited partners in multiple partnerships in which we also own interests and that are consolidated in the historical financial statements of BSMC. For additional information, please read Note 16 to the consolidated financial statements of BSMC included elsewhere in this prospectus.

(10) Reflects dividends 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 units at the beginning of the respective periods, no preferred unit dividends would have been paid. Pro forma cash generated from operations available for distribution on common units would have increased to $         and $         for the year ended December 31, 2013 and the twelve months ended September 30, 2014, respectively and pro forma distributions per common unit would have increased by $         and $         in the respective periods.

(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                 common units as of the year ended December 31, 2013 and                 common units as of September 30, 2014, the excess (shortfall) for the year ended December 31, 2013 and for the twelve months ended September 30, 2014 would have (decreased) increased to $         and $        , respectively.

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Estimated Cash Generated from Operations for Distribution for the Year Ending December 31, 2015

During the year ending December 31, 2015, we estimate that we will generate $274.5 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 year ending December 31, 2015. 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 quarterly cash distributions on our common units.

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.

Management has prepared the prospective financial information set forth in the table below to present our expectations regarding our ability to generate $274.5 million of estimated cash generated from operations for the year ending December 31, 2015. The accompanying prospective financial information was not prepared with a view toward public disclosure or complying with the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the expected course of action and our expected future financial performance. However, this information is not fact and should not be relied upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on this prospective financial information. Inclusion of the prospective financial information in this prospectus should not be regarded as a representation by any person that the results contained in the prospective financial information will be achieved.

We do not undertake any obligation to release publicly the results of any future revisions we may make to the financial forecast or to update this financial forecast to reflect events or circumstances after the date of this prospectus. In light of the above, the statement that we believe that we will have sufficient cash generated from operations to allow us to pay the forecasted quarterly distributions on all of our outstanding common units for the year ending December 31, 2015 should not be regarded as a representation by us or the underwriters or any other person that we will make such distributions. Therefore, you are cautioned not to place undue reliance on this information.

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 year ending December 31, 2015 that would be available for distribution to our common unitholders.

	Year Ending December 31, 2015
	(in thousands, except per unit data)
Revenue:
Oil and condensate sales	$	166,573
Natural gas and natural gas liquids sales		131,051
Gain on commodity derivative instruments		38,141
Lease bonus and other income		40,200
Total revenue		375,965
Operating expense:
Lease operating expense and other		20,693
Production and ad valorem taxes		25,947
Depreciation, depletion, and amortization		113,628
Impairment of oil and natural gas properties		—
General and administrative		77,774
Accretion of asset retirement obligations		591
Gain on sale of assets		—
Total operating expense		238,633
Income from operations		137,332
Other income (expense):
Interest and investment income		—
Interest expense		(3,655	)
Other income		—
Total other expense		(3,655	)
Net income	$	133,667
Adjustments to reconcile to Adjusted EBITDA:
Add:
Depreciation, depletion, and amortization		113,628
Interest expense		3,655
EBITDA(1)		250,960
Add:
Impairment of oil and natural gas properties		—
Accretion of asset retirement obligations		591
Unrealized loss on commodity derivative instruments		—
Equity-based compensation expense(2)		26,307
Less:
Unrealized gain on commodity derivative instruments		—
Adjusted EBITDA(1)		277,858
Adjustments to reconcile to estimated cash generated from operations:
Add:
Net proceeds from this offering to fund future capital expenditures		71,012
Less:
Deferred revenue(3)		(674	)
Cash interest expense		(2,665	)
Capital expenditures		(71,012	)
Estimated cash generated from operations		274,519
Less:
Cash paid to noncontrolling interests(4)		(196	)
Preferred unit dividends(5)		(11,790	)
Estimated cash generated from operations available for distribution on common units		262,533
Estimated cash distribution per common unit(6)
Estimated aggregate distributions to:
Common units issued in this offering(7)
Common units issued in the merger(7)
Total distributions on common units
Excess(7)	$

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

(2) Represents compensation expense that is settled in common units and would not impact cash generated from operations.

(3) Represents working-interest owners’ recoupment of advance royalty payments, which results in a reduction of cash received from production revenues.

(4) Reflects cash distributions made to unaffiliated third-party limited partners in a partnership in which we also own interests and that is consolidated in the historical financial statements of BSMC. For additional information, please read Note 16 to the consolidated financial statements of BSMC included elsewhere in this prospectus.

(5) Reflects dividends 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 units at the beginning of the period, no preferred unit dividends would have been paid, estimated cash generated from operations available for distribution on common units would have increased to $        , and the estimated cash distribution per common unit would have increased by $         for the year ending December 31, 2015.

(6) Includes cash amounts to be paid or accrued with respect to distribution-equivalent rights issued in connection with a grant of                 phantom units immediately after this offering as equity-based compensation. Includes                 restricted units expected to be issued immediately after this offering as equity based compensation.

(7) Assuming the underwriters’ option to purchase additional common units to cover over-allotments is exercised in full and all of our preferred units converted into                 common units as of January 1, 2015, the excess for the year ending December 31, 2015 would have decreased to $        . In addition, assuming the underwriters’ option to purchase additional common units to cover over-allotments is not exercised in full and all of our preferred units converted into common units as of January 1, 2015, the excess for the year ending December 31, 2015 would have decreased to $        .

Assumptions and Considerations

Based upon the specific assumptions outlined below and based on the cash distribution policy we expect our board of directors to adopt, we expect to generate estimated cash from operations in an amount sufficient to allow us to pay $         per common unit on all of our outstanding common units for the year ending December 31, 2015.

While we believe that these assumptions are reasonable in light of our management’s current expectations concerning future events, the estimates underlying these assumptions are inherently uncertain and are subject to significant business, economic, regulatory, environmental, and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate. If our assumptions are not correct, the amount of actual cash 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 2015 production is derived from both our existing wells from our reserve report and from new wells projected to begin producing during the year. For oil and natural gas wells not currently producing, we utilize information from our operators regarding their drilling plans when available. Such information assists us in estimating both mineral-and-royalty-interest production as well as production from working-interest wells in which we expect to participate. In addition, we estimate incremental production based on our historical reserve replacement taking into account play-specific trends, rig counts, and other industry information that we believe may be relevant to our forecast.

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

	Year Ending December 31, 2015			Twelve Months Ended September 30, 2014			Year Ended December 31, 2013
Aggregate production:
Oil and condensate (MBbls)		3,150			2,770			2,626
Natural gas (MMcf)		40,066			42,289			45,400
Combined volumes (MBoe)		9,828			9,818			10,193
Average daily production (MBoe/d)		26.9			26.9			27.9
Percentage attributable to mineral and royalty interests:
Oil and condensate		73	%		75	%		74	%
Natural gas		66	%		66	%		63	%

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, 2013 and the twelve months ended September 30, 2014 and on a forecasted basis for the year ending December 31, 2015:

	Year Ending December 31, 2015		Twelve Months Ended September 30, 2014		Year Ended December 31, 2013
Average benchmark prices(1):
WTI oil price ($/Bbl)	$	56.28	$	99.34	$	97.98
Henry Hub natural gas price ($/Mcf)	$	3.03	$	4.39	$	3.73
Realized prices(2):
Realized oil and condensate price ($/Bbl)	$	52.88	$	92.01	$	96.25
Realized natural gas price ($/Mcf)(3)	$	3.27		4.80		4.07

(1) For historical periods, average prices were calculated using daily spot prices provided by the EIA. For the year ending December 31, 2015, the NYMEX average price curve as of December 31, 2014 was 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 year ending December 31, 2015, we have considered the oil and natural gas NYMEX price curves, our historical realized prices across our asset base, and any forecasted changes in quality or location differentials.

We recognize oil and natural gas revenue from our mineral and royalty and non-operated working interests in producing wells when the oil and natural gas production from the associated acreage is sold. We estimate our oil and natural gas revenue resulting from our mineral and royalty interests for the year ending December 31, 2015 will be $211.4 million, compared to $314.2 million and $336.6 million on a pro forma basis for the year ended December 31, 2013 and for the twelve months ended September 30, 2014, respectively. We estimate our oil and natural gas revenue resulting from our non-operated working interests for the year ending December 31, 2015 will be $86.2 million compared to $123.4 million and $121.4 million on a pro forma basis for the year ended December 31, 2013 and for the twelve months ended September 30, 2014, respectively.

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We anticipate a reduction in our mineral-and-royalty-interest revenues despite increased production from our acreage in the Eagle Ford and Bakken Shales and our geographically diverse mineral-and-royalty-interest acreage. We anticipate a decline in our working-interest revenues despite increased production from our acreage in the Bakken and Haynesville Shales. The decline in our mineral-and-royalty-interest and working-interest revenues is attributable to the decrease in realized prices for oil and natural gas forecasted for the year ending December 31, 2015. For information on the effect of changes in prices and productions volumes, please read “—Sensitivity Analysis.”

Lease Bonus and Other Income. We also generate revenue from lease bonus. When we lease our mineral interests, we generally receive an upfront cash payment, or a lease bonus. Lease bonus and other income are estimated to be $40.2 million for the year ending December 31, 2015. Approximately 82% of our mineral acreage is unleased, and we believe this acreage, along with renewals of leased acreage, will provide future bonuses in line with historical averages. Lease bonus and other income on a pro forma basis for the year ended December 31, 2013 and the twelve months ended September 30, 2014 were $31.8 million and $46.4 million, respectively.

Operating Expenses

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

Lease Operating Expenses and Other. Lease operating expenses include normally recurring expenses necessary to operate and produce hydrocarbons from our non-operated working interests in oil and natural gas wells, non-recurring well workovers, repair-related expenses, and exploration expenses. We estimate that lease operating expenses and other for the year ending December 31, 2015 will be $20.7 million as compared to $21.3 million and $21.5 million on a pro forma basis for each of the year ended December 31, 2013 and the twelve months ended September 30, 2014, respectively.

Production and Ad Valorem Taxes. Production, or severance, taxes include statutory amounts deducted from our production revenues by various state taxing entities. Depending on the states’ regulations where the production originates, these taxes may be based on a percentage of the realized value or a fixed amount per production unit. This category also includes the costs to process and transport our production to applicable sales points. Ad valorem taxes are jurisdictional taxes levied on the value of oil and natural gas minerals and reserves. Rates, methods of calculating property values, and timing of payments vary between taxing authorities. We estimate that production and ad valorem taxes for the year ending December 31, 2015 will be $25.9 million, compared to $42.8 million and $46.5 million on a pro forma basis for the year ended December 31, 2013 and the twelve months ended September 30, 2014, respectively. The reduction in production and ad valorem taxes is driven by the decline in expected revenues as a result of the current outlook 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 year ending December 31, 2015 will be $113.6 million, compared to $102.4 million and $111.3 million on a pro forma basis for the year ended December 31, 2013 and the twelve months ended September 30, 2014, respectively.

Impairment of Oil and Natural Gas Properties. Individual categories of oil and natural gas properties are assessed periodically to determine if the recorded value has been impaired. Management periodically conducts an

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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 year ending December 31, 2015; however, due to the decline in commodity prices during the fourth quarter of 2014 and the possibility of future commodity price deterioration, we may have impairment. We recognized $57.1 million and $29.5 million of impairment on a pro forma basis for the year ended December 31, 2013 and the twelve months ended September 30, 2014, respectively. 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 year ending December 31, 2015 will be $77.8 million, compared to $59.5 million and $59.3 million on a pro forma basis for the year ended December 31, 2013 and the twelve months ended September 30, 2014, respectively. General and administrative expenses for the year ending December 31, 2015 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 $1.5 million related to compliance with the Sarbanes-Oxley Act. General and administrative expenses for the year ending December 31, 2015 also include $17.9 million of incremental compensation expense we expect to incur in connection with our long-term incentive plan, which comprises $17.3 million of equity-based compensation and $0.6 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.”

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

Interest Expense. We estimate that interest expense, which includes amortization of debt issue costs, commitment fees, and agency fees, will be $3.7 million for the year ending December 31, 2015 as compared to $3.6 million and $3.6 million on a pro forma basis for the year ended December 31, 2013 and the twelve months ended September 30, 2014, respectively. We do not expect to have borrowings outstanding under our credit facility during the year ending December 31, 2015 and only expect to incur commitment and agency expense or related costs during the forecast period. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facility.”

Commodity Derivative Contracts

Our ongoing operations expose us to changes in the market price for oil and natural gas. To mitigate the given commodity price risk associated with its operations, we use derivative instruments. From time to time, such instruments may include fixed-price contracts, variable to fixed price swaps, costless collars, and other contractual arrangements. However, we currently utilize 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

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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 83.9% of our projected PDP production through the first nine months of 2014 on a Boe basis, which represented 65.8% of our actual production for the first three quarters of 2014. Taking into account new hedges executed during the first nine months of 2014, we had hedges in place for 72.5% of our actual production for the first three quarters of 2014.

For purposes of the forecast, we have assumed that we do not enter into additional commodity derivative contracts after December 31, 2014. Our existing hedges will cover 16.9 MBoe/d, or approximately 62.6% of our total forecasted production of MBoe/d for the year ending December 31, 2015. We have assumed that the commodity derivative contracts will consist of 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 year ending December 31, 2015:

	Costless Collars
	Hedged Volumes		% of Forecasted Production			Weighted- Average Floor Price		Weighted- Average Ceiling Price
Oil and condensate (MBbls)		871		27.7	%	$	84.14	$	101.71
Natural gas (MMcf)		11,070		27.6	%	$	3.80	$	4.89

	Fixed-Price Hedges
	Hedged Volumes		% of Forecasted Production			Weighted- Average Fixed Price
Oil and condensate (MBbls)		825		26.2	%	$	59.46
Natural gas (MMcf)		15,680		39.1	%	$	3.16

Capital Expenditures

We expect to spend approximately $71.0 million on capital expenditures in connection with our non-operated working interests and support equipment and facilities on a forecasted basis for the year ending December 31, 2015, compared to $74.1 million and $68.6 million on a pro forma basis for the year ended December 31, 2013 and the twelve months ended September 30, 2014, respectively.

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

Regulatory, Industry, and Economic Factors

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

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

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

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

• We will not undertake any extraordinary transactions that would materially affect our cash generated from operations.

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Forecasted Distributions

We expect that aggregate quarterly distributions on our common units for the year ending December 31, 2015 will be approximately $         million. While we believe that the assumptions we have used in preparing the estimates set forth above are reasonable based upon management’s current expectations concerning future events, they are inherently uncertain and are subject to significant business, economic regulatory, and competitive risks and uncertainties, including those described in “Risk Factors,” that could cause actual results to differ materially from those we anticipate. If our assumptions are not realized, the actual cash that we generate could be substantially less than the amount we currently estimate and could, therefore, be insufficient to permit us to pay any amount of distributions on all our outstanding common units in respect of the four calendar quarters ending December 31, 2015 or thereafter, in which event the market price of the common units may decline materially.

Sensitivity Analysis

Our ability to generate sufficient cash from operations to pay distributions to our common unitholders is a function of two primary variables: (i) production volumes and (ii) commodity prices. In the paragraphs below, we demonstrate the impact that changes in either of these variables, while holding all other variables constant, would have on our ability to generate sufficient cash from our operations to pay quarterly distributions on our common units for the year ending December 31, 2015.

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 year ending December 31, 2015.

	Percentage of Forecasted Annual Production
	90%		100%		110%
Forecasted annual production:
Oil and condensate (MBbls)		2,835		3,150		3,465
Natural gas (MMcf)		36,059		40,066		44,073
Combined volumes (MBoe)		8,845		9,828		10,810
Forecasted average daily production:
Oil and condensate (MBbl/d)		7.8		8.6		9.5
Natural gas (MMcf/d)		98.8		109.8		120.7
Combined volumes (MBoe/d)		24.2		26.9		29.6
Forecasted average sales prices:
WTI oil price ($/Bbl)	$	56.28	$	56.28	$	56.28
Realized oil and condensate sales price ($/Bbl)(1)	$	52.88	$	52.88	$	52.88
Henry Hub natural gas price ($/Mcf)	$	3.03	$	3.03	$	3.03
Realized natural gas sales price ($/Mcf)(1)	$	3.27	$	3.27	$	3.27
Estimated cash generated from operations (in thousands):
Oil and condensate sales	$	149,915	$	166,573	$	183,230
Natural gas and natural gas liquids sales		117,946		131,051		144,156
Gain (loss) on commodity derivative instruments(2)		38,141		38,141		38,141
Lease bonus and other income		40,200		40,200		40,200
Operating expenses		236,038		238,633		241,228
Estimated cash generated from operations	$	247,352	$	274,519	$	301,687

(1) Excluding cash settlement on commodity derivative instruments.

(2) Represents cash settlement on commodity derivative instruments maturing in 2015.

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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 year ending December 31, 2015. The amounts shown below are based on forecasted realized commodity prices that take into account our average NYMEX commodity price differential assumptions. We have assumed no changes in our production based on changes in prices.

	Change in Forecasted Commodity Prices
	90%		100%		110%
Forecasted annual production:
Oil and condensate (MBbls)		3,150		3,150		3,150
Natural gas (MMcf)		40,066		40,066		40,066
Combined volumes (MBoe)		9,828		9,828		9,828
Forecasted average daily production:
Oil and condensate (MBbl/d)		8.6		8.6		8.6
Natural gas (MMcf/d)		109.8		109.8		109.8
Combined volumes (MBoe/d)		26.9		26.9		26.9
Forecasted average sales prices:
WTI oil and condensate price ($/Bbl)	$	50.65	$	56.28	$	61.91
Realized oil and condensate sales price ($/Bbl)(1)	$	47.22	$	52.88	$	58.54
Henry Hub natural gas price ($/Mcf)	$	2.73	$	3.03	$	3.33
Realized natural gas sales price ($/Mcf)(1)	$	2.94	$	3.27	$	3.60
Estimated cash generated from operations (in thousands):
Oil and condensate sales	$	148,730	$	166,573	$	184,415
Natural gas and natural gas liquids sales		117,946		131,051		144,156
Gain (loss) on commodity derivative instruments(2)		55,792		38,141		20,491
Lease bonus and other income		40,200		40,200		40,200
Operating expenses		235,908		238,633		241,357
Estimated cash generated from operations	$	264,015	$	274,519	$	285,025

(1) Excluding cash settlement on commodity derivative instruments.

(2) Represents cash settlement on commodity derivative instruments maturing in 2015.

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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 year ending December 31, 2015. Please see “—Assumptions and Considerations.” The assumptions and considerations underlying the forecast for the year ending December 31, 2015 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
	December 31, 2015			September 30, 2015			June  30, 2015			March 31, 2015
	(in thousands)
Revenue:
Oil and condensate sales	$	42,900		$	43,630		$	40,372		$	39,671
Natural gas and natural gas liquids sales		35,727			32,325			30,718			32,281
Gain on commodity derivative instruments		2,011			5,836			13,758			16,535
Lease bonus and other income(1)		14,050			12,050			8,050			6,050
Total revenue		94,688			93,841			92,898			94,537
Operating expense:
Lease operating expense and other		5,253			5,041			5,137			5,262
Production and ad valorem taxes		6,855			6,596			6,206			6,290
Depreciation, depletion, and amortization		28,772			28,496			28,255			28,105
Impairment of oil and natural gas properties		—			—			—			—
General and administrative		19,168			19,168			19,168			20,268
Accretion of asset retirement obligations		148			148			148			148
Gain on sale of assets		—			—			—			—
Total operating expense	$	60,196		$	59,449		$	58,914		$	60,073
Income from operations	$	34,492		$	34,392		$	33,984		$	34,464
Other income (expense):
Interest and investment income		—			—			—			—
Interest expense		(923	)		(898	)		(897	)		(938	)
Other income		—			—			—			—
Total other expense		(923	)		(898	)		(897	)		(938	)
Net income	$	33,569		$	33,494		$	33,087		$	33,526

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	Three Months Ending
	December 31, 2015			September 30, 2015			June  30, 2015			March 31, 2015
	(in thousands)
Adjustments to reconcile to Adjusted EBITDA:
Add:
Depreciation, depletion, and amortization		28,772			28,496			28,255			28,105
Interest expense		923			898			897			938
EBITDA		63,264			62,888			62,239			62,569
Add:
Impairment of oil and natural gas properties		—			—			—			—
Accretion of asset retirement obligations		148			148			148			148
Unrealized loss on commodity derivative instruments		—			—			—			—
Equity-based compensation expense		8,047			5,720			5,720			6,820
Less:
Unrealized gain on commodity derivative instruments		—			—			—			—
Adjusted EBITDA		71,459			68,756			68,107			69,537
Adjustments to reconcile to estimated cash generated from operations:
Add:
Net proceeds from this offering to fund future capital expenditures		20,660			23,945			15,640			10,767
Less:
Deferred revenue		(329	)		(147	)		(89	)		(110	)
Cash interest expense		(656	)		(656	)		(656	)		(697	)
Capital expenditures		(20,660	)		(23,945	)		(15,640	)		(10,767	)
Estimated cash generated from operations		70,474			67,953			67,362			68,730
Less:
Cash paid to noncontrolling interests(2)		(50	)		(48	)		(48	)		(52	)
Preferred unit dividends		(2,972	)		(2,972	)		(2,939	)		(2,907	)
Estimated cash generated from operations available for distribution on common units		67,454			64,933			64,375			65,771
Estimated cash distribution per common unit
Estimated aggregate distributions to:
Common units issued in this offering
Common units issued in the merger
Total distributions on common units
Excess	$			$			$			$

(1) Lease bonus income can vary from quarter to quarter. Historically, lease bonus income has been higher in the third and fourth quarters relative to the first and second quarters.

(2) Reflects cash distributions made to unaffiliated third-party limited partners in a partnership in which we also own interests and that is consolidated in the historical financial statements of BSMC. For additional information, please read Note 16 to the consolidated financial statements of BSMC included elsewhere in this prospectus.

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The following table sets forth information regarding production associated with our mineral and royalty interests and non-operated working interests on a forecasted basis for each quarter during the year ending December 31, 2015. Although the above forecasted amounts are based upon assumptions we believe to be reasonable, there can be no assurance that actual quarter-by-quarter information will not differ materially from the quarter-by-quarter forecast information presented below:

	Three Months Ending
	December 31, 2015			September 30, 2015			June 30, 2015			March 31, 2015
Aggregate production:
Oil and condensate (MBbls)		775			812			783			780
Natural gas (MMcf)		10,570			9,821			9,678			9,996
Combined volumes (MBoe)		2,537			2,449			2,396			2,446
Average daily production (MBoe/d)		27.6			26.6			26.3			27.2
Percentage attributable to mineral and royalty interests:
Oil and condensate		73	%		74	%		73	%		72	%
Natural gas		63	%		67	%		69	%		67	%

The following table illustrates the relationship between average oil and natural gas realized sales prices and the average WTI oil and Henry Hub natural gas prices on a forecasted basis for each quarter during the year ending December 31, 2015. Although the above forecasted amounts are based upon assumptions we believe to be reasonable, there can be no assurance that actual quarter-by-quarter information will not differ materially from the quarter-by-quarter forecast information presented below:

	Three Months Ending
	December 31, 2015		September 30, 2015		June 30, 2015		March 31, 2015
Average benchmark prices(1):
WTI oil price ($/Bbl)	$	58.79	$	56.88	$	54.96	$	54.50
Henry Hub natural gas price ($/Mcf)	$	3.20	$	3.02	$	2.91	$	2.99
Realized prices(2):
Realized oil and condensate price ($/Bbl)	$	55.35	$	53.73	$	51.56	$	50.86
Realized natural gas price ($/Mcf)(3)	$	3.38	$	3.29	$	3.17	$	3.23

(1) The NYMEX average price curve as of December 31, 2014 was 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 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.

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SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA

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

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

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

We have not given pro forma effect to incremental general and administrative expenses of approximately $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 selected historical financial data contained in the following table, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The following table should also be read in conjunction with “Use of Proceeds” and the audited and unaudited historical financial statements of BSMC 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
	Nine Months Ended September 30,						Year Ended December 31,						Nine Months Ended September 30, 2014			Year Ended December 31, 2013
	2014			2013			2013			2012
	(unaudited)												(unaudited)
	(in thousands)
Revenue:
Oil and condensate sales	$	195,665		$	193,534		$	252,742		$	202,104		$	195,665		$	252,742
Natural gas and natural gas liquids sales		156,554			138,226			184,868			166,849			156,554			184,868
Gain (loss) on commodity derivative instruments		339			(3,441	)		(5,860	)		12,275			339			(5,860	)
Lease bonus and other income		26,586			11,964			31,809			53,918			26,586			31,809
Total revenue		379,144			340,283			463,559			435,146			379,144			463,559
Operating (income) expense:
Lease operating expense and other		16,151			15,952			21,316			20,527			16,151			21,316
Production and ad valorem taxes		33,589			29,910			42,813			36,680			33,589			42,813
Depreciation, depletion, and amortization		84,058			75,213			102,442			104,059			84,058			102,442
Impairment of oil and natural gas properties		—			27,630			57,109			62,987			—			57,109
General and administrative		45,607			45,789			59,501			50,348			45,607			59,501
Accretion of asset retirement obligations		443			461			588			608			443			588
Gain on sale of assets		—			(18	)		(18	)		(363	)		—			(18	)
Total operating expense		179,848			194,937			283,751			274,846			179,848			283,751
Income from operations		199,296			145,346			179,808			160,300			199,296			179,808
Other income (expense):
Interest and investment income		27			79			90			209			27			90
Interest expense(1)		(10,292	)		(7,922	)		(11,342	)		(9,166	)		(2,733	)		(3,633	)
Other income		869			274			407			467			869			407
Total other expense		(9,396	)		(7,569	)		(10,845	)		(8,490	)		(1,837	)		(3,136	)
Net income	$	189,900		$	137,777		$	168,963		$	151,810		$	197,459		$	176,672
Statement of Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	278,398		$	218,305		$	320,764		$	358,002
Investing activities		(92,545	)		(170,446	)		(195,631	)		(198,975	)
Financing activities		(207,984	)		(77,952	)		(142,311	)		(138,172	)
Other Financial Data:
EBITDA(2)	$	284,250		$	220,912		$	282,747		$	265,035		$	284,250		$	282,747
Adjusted EBITDA(2)		288,437			257,252			354,576			346,574			288,437			354,576
Capital expenditures(3)		(92,545	)		(170,446	)		(195,631	)		(198,975	)
Balance Sheet Data (at period end):
Cash and cash equivalents	$	7,992					$	30,123		$	47,301		$
Total assets		1,444,467						1,444,413			1,199,187
Credit facilities		430,000						451,000			363,100			—
Total liabilities		552,992						566,618			711,143			122,992
Total mezzanine equity		161,165						161,392			161,381			161,165
Total equity		730,310						716,403			326,663

(1) Includes cash expenses for commitment fees and agency fees and non-cash amortization of debt issuance costs.

(2) Please read “Summary—Summary Historical and Pro Forma Financial Data—Non-GAAP Financial Measures” 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 GAAP.

(3) Net of proceeds from the sale of assets of $0.1 million and $1.0 million for the years ended December 31, 2013 and December 31, 2012, respectively, and no proceeds for the nine months ended September 30, 2014 and $0.1 million for the nine months ended September 30, 2013.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Overview

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

Our mineral and royalty interests consist of mineral interests in approximately 14.5 million acres, with an average 48.1% ownership interest in that acreage, NPRIs in 1.2 million acres, and ORRIs in 1.3 million acres. These non-cost-bearing interests include ownership in approximately 40,000 producing wells. We also own non-operated working interests. We recognize oil and natural gas revenue from our mineral and royalty and non-operated working interests in producing wells when the oil and natural gas production from the associated acreage is sold. Our other sources of revenue include mineral lease bonus and delay rentals, which are recognized as revenue according to the terms of the lease agreements.

Business Environment

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

Rig Count

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

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

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

	Third Quarter 2014		Second Quarter 2014		First Quarter 2014		Fourth Quarter 2013
Oil		1,592		1,558		1,487		1,382
Natural gas		338		314		318		374
Other		1		1		4		1
Total		1,931		1,873		1,809		1,757

Source: Baker Hughes Incorporated

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Natural Gas Storage

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

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

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

Location	Third Quarter 2014 (Bcf)		Second Quarter 2014 (Bcf)		First Quarter 2014 (Bcf)		Fourth Quarter 2013 (Bcf)
East(1)		1,714		923		310		1,501
West(2)		453		331		160		412
Producing(3)		933		675		352		1,061
Total		3,100		1,929		822		2,974

Source: EIA

(1) CT, DE, DC, FL, GA, IA, IL, IN, KY, MA, MD, ME, MI, MO, NC, NE, NH, NJ, NY, OH, PA, RI, SC, TN, VT, VA, WI, and WV

(2) AZ, CA, CO, ID, MN, MT, NV, ND, OR, SD, WA, WY, and UT

(3) AL, AR, KS, LA, MI, NM, OK, and TX

How We Evaluate Our Operations

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

• volumes of oil and natural gas produced;

• commodity prices; and

• EBITDA and Adjusted EBITDA.

Volumes of Oil and Natural Gas Produced

In order to assess and track performance of our assets, we monitor and analyze production volumes from the various basins and plays that comprise our extensive asset base. We also periodically compare projected volumes to actual reported volumes and investigate unexpected variations. Please read “Business—Estimated Proved Reserves—Summary of Estimated Proved Reserves.”

Commodity Prices

Factors Affecting the Sales Price of Oil and Natural Gas

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

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

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

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

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

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

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

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

Hedging

We enter into derivative instruments to partially mitigate the impact of commodity price volatility on our cash generated from operations. From time to time, such instruments may include fixed-price contracts, variable to fixed price swaps, costless collars, and other contractual arrangements. However, we currently utilize only costless collars. In addition, we 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. For further information, please read “— Quantitative and Qualitative Disclosures About Market Risk.”

EBITDA; Adjusted EBITDA

EBITDA and Adjusted EBITDA are non-GAAP supplemental financial measures used by our management and by external users of our financial statements such as investors, 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.

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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 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.

Factors Affecting the Comparability of Our Financial Results

Our historical financial condition and results of operations for the periods presented may not be comparable, either from period to period or going forward, because we will incur annual incremental general and administrative expenses as a result of operating as a publicly traded partnership, which includes expenses associated with SEC reporting requirements, including annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, Sarbanes-Oxley Act compliance, NYSE listing, independent registered public accounting firm fees, legal fees, investor-relations activities, registrar and transfer agent fees, director-and-officer insurance, and additional compensation. These direct, incremental general and administrative expenses are not included in our historical results of operations.

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Results of Operations

Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013

Revenues

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

	Nine Months Ended September 30,
	2014		2013
	(unaudited)
Production:
Oil and condensate (MBbls)		2,106		1,962
Natural gas (MMcf)		31,173		34,285
Equivalents (Boe)(1)		7,302		7,676
Realized prices:
Oil and condensate ($/Bbl)	$	92.91	$	98.64
Natural gas ($/Mcf)(2)		5.02		4.03
Combined equivalents ($/Boe)	$	48.24	$	43.22
Revenue:
Oil and condensate sales	$	195,665	$	193,534
Natural gas and natural gas liquids sales		156,554		138,226
Gain (loss) on commodity derivative instruments		339		(3,441	)
Lease bonus and other income		26,586		11,964
Total revenue	$	379,144	$	340,283

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

(2) As a mineral-and-royalty-interest owner, we are often provided insufficient and inconsistent data by our operators. As a result, we are unable to reliably determine the total volumes of NGLs associated with the production of natural gas on our acreage. As such, the realized prices account for all sales attributable to NGLs. The oil and condensate production volumes and natural gas production volumes do not include NGL volumes.

Total revenues for the nine months ended September 30, 2014 increased $38.9 million, or 11.4%, compared to the nine months ended September 30, 2013. The increase was comprised of $22.7 million as a result of higher realized commodity prices, $14.6 million from higher lease bonus, and $3.8 million from derivatives, offset by a decrease of $2.2 million as a result of lower production volumes.

Oil and condensate sales during the period were $2.1 million, or 1.1%, higher than the corresponding period in 2013 primarily due to an increase in production volumes. Our mineral-and-royalty-interest oil volumes accounted for 76.0% and 73.6% of total oil and condensate volumes for the nine months ended September 30, 2014 and the nine months ended September 30, 2013, respectively. The 10.8% increase in mineral-and-royalty-interest oil volumes, period to period, was driven primarily by production increases from new wells in the Eagle Ford Shale. Our working-interest oil volumes decreased by 2.2% to 505.5 MBbls during the first three quarters of 2014 versus the comparable period of 2013 primarily due to a reduction in the amount of capital expenditures in the Granite Wash and Woodford plays, which reduced production volumes. This decrease was almost entirely offset by volumes added from new wells in the Bakken/Three Forks play. A 5.8% decrease in realized oil prices partially offset the overall increase in oil and condensate revenue and production.

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Natural gas revenues increased by $18.3 million, or 13.3%, for the nine months ended September 30, 2014 as compared to the same period for 2013. A 24.6% increase in the realized natural gas price for the first nine months of 2014 versus the same period in 2013 generated the increase. The favorable price variance was partially offset by a decrease in produced volumes. As we expected, natural gas production declined from period to period. The 9.1% decline in both mineral-and-royalty-interest and working-interest volumes was primarily driven by the run-off in production in the Hayneville/Bossier play. In 2008 and 2009, we entered into lease agreements which covered the majority of our Hayneville/Bossier play acreage in Louisiana and Texas. As operators drilled wells to hold acreage, our natural gas production increased significantly in the play, with the volumes peaking in 2012. With most acreage now held by production, many operators have moved drilling rigs out of the play. Although these wells initially produce at high rates, they tend to decline rapidly, so without consistent drilling activity to replace the high decline rates of the individual wells, the overall production rate from the play has declined. While operators have recently begun to increase the drilling activity on our acreage, the production from these new wells has not yet reached the point of offsetting the declines in the existing wells. Mineral-and-royalty-interest production made up 66.0% and 61.8% of our natural gas volumes for the first nine months of 2014 and 2013, respectively.

Lease bonus and delay-rental revenue increased $14.6 million, or 122.2%, for the nine months ended September 30, 2014 as compared to the same period in 2013. The increase primarily resulted from the successful closing of several significant leases in the Canyon Lime and Canyon Wash plays and the Permian Basin during the first three quarters of 2014.

Operating Expenses

Lease Operating Expenses and Other. Lease operating expenses include normally recurring expenses necessary to operate and produce hydrocarbons from our non-operated working interests in oil and natural gas wells, non-recurring well workovers, repair-related expenses, and exploration expenses. Lease operating expenses did not vary significantly for the nine months ended September 30, 2014 as compared to the same period in 2013.

Production and Ad Valorem Taxes. Production, or severance, taxes include statutory amounts deducted from our production revenues by various state taxing entities. Depending on the states’ regulations where the production originates, these taxes may be based on a percentage of the realized value or a fixed amount per production unit. This category also includes the costs to process and transport our production to applicable sales points. Ad valorem taxes are jurisdictional taxes levied on the value of oil and natural gas minerals and reserves. Rates, methods of calculating property values, and timing of payments vary between taxing authorities. For the nine months ended September 30, 2014, production and ad valorem taxes increased by $3.7 million, or 12.3%, over the nine months ended September 30, 2013, generally as a result of higher oil and natural gas sales.

Depreciation, Depletion, and Amortization Expense. Depletion is the amount of cost basis of oil and natural gas properties at the beginning of a period attributable to the volume of hydrocarbons extracted during such period, calculated on a unit-of-production basis. Estimates of proved developed producing reserves are a major component of the calculation of depletion. We have historically adjusted our depletion rates in the fourth quarter of each year based upon the year-end reserve report and other times during the year when circumstances indicate that there has been a significant change in reserves or costs. Depreciation, depletion, and amortization increased $8.8 million, or 11.8%, primarily due to an increase in our overall average depletion rate by field. The nine-month average rate was reduced by downward reserve revisions, which resulted from adjustments to projected lease operating expenses and shrinkage values. In addition, during the third quarter of 2014, we experienced higher depletion expense for certain of our working-interest wells due to rapidly declining reservoir characteristics; however, lower natural gas production volumes served to partially mitigate this increase in depletion expense.

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

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in-depth evaluation of the cost of property acquisitions, successful exploratory wells, development activities, unproved leasehold, and mineral interests to identify impairments. Impairments totaled $27.6 million for the nine months ended September 30, 2013 primarily due to the impact that changes in price had on the value of our reserve estimates. The primary areas negatively affected by impairments were the Appalachian Basin and the Haynesville/Bossier and Barnett Shale plays. No impairments were recorded during the nine months ended September 30, 2014.

General and Administrative. During the nine months ended September 30, 2014, general and administrative expenses decreased by $0.2 million, or less than 1.0% as compared to the same time period in 2013. In 2013, we incurred legal fees and recording fees associated with our exchange offer as well as an acquisition-related broker fee. In 2014, expenses attributable to our long-term incentive plans were higher than in the prior period. Please read the notes to the historical financial statements of BSMC included elsewhere in this prospectus for additional information regarding the exchange offer.

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

Interest Expense. Interest expense increased by $2.4 million, or 29.9%, due to additional borrowings under our credit facility. Outstanding borrowings during 2014 were higher than 2013, primarily due to increased expenditures for acquisitions, drilling activity, and funding of common equity repurchases during 2013.

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

Revenues

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

	Year Ended December 31,
	2013			2012
Production:
Oil and condensate (MBbls)(1)		2,626			2,173
Natural gas (MMcf)(1)		45,400			52,965
Equivalents (MBoe)(2)		10,193			11,001
Realized Prices:
Oil and condensate ($/Bbl)	$	96.25		$	93.01
Natural gas ($/Mcf)(1)(2)		4.07			3.15
Combined equivalents ($/Boe)	$	42.93		$	33.54
Revenue:
Oil and condensate sales	$	252,742		$	202,104
Natural gas and natural gas liquids sales		184,868			166,849
Gain (loss) on commodity derivative instruments		(5,860	)		12,275
Lease bonus and other income		31,809			53,918
Total revenue	$	463,559		$	435,146

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

(2) As a mineral-and-royalty-interest owner, we are often provided insufficient and inconsistent data by our operators. As a result, we are unable to reliably determine the total volumes of NGLs associated with the production of natural gas on our acreage, and these production amounts exclude NGL quantities. As such, the realized prices account for all sales attributable to NGLs. The oil and condensate production volumes and natural gas production volumes do not include NGL volumes.

Total revenues for the year ended December 31, 2013 increased $28.4 million, or 6.5%, compared to 2012. The increase was comprised of $55.8 million as a result of higher realized commodity prices and $12.8 million as a result of a change in product mix. The increase was offset by a decrease in lease bonus revenue of $22.1 million and derivatives revenue of $18.1 million.

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

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

Operating Expenses

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

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

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

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

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General and Administrative. General and administrative expenses increased $9.2 million, or 18.2%, in 2013, as compared to 2012, primarily as a result of higher personnel and benefit expenses, costs associated with our long-term incentive plans, an acquisition-related broker fee, contractor fees resulting from land and title work, and higher exchange-offer-related costs, relative to 2012, including legal fees, recording fees associated with the acquired assets, and other professional fees.

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

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

Liquidity and Capital Resources

Overview

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

In connection with the closing of this offering, the board of directors of our general partner will adopt a policy pursuant to which we will distribute a substantial majority of the cash we generate from operations each quarter. 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. Our initial distribution will be $         per common unit on an annualized basis (or $         per unit on a quarterly basis), which we forecast to represent approximately     % of our cash generated from operations for the year ending December 31, 2015. We may borrow to make distributions to our unitholders when, for example, we believe that the distribution level is sustainable over the long term, but short-term factors may cause cash generated from operations to be insufficient to pay the distribution at the then-current level. The board of directors of our general partner may change the foregoing distribution policy at any time and from time to time. Our partnership agreement does not require us to pay cash distributions on a quarterly or other basis.

It is our intent, for at least the next several years, to finance most of our acquisitions and working-interest capital needs with cash generated from operations, the retained net proceeds from this offering and borrowings from our credit facility and, in certain circumstances, proceeds from future equity and debt issuances. Replacement capital expenditures are expenditures necessary to replace our existing oil and natural gas reserves or otherwise maintain our asset base over the long-term. Unlike a number of other master limited partnerships, we are not required by our partnership agreement to retain cash from our operations for replacement capital expenditures. However, we have set our initial distribution rate at a level we believe 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.

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

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Cash Flows

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

	Nine Months Ended September 30,						Year Ended December 31,
	2014			2013			2013			2012
	(unaudited)
Cash flows from operating activities	$	278,398		$	218,305		$	320,764		$	358,002
Cash flows used in investing activities	$	(92,545	)	$	(170,446	)	$	(195,631	)	$	(198,975	)
Cash flows used in financing activities	$	(207,984	)	$	(77,952	)	$	(142,311	)	$	(138,172	)

Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013

Operating Activities. Our operating cash flow is dependent in large part on our production, realized commodity prices, leasing revenues, and operating expenses. For the nine months ended September 30, 2014, cash flows from operating activities increased by $60.1 million as compared to the same period in 2013 due to increased realized natural gas prices and higher oil and condensate volumes.

Investing Activities. The net cash used in investing activities decreased by $77.9 million in the first nine months of 2014 as compared to the same period in 2013 primarily due to reduced capital spent on acquisitions and lower capital expenditures under our working-interest participation program. For the nine months ended September 30, 2014, our cash expenditures for acquisitions totaled $39.8 million versus $112.3 million for the same period in 2013. Expenditures for our working interests decreased by $5.4 million to $52.4 million for the first nine months of 2014 versus the comparable period of 2013.

Financing Activities. For the first three quarters of 2014, the net cash used in financing activities increased $130.0 million compared to the same period in 2013. During the first nine months of 2013, we received $191.6 million in equity contributions as a result of our exchange offer and borrowed $117.0 million under our credit facility. These activities were partially offset by common equity repurchases of $93.8 million, repayments under our credit facility of $46.1 million, and purchases of noncontrolling interests of $60.7 million. Please read the notes to the historical financial statements of BSMC included elsewhere in this prospectus for additional information regarding the exchange offer.

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

Operating Activities. Cash flows from operating activities decreased by $37.2 million for 2013 as compared to 2012 primarily due to the fact that lease bonus revenue was $22.1 million lower in 2013; certain leasing arrangements were being negotiated during the latter part of 2013, but the actual execution of such documents was delayed until 2014. In addition, cash flow from operating activities was positively impacted in 2012 by $7.9 million as result of a prepaid royalty that was received in 2012 but was deferred and did not impact the statement of operations until 2013.

Investing Activities. The net cash used in investing activities was essentially unchanged for the year ended December 31, 2013 as compared to the same period in 2012. For 2013, total cash expenditures for acquisitions increased by $11.2 million to $121.6 million but were offset by a $15.6 million reduction of capital spent on our working interests. The reduction in drilling capital was attributable to a decline in expenditures for the Haynesville/Bossier play and a delay until 2014 in the drilling of wells in the Bakken/Three Forks play.

Financing Activities. In 2013, net cash used by financing activities was $4.1 million higher than 2012.

Capital Expenditures

During the first nine months of 2014, we spent approximately $39.8 million on three acquisitions using cash on hand and completed another acquisition for $2.3 million with an issuance of equity securities. Our 2014 capital forecast for drilling and completion is approximately $73.0 million. Approximately 41% and 29% of our

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drilling capital budget will be spent in the Bakken/Three Forks play and the Haynesville/Bossier play, respectively, with the remainder spent in various plays including the Granite Wash. As of September 30, 2014, the substantial majority of our 2014 drilling and completion budget was either spent or committed. Accordingly, we do not expect that any delays in drilling under this program would have a material impact on our 2014 results of operations.

Credit Facility

As of January 23, 2015, we amended and restated our $1.0 billion senior secured revolving credit agreement. Under this third amended and restated credit facility, the commitment of the lenders equals the lesser of the aggregate maximum credit amounts of the lenders and the borrowing base (which is determined based on the value of our oil and natural gas properties). As of September 30, 2014, the borrowing base was $700.0 million, and we had outstanding borrowings of $430.0 million. As of the closing of the third amended and restated credit facility on January 23, 2015, the borrowing base was reaffirmed at $700.0 million. The third amended and restated credit facility will terminate on February 3, 2017. Borrowings under the third amended and restated credit facility may be used for the acquisition of properties, cash distributions, and other general corporate purposes.

Outstanding borrowings under the third amended and restated credit agreement bear interest at a floating rate elected by us equal to an alternative base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5% and 1-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.50% to 1.50% in the case of the alternative base rate and from 1.50% to 2.50% in the case of LIBOR, in each case depending on the amount of borrowings outstanding in relation to the borrowing base. We are obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the borrowing base, which fee is also dependent on the amount of the borrowings outstanding in relation to the borrowing base. Principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage) and is required to be paid (a) if the amount outstanding exceeds the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period) and (b) at the maturity date. The facility is secured by liens on substantially all of our properties.

The third amended and restated credit agreement contains various affirmative, negative, and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements, and require the maintenance of certain financial ratios. The lenders have the right to accelerate all of the indebtedness under the third amended and restated credit facility upon the occurrence and during the continuance of any event of default, and the third amended and restated credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy, and change of control. There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods.

Contractual Obligations

The following table summarizes our minimum payments as of December 31, 2013 (in thousands):

			Payments due by period
	Total		Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years
Credit facility	$	451,000	$	—	$	—	$	451,000	$	—
Operating lease obligations		3,961		1,294		2,667		—		—
Total	$	454,961	$	1,294	$	2,667	$	451,000	$	—

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Off-Balance Sheet Arrangements

At December 31, 2013, we did not have any material off-balance sheet arrangements.

Critical Accounting Policies and Related Estimates

The discussion and analysis of our financial condition and results of operations are based upon the historical financial statements of BSMC, which have been prepared in accordance with GAAP. Certain of our accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts would have been reported under different conditions, or if different assumptions had been used. The following discussions of critical accounting estimates, including any related discussion of contingencies, address all important accounting areas where the nature of accounting estimates or assumptions could be material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change. Below, we have provided expanded discussion of our more significant accounting estimates.

Please read the notes to the historical financial statements of BSMC included elsewhere in this prospectus for additional information regarding our accounting policies.

Successful Efforts Method of Accounting

We use the successful efforts method of accounting for oil and natural gas operations. Under this method, costs to acquire interests in oil and natural gas properties are capitalized. The cost of property acquisitions, successful exploratory wells, development costs, and support equipment and facilities are initially capitalized when incurred. DD&A of producing oil and natural gas properties is recorded based on units of production. Acquisition costs of proved properties are amortized on the basis of all proved reserves, developed and undeveloped, and capitalized development costs are amortized on the basis of proved developed reserves. Other exploratory costs, including annual delay rentals and geological and geophysical costs, are charged to expense when incurred. Mineral and royalty interests and working interests are recorded at cost at the time of acquisition. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized.

The costs of unproved leaseholds and mineral interests are capitalized as unproved properties pending the results of exploration efforts. As unproved leaseholds are determined to be producing, the related costs are transferred to producing properties. The remaining net book values associated with unproved leaseholds that have expired are charged to exploration expense. Non-producing property costs are assessed periodically, on a property-by-property basis, and a loss is recognized to the extent, if any, the recorded value has been impaired. Any impairment will generally be based on geographic or geologic data.

Mineral interests are recorded at cost at the time of acquisition. Mineral interests are assessed for impairment annually via comparison to third-party valuation information and a loss is recognized to the extent fair value is below the recorded value.

We evaluate impairment of producing properties in accordance with Accounting Standards Codification (“ASC”) 360 Property, Plant, and Equipment. This standard requires that long-lived assets that are held and used by an entity be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. We estimate the future cash flows expected in connection with the properties and compare such future cash flows to the carrying amount of the properties to determine if the carrying amount is recoverable. When the carrying amount of a property exceeds its estimated undiscounted future cash flows, the carrying amount is reduced to its fair value. Fair value is calculated as the present value of estimated future cash flows of such properties. The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing of future production, future capital expenditures, and a risk-adjusted discount rate.

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Asset Retirement Obligations

Under various contracts, permits, and regulations, we have legal obligations to restore the land at the end of operations at certain sites. Estimating the future restoration costs necessary for this accounting calculation is difficult. Most of these restoration obligations are many years, or decades, in the future and the contracts and regulations often have vague descriptions of what practices and criteria must be met when the event actually occurs. Asset-restoration technologies and costs, regulatory and other compliance considerations, expenditure timing, and other inputs into valuation of the obligation, including discount and inflation rates, are also subject to change.

Revenue Recognition

We recognize revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller’s price to the buyer is fixed or determinable, and (iv) collectability is reasonably assured. We recognize oil and natural gas revenue from our interests in producing wells when the associated production is sold. Our other sources of revenue include mineral lease bonus and delay rentals, which are recognized as revenue according to the terms of the lease agreements. We generate lease bonus revenue from leasing our mineral interests to other exploration and production companies. The lease agreements transfer the rights to any oil or natural gas discovered, grant us a right to a specified royalty interest and require that drilling be done within a specified time period. We recognize such lease bonus revenue at which time the lease agreement has been executed, payment has been collected, and we have no further obligation to refund the payment. We also recognize revenue from delay rentals to the extent drilling has not started within the specified period, payment has been collected, and we have no further obligation to refund the payment.

Derivatives and Financial Instruments

Our ongoing operations expose us to changes in the market price for oil and natural gas. To mitigate the given commodity price risk associated with its operations, we use derivative instruments. From time to time, such instruments may include fixed-price contracts, variable to fixed price swaps, costless collars, and other contractual arrangements. However, we currently utilize only costless collars. We do not enter into derivative instruments for speculative purposes. In addition, we 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.

In accordance with ASC 815, Derivatives and Hedging, derivative instruments are initially recognized at fair value on the date on which a derivative contract is entered into and are subsequently remeasured at fair value. If a right of offset exists under master netting arrangements and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on the consolidated balance sheet. Gains and losses arising from changes in the fair value of derivatives are recognized on a net basis in the accompanying consolidated statements of operations within gain (loss) on commodity derivative instruments.

Although these derivative instruments may expose us to credit risk, we monitor the creditworthiness of our counterparties.

Equity-Based Compensation

We recognize equity-based compensation expense for restricted common units awarded to our employees and the board of directors of our general partner. The total compensation expense related to the time-based restricted common units is measured as the number of units granted multiplied by the grant date fair value per unit. Compensation expense is recognized on a straight-line basis over the service period (generally equivalent to the vesting period).

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Our board of directors determined the fair value of the equity-based awards’ unit price by considering various objective and subjective factors, along with input from management, and using the same methodology as required under our partnership agreement for purposes of us purchasing common units from those limited partners who exercise their right under the partnership agreement to annually sell a portion of their common units. To determine the fair value of the equity-based awards’ unit price, we consider information provided by third-party consultants and rely on generally accepted valuation techniques, which include, but are not limited to, the net asset value method under the asset approach, the guideline public company method under the market approach, and the dividend discount method of the income approach. Our estimate of value using the net asset value method was derived using assumptions including commodity prices, estimated development timing of our acreage, and market-based discount rates. The value conclusion using the guideline public company method was estimated by considering peer company performance metrics, comparability of the peer company portfolio and risk profiles to the Company, and implied forward distribution yields and multiples. To estimate the value of the awards using the transaction method, we reviewed publicly available data related to acquisitions of mineral properties and applied the implied deal metrics to our performance measures. The dividend discount method was developed based on assumptions including our projected distributions, anticipated long-term distribution growth rates, and near- and long-term cost of capital estimates. In determining the fair value of the awards, we also considered our historical transactions and performance in making these estimates. There is inherent uncertainty in making these estimates as the assumptions require significant judgment and are subject to change as a result of new operating data and economic and other conditions that impact our business. We will not need these estimates to determine the fair value of new unit-based compensation awards once our underlying shares begin trading publicly.

As of the valuation date of January 1, 2014, we were not planning to pursue an initial public offering. We believe that it is reasonable to expect that the completion of an initial public offering will add value to our restricted common units because they will have increased liquidity and marketability. However, the amount of such additional value cannot be measured or projected with precision or certainty. As described in Note 11 to the consolidated financial statements of BSMC, under the new management and senior management long-term incentive plans, 50% of the equity awards are classified as a liability during the corresponding year prior to the vesting date until a request for the Company to repurchase is made by the recipient, or the repurchase option period ends, which is 30 days prior to the vesting date. The liability is measured periodically at fair value. Any change in the fair value of these awards will change the value of the outstanding liability with a corresponding increase or decrease in expense recorded during the period. The following table shows restricted common units granted, in thousands except for per unit amounts, since October 1, 2013:

Grant Date	Number of Units  Granted		Fair Value Per Unit at Grant Date		Aggregate Fair Value of Units Granted
January 1, 2014		6,097	$	1.61	$	9,816

Future results of operations for any particular quarterly or annual period could be materially affected by changes in our assumptions. Any change in inputs or number of inputs to this calculation could impact the valuation and thus the equity-based compensation expense recognized. Please read Note 11 to the consolidated financial statements of BSMC included elsewhere in this prospectus for additional information. Equity-based compensation expense related to restricted common unit grants is included in general and administrative expense within the consolidated statements of operations.

New and Revised Financial Accounting Standards

The effects of new accounting pronouncements are discussed in the notes to the consolidated financial statements of BSMC included elsewhere in this prospectus.

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Quantitative and Qualitative Disclosure about Market Risk

Commodity Price Risk

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

To reduce the impact of fluctuations in oil and natural gas prices on our revenues, historically we have executed hedge contracts, the majority being costless collars, to reduce our exposure to price risk in the spot market for oil and natural gas. The counterparties to the contracts are unrelated third parties. The contracts settled monthly in cash based on a designated floating price. Historically the designated floating price has been based off the NYMEX index for oil and natural gas. We have not designated any of our contracts as fair value or cash flow hedges. Accordingly, the changes in fair value of the contracts are included in net income in the period of the change.

Counterparty and Customer Credit Risk

Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require our counterparties to our derivative contracts to post collateral, we do evaluate the credit standing of such counterparties as we deem appropriate. This evaluation includes reviewing a counterparty’s credit rating and latest financial information. Our counterparties are composed of 10 institutions, all of which are rated Baa2 or better by Moody’s. Six of our counterparties are lenders under our credit facility.

Our principal exposure to credit risk results from receivables generated by the production activities of our operators. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. However, we believe the credit risk associated with our operators and customers is acceptable.

Interest Rate Risk

We will have exposure to changes in interest rates on our indebtedness. As of September 30, 2014, we had total borrowings outstanding under our credit facility of $430.0 million. The impact of a 1% increase in the interest rate on this amount of debt would have resulted in an increase in interest expense, and a corresponding decrease in our results of operations, of approximately $4.3 million annually, assuming, however, that our indebtedness remained constant throughout the year. We may use certain derivative instruments to hedge our exposure to variable interest rates in the future, but we do not currently have in place any hedges.

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BUSINESS

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 while distributing a substantial majority of our cash generated from operations to our common 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 1.3 million acres. These non-cost-bearing interests, which we refer to collectively as our “mineral and royalty interests,” include ownership in approximately 40,000 producing wells. Our mineral and royalty interests are located in 41 states and in 62 onshore basins in the continental United States. Many of these interests are in active resource plays, including the Bakken/Three Forks play, Eagle Ford Shale, Wolfcamp play, Haynesville/Bossier play, Granite Wash play, and Fayetteville Shale, as well as emerging plays such as the Tuscaloosa Marine Shale and the Canyon Lime play. The combination of the breadth of our asset base and the long-lived, non-cost-bearing nature of our mineral and royalty interests exposes us to potential additional production and reserves from new and existing plays without investing additional capital.

Our history dates back to 1876, when W.T. Carter & Bro., a predecessor of BSMC, was established as a lumber company in Southeast Texas. W.T. Carter & Bro. acquired significant land holdings for timber, and those acquisitions typically included mineral interests. Beginning in the late 1960s, we began to divest the timber and surface rights on our properties but retained the mineral interests. We began developing our prospective oil and natural gas acreage in the 1980s. In 1985, we were involved in the discovery of the Double A Wells Field in East Texas, a natural gas field that has produced over 540 Bcfe to date. In 1992, we made our first third-party 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 nine months ended September 30, 2014 was approximately 25.9 MBoe/d, which includes production from our mineral and royalty interests, as well as production attributable to our working-interest participation program.

Our Assets

Mineral and Royalty Interests

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

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

• 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

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

Our revenue generated from these mineral and royalty interests was $314.2 million and $260.1 million for the year ended December 31, 2013 and the nine months ended September 30, 2014, respectively.

Working-Interest Participation Program

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

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 2014 non-operated working-interest capital expenditure budget and likely will be less in the future.

We collectively refer to these working interests as our “working-interest participation program.” When we participate in non-operated working-interest opportunities, we are required to pay our portion of the costs associated with drilling and operating these wells. Our 2014 drilling capital expenditure budget associated with our working-interest participation program is approximately $73.0 million. Approximately 41% and 29% of our 2014 drilling capital budget will be spent in the Bakken/Three Forks play and the Haynesville/Bossier play, respectively, with the remainder spent in various plays including the Granite Wash. As of September 30, 2014, the substantial majority of our 2014 drilling and completion budget was either spent or committed. Accordingly, we do not expect that any delays in drilling under this program would have a material impact on our results of operations. We historically have participated in approximately 200 new wells per year. As of September 30, 2014, we owned non-operated working interests in approximately 9,000 gross wells. For the year ended December 31, 2013 and the nine months ended September 30, 2014, our revenue generated from these working interests was $123.4 million and $92.1 million, respectively.

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The following graphs provide information regarding our production and revenue for the nine months ended September 30, 2014.

Reserves

As of December 31, 2013 and September 30, 2014, our total estimated proved oil and natural gas reserves were 58,942 MBoe and 51,987 MBoe, respectively, based on a reserve report prepared by Pressler and NSAI, respectively, each a third-party petroleum engineering firm. Of the reserves as of December 31, 2013, approximately 95.2% were proved developed reserves (approximately 93.5% proved developed producing and 1.7% proved developed non-producing) and approximately 4.8% were proved undeveloped reserves. Of the reserves as of September 30, 2014, approximately 95.8% were proved developed reserves (approximately 95.7% proved developed producing and 0.1% proved developed non-producing) and approximately 4.2% were proved undeveloped reserves. We generally do not have our operators’ approved development plans. As a result, our proved undeveloped reserve estimates are limited to those relatively few locations for which we have received and approved an Authority for Expenditure (“AFE”). At December 31, 2013 and September 30, 2014, our estimated proved reserves were 32.1% oil and 67.9% natural gas and 32.8% oil and 67.2% natural gas, respectively.

Business Strategies

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

• Actively lease our minerals to third-party operators. We intend to continue actively marketing our mineral interests for lease in order to generate income from lease bonus and ensure that our acreage is drilled as quickly as possible. Our staff actively manages the leasing of our acreage in order to accelerate royalty revenue and maximize our working-interest optionality. While our leasing activity

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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. In this prospectus, we define identified potential drilling locations as locations specifically identified by management based on evaluation of applicable geologic and engineering data accrued over our multi-year historical drilling activities. When leasing acreage, we consider the potential lessee’s operational track record to ensure that we maximize the pace of development. Our leases often contain provisions which provide us the option to participate on a working-interest (cost-bearing) basis in the operators’ third-party drilling programs. Typically, this option is structured to allow us to elect to participate after the operator has demonstrated repeatable attractive economics, thereby allowing us to increase our exposure to a play after the risks of failure or poor returns have been substantially reduced.

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

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

• geologic support for future production and reserve growth;

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

• targeted positions in high-growth resource and conventional plays.

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

• Maintain a conservative capital structure and prudently manage the business for the long term. We are committed to maintaining a conservative capital structure that will afford us the financial flexibility to execute our business strategies on an ongoing basis. Upon completion of this offering, we will have no outstanding indebtedness. We believe that proceeds from this offering, internally generated cash from operations, our $700.0 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.

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Competitive Strengths

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

• Significant diversified portfolio of mineral and royalty interests in mature producing basins and exposure to prospective exploration opportunities. We have a large-scale, diversified asset base with exposure to active high-quality conventional and unconventional plays. With our mineral and royalty interests spanning over 16.5 million total acres across the continental United States, we have established a strong position with significant growth opportunities and exposure to potentially large new discoveries in the future. Several of our positions are in basins still in the early stages of development, including the Bakken Shale, Eagle Ford Shale and Haynesville Shale. In some cases, we have built our positions in anticipation of development in a play, as we did in the Eagle Ford Shale. In other cases, we acquired diversified mineral packages in rich geologic basins with multiple prospective horizons from which subsequent resource plays, including the Bakken/Three Forks play and the Haynesville/Bossier play, have developed. Because our asset base is large and diversified, we are able to make significant focused acquisitions in active areas within well-established resource plays, while maintaining overall diversity. Furthermore, the geographic breadth of our assets 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. Over the past decade, the combination of horizontal drilling and hydraulic fracturing has provided access to large volumes of shale natural gas resources that were previously uneconomic to produce. In the United States, the availability of large quantities of shale natural gas has provided a commodity price advantage over coal and other international natural gas supply options. 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

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plays, which is projected to grow from 9.7 trillion cubic feet in 2012 to 19.8 trillion cubic feet in 2040. We have significant exposure to domestic natural gas resource plays, including the Haynesville/Bossier play, the Fayetteville Shale, and the Barnett Shale, and we believe that these assets will provide meaningful upside in production and revenue growth as demand for natural gas increases. Our 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 $         million of cash on hand, and $         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 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.

Our Properties

Material Basins and Producing Regions

The following is an overview of the U.S. basins and regions we consider most material to our current and future business.

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

• Western Gulf (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 basin and is being actively drilled and tested by several operators in the Western Gulf region. In addition to the Eagle Ford Shale and Tuscaloosa Marine Shale plays, there are a number of other active conventional and unconventional plays to which we have exposure to in the region, including the Austin Chalk, Buda, Eaglebine (or Maness) Shale, Frio, Glenrose, Olmos, Woodbine, Vicksburg, Wilcox, and Yegua plays.

• Williston Basin. The Williston Basin stretches through all of North Dakota, the northwest part of South Dakota, and eastern Montana and includes plays such as the Bakken/Three Forks play, where we have

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significant exposure through our mineral and royalty interests as well as through our working interests. We are also exposed to other well-known plays in the basin, including the Duperow, Mission Canyon, Madison, Ratcliff, Red River, and Spearfish plays.

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

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

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

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

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

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

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

• Southwestern Wyoming. The Southwestern Wyoming region covers most of southern and western Wyoming. The Pinedale Anticline is one of the basin’s largest producing fields and mainly produces

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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.

Interests by USGS Petroleum Province

The following tables present information about our mineral-and-royalty-interest and non-operated working-interest acreage, production, and well count by basin. We may own more than one type of interest in the same tract of land. For example, where we have acquired working interests through our working-interest participation program in a given tract, our working-interest acreage in that tract will relate to the same tract acres as our mineral-interest acreage in that tract. Consequently, some of the acreage shown for one type of interest below 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 significant.

Mineral Interests

The following table sets forth information about our mineral interests:

	As of								Average Daily Production (Boe/d)
	September 30, 2014								6:1(4)(5)				20:1(4)(6)
USGS Petroleum Province(1)	Acres		Average Ownership Interest(2)			Average Percent Leased(3)			Nine Months Ended September  30, 2014		Year Ended December 31, 2013		Nine Months Ended September  30, 2014		Year Ended December 31, 2013
Louisiana-Mississippi Salt Basins		5,273,142		54.6	%		6.4	%		4,036		5,453		1,589		2,043
Western Gulf (onshore)		1,543,417		55.7	%		36.0	%		3,963		3,505		2,649		2,342
Williston Basin		1,113,650		16.8	%		23.6	%		1,879		1,636		1,721		1,498
Palo Duro Basin		1,010,374		46.7	%		12.8	%		15		15		11		12
Permian Basin		696,286		17.9	%		38.5	%		562		495		465		405
Eastern Great Basin		599,342		96.8	%		0.5	%		—		—		—		—
Black Warrior Basin		591,842		54.7	%		2.6	%		41		41		15		14
Anadarko Basin		535,607		33.0	%		60.5	%		799		812		399		382
Appalachian Basin		490,006		39.6	%		30.9	%		86		63		29		22
East Texas Basin		406,279		56.1	%		39.6	%		712		993		240		323
Arkoma Basin		331,168		54.2	%		26.4	%		1,641		1,555		505		480
Western Great Basin		308,258		88.9	%		—			—		—		—		—
Piedmont		179,724		67.7	%		—			—		—		—		—
North-Central Montana		151,113		14.7	%		16.3	%		9		4		3		2
Bend Arch-Fort Worth Basin		138,018		20.5	%		31.7	%		247		325		91		119
Atlantic Coastal Plain		117,326		12.2	%		—			—		—		—		—
Cherokee Platform		106,488		13.8	%		29.8	%		41		34		27		21
Illinois Basin		79,096		53.7	%		5.9	%		1		1		1		1
Powder River Basin		66,575		11.0	%		15.4	%		2		2		2		2
Uinta-Piceance Basin		63,408		3.2	%		69.6	%		4		5		3		3
Other		695,661		35.2	%		14.3	%		309		332		151		154
Total		14,496,780		48.1	%		17.6	%		14,347		15,271		7,900		7,822

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

(1) The basins and regions shown in the table are consistent with USGS petroleum-province delineations.

(2) Ownership interest is equal to the percentage that our undivided ownership interest in a tract bears to the entire tract. The per-basin average ownership interest shown reflects the weighted average of our ownership interests in all tracts in the basin. Our weighted-average mineral royalty for all of our mineral interests is approximately 20%, which may be multiplied by our ownership interest to approximate the average royalty interest in our mineral and royalty interests.

(3) The average percent leased reflects the weighted average of our leased acres relative to our total acreage on a tract-by-tract basis in the basin.

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(4) For the year ended December 31, 2013, production volumes represent actual production by production month during the period. For the nine months ended September 30, 2014, production volumes represent actual production plus allocated accrued volumes attributable to the period presented.

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

(6) “Value-equivalent” production volumes are presented on an oil-equivalent basis using a conversion factor of 20 Mcf of natural gas per barrel of “oil equivalent,” which is the conversion factor we use in our business. We are providing this measure supplementally because we believe this conversion factor represents an estimation of value equivalence over time and better correlates with the respective contribution of oil and natural gas to our revenues. We use the 20-to-1 conversion factor as we assess our business, including analysis of our financial and production performance, strategic decisions to purchase additional properties or to invest in working-interest wells, and budgeting. We do not adjust the 20-to-1 ratio to reflect current pricing, because the significant volatility in the conversion ratio makes it difficult for us to compare results across periods. By reviewing our aggregate production on a constant 20-to-1 basis, which removes the variability of price fluctuations but generally approximates price equivalence over recent periods, we are able to compare production data from period to period as well as the relative contribution of oil and natural gas to our revenues. The 20-to-1 conversion factor approximates the mean ratio of the price of WTI oil to the price of Henry Hub natural gas from January 3, 2006 to December 31, 2014, as reported by the EIA. During this period, the ratio of the price of oil to the price of natural gas ranged from 5.6 to 56.9. The mean ratios of the price of oil to the price of natural gas were 26.5 and 21.6 for the year ended December 31, 2013 and December 31, 2014, respectively. Due to the variability of the prices of oil and natural gas, there is no standard conversion ratio for value equivalence, and the 20-to-1 ratio presented here may not accurately reflect the ratio of oil prices to natural gas prices for a given period.

NPRIs

The following table sets forth information about our NPRIs:

	As of								Average Daily Production (Boe/d)
	September 30, 2014								6:1(4)(5)				20:1(4)(6)
USGS Petroleum Province(1)	Acres		Average Royalty Interest(2)			Average Percent Leased(3)			Nine Months Ended September 30, 2014		Year Ended December 31, 2013		Nine Months Ended September  30, 2014		Year Ended December 31, 2013
Permian Basin		544,648		3.5	%		21.9	%		6		3		5		2
Western Gulf (onshore)		180,901		5.2	%		35.9	%		15		3		10		1
North-Central Montana		127,467		3.0	%		8.3	%		—		—		—		—
Louisiana-Mississippi Salt Basins		111,707		6.8	%		24.5	%		—		—		—		—
Williston Basin		60,734		2.7	%		29.3	%		59		31		52		28
Bend Arch-Fort Worth Basin		52,208		4.1	%		7.1	%		3		2		1		1
East Texas Basin		36,191		3.2	%		77.0	%		1		1		—		—
Powder River Basin		32,424		6.3	%		4.2	%		—		—		—		—
Palo Duro Basin		22,791		3.8	%		1.7	%		—		—		—		—
Anadarko Basin		10,628		4.4	%		94.0	%		1		3		1		1
Cambridge Arch-Central Kansas Uplift		8,583		5.7	%		83.1	%		—		—		—		—
Montana Thrust Belt		6,474		3.2	%		14.7	%		—		—		—		—
Southwest Montana		6,307		5.3	%		5.1	%		—		—		—		—
Arkoma Basin		5,170		4.5	%		71.6	%		10		—		3		—
Cherokee Platform		2,634		4.6	%		30.4	%		—		—		—		—
Nemaha Uplift		2,334		1.6	%		41.4	%		—		—		—		—
Sedgwick Basin		1,530		3.1	%		78.4	%		—		—		—		—
Southwestern Wyoming		560		1.0	%		–			—		—		—		—
Denver Basin		480		9.1	%		–			—		—		—		—
Appalachian Basin		416		8.9	%		6.0	%		—		—		—		—
Other		373		2.0	%		12.1	%		157		148		157		148
Total		1,214,559		4.1	%		24.6	%		253		192		229		182

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

(1) The basins and regions shown in the table are consistent with USGS petroleum-province delineations.

(2) Average royalty interest is equal to the weighted-average percentage of production or revenues (before operating costs) that we are entitled to on a tract-by-tract basis in the basin.

(3) The average percent leased reflects the weighted average of our leased acres relative to our total acreage on a tract-by-tract basis in the basin.

(4) For the year ended December 31, 2013, production volumes represent actual production by production month during the period. For the nine months ended September 30, 2014, production volumes represent actual production plus allocated accrued volumes attributable to the period presented.

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

(6) “Value-equivalent” production volumes are presented on an oil-equivalent basis using a conversion factor of 20 Mcf of natural gas per barrel of “oil equivalent,” which is the conversion factor we use in our business. For a discussion of the 20-to-1 conversion factor, please see footnote 6 to the Mineral Interests table on page 95 under “—Interests by USGS Petroleum Province.”

ORRIs

The following table sets forth information about our ORRIs:

	As of					Average Daily Production (Boe/d)
	September 30, 2014					6:1(3)(4)				20:1(3)(5)
USGS Petroleum Province(1)	Acres		Average Royalty Interest(2)			Nine Months Ended September 30, 2014		Year Ended December 31, 2013		Nine Months Ended September  30, 2014		Year Ended December 31, 2013
North-Central Montana		458,402		2.4	%		30		42		9		13
Anadarko Basin		180,443		2.6	%		251		242		112		106
Western Gulf (onshore)		82,481		2.7	%		172		126		142		92
Powder River Basin		74,794		1.5	%		58		52		28		20
Southwestern Wyoming		70,607		2.1	%		540		632		168		196
Louisiana-Mississippi Salt Basins		17,140		3.3	%		568		819		178		263
Permian Basin		59,033		1.8	%		67		69		47		52
Michigan Basin		56,178		1.0	%		21		24		10		12
Uinta-Piceance Basin		55,684		1.6	%		33		37		18		19
Bend Arch-Fort Worth Basin		41,038		4.5	%		182		208		56		64
Arkoma Basin		36,109		2.3	%		24		24		7		7
Williston Basin		30,645		2.1	%		52		53		49		50
San Juan Basin		28,187		1.1	%		3		4		1		2
East Texas Basin		25,252		5.8	%		84		110		28		37
Paradox Basin		23,296		0.6	%		2		3		1		1
Northern Alaska		20,039		1.7	%		30		18		30		18
Wind River Basin		17,806		1.9	%		30		33		11		12
Denver Basin		16,371		2.6	%		87		107		50		60
Wyoming Thrust Belt		8,720		1.2	%		4		5		1		2
Cambridge Arch-Central Kansas Uplift		5,762		3.8	%		3		4		3		4
Other		29,782		2.3	%		900		904		333		328
Total		1,337,768		2.3	%		3,141		3,516		1,281		1,360

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

(1) The basins and regions shown in the table are consistent with USGS petroleum-province delineations.

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(2) Average royalty interest is equal to the weighted-average percentage of production or revenues (before operating costs) that we are entitled to on a tract-by-tract basis in the basin.

(3) For the year ended December 31, 2013, production volumes represent actual production by production month during the period. For the nine months ended September 30, 2014, production volumes represent actual production plus allocated accrued volumes attributable to the period presented.

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

(5) “Value-equivalent” production volumes are presented on an oil-equivalent basis using a conversion factor of 20 Mcf of natural gas per barrel of “oil equivalent,” which is the conversion factor we use in our business. For a discussion of the 20-to-1 conversion factor, please see footnote 6 to the Mineral Interests table on page 95 under “—Interests by USGS Petroleum Province.”

Working Interests

The following table sets forth information about our non-operated working interests:

	As of				Average Daily Production(Boe/d)
	September 30, 2014				6:1(3)(4)				20:1(3)(5)
USGS Petroleum Province(1)	Gross Acres(2)		Net Acres(2)		Nine Months Ended September 30, 2014		Year Ended December 31, 2013		Nine Months Ended September 30, 2014		Year Ended December 31, 2013
East Texas Basin		126,495		33,673		1,450		1,430		464		456
Western Gulf (onshore)		116,933		17,677		780		831		433		470
Anadarko Basin		28,296		21,404		1,410		1,559		603		691
Bend Arch-Fort Worth Basin		55,841		13,408		134		159		41		48
Louisiana-Mississippi Salt Basins		54,685		6,850		2,172		3,105		700		984
Williston Basin		52,770		7,429		1,333		842		1,250		779
Denver Basin		4,286		1,037		4		4		4		4
Southwestern Wyoming		15,458		2,492		7		8		3		3
Michigan Basin		13,287		1,330		6		6		2		2
Powder River Basin		11,507		2,535		100		61		91		54
Permian Basin		8,353		5,054		195		159		132		92
Arkoma Basin		8,943		2,408		354		415		106		125
Wyoming Thrust Belt		3,979		3,366		—		—		—		—
San Juan Basin		3,442		1,575		10		10		3		3
North-Central Montana		1,920		605		1		1		—		—
Wind River Basin		2,000		935		—		—		—		—
Paradox Basin		520		280		5		5		2		2
Southern Oklahoma		350		92		134		138		66		67
Cherokee Platform		393		163		9		14		7		10
Illinois Basin		240		23		—		—		—		—
Other		1,370		1,218		85		129		57		95
Total		511,069		123,554		8,188		8,875		3,964		3,882

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

(1) The basins and regions shown in the table are consistent with USGS petroleum-province delineations.

(2) Excludes acreage that is not quantifiable due to incomplete seller records.

(3) For the year ended December 31, 2013, production volumes represent actual production by production month during the period. For the nine months ended September 30, 2014, production volumes represent actual production plus allocated accrued volumes attributable to the period presented.

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

(5) “Value-equivalent” production volumes are presented on an oil-equivalent basis using a conversion factor of 20 Mcf of natural gas per barrel of “oil equivalent,” which is the conversion factor we use in our business. For a discussion of the 20-to-1 conversion factor, please see footnote 6 to the Mineral Interests table on page 95 under “—Interests by USGS Petroleum Province.”

Wells

The following table sets forth information about our mineral-and-royalty-interest and working-interest wells as of September 30, 2014:

Mineral and Royalty Interests			Working Interests
USGS Petroleum Province(1)	Well Count(2)		USGS Petroleum Province(1)	Well Count(2)
Permian Basin		18,036	Anadarko Basin		3,078
Anadarko Basin		3,225	Uinta-Piceance Basin		1,111
Louisiana-Mississippi Salt Basins		2,273	Permian Basin		800
Western Gulf (onshore)		2,225	Arkoma Basin		668
East Texas Basin		2,063	East Texas Basin		613
Williston Basin		1,918	Western Gulf (onshore)		534
Uinta-Piceance Basin		1,350	Louisiana-Mississippi Salt Basins		521
Arkoma Basin		1,334	Southern Oklahoma Basins		490
Bend Arch-Fort Worth Basin		1,142	Williston Basin		431
Michigan Basin		875	Bend Arch-Fort Worth Basin		228
Southwestern Wyoming		683	Nemaha Uplift		202
Los Angeles Basin		589	Appalachian Basin		155
Appalachian Basin		541	Michigan Basin		62
Cherokee Platform		511	Powder River Basin		59
San Juan Basin		507	Cherokee Platform		12
North-Central Montana		481	Denver Basin		10
Powder River Basin		358	Los Angeles Basin		9
Wyoming Thrust Belt		351	San Juan Basin		8
Denver Basin		332	North-Central Montana		7
Palo Duro Basin		267	Paradox Basin		6
Other		1,174	Other		10
Total		40,235	Total		9,014

(1) The basins and regions shown in the table are consistent with USGS petroleum-province delineations.

(2) We own both mineral and royalty interests and working interests in 2,994 of the wells shown in each column above.

Interests by Resource Play

The following tables present information about our mineral-and-royalty-interest and non-operated working-interest acreage, production, and well count by resource play. As with the acreage shown for the basins above, we may own more than one type of interest in the same tract of land. Consequently, some of the acreage shown for one type of interest below may also be included in the acreage shown for another type of interest.

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Mineral Interests

The following table sets forth information about our mineral interests:

	As of								Average Daily Production (Boe/d)
	September 30, 2014								6:1(4)(5)				20:1(4)(6)
Resource Play(1)	Acres		Average Ownership Percent(2)			Average Percent Leased(3)			Nine Months Ended September 30, 2014		Year Ended December 31, 2013		Nine Months Ended September 30, 2014		Year Ended December 31, 2013
Bakken Shale		318,909		18.3	%		69.9	%		1,209		1,069		1,106		975
Three Forks		296,449		18.1	%		74.1	%		589		486		537		445
Haynesville Shale		275,275		68.1	%		76.7	%		2,997		4,141		908		1,256
Marcellus Shale		253,536		18.3	%		50.1	%		76		50		23		15
Canyon Lime		232,381		31.9	%		47.0	%		1		1		1		1
Bossier Shale		213,539		70.6	%		77.6	%		592		1,063		178		319
Tuscaloosa Marine Shale		181,480		64.5	%		42.2	%		2		—		2		—
Granite Wash		110,648		15.8	%		56.2	%		249		272		112		118
Fayetteville Shale		76,539		54.7	%		75.7	%		1,522		1,421		457		426
Barnett Shale		62,171		15.8	%		57.0	%		224		299		70		97
Eagle Ford Shale		46,396		18.9	%		81.1	%		1,423		960		1,184		804
Wolfcamp-Delaware		44,535		15.6	%		57.9	%		135		69		122		56
Wolfcamp-Midland		58,498		4.2	%		90.0	%		19		15		17		13

(1) The plays above have been delineated based on information from the EIA, the USGS, state agencies, or according to areas of the most active industry development.

(2) Ownership interest is equal to the percentage that our undivided ownership interest in a tract bears to the entire tract. The per-play average ownership interests shown above reflect the weighted average of our ownership interests in all tracts in the play. Our weighted-average mineral royalty for all of our mineral interests is approximately 20%, which may be multiplied by our ownership interest to approximate the average royalty interest in our mineral and royalty interests.

(3) The average percent leased reflects the weighted average of our leased acres relative to our total acreage on a tract-by-tract basis in the play.

(4) For the year ended December 31, 2013, production volumes represent actual production by production month during the period. For the nine months ended September 30, 2014, production volumes represent actual production plus allocated accrued volumes attributable to the period presented.

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

(6) “Value-equivalent” production volumes are presented on an oil-equivalent basis using a conversion factor of 20 Mcf of natural gas per barrel of “oil equivalent,” which is the conversion factor we use in our business. For a discussion of the 20-to-1 conversion factor, please see footnote 6 to the Mineral Interests table on page 95 under “—Interests by USGS Petroleum Province.”

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NPRIs

The following table sets forth information about our NPRIs:

	As of								Average Daily Production(Boe/d)
	September 30, 2014								6:1(4)(5)				20:1(4)(6)
Resource Play(1)	Acres		Average Royalty Interest(2)			Average Percent Leased(3)			Nine Months Ended September 30, 2014		Year Ended December 31, 2013		Nine Months Ended September 30, 2014		Year Ended December 31, 2013
Bakken Shale		35,261		1.4	%		46.1	%		34		18		30		16
Three Forks		32,442		1.3	%		49.2	%		25		13		22		12
Haynesville Shale		6,523		4.5	%		96.8	%		—		—		—		—
Marcellus Shale		—		—			NA			—		—		—		—
Canyon Lime		—		—			NA			—		—		—		—
Bossier Shale		1,496		3.2	%		44.3	%		—		—		—		—
Tuscaloosa Marine Shale		4,081		2.1	%		NA			—		—		—		—
Granite Wash		4,042		0.9	%		NA			—		—		—		—
Fayetteville Shale		—		—			NA			10		—		3		—
Barnett Shale		4,004		2.6	%		NA			2		2		1		1
Eagle Ford Shale		85,864		1.5	%		27.6	%		9		—		8		—
Wolfcamp-Delaware		11,785		9.9	%		41.0	%		2		—		2		—
Wolfcamp-Midland		46,720		2.0	%		47.4	%		—		—		—		—

(1) The plays above have been delineated based on information from the EIA, the USGS, state agencies, or according to areas of the most active industry development.

(2) Average royalty interest is equal to the weighted-average percentage of production or revenues (before operating costs) that we are entitled to on a tract-by-tract basis for the given area.

(3) The average percent leased reflects the weighted average of our leased acres relative to our total acreage on a tract-by-tract basis in the play.

(4) For the year ended December 31, 2013, production volumes represent actual production by production month during the period. For the nine months ended September 30, 2014, production volumes represent actual production plus allocated accrued volumes attributable to the period presented.

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

(6) “Value-equivalent” production volumes are presented on an oil-equivalent basis using a conversion factor of 20 Mcf of natural gas per barrel of “oil equivalent,” which is the conversion factor we use in our business. For a discussion of the 20-to-1 conversion factor, please see footnote 6 to the Mineral Interests table on page 95 under “—Interests by USGS Petroleum Province.”

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ORRIs

The following table sets forth information about our ORRIs:

	As of					Average Daily Production (Boe/d)
	September 30, 2014					6:1(3)(4)				20:1(3)(5)
Resource Play(1)	Acres		Average Royalty Interest(2)			Nine Months Ended September 30, 2014		Year Ended December 31, 2013		Nine Months Ended September 30, 2014		Year Ended December 31, 2013
Bakken Shale		12,610		1.2	%		23		20		22		20
Three Forks		11,930		1.2	%		19		20		18		19
Haynesville Shale		14,468		7.6	%		489		689		147		207
Marcellus Shale		1,002		7.0	%		—		—		—		—
Canyon Lime		—		—			—		—		—		—
Bossier Shale		8,441		4.7	%		52		89		16		27
Tuscaloosa Marine Shale		6,409		9.8	%		—		—		—		—
Granite Wash		87,516		1.9	%		188		164		85		74
Fayetteville Shale		11,833		4.0	%		—		—		—		—
Barnett Shale		37,803		4.7	%		180		205		54		62
Eagle Ford Shale		44,324		2.3	%		102		52		97		51
Wolfcamp-Delaware		1,080		0.7	%		—		—		—		—
Wolfcamp-Midland		14,964		0.8	%		3		5		2		3

(1) The plays above have been delineated based on information from the EIA, the USGS, state agencies, or according to areas of the most active industry development.

(2) Average royalty interest is equal to the weighted-average percentage of production or revenues (before operating costs) that we are entitled to on a tract-by-tract basis in this play.

(3) For the year ended December 31, 2013, production volumes represent actual production by production month during the period. For the nine months ended September 30, 2014, production volumes represent actual production plus allocated accrued volumes attributable to the period presented.

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

(5) “Value-equivalent” production volumes are presented on an oil-equivalent basis using a conversion factor of 20 Mcf of natural gas per barrel of “oil equivalent,” which is the conversion factor we use in our business. For a discussion of the 20-to-1 conversion factor, please see footnote 6 to the Mineral Interests table on page 95 under “—Interests by USGS Petroleum Province.”

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Working Interests

The following table sets forth information about our working interests.

	As of				Average Daily Production(Boe/d)
	September 30, 2014				6:1(3)(4)				20:1(3)(5)
Resource Play(1)	Gross Acres(2)		Net Acres(2)		Nine Months Ended September 30, 2014		Year Ended December 31, 2013		Nine Months Ended September 30, 2014		Year Ended December 31, 2013
Bakken Shale		48,195		6,782		877		514		821		474
Three Forks		48,397		6,420		431		298		405		277
Haynesville Shale		169,257		39,396		3,100		3,937		931		1,181
Marcellus Shale		—		—		—		—		—		—
Canyon Lime		—		—		—		—		—		—
Bossier Shale		135,208		33,243		210		277		63		83
Tuscaloosa Marine Shale		—		—		—		—		—		—
Granite Wash		5,194		1,364		654		745		260		300
Fayetteville Shale		—		—		29		36		9		11
Barnett Shale		20,665		8,322		129		154		39		46
Eagle Ford Shale		235		118		—		—		—		—
Wolfcamp-Delaware		642		160		22		4		20		3
Wolfcamp-Midland		160		4		1		1		1		1

(1) The plays above have been delineated based on information from the EIA, the USGS, state agencies, or according to areas of the most active industry development.

(2) Excludes acreage that is not quantifiable due to incomplete seller records.

(3) For the year ended December 31, 2013, production volumes represent actual production by production month during the period. For the nine months ended September 30, 2014, production volumes represent actual production plus allocated accrued volumes attributable to the period presented.

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

(5) “Value-equivalent” production volumes are presented on an oil-equivalent basis using a conversion factor of 20 Mcf of natural gas per barrel of “oil equivalent,” which is the conversion factor we use in our business. For a discussion of the 20-to-1 conversion factor, please see footnote 6 to the Mineral Interests table on page 95 under “—Interests by USGS Petroleum Province.”

Estimated Proved Reserves

Evaluation and Review of Estimated Proved Reserves

The information included in this prospectus relating to our estimated proved oil and natural gas reserves is based upon (1) a reserve report prepared by Pressler, a third-party petroleum engineering firm, as of December 31, 2013 and (2) a reserve report prepared by NSAI, a third-party petroleum engineering firm, as of September 30, 2014.

Pressler provides domestic petroleum property analysis services for energy clients, financial organizations, and government agencies. Pressler was founded in 1991 and performs petroleum-engineering consulting services under Texas Board of Professional Engineers Firm (Registration No. 7807). Within Pressler, the technical person primarily responsible for preparing the estimates set forth in the Pressler summary reserve report incorporated herein is Mr. Jim R. McReynolds, P.E. Mr. McReynolds has been practicing petroleum-engineering consulting at Pressler since 1993. Mr. McReynolds is a Licensed Professional Engineer in the State of Texas (Registration No. 73027) and has over 35 years of practical experience in petroleum engineering, the vast majority of which is in the estimation and evaluation of reserves. He graduated from the University of Oklahoma in 1977 with a

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Bachelor of Science Degree in Petroleum Engineering. As technical principal, Mr. McReynolds meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and is proficient in applying industry standard practices to engineering evaluations as well as in applying SEC and other industry reserves definitions and guidelines. A copy of Pressler’s estimated proved reserve report as of December 31, 2013 is attached as an exhibit to the registration statement of which this prospectus forms a part.

NSAI provides worldwide petroleum property analysis services for energy clients, financial organizations, and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical person primarily responsible for preparing the estimates set forth in the NSAI summary reserve report incorporated herein is Mr. J. Carter Henson, Jr. Mr. Henson has been practicing consulting petroleum engineering at NSAI since 1989. Mr. Henson is a Licensed Professional Engineer in the State of Texas (License No. 73964) and has over 31 years of practical experience in petroleum engineering, with over 24 years of experience in the estimation and evaluation of reserves. He graduated from Rice University in 1981 with a Bachelor of Science Degree in Mechanical Engineering. As technical principal, Mr. Henson meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and is proficient in judiciously applying industry standard practices to engineering evaluations as well as applying SEC and other industry reserves definitions and guidelines. NSAI does not own an interest in us or any of our properties, nor is it employed by us on a contingent basis. A copy of NSAI’s estimated proved reserve report as of September 30, 2014 is attached as an exhibit to the registration statement to which this prospectus forms a part.

We maintain an internal staff of petroleum engineers and geoscience professionals who worked closely with our third-party reserve engineers to ensure the integrity, accuracy, and timeliness of the data used to calculate our estimated proved reserves. Our internal technical team members met with our third-party reserve engineers periodically during the periods covered by the above referenced reserve report to discuss the assumptions and methods used in the reserve estimation process. We provided historical information to the third-party reserve engineers for our properties, such as oil and natural gas production, well test data, realized commodity prices, and operating and development costs. We also provided ownership interest information with respect to our properties. Brock Morris, our Senior Vice President, Engineering and Geology, is primarily responsible for overseeing the preparation of all of our reserve estimates. Mr. Morris is a petroleum engineer with approximately 29 years of reservoir-engineering and operations experience, and our engineering and geoscience staff has an average of approximately 22 years of industry experience.

The preparation of our historical proved reserve estimates were completed in accordance with our internal control procedures. Throughout the year, our technical team met with Pressler and NSAI to review properties and discuss evaluation methods and assumptions used in the proved reserves estimates, in accordance with our prescribed internal control procedures. Our internal controls over the reserves estimation process include verification of input data used in the reserves evaluation software as well as reviews by our internal engineering staff and management, which include the following:

• Comparison of historical operating expenses from the lease operating statements to the operating costs input in the reserves database;

• Review of working interests and net revenue interests in the reserves database against our well ownership system;

• Review of historical realized commodity prices and differentials from index prices compared to the differentials used in the reserves database;

• Review of capital costs assumptions to actual historical capital costs;

• Review of actual historical production volumes compared to projections in the reserve report;

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• Discussion of material reserve variances among our internal reservoir engineers and our Senior Vice President, Engineering and Geology; and

• Review of preliminary reserve estimates by our President and Chief Executive Officer with our internal technical staff.

Estimation of Proved Reserves

In accordance with rules and regulations of the SEC applicable to companies involved in oil and natural gas producing activities, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” means deterministically, the quantities of oil and/or natural gas are much more likely to be achieved than not, and probabilistically, there should be at least a 90% probability of recovering volumes equal to or exceeding the estimate. All of our estimated proved reserves as of December 31, 2013 and September 30, 2014 are based on deterministic methods. Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by using reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

In order to establish reasonable certainty with respect to our estimated net proved reserves, Pressler and NSAI employed technologies including, but not limited to, electrical logs, radioactivity logs, core analyses, geologic maps, and available down hole pressure and production data, seismic data, and well test data. Reserves attributable to producing wells with sufficient production history were estimated using appropriate decline curves or other performance relationships. Reserves attributable to producing wells with limited production history and for undeveloped locations were estimated using performance from analogous wells in the surrounding area and geologic data to assess the reservoir continuity. In addition to assessing reservoir continuity, geologic data from well logs, core analyses, and seismic data were used to estimate original oil and natural gas in place. Recovery factors were determined utilizing reservoir simulation or analogy with similar reservoirs where similar drilling and completion techniques have been employed.

Summary of Estimated Proved Reserves

The following table presents our estimated proved oil and natural gas reserves as of December 31, 2013 and September 30, 2014:

	September 30, 2014(1)			December 31, 2013(1)
Estimated proved developed reserves(2):
Oil (MBbls)		16,391			17,290
Natural gas (MMcf)		200,332			232,777
Total (MBoe)(3)		49,780			56,086
Estimated proved undeveloped reserves(4):
Oil (MBbls)		666			1,659
Natural gas (MMcf)		9,247			7,183
Total (MBoe)(3)		2,207			2,856
Estimated proved reserves:
Oil (MBbls)		17,057			18,949
Natural gas (MMcf)		209,579			239,960
Total (MBoe)(3)		51,987			58,942
Percent proved developed		95.8	%		95.2	%

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(1) Estimates of reserves as of December 31, 2013 were prepared using oil and natural gas prices equal to the unweighted arithmetic average of the first-day-of-the-month market price for each month in the period January through December 2013. Estimates of reserves as of September 30, 2014 were prepared using oil and natural gas prices equal to the unweighted arithmetic average of the first-day-of-the-month market price for each month in the period October 2013 through September 2014. For oil volumes, the average WTI Cushing, Oklahoma spot oil prices of $96.78 per barrel and $99.08 per barrel are used for estimates of reserves for all the properties as of December 31, 2013 and September 30, 2014, respectively. These average prices are adjusted for quality, transportation fees, and regional price differentials. For natural gas volumes, the average Henry Hub prices of $3.67 per MMBTU and $4.24 per MMBTU are used for estimates of reserves for all the properties as of December 31, 2013 and September 30, 2014, respectively. These average prices are adjusted for energy content, transportation fees, and regional price differentials. Natural gas prices are also adjusted to account for NGL revenue since there is not sufficient data to account for NGLs separately in the reserve estimates. These reserve estimates exclude NGL quantities. The adjusted prices are $94.84 per Bbl of oil and $93.97 per Bbl of oil and $3.74 per Mcf of natural gas and $4.54 per Mcf of natural gas as of December 31, 2013 and September 30, 2014, respectively. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses, and quantities of recoverable oil and natural gas may vary substantially from these estimates.

(2) Proved developed reserves of 119 MBoe and 88 MBoe as of December 31, 2013 and September 30, 2014, respectively, were attributable to noncontrolling interests in our consolidated subsidiaries.

(3) Estimated proved reserves are presented on an oil-equivalent basis using a conversion of six Mcf per barrel of “oil equivalent.” This conversion is based on energy equivalence and not price or value equivalence. If a price equivalent conversion based on the twelve-month average prices for the year ended December 31, 2013 was used, the conversion factor would be approximately 26 Mcf per Bbl of oil. If a price equivalent conversion based on the twelve-month average prices for the twelve months ended September 30, 2014 was used, the conversion factor would be approximately 23 Mcf per Bbl of oil. In this prospectus, we supplementally provide “value-equivalent” production information or volumes presented on an oil-equivalent basis using a conversion factor of 20 Mcf of natural gas per barrel of “oil equivalent,” which is the conversion factor we use in our business. For a discussion of the 20-to-1 conversion factor, please see footnote 6 to the Mineral Interests table on page 95 under “—Interests by USGS Petroleum Province.”

(4) As of December 31, 2013 and September 30, 2014, no proved undeveloped reserves were attributable to noncontrolling interests in our consolidated subsidiaries.

Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing, and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices, and future production rates and costs. Please read “Risk Factors.”

Additional information regarding our estimated proved reserves can be found in the notes to the consolidated financial statements of BSMC included elsewhere in this prospectus and the estimated proved reserve reports as of December 31, 2013 and September 30, 2014, which are included as exhibits to the registration statement of which this prospectus forms a part.

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Estimated Proved Undeveloped Reserves

As of December 31, 2013, our PUDs were composed of 1,659 MBbls of oil and 7,183 MMcf of natural gas, for a total of 2,856 MBoe. As of September 30, 2014, our PUDs were composed of 666 MBbls of oil and 9,247 MMcf of natural gas, for a total of 2,207 MBoe. PUDs will be converted from undeveloped to developed as the applicable wells begin production.

The following tables summarize our changes in PUDs during the period from the year ended December 31, 2013 to September 30, 2014 (in MBoe) and during the year ended December 31, 2013 (in MBoe):

	Proved Undeveloped Reserves(1)
Balance, December 31, 2012		5,580
Acquisitions of reserves		24
Extensions and discoveries		2,391
Revisions of previous estimates		(643	)
Transfers to estimated proved developed		(4,497	)
Balance, December 31, 2013		2,856
Acquisitions of reserves		575
Extensions and discoveries		1,390
Revisions of previous estimates		(266	)
Transfers to estimated proved developed		(2,348	)
Balance, September 30, 2014		2,207

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

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

Extensions and discoveries of 2,391 MBoe and 1,390 MBoe during the year ended December 31, 2013 and the nine months ended September 30, 2014, respectively, resulted primarily from drilling and capital expenditures in the Bakken Shale, Haynesville Shale, Granite Wash, and Southeast Texas Wilcox plays.

During the year ended December 31, 2013, we had total downward reserve estimate revisions of previous estimates of 643 MBoe, which were made up of 3,540 MMcf of natural gas reserve estimate revisions and 53 MBbl of oil reserve estimate revisions. The revisions included reductions of 489 MBoe to PUD reserves associated with three wells that were removed from the PUD category due to new information from operators or permits that expired, resulting in a lack of certainty regarding the timing of the drilling of those wells. Two of the removed wells were in the Haynesville Shale and one well was in the Bakken Shale. An additional 111 MBoe reduction related to a well in the Haynesville Shale, which was abandoned as a result of a mechanical failure. We are not certain as to the timing of a replacement well and therefore removed it from the PUD category. The remaining 43 MBoe reduction related to negative technical revisions of estimated reserves during the period.

During the nine months ended September 30, 2014, we acquired additional working interests in natural gas properties in the Haynesville Shale play in San Augustine County, Texas, which included two drilling locations with estimated PUD reserves totaling 575 MBoe. Both wells were drilled but not yet fracture stimulated as of September 30, 2014, and they began producing in November 2014.

During the nine months ended September 30, 2014, we had total downward reserve estimate revisions of previous estimates of 266 MBoe, which were made up of 517 MMcf of natural gas reserve estimate revisions and

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180 MBbl of oil reserve estimate revisions. Reductions of 143 MBoe related to corrections to reserve bookings for eight wells in the December 31, 2013 reserve report, and reductions of 33 MBoe related to wells removed from PUD status as a result of stale permits or updated operator information. The remaining 90 MBoe of revisions were technical revisions of estimated PUDs by NSAI in connection with the preparation of its September 30, 2014 reserve report, the majority of which related to revised reserve estimates on five Bakken Shale wells and one Haynesville Shale well.

Costs incurred relating to the development of locations that were classified as PUDs at December 31, 2012 were $19.1 million during the year ended December 31, 2013. Costs incurred relating to the development of locations that were classified as PUDs at December 31, 2013 were $12.1 million during the nine months ended September 30, 2014. Additionally, during 2013, we spent approximately $51.8 million drilling and completing other in-field wells which were not classified as PUDs as of December 31, 2012. Additionally, during the nine months ended September 30, 2014, we spent approximately $46.0 million drilling and completing other in-field wells which were not classified as PUDs as of December 31, 2013. Estimated future development costs relating to the development of PUDs at December 31, 2013 were projected to be approximately $21.3 million in the year ended December 31, 2014. Estimated future development costs relating to the development of PUDs at September 30, 2014 were projected to be approximately $20.0 million over the next twelve months. As we continue to participate in new wells on our properties and have more well production and completion data, we believe we will continue to realize cost savings and experience lower relative drilling and completion costs as we convert PUDs into proved developed reserves in upcoming years. All of our PUD drilling locations as of December 31, 2013 and September 30, 2014 are scheduled to be drilled within five years or less from the date the reserves were initially booked as proved undeveloped reserves.

We generally do not have our operators’ approved development plans. As a result, our proved undeveloped reserve estimates are limited to those relatively few locations for which we have received and approved an AFE. As of December 31, 2013 and September 30, 2014, approximately 4.8% and 4.2% of our total proved reserves were classified as PUDs, respectively.

Oil and Natural Gas Production Prices and Production Costs

Production and Price History

The following table sets forth information regarding production of oil and natural gas and certain price and cost information for each of the periods indicated:

	For the Nine Months Ended September 30, 2014		For the Year Ended December 31,
			2013		2012		2011
Production Data:
Oil and condensate (MBbls)(1)		2,106		2,626		2,173		1,850
Natural gas(1)(MMcf)		31,173		45,400		52,965		51,467
Total (MBoe)(6:1)(2)		7,302		10,193		11,001		10,428
Average daily production (MBoe/d)(6:1)		26.7		27.9		30.1		28.6
Total (MBoe)(20:1)(3)		3,664		4,896		4,821		4,423
Average daily production (MBoe/d)(20:1)		13.4		13.4		13.2		12.1
Average Realized Sale Prices(4):
Oil and condensate (per Bbl)	$	92.91	$	96.25	$	93.01	$	95.35
Natural gas and natural gas liquids (per Mcf)		5.02		4.07		3.15		4.59
Average Unit Cost per Boe(6:1):
Lease operating expense and other	$	2.21	$	2.09	$	1.87	$	2.31
Production and ad valorem taxes		4.60		4.20		3.33		3.45
Total (per Boe)	$	6.81	$	6.29	$	5.20	$	5.75

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(1) The oil and condensate production volumes and natural gas production volumes do not include NGL volumes.

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

(3) “Value-equivalent” production volumes are presented on an oil-equivalent basis using a conversion factor of 20 Mcf of natural gas per barrel of “oil equivalent,” which is the conversion factor we use in our business. For a discussion of the 20-to-1 conversion factor, please see footnote 6 to the Mineral Interests table on page 95 under “—Interests by USGS Petroleum Province.”

(4) Excludes the effect of commodity derivative instruments.

Productive Wells

Productive wells consist of producing wells, wells capable of production, and exploratory, development, or extension wells that are not dry wells. As of September 30, 2014, we owned mineral and royalty interests or working interests in 46,255 productive wells, which consisted of 27,532 oil wells and 18,723 natural gas wells. As of September 30, 2014, we owned mineral and royalty interests in 40,235 productive wells, which consisted of 24,396 oil wells and 12,845 natural gas wells, and working interests in 9,014 gross productive wells and 203 net productive wells, which consisted of 1,092 gross (43 net) productive oil wells and 4,928 gross (160 net) productive natural gas wells. We own both mineral and royalty interests and working interests in 2,994 of these wells.

Acreage

Mineral and Royalty Interests

The following table sets forth information relating to our acreage for our mineral interests as of September 30, 2014:

State	Developed Acreage		Undeveloped Acreage		Total Acreage
Texas		333,297		3,518,839		3,852,137
Mississippi		6,036		2,318,396		2,324,432
Alabama		2,792		2,025,780		2,028,572
Arkansas		4,887		1,188,436		1,193,323
North Dakota		14,222		854,725		868,947
Nevada		—		792,208		792,208
Florida		—		695,035		695,035
Louisiana		35,295		496,478		531,773
Oklahoma		119,561		350,065		469,626
Montana		20,765		408,373		429,138
Other		82,081		1,229,508		1,311,589
Total		618,936		13,877,844		14,496,780

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

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The following table sets forth information relating to our acreage for our NPRIs as of September 30, 2014:

State	Developed Acreage		Undeveloped Acreage		Total Acreage
Texas		194,327		627,257		821,585
Montana		12,244		167,206		179,450
Louisiana		11,148		43,748		54,896
Mississippi		9,787		33,766		43,554
North Dakota		16,291		19,465		35,756
Arkansas		3,974		15,207		19,180
Wyoming		1,360		16,840		18,200
New Mexico		14,129		1,120		15,249
Oklahoma		7,068		4,828		11,897
Kansas		8,722		2,663		11,384
Other		367		3,041		3,408
Total		279,418		935,141		1,214,559

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

The following table sets forth information relating to our acreage for our ORRIs as of September 30, 2014:

State	Developed Acreage		Undeveloped Acreage		Total Acreage
Montana		295,568		165,674		461,242
Texas		221,897		2,482		224,379
Wyoming		136,279		35,671		171,950
Oklahoma		154,952		—		154,952
Louisiana		15,186		6,122		21,308
Utah		41,790		28,149		69,939
Michigan		55,259		919		56,178
New Mexico		46,631		1,847		48,478
Colorado		28,319		5,111		33,430
Alaska		7,664		12,375		20,039
Other		64,775		11,097		75,872
Total		1,068,321		269,447		1,337,768

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

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Working Interests

The following table sets forth information relating to our acreage for our working interests as of September 30, 2014:

State	Developed Acreage				Undeveloped Acreage				Total Acreage
	Gross		Net		Gross		Net		Gross		Net
Texas		167,791		42,952		153,614		37,147		321,405		80,099
North Dakota		40,120		5,856		8,849		977		48,969		6,833
Louisiana		31,221		4,128		18,874		2,021		50,095		6,149
Wyoming		22,342		4,207		11,443		5,961		33,785		10,168
Colorado		7,088		2,598		202		50		7,290		2,649
Michigan		13,208		1,330		79		—		13,287		1,330
Oklahoma		10,693		3,073		155		33		10,848		3,106
Kansas		5,856		6,213		921		—		6,777		6,213
New Mexico		6,118		3,926		520		98		6,638		4,024
South Dakota		2,160		504		880		55		3,040		559
Other		6,302		1,924		2,633		499		8,934		2,422
Total		312,899		76,712		198,170		46,842		511,069		123,554

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

The following table lists the net undeveloped acres, the net acres expiring in the years ending December 31, 2015, 2016, and 2017, and, where applicable, the net acres expiring that are subject to extension options:

	2017 Expirations				2016 Expirations				2015 Expirations
Net Undeveloped Acreage	Net Acreage without Ext. Opt.		Net Acreage with Ext. Opt.		Net Acreage without Ext. Opt.		Net Acreage with Ext. Opt.		Net Acreage without Ext. Opt.		Net Acreage with Ext. Opt.
46,842		1,605		151		6,188		202		4,919		522

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Drilling Results for Our Working Interests

The following table sets forth information with respect to the number of wells completed on our properties during the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation among the number of productive wells drilled, the quantities of reserves found, and the economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of return.

	For the Nine Months Ended September 30, 2014		For the Year Ended December 31,
			2013		2012		2011
Gross development wells:
Productive		112.0		191.0		217.0		209.0
Dry		—		—		—		1.0
Total		112.0		191.0		217.0		210.0
Net development wells:
Productive		3.8		7.2		8.1		9.2
Dry		—		—		—		—
Total		3.8		7.2		8.1		9.2
Gross exploratory wells:
Productive		—		1.0		—		—
Dry		—		—		—		—
Total		—		1.0		—		—
Net exploratory wells:
Productive		—		0.1		—		—
Dry		—		—		—		—
Total		—		0.1		—		—

As of September 30, 2014, we had 93 wells in the process of drilling, completing or dewatering, or shut in awaiting infrastructure that are not reflected in the above table.

Environmental Matters

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

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Waste Handling

The Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development, and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal, and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, development, and production of oil and natural gas are exempt from regulation as hazardous wastes under RCRA, these wastes typically constitute “solid wastes” that are subject to less stringent non-hazardous waste requirements. However, it is possible that RCRA could be amended or the EPA or state environmental agencies could adopt policies to require oil and natural gas exploration, development, and production wastes to become subject to more stringent waste handling requirements. Administrative, civil, and criminal penalties can be imposed for failure to comply with waste handling requirements. Any changes in the laws and regulations could have a material adverse effect on our operators’ capital expenditures and operating expenses, which in turn could affect production from our properties and adversely affect our business and prospects.

Remediation of Hazardous Substances

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

Water Discharges

The Federal Water Pollution Control Act of 1972, also known as the “Clean Water Act,” the SDWA, the Oil Pollution Act (“OPA”), and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. In addition, spill prevention, control, and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture, or leak. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges.

The OPA is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the

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requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil into surface waters.

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

Air Emissions

The federal Clean Air Act and comparable state laws and regulations regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, in August 2012, the EPA adopted new regulations under the Clean Air Act that established new emission control requirements for oil and natural gas production and processing operations. These laws and regulations may increase the costs of compliance for oil and natural gas producers and impact production on our properties, and federal and state regulatory agencies can impose administrative, civil, and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. Moreover, obtaining or renewing permits has the potential to delay the development of oil and natural gas projects.

Climate Change

In December 2009, the EPA issued an Endangerment Finding that determined that emissions of carbon dioxide, methane, and other GHGs present an endangerment to public health and the environment because, according to the EPA, emissions of these gases contribute to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allowed the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs from certain large stationary sources of GHG emissions. Additionally, in September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including certain onshore oil and natural gas exploration and production facilities.

In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of GHGs and almost one-half of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Although the U.S. Congress has not adopted this type of legislation at this time, it may do so in the future and many states continue to pursue regulations to reduce GHG emissions. Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect the oil and natural gas industry at this time; it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

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

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Hydraulic Fracturing

Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand, and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Our operators routinely use hydraulic fracturing. The SDWA regulates the underground injection of substances through the Underground Injection Control (“UIC”) program. Hydraulic fracturing generally is exempt from regulation under the UIC program, and the hydraulic-fracturing process is typically regulated by state oil and natural gas commissions. The EPA, however, has recently taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program, and issued guidance in February 2014 for hydraulic-fracturing activities involving the use of diesel. Additional regulatory actions taken by the EPA include: (i) the issuance an Advanced Notice of Proposed Rulemaking seeking public comment on the agency’s intent to develop and issue regulations under the Toxic Substances Control Act regarding the disclosure of information related to the chemicals used in hydraulic fracturing; (ii) announcing its intent to develop effluent limitations for the treatment and discharge of wastewater resulting from hydraulic-fracturing activities, expected sometime in 2015; (iii) publishing final rules under the federal Clean Air Act that require companies to employ “green completion” technology to address emissions of volatile organic compounds. Also, the U.S. Department of the Interior published a revised proposed rule on May 24, 2013 that would implement updated requirements for hydraulic-fracturing activities on federal lands, including new requirements relating to public disclosure, well bore integrity, and handling of flowback water.

Certain governmental reviews also have been conducted or are underway that focus on environmental aspects of hydraulic-fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic-fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, expected to be released sometime in 2015. Other governmental agencies, including the U.S. Department of Energy, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms.

Several states have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic-fracturing fluids. For example, Texas requires oil and natural gas operators to publicly disclose the chemicals used in the hydraulic-fracturing process. Regulations require that well operators disclose the list of chemical ingredients subject to the requirements of the Occupational Safety and Health Act, as amended (“OSHA”) on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission. Furthermore, in May 2013, the Texas Railroad Commission issued a “well integrity rule,” which updates the requirements for drilling, installing pipe, and cementing wells. The rule also includes new testing and reporting requirements, such as (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The “well integrity rule” took effect in January 2014. In addition, municipalities in Texas, Colorado, and several other states have adopted, or are in the process of adopting, ordinances restricting or prohibiting hydraulic fracturing within their jurisdictions. The widespread adoption of ordinances limiting hydraulic fracturing could adversely affect our business.

There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, the use of water and the potential for impacts to surface water, groundwater, and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic-fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, these laws could make it more difficult or costly to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing is further regulated at the federal or state level, hydraulic-fracturing activities on our properties could become subject to additional

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permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements, and potential increases in costs. These types of legislative changes could cause us and our operators to incur substantial compliance costs, and compliance or the consequences of any failure to comply could have a material adverse effect on our financial condition and our business. 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.

Occupational Safety and Health Act

The OSHA and comparable state laws and regulations govern the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard, the Emergency Planning and Community Right to Know Act and implementing regulations, and similar state statutes and regulations require that information be maintained about hazardous materials used or produced in operations on our properties and that this information be provided to employees, state and local government authorities, and citizens.

Endangered Species

The Endangered Species Act (“ESA”) and analogous state laws restrict activities that may affect endangered or threatened species or their habitats. Some of our properties may be located in areas that are or may be designated as habitats for endangered or threatened species, and previously unprotected species may later be designated as threatened or endangered in areas where we hold mineral interests. This could cause our operators to incur increased costs arising from species protection measures, delay the completion of exploration and production activities and/or result in limitations on operating activities that could have an adverse impact on our business.

Title to Properties

Prior to completing an acquisition of producing oil and natural gas properties, we perform title reviews on significant leases, and depending on the materiality of properties, we may obtain a title opinion or review previously obtained title opinions. As a result, title examinations have been obtained on a significant portion of our properties. After an acquisition, we review the assignments from the seller for scrivener’s and other errors and execute and record corrective assignments as necessary.

As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the titles to our properties on which we do not have proved reserves. Prior to the acquisition of those properties, our operators conduct a thorough title examination, and we perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. Our operators generally will not commence drilling operations on a property until we have cured any material title defects on such property.

We believe that the title to our assets is satisfactory in all material respects. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions, and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens, and encumbrances will materially detract from the value of these properties or from our interest in these properties or materially interfere with our use of these properties in the operation of our business. In addition, we believe that we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this prospectus.

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Competition

The oil and natural gas business is highly competitive in the exploration for and acquisition of reserves, the acquisition of minerals and oil and natural gas leases and personnel required to find and produce reserves. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national, or worldwide basis. Certain of our competitors may possess financial or other resources substantially larger than we possess. Our ability to acquire additional minerals and properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Oil and natural gas products compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal, and fuel oils. Changes in the availability or price of oil and natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations, and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas.

Seasonal Nature of Business

Weather conditions affect the demand for, and prices of, natural gas and can also delay drilling activities, disrupting our overall business plans. Demand for natural gas is typically higher during the winter, resulting in higher natural gas prices for our natural gas production during our first and fourth quarters. Certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Seasonal weather conditions can limit drilling and producing activities and other oil and natural gas operations in a portion of our operating areas. Due to these seasonal fluctuations, our results of operations for individual quarterly periods may not be indicative of the results that we may realize on an annual basis.

Employees

We are managed and operated by the board of directors and executive officers of our general partner. All of our employees, including our executive officers, are employees of Black Stone Management. As of September 30, 2014, Black Stone Management had 117 full-time employees. None of Black Stone Management’s employees are represented by labor unions or covered by any collective bargaining agreements.

Facilities

Our principal office location is in Houston, Texas and consists of 58,261 square feet of leased space.

Legal Proceedings

Although we may, from time to time, be involved in various legal claims arising out of our operations in the normal course of business, we do not believe that the resolution of these matters will have a material adverse impact on our financial condition or results of operations.

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MANAGEMENT

Management

We are managed and operated by the board of directors and executive officers of our general partner, the latter of whom are employed by Black Stone Management, our administrative manager and wholly owned subsidiary. The executive officers of our general partner will manage the day-to-day affairs of our business.

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 “Summary—Formation Transactions and Structure.” Our partnership agreement provides that our limited partners holding common units have the right to nominate and vote in the election of directors to the board of directors of our general partner. Except with respect to matters requiring preferred unitholder super majority approval, preferred unitholder majority approval or the approval of a preferred unitholder, at each meeting of the limited partners (or pursuant to any action by written consent), with respect to any and all matters presented to the limited partners for their action or consideration, each preferred unitholder is entitled to vote as a single class with the common units on an “as-converted” basis, meaning that each preferred unit has a number of votes equal to the number of common units into which the preferred unit is convertible at the time of a vote or consent. Please read “Description of Our Preferred Units—Voting; Waiver.”

Upon the closing of this offering, we expect that the board of directors of our general partner will have eleven directors. All of whom, other than             , will be independent as defined under the independence standards established by the NYSE and the Exchange Act. The NYSE does not require a listed publicly traded partnership, such as ours, to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating and corporate governance committee although we have determined to establish these committees. However, our general partner is required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by the NYSE and the Exchange Act.

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 the 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 the limited partner, multiplied by (y) the number of directors to be elected at the meeting.

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Executive Officers and Directors of Our General Partner

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

Name	Age (as of September 30, 2014)	Position With Our General Partner
Thomas L. Carter, Jr.	63	President, Chief Executive Officer, and Chairman
Marc Carroll	45	Senior Vice President and Chief Financial Officer
Holbrook F. Dorn	38	Senior Vice President, Business Development
Brock Morris	50	Senior Vice President, Engineering and Geology
Steve Putman	39	Senior Vice President, General Counsel, and Secretary
Allan Skov	51	Senior Vice President, Corporate Services, and Chief Information Officer
William G. Bardel	75	Director
D. Mark DeWalch	53	Director
Jerry V. Kyle, Jr.	53	Director
Michael C. Linn	62	Director
John H. Longmaid	69	Director
William N. Mathis	48	Director
Richard N. Papert	54	Director
Alexander D. Stuart	64	Director
Allison K. Thacker	41	Director
		Director

Thomas L. Carter, Jr. Mr. Carter has served as President, Chief Executive Officer, and Chairman of our general partner since November 2014. Mr. Carter is the founder of BSMC and has served as President, Chief Executive Officer and Chairman of BSNR since 1998. Prior to his latest position with BSMC, Mr. Carter served as Managing General Partner of W.T. Carter & Bro. from 1987 to 1992 and Black Stone Energy Company from 1980 to present, both of which preceded our general partner. Mr. Carter founded Black Stone Energy Company, BSMC’s operating and exploration subsidiary, in 1980. From 1978 to 1980, Mr. Carter served as a lending officer in the Energy Department of Texas Commerce Bank in Houston, Texas, after serving in various other roles from 1975. Mr. Carter received M.B.A. and B.B.A. degrees from the University of Texas at Austin. Mr. Carter has been a director of Carrizo Oil & Gas Inc. since 2005. He has served as a Trustee at Episcopal High School in Houston, Texas since 2004, and as a Trustee of St. Edward’s University since 2009. Mr. Carter has been a trustee of a nonprofit since 1998, and was elected to a four year term as president of the board of trustees of the nonprofit in 2013. Mr. Carter also serves on the University of Texas at Austin Internal Audit Committee, the University Lands Advisory Board, and the Ripley Foundation board.

Mr. Carter’s extensive industry and executive management experience and his background in finance qualify him to serve on the board of directors of our general partner.

Marc Carroll. Mr. Carroll has served as Senior Vice President and Chief Financial Officer of our general partner since November 2014. Mr. Carroll has served as Senior Vice President and Chief Financial Officer of BSNR since January 2008. Mr. Carroll previously served as Vice President of Finance, after beginning his employment with our general partner as the Manager of Finance in September 2004. Before joining BSMC, Mr. Carroll was employed by El Paso Corporation from July 1998 to August 2004 as a Natural Gas Trader, Manager of Business Development, and Manager of Financial Planning and Analysis. Mr. Carroll held several positions at The Coastal Corporation and Energy Ventures Inc. (predecessor to Weatherford International) from 1992 to 1996. Mr. Carroll received a B.B.A. in Accounting and a B.B.A. in Business Analysis from Texas A&M University, and received his M.B.A. from Rice University. Mr. Carroll is a Certified Public Accountant.

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Holbrook F. Dorn. Mr. Dorn has served as Senior Vice President, Business Development of our general partner since November 2014. Mr. Dorn has served as Senior Vice President, Business Development of BSNR since 2010. Prior to serving as Senior Vice President, Mr. Dorn served as Vice President, Business Development from 2008 through 2010. He was also previously employed at BSMC from 2002 to 2004 as an Associate in Business Development. Mr. Dorn also served at Touradji Capital Management, LP from 2006 to 2008. Mr. Dorn received a B.B.A. from the University of Texas at Austin and an M.B.A. from Columbia University.

Allan Skov. Mr. Skov has served as Senior Vice President, Corporate Services and Chief Information Officer of our general partner since November 2014. Mr. Skov has served as Senior Vice President, Corporate Services, and Chief Information Officer of BSNR since 2013. Prior to his current role, Mr. Skov held the position of Chief Information Officer of BSNR beginning in 2009. Before he joined BSMC, Mr. Skov served as Vice President Information Technology of DCP Midstream, Duke Energy’s joint venture with ConocoPhillips, from 2003 to 2008 and held the position of Director IT Strategies and Consulting at Duke Energy from 2001 to 2003. He also served as Chief Information Officer of Newfoundland Power Inc. from 1997 to 2001 and held various positions in finance, human resources, customer service, and information technology at Union Gas Limited from 1986 to 1997. Mr. Skov received Bachelor of Commerce and M.B.A. degrees from the University of Windsor in Ontario, Canada.

Brock Morris. Mr. Morris has served as Senior Vice President, Engineering and Geology of our general partner since November 2014. Mr. Morris has served as Senior Vice President, Engineering and Geology of BSNR since 2013. From 2006 to 2013, Mr. Morris served as Managing Director—Exploration and Production of Quintana Capital Group and its energy-focused private equity funds, overseeing all upstream oil and natural gas investments. He served as Vice President, Exploration and Production of Quintana Minerals Corporation from 1995 to 2006 and in various engineering and management roles at Quintana Petroleum Corporation from 1985 to 1995. Mr. Morris received a B.S. in Petroleum Engineering from Texas A&M University.

Steve Putman. Mr. Putman has served as Senior Vice President, General Counsel, and Secretary of our general partner since November 2014. Mr. Putman has served as Senior Vice President, General Counsel, and Secretary of BSNR since 2013. Prior to joining BSMC, Mr. Putman was Managing Director and General Counsel of Quintana Capital Group from 2008 to 2013 and Vice President, General Counsel, and Secretary of Quintana Maritime Limited from 2005 to 2008. He also worked as an associate at Vinson & Elkins L.L.P. from 2001 to 2005 and Mayer Brown LLP from 2000 to 2001. Mr. Putman received a B.A. from the University of Texas at Austin and a J.D. from the University of Chicago. He is licensed to practice law in the states of Texas and Illinois.

William G. Bardel. Mr. Bardel has served as director of our general partner since January 2015. Mr. Bardel has served as director of BSNR since 2004. He has acted as a financial consultant to a number of educational institutions since 2006. He previously served as the Chief Financial Officer of the Lawrenceville School, a preparatory high school in Lawrenceville, New Jersey, from 1994 until 2006. The Lawrenceville School had an annual budget of $40 million and an endowment of $200 million. Mr. Bardel has been a director of Hudson City Bancorp, Inc. since 2003 and currently serves as its lead independent director and is the audit committee financial expert. From 1988 until 1994, Mr. Bardel was the head of the Government Advisory Group of Lehman Brothers in London, England. From 1984 to 1994, Mr. Bardel served as a managing director of Lehman Brothers. A graduate of Yale University, Mr. Bardel has a Masters degree from Oxford University where he was a Rhodes Scholar. Mr. Bardel received his J.D. from Harvard Law School.

Mr. Bardel brings valuable expertise to the board of directors of our general partner due to his high level of familiarity with financial control issues and strategic planning, including time as a director for financial institutions.

D. Mark DeWalch. Mr. DeWalch has served as director of our general partner since January 2015. Mr. DeWalch has served as director of BSNR since 2009 and currently serves as chair of the CapEx Committee and member of the Nominating and Governance Committee. Mr. DeWalch has served as Executive Vice President and Chief Financial Officer of DeWalch Technologies, Inc. since 1993 and has been a co-owner of

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DeWalch Technologies, Inc. since 1995. Mr. DeWalch has served on the board of directors of DeWalch Technologies, Inc. since 1985. Mr. DeWalch also serves as President of DeWalch Holdings LLC and is co- owner of DeWalch Holdings LLC. Mr. DeWalch began his career in commercial banking in New York with the Irving Trust Company where he served as a lending officer. Mr. DeWalch received MBA and BBA degrees from the University of Texas at Austin.

Mr. DeWalch provides valuable financial expertise to the board of directors of our general partner due to his background in commercial banking, as well as a unique operational perspective due to his experience with DeWalch Technologies, Inc.

Jerry V. Kyle, Jr. Mr. Kyle has served as director of our general partner since January 2015. Mr. Kyle has served as director of BSNR since January 2013. Mr. Kyle has been a Partner at Andrews Kurth LLP since 2002. Mr. Kyle received his J.D. from the University of Texas School of Law in 1990 and his BA from The Colorado College in 1984. He is a member of the Texas Bar Foundation and the Austin Bar Association.

Mr. Kyle’s extensive experience as a lawyer practicing in matters related to finance, lending, securities issuance and regulation, and legislative and regulatory affairs qualify him to serve on the board of directors of our general partner.

Michael C. Linn. Mr. Linn has served as a director of our general partner since January 2015. Mr. Linn has served as director of BSNR since January 2013 and currently serves on the CapEx Committee and the Compensation Committee. Mr. Linn is the founder of Linn Energy LLC and has served as a director of Linn Energy LLC since December 2011. Prior to such time, he was Executive Chairman of the Board of Directors of Linn Energy LLC since January 2010 and Chairman and Chief Executive Officer of Linn Energy, LLC from December 2007 to January 2010. Following his retirement as Executive Chairman of the Board of Linn Energy LLC in December 2011, Mr. Linn formed MCL Ventures LLC, a private investment vehicle that will focus on purchasing oil and natural gas royalty interests as well as non-operated interests in oil and natural gas wells, subject to the non-competition provisions in his retirement agreement with Linn Energy LLC. Mr. Linn has served as President of MCL Ventures LLC since 2011. Mr. Linn has also served as a member of the board of directors of Nabors Industries Ltd. since 2012, a senior advisor to Quantum Energy Partners since 2012, a member of the board of directors and a member of the Audit Committee of Western Refining GP LLC since 2013, and a member of the board of directors of Centrica, plc since June 2013.

Mr. Linn’s many years of experience as the Chief Executive Officer of a publicly traded oil and natural gas master limited partnership, as well as his deep industry knowledge and prior public company board experience, make him particularly well-suited to serve on the board of directors of our general partner.

John H. Longmaid. Mr. Longmaid has served as director of our general partner since January 2015. Mr. Longmaid has served as director of W.T. Carter & Bro., a predecessor to BSMC, then BSNR since 1984. He has been the President of John Longmaid Designs, Inc., a Maine corporation since 1982. Mr. Longmaid holds a BS degree in physics/environmental science from the University of Puget Sound with additional studies in physical chemistry, advanced math, and engineering. He attended post graduate studies at Washington State University.

Mr. Longmaid brings a wealth of experience to the board due to his continuous membership on the board of directors of W.T. Carter & Bro., as well as BSNR, where he gained experience overseeing entities in the oil and natural gas industry.

William N. Mathis. Mr. Mathis has served as director of our general partner since January 2015. Mr. Mathis has served as director of BSNR since 2009. Since 2001, he has been the managing partner of Conti Street Partners LLC, an investment company in Houston, Texas. He has served on the board of Highland Resources, Inc. since 2004, the board of The GRB Partnership since 1998, and has been chairman of Australis Aquaculture LLC since 2009. He has also served as managing member of Wellspring Energy Partners, L.P. since 2012.

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Mr. Mathis served on the board of Wilson Industries Inc. from 1994 to 1998, Paradigm Services LP from 1998 to 2008 and EnTouch Communications from 1999 to 2007. In addition, Mr. Mathis served on the board and executive committee of Davidson College and currently serves on the boards of The Museum of Fine Arts – Houston, The Chinquapin School, The Brown Foundation Inc of Houston, The Texas Medical Center, and Texas Children’s Hospital. Mr. Mathis is a graduate of Davidson College.

Mr. Mathis’s extensive experience in the oil and natural gas industry as well as extensive director-level corporate governance expertise qualify him to serve on the board of directors of our general partner.

Richard N. Papert. Mr. Papert has served as director of our general partner since January 2015. Mr. Papert has served as director of BSNR since 2009. He is President of LeFrak Energy, the oil and natural gas division of LeFrak, a privately held company based in New York City that is active in real estate, energy, and other investments. Mr. Papert has also held various positions at LeFrak since 1992 and currently serves, in addition to President of LeFrak Energy, as Executive Vice President and Co-Chief Investment Officer of LeFrak. He helps oversee the LeFrak family office where he supervises LeFrak’s extensive holdings which have included equities, fixed income, hedge funds and hedge fund strategies, and private equity. Prior to joining LeFrak in 1992, Mr. Papert was a Vice President at Goldman, Sachs & Co., Inc., a strategic consultant with the Boston Consulting Group, Inc., and an officer of the Chase Manhattan Bank, N.A. Mr. Papert is a graduate of Dartmouth College, where he received highest distinction in economics and was elected to Phi Beta Kappa. Mr. Papert also attended the Harvard Graduate School of Business Administration, where he earned his MBA.

Mr. Papert brings valuable financial expertise and oil and natural gas experience to the board of directors of our general partner due to his distinguished career in finance and prior roles related to investments in the oil and natural gas industry.

Alexander D. Stuart. Mr. Stuart has served as director of our general partner since January 2015. Mr. Stuart has served as director of BSNR since 1990 and serves as Chair of the Finance Committee. He has been the President of North Star Investments, an investment firm responsible for identifying and managing a wide variety of assets, since 2004 and has served as the managing partner of RDS Investments, a limited partnership with extensive holdings in private equity, venture capital, real estate, energy, and publicly traded stocks and bonds since 2005. Mr. Stuart became a trustee of Lake Forest College in 2012 and St. Andrews School in 2009 and serves on the endowment committees for both institutions. Since 2006, Mr. Stuart has been a director of Northwestern Lake Forest Hospital and is also a member of the investment committee for the parent organization, Northwestern Memorial Hospital. Mr. Stuart received his A.B. from Princeton University and his MBA from Harvard Business School.

Mr. Stuart’s investment management experience and experience serving as a director of BSNR qualify him to serve on the board of directors of our general partner.

Allison K. Thacker. Ms. Thacker has served as director of our general partner since January 2015. Ms. Thacker has served as director of BSNR since January 2013. She joined Rice University in 2011 as Vice President for Investments and Treasurer and President of the Rice Management Company with the responsibility of managing a $5.5 billion endowment fund. The Rice University Endowment ranks in the top 20 endowments of private research universities in the United States. Prior to joining Rice University, Ms. Thacker spent 11 years with RS Investments, a San Francisco-based investment firm specializing in public equities. At RS Investments, Ms. Thacker held roles including portfolio manager, managing director, and research analyst. In the earlier portion of her career, Ms. Thacker served as a summer analyst at Putnam Investments and as a financial analyst in the energy investment banking group at Merrill Lynch & Co. She was a founding board member of KIPP Heartwood Academy, a college preparatory charter school serving East San Jose, California and is currently a member of the KIPP Houston Advisory board and the Houston Ballet board of trustees. Ms. Thacker is a graduate of Harvard Business School, where she received an MBA. She has a Bachelor of Arts degree in economics with honors from Rice University.

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Ms. Thacker brings significant financial expertise to the board of directors of our general partner due to her extensive prior experience in investment management as well as her experience as a board member of BSNR.

Director Independence

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

Committees of the Board of Directors

The board of directors of our general partner will have an audit committee, a compensation committee, a nominating and governance committee, and a conflicts committee.

Audit Committee

We are required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by the NYSE and Rule 10A-3 promulgated under the Exchange Act.              will serve as the initial members of the audit committee. The audit committee will assist the board of directors in its oversight of (i) the integrity of our financial statements, (ii) our compliance with legal and regulatory requirements, (iii) qualifications and independence of our independent registered public accounting firm, and (iv) performance of our internal audit function and independent registered public accounting firm. The audit committee will have the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm, and pre-approve any non-audit services and tax services to be rendered by our independent registered public accounting firm. The audit committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to the audit committee and our management, as necessary.

Compensation Committee

Because we are a limited partnership, we are not required by the rules of the NYSE to have a compensation committee or, in the event we choose to establish one, a compensation committee composed entirely of independent directors. However, we nevertheless expect that we will have a compensation committee following the completion of this offering. The compensation committee will review and determine the compensation for the executive officers of our general partner and will review and make recommendations to the board of directors of our general partner regarding director compensation. The compensation committee will also administer our incentive compensation and equity-based benefit plans.              will serve as the initial members of the compensation committee.

Nominating & Governance Committee

Because we are a limited partnership, we are not required by the rules of the NYSE to have a nominating and governance committee or, in the event we choose to establish one, a nominating and governance committee composed entirely of independent directors. However, we nevertheless expect that we will have a nominating and governance committee following the completion of this offering. The nominating and governance committee will identify individuals qualified to serve on the board of directors of the general partner and recommend director nominees for each annual meeting of unitholders or for appointment to fill vacancies, oversee our governance policies, including developing and recommending to the board of directors of the general partner a set of corporate governance guidelines, and oversee the evaluation of the board and its committees.              will serve as the initial members of the nominating and governance committee.

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Conflicts Committee

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

Certain Relationships and Related Party Transactions

Promissory Notes

We executed promissory notes dated April 15, 2010, in the amount of $0.5 million to Marc Carroll and Holbrook F. Dorn. The promissory notes related to the acquisition of a partnership interest in Ivory Acquisitions Partners, L.P. by the officers and the notes were collateralized by a security interest in BSMC. The promissory notes provided for quarterly payments of interest at a blended rate of 2.73% and 2.83% at December 31, 2013 and 2012, respectively, equal to the rate at which BSMC paid interest on its borrowings. At December 31, 2013 and 2012, less than $0.1 million of interest receivable on the notes was included in prepaid expenses and other current assets on the consolidated balance sheets. At December 31, 2013 and 2012, the aggregated note balances were $0.1 million and $0.2 million, respectively, and were included in prepaid expenses and other current assets, respectively, on the consolidated balance sheets. These promissory notes were paid in full on the maturity date of April 15, 2014.

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

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

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

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EXECUTIVE COMPENSATION AND OTHER INFORMATION

We are providing compensation disclosure that satisfies the requirements applicable to emerging growth companies, as defined in the JOBS Act.

Summary Compensation Table

The table below provides information concerning the annual compensation of our named executive officers (our “Named Executive Officers” or “NEOs”) for the fiscal years ended December 31, 2013 and December 31, 2014.

Name and Principal Position	Year		Salary ($)(1)		Unit Awards ($)(2)		Non-Equity Incentive Plan Compensation ($)(3)		All Other Compensation ($)(4)		Total ($)
Thomas L. Carter, Jr.		2014	$	669,500	$	2,594,313	$	787,939	$	119,286	$	4,171,038
(Chairman of the Board of Directors and Chief Executive Officer)		2013	$	650,000	$	2,518,750	$	1,579,841	$	25,055	$	4,773,646
Marc Carroll		2014	$	386,250	$	1,158,750	$	275,000	$	13,000	$	1,833,000
(Senior Vice President and Chief Financial Officer)		2013	$	355,000	$	1,125,000	$	669,075	$	12,750	$	2,161,825
Holbrook F. Dorn		2014	$	334,750	$	1,004,250	$	208,333	$	13,000	$	1,560,333
(Senior Vice President, Business Development)		2013	$	311,666	$	975,000	$	549,864		—	$	1,836,530

(1) Amounts include elective deferrals made by our Named Executive Officers under the Black Stone Energy Company 401(k) Plan (the “401(k) Plan”).

(2) Amounts reflect the grant date fair value of common units in our predecessor and common shares in BSNR granted on January 1, 2013, computed in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 718. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional details regarding the assumptions underlying the value of these awards. Effective as of December 31, 2013, the common shares in BSNR were exchanged for common units in our predecessor.

(3) Amounts reflect (i) short-term incentive bonus awards earned by Messrs. Carter, Carroll, and Dorn in 2013 and (ii) performance-based cash incentive awards under the BSMC 2012 Executive Incentive Plan (the “EIP”) earned by each NEO in 2013 and 2014. Please see “Narrative Disclosure to the Summary Compensation Table—Short-Term Incentive Bonuses” for additional details regarding the short-term incentive bonus awards earned in 2013. Please see “Narrative Disclosure to the Summary Compensation Table—Long-Term Incentive Awards” for additional details regarding the performance-based cash incentive awards under the EIP earned in 2013. Short-term incentive bonus awards for fiscal 2014 have not been included because they were not calculable through the latest practicable date. These amounts are expected to be determined when our audited financials for fiscal 2014 are completed. Once determined, these amounts will be disclosed in a filing under Item 5.02(f) of Form 8-K.

(4) The amounts included in “All Other Compensation” reflect (i) for Mr. Carter: reimbursement in 2014 for his personal use of private aircraft in an amount equal $106,286 and sporting event tickets of $12,305 that we paid on his behalf in 2013 as well as matching contributions equal to $12,750 and $13,000 that were made to the 401(k) Plan on his behalf in 2013 and 2014, respectively; (ii) for Mr. Carroll: matching contributions equal to $12,750 and $13,000 that were made to the 401(k) Plan on his behalf in 2013 and 2014, respectively; and (iii) for Mr. Dorn: matching contributions equal to $13,000 that were made to the 401(k) Plan on his behalf in 2014.

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Narrative Disclosure to the Summary Compensation Table

For fiscal 2013 and 2014, the principal elements of compensation provided to our Named Executive Officers were base salaries, short-term incentive bonuses, long-term incentive awards, and retirement, health, welfare, and additional benefits.

Base Salary

Base salaries are generally set at levels deemed necessary to attract and retain individuals with superior talent commensurate with their relative expertise and experience.

Short-Term Incentive Bonuses

The short-term incentive bonus (“STI Bonus”) opportunity is based upon our pay-for-performance philosophy. The STI Bonus provides our Named Executive Officers with an incentive in the form of an annual cash bonus to achieve our overall business goals. The STI Bonuses for fiscal 2013 were equal to the product of each Named Executive Officer’s (i) target bonus and (ii) our EBITDA achievement factor for 2013 as reflected below.

Name	Target Bonus Value		EBITDA Achievement Ratio			Actual Bonus Earned
Thomas L. Carter, Jr.	$	780,000		1.0152596	(1)	$	791,902
Marc Carroll	$	375,000		1.0508654	(2)	$	394,075
Holbrook F. Dorn	$	325,000		1.0508654	(2)	$	341,531

(1) For purposes of calculating Mr. Carter’s 2013 STI Bonus, the EBITDA achievement ratio was calculated as the ratio of our contract EBITDA for 2013 to our budgeted contract EBITDA for 2013. For this purpose, (a) our contract EBITDA for 2013 was calculated as the sum of our (i) net income, (ii) interest expense, (iii) income tax expense, (iv) depreciation, depletion and amortization expense, (v) targeted compensation associated with grants or issuances of equity interests (including carried interests in real property) to employees or members of our board or associated with our incentive or retention plans or agreements (whether cash or equity), and (vi) dry hole expense, as determined in accordance with GAAP, consistently applied and (b) our budgeted contract EBITDA for 2013 was the contract EBITDA amount projected in the annual budget approved by our board.

(2) For purposes of calculating Messrs. Carroll’s and Dorn’s 2013 STI Bonuses, the EBITDA achievement ratio was calculated as the ratio of our actual EBITDA for 2013 to our budgeted EBITDA for 2013, as adjusted by an adjustment factor that accelerates the effect of under- or over-achievement such that an EBITDA achievement ratio of 1.3 or more results in a 200% adjustment factor and an EBITDA achievement ratio of 0.7 or less results in a 0% adjustment factor, with linear interpolation between such thresholds. For this purpose, (a) our actual EBITDA for 2013 was calculated as the sum of items (i) through (vi) in footnote 2 above and (b) our budgeted EBITDA for 2013 was the EBITDA amount projected in the annual budget approved by our board.

As noted above, STI Bonuses for fiscal 2014 have not been included because they were not calculable through the latest practicable date. These amounts are expected to be determined when our audited financials for fiscal 2014 are completed. Once determined, these amounts will be disclosed in a filing under Item 5.02(f) of Form 8-K.

Long-Term Incentive Awards

In each of fiscal 2013 and fiscal 2014, each of our Named Executive Officers was granted a target incentive award. 50% of each target incentive award consists of a performance-based cash incentive award under the EIP. The performance-based cash incentive awards “cliff” vest at the end of a three-year performance period so long as the NEO remains continuously employed by BSNR or one of its subsidiaries through such date, subject to certain exceptions discussed below under “Additional Narrative Disclosure—Potential Payments Upon Termination or a Change in Control—2012 Executive Incentive Plan and Restricted Unit Award Agreements.”

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However, the performance-based cash awards granted in 2012 are subject to three-year graded vesting based on the continued employment requirement (and the applicable exceptions) described above. The ultimate amount paid in respect of each cash incentive award is determined based on the achievement of certain reserve and production targets established by the compensation committee of our board.

The remaining 50% of each target incentive award consisted of common units in our predecessor (and, with respect to awards granted in 2013, common shares in BSNR) granted pursuant to Restricted Unit Award Agreements entered into with each NEO. Effective as of December 31, 2013, the common shares in BSNR were exchanged for common units in our predecessor. One-third of the units subject to such awards vest ratably on January 1 of each of the three years following the first day of the performance period so long as the NEO remains continuously employed by BSNR or one of its subsidiaries through such date, subject to certain exceptions discussed below under “Additional Narrative Disclosure—Potential Payments Upon Termination or a Change in Control—2012 Executive Incentive Plan and Restricted Unit Award Agreements.” Within 30 days of each vesting date, each NEO may request that we repurchase up to 50% of the units that vest on such date in exchange for a cash payment equal to the then-current fair market value of such units, but we are not under any obligation to accept any such proposed repurchase. In connection with this offering and the other formation transactions described in this prospectus, all unvested units in our predecessor will be exchanged for an aggregate of restricted units pursuant to the Black Stone Minerals, L.P. Long-Term Incentive Plan (the “LTIP”) described below.

Employment Agreement with Mr. Carter

Mr. Carter entered into an employment agreement with our predecessor in 2008, which was subsequently amended in 2014. The term of the agreement automatically renews annually for successive 12-month periods on March 31 of each year unless either party provides written notice of non-renewal. Under the agreement, Mr. Carter is entitled to an annualized base salary and is eligible for short-term annual bonuses based on the performance measures described above. As discussed below under “Additional Narrative Disclosure—Potential Payments Upon Termination or a Change in Control—Mr. Carter’s Employment Agreement,” the employment agreement also provides for certain severance payments in the event Mr. Carter’s employment is terminated under certain circumstances. However, we expect that Mr. Carter’s employment agreement will be terminated in connection with this offering and that our general partner or one of our subsidiaries will enter into a severance agreement with Mr. Carter, as described below under “Additional Narrative Disclosure—Potential Payments Upon Termination or a Change in Control—Severance Agreements.”

Outstanding Equity Awards at 2014 Fiscal Year-End

The following table reflects information regarding outstanding unvested common units in BSMC held by our Named Executive Officers as of December 31, 2014. In connection with this offering and the other formation transactions described under “Summary—Formation Transactions and Structure,” the common units in our predecessor included in the table below will be exchanged for an aggregate of              restricted units pursuant to the LTIP (as defined below).

	Unit Awards
Name	Number of Units that Have Not Vested(1)			Market Value of Units that Have Not Vested(5)
Thomas L. Carter, Jr.		2,999,393	(2)	$
Marc Carroll		1,294,155	(3)	$
Holbrook F. Dorn		1,103,847	(4)	$

(1) The applicable equity awards that are disclosed in this Outstanding Equity Awards at 2014 Fiscal Year-End table are common units in our predecessor.

(2) 1,476,291 of these units vested on January 1, 2015. 1,009,990 of the remaining units will become vested on January 1, 2016 and the remaining 513,112 units will become vested on January 1, 2017, in each case, so long as Mr. Carter remains employed by our general partner or one of our affiliates on such dates.

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(3) 613,862 of these units vested on January 1, 2015. 451,112 of the remaining units will become vested on January 1, 2016 and the remaining 229,181 units will become vested on January 1, 2017, in each case, so long as Mr. Carroll remains employed by our general partner or one of our affiliates on such dates.

(4) 514,259 of these units vested on January 1, 2015. 390,964 of the remaining units will become vested on January 1, 2016 and the remaining 198,624 units will become vested on January 1, 2017, in each case, so long as Mr. Dorn remains employed by our general partner or one of our affiliates on such dates.

(5) Reflects the market value of common units in our predecessor as of December 31, 2014, calculated using mid-point of the price range set forth on the cover page of this prospectus.

Additional Narrative Disclosure

Retirement Benefits

We have not maintained, and do not currently maintain, a defined benefit pension plan or a nonqualified deferred compensation plan providing for retirement benefits. Our Named Executive Officers currently participate in the 401(k) Plan, which permits all eligible employees, including the Named Executive Officers, to make voluntary pre-tax contributions to the plan. In addition, we are permitted to make discretionary matching contributions under the plan. Matching contributions are subject to a graded vesting schedule, with 33% vested after one year, 66% vested after two years, and 100% vested after the initial three years of employment with us. Following three years of employment, future company matching contributions vest immediately. All contributions under the plan are subject to certain annual dollar limitations, which are periodically adjusted for changes in the cost of living.

Potential Payments Upon Termination or a Change in Control

Mr. Carter’s Employment Agreement

Under Mr. Carter’s employment agreement, if his employment is terminated by our predecessor without “cause,” then so long as Mr. Carter executes a release in a form satisfactory to us within 10 days following such termination, he will receive a lump sum cash severance payment within 60 days following the date of such termination equal to the sum of (1) a pro-rated portion of his target STI Bonus for the year in which such termination occurs (determined without regard to actual performance) and (2) the greater of (A) the sum of (i) any unpaid STI Bonus for the year prior to the year in which such termination occurs and (ii) his then-current base salary and target STI Bonus payable for the remainder of the term of the agreement or (B) the sum of his then-current annualized base salary and target STI Bonus.

In addition, upon Mr. Carter’s resignation for “good reason” or a termination of his employment by us without cause following a “change in control,” so long as Mr. Carter executes a release in a form satisfactory to us within 10 days following such termination, he will receive a lump sum cash severance payment within 60 days following the date of such termination equal to the sum of (1) a pro-rated portion of his target STI Bonus for the year in which such termination occurs (determined without regard to actual performance) and (2) the greater of (A) the sum of (i) any unpaid STI Bonus for the year prior to the year in which such termination occurs and (ii) his then-current base salary and target STI Bonus payable for the remainder of the term of the agreement or (B) two times the sum of his then-current annualized base salary and target STI Bonus.

As noted above, we expect that Mr. Carter’s employment agreement will be terminated in connection with this offering and that our general partner or one of our subsidiaries will enter into a severance agreement with Mr. Carter that will provide for the payment of a cash severance payment in the event Mr. Carter’s employment is terminated under certain circumstances, as described below under “Additional Narrative Disclosure—Potential Payments Upon Termination or a Change in Control—Severance Agreements.”

For purposes of Mr. Carter’s employment agreement:

• “Cause” means Mr. Carter (i) has failed or refused to perform or observe any material term or provision of the agreement (including voluntarily terminating his employment) or to materially follow and satisfactorily perform (in our reasonable discretion) any lawful directions of the board; (ii) has been

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indicted for or convicted of, or has pleaded guilty or nolo contendere to a charge that he committed, a felony or other crime of moral turpitude; (iii) has perpetrated an act of fraud or dishonesty against or involving, or theft of our property; (iv) has violated any applicable federal, state, or local law or regulation and, as a result of such violation, has become, or has caused us to become the subject of any legal action or administrative proceeding or a suspension of any right or privilege; or (v) has committed any act that causes, or knowingly or recklessly fails to take reasonable and appropriate action to prevent, any material injury to our financial condition or business reputation.

• “Good Reason” means at any time subsequent to a change of control or the first public equity offering of partnership interests or other equity securities of our predecessor, BSNR, or any controlled subsidiary thereof or successor thereto registered under the Securities Act, we assign to Mr. Carter any duties materially inconsistent with his positions, duties, responsibilities, and status with us immediately prior to such change of control or public equity offering or we change Mr. Carter’s reporting responsibilities, titles, or offices as in effect immediately prior to such change of control or public equity offering.

• “Change of Control” means (i) the transfer of beneficial ownership of a majority of the outstanding units of our predecessor or a majority of the outstanding units of BSNR to any person or entity, except that if beneficial ownership would be deemed to occur merely upon the execution of voting agreements to support a merger, consolidation, or other business combination transaction to be consummated in the future, then the board may in its sole discretion determine that the date of such Change of Control shall instead be the date of such consummation; (ii) the partners of our predecessor or the members of BSNR prior to any merger, consolidation, or other business combination transaction do not continue to own at least 50% of the surviving entity following such merger, consolidation, or other business combination transaction; (iii) other than in the ordinary course of business, our predecessor sells, leases, or exchanges all or substantially all of its assets and its controlled subsidiaries, taken as a whole, to any other person or entity (other than a direct or indirect controlled subsidiary of our predecessor); (iv) our predecessor is materially or completely liquidated; (v) on or after an initial public offering, any person or entity becomes the beneficial owner, directly or indirectly, of 30% or more of the units, shares, or other equity securities of our predecessor, BSNR, or any such subsidiary or successor; or (vi) during any consecutive two-year period, individuals who constituted the board (together with any new managers whose election by the board or whose nomination for election by BSNR was approved by a vote of at least three quarters of the managers still in office who were either managers at the beginning of such period or whose election or nomination for election was previously so approved) cease for any reason to constitute a majority of the board.

Mr. Carter’s employment agreement also contains certain restrictive covenants pursuant to which he has recognized certain confidentiality covenants as well as a covenant not to solicit any of our employees or any independent contractor working in our land administration department during the term of the agreement and for a period of two years thereafter.

2012 Executive Incentive Plan and Restricted Unit Award Agreements

Under the EIP, if a NEO’s employment terminates due to his death or “disability” or his employment is involuntarily terminated for any other reason other than cause (or, if the NEO has an employment agreement, due to the NEO’s resignation for good reason), the NEO (or the NEO’s estate, as applicable) will be entitled to receive a pro-rated portion of each cash incentive award for each performance period that includes the NEO’s termination date. In addition, pursuant to the Restricted Unit Award Agreements, if a NEO’s employment terminates due to his death or “disability” or his employment is involuntarily terminated for any other reason other than cause, a pro-rated portion of the NEO’s unvested common units in our predecessor and common units in BSNR will become vested as of such termination. For purposes of the EIP and the Restricted Unit Award Agreements, “cause” and “good reason” generally have the same meanings as described above with respect to Mr. Carter’s employment agreement and “disability” means a mental or physical condition resulting from an injury or illness that renders the NEO incapable of performing the essential functions of the NEO’s position with reasonable accommodations for 90 days out of any 120-day period.

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Severance Agreements

In connection with the closing of this offering, our general partner intends to enter into, or cause one of our affiliates to enter into, a severance agreement with each of our executive officers that, among other things, will provide for the payment of a cash severance payment in the event the executive officer’s employment is terminated under certain circumstances. Please see “Management—Executive Officers and Directors of Our General Partner” for information on the executive officers of our general partner upon consummation of this offering.

Long-Term Incentive Plan

Prior to the closing of this offering, our general partner intends to adopt the LTIP, pursuant to which non-employee directors of our general partner and certain employees and certain consultants of our general partner and our affiliates will be eligible to receive awards with respect to our common units. The description of the LTIP set forth below is a summary of the material anticipated features of the LTIP. This summary, however, does not purport to be a complete description of all of the anticipated provisions of the LTIP and is qualified in its entirety by reference to the LTIP, the form of which is filed as an exhibit to this registration statement.

The LTIP will provide for the grant, from time to time, at the discretion of the board of directors of our general partner or a committee thereof, of unit options, unit appreciation rights, restricted units, phantom units, unit awards, distribution equivalent rights (“DERs”), cash awards, and other unit-based awards. Subject to adjustment in the event of certain transactions or changes in capitalization, an aggregate of              common units may be delivered pursuant to awards under the LTIP. Units subject to awards that are forfeited, cancelled, exercised, paid, or otherwise terminated without the delivery of units, and certain units held back to cover the exercise price or tax withholding applicable to an award, will be available for delivery pursuant to other awards under the LTIP. Under the LTIP, the maximum aggregate grant date fair value of awards granted to a non-employee director of our general partner during any calendar year will not exceed $         (or $         in the first year in which an individual becomes a non-employee director). The LTIP will be administered by the board of directors of our general partner or a committee thereof, either of which we refer to herein as the “committee.” The LTIP will be designed to promote our interests, as well as the interests of our unitholders and to encourage superior performance, by rewarding the directors of our general partner and employees and consultants of our general partner and our affiliates, as well as by strengthening our general partner’s and our affiliates’ abilities to attract, retain, and motivate individuals who are essential for our growth and profitability.

Unit Options and Unit Appreciation Rights

The LTIP will permit the grant of unit options and unit appreciation rights covering common units. Unit options represent the right to purchase a number of common units at a specified exercise price. Unit appreciation rights represent the right to receive the appreciation in the value of a number of common units as of the exercise date over a specified exercise price, either in cash, common units, or a combination thereof, as determined in the discretion of the committee. Unit options and unit appreciation rights may be granted to such eligible individuals and with such terms as the committee may determine, consistent with the terms of the LTIP; however, the exercise price of a unit option or unit appreciation right may not be less than the fair market value of a common unit on the date such unit option or unit appreciation right is granted.

Restricted Units and Phantom Units

The LTIP will also permit the grant of restricted units and phantom units. A restricted unit is a common unit that is subject to forfeiture. Upon vesting, the forfeiture restrictions lapse and the participant holds a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the participant to receive a common unit (or such greater or lesser number of common units as may be provided pursuant to the applicable award agreement) upon the vesting of the phantom unit (or on a deferred basis upon specified future dates or events) or cash equal to the fair market value of a common unit (or such greater or lesser number of common units) or a combination thereof, as determined in the discretion of the committee. The committee may make grants of restricted and phantom units under the LTIP that contain such terms, consistent with the LTIP, as the

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committee may determine are appropriate, including the period over which restricted or phantom units will vest. The committee may, in its discretion, base vesting on the participant’s completion of a period of service or upon the achievement of specified performance criteria or as otherwise set forth in an award agreement. Distributions made by us with respect to awards of restricted units may be subject to the same vesting requirements as the restricted units. The committee, in its discretion, may also grant tandem DERs with respect to phantom units. DERs are described in more detail below.

Distribution Equivalent Rights

The committee is authorized to grant DERs either in tandem with an award or as a separate award. DERs are contingent rights to receive an amount in cash, common units, restricted units, phantom units, or any combination thereof, as determined by the committee in its discretion, equal to the cash distributions made on our common units during the period in which such DERs remain outstanding. The terms and conditions applicable to DERs will be determined by the committee and set forth in an award agreement.

Cash Awards

The LTIP will permit the grant of awards denominated in and settled in cash as an element of or supplement to, or independent of, any award under the LTIP.

Other Unit-Based Awards

The LTIP will also permit the grant of “other unit-based awards,” which are awards that, in whole or in part, are denominated or payable in, valued in, or otherwise based on or related to common units. An other unit-based award may be fully vested at grant, or the vesting of an other unit-based award may be based on a participant’s continued service, the achievement of specified performance criteria or other measures. On vesting (or on a deferred basis upon specified future dates or events), an other unit-based award may be paid in cash and/or in units (including restricted units), as determined by the committee.

Source of Common Units; Cost; Proceeds

Common units to be delivered with respect to awards under the LTIP may consist, in whole or in part, of common units acquired by us or our general partner in the open market, common units already owned by our general partner or us, common units acquired by our general partner directly from us, one of our affiliates or any other person, new common units otherwise issuable by us or any combination of the foregoing, as determined by the committee in its discretion. With respect to awards made to non-employee directors of our general partner and employees and consultants of our general partner and our affiliates, our general partner will be entitled to reimbursement by us for the cost incurred in acquiring such common units or, with respect to unit options, for the difference between the cost it incurs in acquiring these common units and the proceeds it receives from a participant at the time of the participant’s exercise of an option. Thus, we will bear the cost of all awards under the LTIP. If we issue new common units with respect to these awards, the total number of common units outstanding will increase, and our general partner will remit the proceeds it receives from a participant, if any, upon exercise of an award to us. With respect to any awards settled in cash, our general partner will be entitled to reimbursement by us for the amount of the cash settlement.

Amendment or Termination of LTIP

The committee, at its discretion, may terminate the LTIP at any time with respect to the common units for which an award has not previously been granted. The LTIP will automatically terminate on the 10th anniversary of the date it is initially adopted by our general partner. The committee also has the right to alter or amend the LTIP or any part of it from time to time or to amend any outstanding award granted under the LTIP, provided that no change in any outstanding award may be made that would materially reduce the benefit to a participant immediately prior to such change without the consent of the affected participant.

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LTIP Awards

The board of directors of our general partner has approved grants of restricted units under the LTIP to each of our named executive officers and certain other employees of Black Stone Management consisting, in the aggregate, of approximately                  restricted units (based on an assumed initial offering price of $            , the mid-point of the price range set forth on the cover page of this prospectus). In addition, the board of directors of our general partner has approved grants of performance unit awards to each of our named executive officers and certain senior management employees of Black Stone Management that, if earned at targeted levels of performance and vested, will be settled in the aggregate in the form of approximately                  common units under the LTIP (based on an assumed initial offering price of $            , the mid-point of the price range set forth on the cover page of this prospectus). The board of directors of our general partner has also approved grants of awards to the non-employee directors of our general partner consisting, in the aggregate, of approximately             common units under the LTIP (based on an assumed initial offering price of $        , the mid-point of the price range set forth on the cover page of this prospectus). These awards represent the non-employee directors’ annual equity-based compensation grants for fiscal 2015 and the special one-time $100,000 grants being granted in connection with this offering, as described below under “Director Compensation.” All of the awards described above will be granted upon the filing of the registration statement on Form S-8 registering the common units issuable under the LTIP. Each award will be subject to the terms and conditions of the LTIP and an award agreement that we will enter into with the applicable Black Stone Management employee or non-employee director of our general partner.

Director Compensation

Officers or employees of Black Stone Management who also serve as directors of our general partner will not receive additional compensation for such service. Each director of our general partner who is not an officer or employee of Black Stone Management will receive the following cash compensation:

• an annual base retainer fee of $75,000 per year;

• an additional retainer of $20,000 per year if such director serves as the chairperson of the audit committee;

• an additional retainer of $15,000 per year if such director serves as the chairperson of the compensation committee; and

• an additional retainer of $10,000 per year if such director serves as the chairperson of any other committee.

In addition to cash compensation, our non-employee directors will receive annual equity-based compensation under the LTIP consisting of fully vested common units. Such awards will have an aggregate grant date value equal to $175,000 and will be subject to the terms and conditions of the LTIP and the award agreements pursuant to which such awards are granted. Furthermore, as noted above, in connection with this offering, each non-employee director will receive a one-time grant of an award under the LTIP with an aggregate grant date value equal to $100,000, subject to the terms and conditions of the LTIP and the award agreements pursuant to which such awards are granted. Following the closing of this offering, in the year in which a non-employee director is first elected to the board of directors of our general partner, such director will also receive a one-time grant of an award under the LTIP with an aggregate grant date value equal to $100,000, subject to the terms and conditions of the LTIP and the award agreement pursuant to which such award is granted.

All retainers will be paid in cash on a quarterly basis in arrears. Our non-employee directors will not receive any meeting fees, but each director will be reimbursed for (i) travel and miscellaneous expenses to attend meetings and activities of the board of directors of our general partner or its committees and (ii) travel and miscellaneous expenses related to participation in general education and orientation programs for directors.

Each director will be fully indemnified by us for actions associated with serving as a director.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

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

• our general partner;

• each of our general partner’s directors and named executive officers;

• each unitholder known by us to beneficially hold 5% or more of our common units, on an as-converted basis; and

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

Beneficial ownership is determined under the rules of the SEC and generally includes voting or investment power with respect to securities. Unless otherwise noted, the address for each beneficial owner listed below is 1001 Fannin Street, Suite 2020, Houston, Texas 77002.

The following table does not include any units that may be purchased pursuant to our directed unit program. Please read “Underwriting—Directed Unit Program.”

Name of Beneficial Owner	Common Units Beneficially Owned(1)	Percentage of Common Units Beneficially Owned(1)
Black Stone Minerals G.P., L.L.C.(2)			%
Camden Energy Limited Partnership(3)			%
Thomas L. Carter, Jr.(3)(4)			%
Marc Carroll(5)(6)			%
Holbrook F. Dorn(5)(7)			%
William G. Bardel(8)			%
D. Mark DeWalch(8)(9)			%
Jerry V. Kyle, Jr.(8)(10)			%
Michael C. Linn(8)			%
John H. Longmaid(8)(11)			%
William N. Mathis(8)(12)			%
Richard A. Papert(8)			%
Alexander D. Stuart(8)(13)			%
Allison K. Thacker(8)(14)			%
Directors and executive officers as a group (15 people)			%

* Less than 1%

(1) Reflects conversion of our preferred units. Preferred units may be converted at the conversion rate of             common units per preferred unit at any time subsequent to the consummation of this offering and are mandatorily convertible in annual tranches from January 1, 2016 to January 1, 2018. Upon the consummation of this offering, our          preferred units will represent     % of our total common units outstanding on an as-converted basis. Except with respect to certain matters requiring the approval of the holders of preferred units, each preferred unit is entitled to vote as a single class with the common units on an as-converted basis. For a detailed discussion of our preferred units, please read “Description of Our Preferred Units.”

(2) Black Stone Minerals G.P., L.L.C., our general partner, owns          common units; these common units are not included in the beneficial ownership table or in total common units outstanding because this entity is a wholly owned subsidiary of the Partnership.

(3) Camden Energy Limited Partnership is a family partnership, of which our Chairman, Chief Executive Officer, and President, Thomas L. Carter, Jr., serves as the general partner.

(4) Mr. Carter has sole voting power over the units held by Camden Energy Limited Partnership, described above, and by Preference Partners LP, whose general partner he controls. He shares voting control and

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investment power over an aggregate of              units owned by a nonprofit institution on whose board he serves, and he disclaims beneficial ownership of those units. Mr. Carter’s ownership also includes              units of unvested restricted units previously issued as equity-based compensation.

(5) Does not include an aggregate of             restricted units expected to be issued to BSM’s management team immediately after the offering and that are subject to performance and time vesting.

(6) Includes             unvested restricted units previously issued as equity-based compensation.

(7) Includes             unvested restricted units previously issued as equity-based compensation.

(8) Includes             units expected to be issued immediately after the offering to each non-employee director as director compensation.

(9) Mr. DeWalch has shared voting and investment power over             units held by a trust, of which he serves as co-trustee.

(10) Mr. Kyle has shared voting and investment power over an aggregate of             units held by two trusts, of which he serves as co-trustee.

(11) Mr. Longmaid has sole voting and investment power over             units held in a trust of which he is the trustee and shares investment and voting power over             units held in a trust of which he is a beneficiary.

(12) Mr. Mathis has sole voting and investment power over an aggregate of             units held by WM Capital Partners, L.P., Conti Street Partners, L.P., and Conti Street Minerals, L.P. He has shared voting and investment power of aggregate of             units held by B.S. Ivory Associates, L.L.C. and the estate of a family member, of which he serves as co-executor.

(13) Mr. Stuart has sole voting and investment power over an aggregate of             units owned by North Star Oil & Gas, Topsfield Energy, Ltd., and RDS Investments, L.P. He also shares voting and investment power over             units owned by a trust, of which he serves as co-trustee.

(14) Ms. Thacker has shared voting and investment power over             units held by William Marsh Rice University. Ms. Thacker serves as Chief Investment Officer of an affiliate of that entity.

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FIDUCIARY DUTIES

The Delaware Revised Uniform Limited Partnership Act, which we refer to as the Delaware Act, provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict, or eliminate the fiduciary duties otherwise owed by the general partner and the directors and executive officers of the general partner to the partnership and its partners. 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 constitute breaches of duty under applicable Delaware law and breaches of the contractual obligations in our partnership agreement.

When our general partner and the directors and executive officers of our general partner act, it and they must act in “good faith,” meaning it and they must not act in a manner that it and they subjectively believe is adverse to our interest. This duty to act in good faith is the default standard set forth under our partnership agreement, and our general partner and the directors and executive officers of our general partner will not be subject to any higher standard under the partnership agreement or law or equity.

When the directors and executive officers of our general partner cause our general partner to manage and operate our business, the directors and executive officers must cause our general partner to act in a manner consistent with our general partner’s applicable duties and contractual standards. Therefore, where the directors and executive officers of our general partner are causing our general partner to act, the directors and executive officers must cause the general partner to act in good faith, meaning they cannot cause the general partner to take an action that they subjectively believe is adverse to our interest. However, the directors of our general partner may determine, in their sole discretion and free of any duty or obligation (including the obligation to act in good faith), whether to submit a determination to the conflicts committee for review or to seek approval by the unitholders, as described below.

Duties owed by our general partner and the directors and executive officers of our general partner to the partnership and to the unitholders are prescribed by law and in our partnership agreement. The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict, or eliminate the fiduciary duties that otherwise may be owed by the general partner and the directors and executive officers of our general partner to the partnership and its partners.

Our partnership agreement contains various provisions eliminating the fiduciary duties that might otherwise be owed by our general partner and the directors and executive officers of our general partner and imposing contractual standards that our general partner and its directors and executive officers must follow. We have adopted these provisions to 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. Without these modifications, our general partner’s and the directors’ and officers’ of our general partner ability to make decisions—and, in particular, decisions involving conflicts of interest—may be restricted. The modifications to the fiduciary standards benefit our general partner and the directors and executive officers of our general partner by providing greater flexibility and enabling them to take into consideration all factors and interests of various parties while still imposing a duty to manage our partnership in good faith. These modifications also strengthen the ability of our general partner to attract and retain experienced and capable directors and executive officers.

These modifications may represent a detriment to our public unitholders because they restrict the remedies available to our public unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below.

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The following is a summary of:

• the default fiduciary duties under Delaware law;

• the contractual standards contained in our partnership agreement that replace the default fiduciary duties; and

• certain rights and remedies of limited partners contained in the Delaware Act.

Default state law fiduciary duty standards Fiduciary duties are generally considered to include a duty of care and a duty of loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act and make decisions in an informed and deliberate manner after availing itself of all reasonably available material information. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to make decisions based on the best interests of the partnership and its partners, and not for personal or other reasons. A general partner would generally satisfy the duty of loyalty when it is in a position to base its decision on the merits of the issue rather than being governed by extraneous considerations or influences. In the absence of a provision in a partnership agreement providing otherwise, where a general partner has a material conflict of interest with the partnership and/or the partners with respect to a potential transaction or determination, the duty of loyalty would generally require that any such action taken or determination made be entirely fair to the partnership and the partners and the general partner would typically have the burden of proving the action or transaction is entirely fair.

Partnership agreement modified standards Our partnership agreement contains provisions that eliminate state law fiduciary duties and replace these duties with a contractually defined standard of “good faith.” For example, our partnership agreement provides that when our general partner is acting it must act in “good faith,” meaning that it believes its actions or omissions are not adverse to the interests of the partnership, and will not be subject to any other standard. The contractual standards set forth in the partnership agreement replace the obligations to which our general partner would otherwise be held.

With respect to matters involving a conflict of interest, our general partner and its directors and officers are permitted in their sole discretion and free of any duty or obligation (including the obligation to act in good faith) to determine whether or not to submit these matters for approval by the conflicts committee of the board of directors of our general partner or our common unitholders. If our general partner or its directors or officers in their sole discretion determines not to submit a conflict of interest transaction for approval either by the conflicts committee or our common unitholders, and instead the board of directors of our general partner approves the resolution or course of action taken with respect to the conflict of interest, then it will be presumed that, in making its decision, the

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general partner and the board, which may include board members affected by the conflict of interest, acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting the proceeding will have the burden of overcoming such presumption and proving that the decision was not in good faith. These standards replace the obligations and presumptions to which our general partner would otherwise be held.

Default State Law rights and remedies of limited partners
The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a person where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These actions include actions against a general partner for breach of its duties or of our partnership agreement. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.

Partnership agreement modified standards The Delaware Act provides that, unless otherwise provided in a partnership agreement, a partner or other person shall not be liable to a limited partnership or to another partner or to another person that is a party to or is otherwise bound by a partnership agreement for breach of fiduciary duty for the partner’s or other person’s good faith reliance on the provisions of the partnership agreement. Under our partnership agreement, to the extent that, at law or in equity an indemnitee has duties (including fiduciary duties) and liabilities relating thereto to us or to our partners, our general partner and any other indemnitee acting in connection with our business or affairs shall not be liable to us or to any partner for its reliance on the provisions of our partnership agreement. In addition, our partnership agreement provides that our general partner and its directors and officers will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in willful misconduct or fraud or, with respect to any criminal conduct, with the knowledge that its conduct was unlawful.

By purchasing our common units, each common unitholder automatically agrees to be bound by the provisions in our partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner to sign a partnership agreement does not render the partnership agreement unenforceable against that person.

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DESCRIPTION OF OUR COMMON UNITS

Our Common Units

The common units offered hereby represent limited partner interests in us. The holders of common units are entitled to participate in partnership distributions and exercise the rights and privileges provided to limited partners holding common units under our partnership agreement. For a description of the relative rights and privileges of holders of our common units to partnership distributions, please read “Cash Distribution Policy and Restrictions on Distributions” and “Description of Our Preferred Units—Distributions.” For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please read “The Partnership Agreement” and “Description of Our Preferred Units—Distributions.”

Transfer Agent and Registrar

American Stock Transfer & Trust Company, LLC will serve as registrar and transfer agent for the common units. We pay all fees charged by the transfer agent for transfers of common units, except the following, which must be paid by unitholders:

• surety bond premiums to replace lost or stolen certificates, taxes, and other governmental charges;

• special charges for services requested by a holder of a common unit; and

• other similar fees or charges.

There is no charge to our unitholders for disbursements of our quarterly cash distributions. We will indemnify the transfer agent, its agents, and each of their stockholders, directors, officers, and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If a successor has not been appointed or has not accepted its appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when the transfer and admission are reflected in our books and records. Each transferee:

• represents that the transferee has the capacity, power, and authority to become bound by our partnership agreement;

• automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement; and

• gives the consents, acknowledgments, and waivers contained in our partnership agreement, such as the approval of all transactions and agreements entered into in connection with our formation and this offering.

A transferee will become a substituted limited partner of our partnership for the transferred common units automatically upon the recording of the transfer on our books and records. Our general partner will cause any transfers to be recorded on our books and records from time to time as necessary to accurately reflect the transfers.

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We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and are transferable according to the laws governing transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a limited partner in our partnership for the transferred common units.

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the common unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

Listing

We have applied to list our common units on the NYSE under the symbol “BSM.”

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DESCRIPTION OF OUR PREFERRED UNITS

Our Preferred Units

Our Series A Preferred Units, which we refer to as the “preferred units,” are substantially the same as the Series A preferred units issued by our predecessor and represent limited partner interests in us. The holders of preferred units are entitled to participate in partnership distributions and exercise certain other rights and privileges under our partnership agreement. We do not currently expect to issue additional preferred units. For a description of the relative rights and privileges of holders of our preferred units to partnership distributions, please read “Cash Distribution Policy and Restrictions on Distributions” and “—Distributions.” For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please read “The Partnership Agreement” and “—Voting; Waiver.”

Distributions

Prior to the liquidation of the partnership, and while any of our preferred units remain outstanding, cash or other property of the partnership will be distributed to our limited partners in the following order and priority at times and in amounts as the general partner determines in its sole discretion:

(1) First, 100% to our preferred unitholders pro rata, until the aggregate Unpaid Preferred Yield of each preferred unit accrued through the last day of the immediately preceding calendar quarter has been reduced to zero; then

(2) Second, in respect of each calendar year, 100% to our common unitholders pro rata, until there has been distributed pursuant to this paragraph an aggregate amount in respect of such calendar year equal to 10% of the aggregate Interest Fair Market Value of the outstanding common units as of the first day of each calendar year; and

(3) Finally, 100% to our common unitholders and our preferred unitholders pro rata in accordance with their interests in us, determined on an “as converted” basis.

The general partner will be entitled to establish record dates for the payment of distributions and adopt any other procedures deemed by the general partner to be necessary or appropriate.

In connection with the liquidation of the partnership, cash, or other property will be distributed to the Partners in accordance with capital account balances. The manner in which profits and losses are allocated among the Partners pursuant to the partnership agreement is designed to maintain a capital account balance for each preferred unit equal to the Liquidation Preference Amount so that each preferred unitholder will receive the Liquidation Preference Amount upon our liquidation. In the event the capital account balance with respect to each preferred unit does not equal the Liquidation Preference Amount, the preferred unitholders will receive an amount equal to the Liquidation Preference Amount for each preferred unit held by the preferred unitholder.

The terms “Interest Fair Market Value,” “Preferred Yield,” “Unpaid Preferred Yield,” and “Liquidation Preference Amount” have the following meanings:

“Interest Fair Market Value” means, as of any date, the amount which would be received by the holder of a common unit if (a) all of the preferred units and any other convertible securities issued by us were converted into or exchanged for common units, and (b) an amount equal to the fair market value of our assets minus our liabilities (adjusted to reflect any increases in our equity value resulting from the deemed conversion of our preferred units and other convertible securities) were distributed to our partners.

“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.

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“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.

“Liquidation Preference Amount” means, with respect to any preferred unit outstanding at the time of the liquidation of the Partnership, an amount equal to the sum of (i) the Unpaid Preferred Yield plus (ii) $1,000.

Conversion of the Preferred Units

Each preferred unit may be converted, at the option of the holder thereof, at any time, and without the payment of additional consideration, into common units at the then-effective conversion rate. The preferred units currently have a conversion rate of 907.3629601 common units per preferred unit, each subject to adjustment as provided herein.

On January 1 of each year from 2016 to 2018, a number of preferred units will automatically be converted into common units at the then-effective conversion rate. As a result of these mandatory conversions, all preferred units will have either been redeemed or converted into common Units as of January 1, 2018.

A preferred unitholder who converts its shares, or whose shares are automatically converted, will be entitled to receive the Unpaid Preferred Yield on its shares through the conversion date. We will not issue fractions of common units upon conversion of preferred units. We will pay cash in lieu of each fraction of a common unit otherwise issuable upon a conversion.

The preferred units will cease to be convertible on the day of the first liquidating distribution by the partnership.

Each preferred unit which is surrendered for conversion as provided in our partnership agreement will no longer be deemed outstanding as of the conversion date, and all rights with respect to the preferred unit will terminate, except for the rights of the holder thereof to receive common units in exchange therefor (and any payment in lieu of a fractional common unit and payment of any Unpaid Preferred Yield thereon).

Redemption of the Preferred Units

On December 31 of each year from 2015 through 2017 (each date, a “Scheduled Redemption Date”), each preferred unitholder may, upon written notice, require the partnership to redeem a portion of its preferred units for a cash price per preferred unit equal to the sum of $1,000 plus the Unpaid Preferred Yield accrued through that date (the aggregate amount, the “Holder Redemption Price”). The partnership will pay to the redeeming preferred unitholder the Holder Redemption Price plus, in the event of a payment after the Scheduled Redemption Date, interest on the Holder Redemption Price at a rate of 10% per annum (subject to adjustment following certain events of default by the Partnership from the Scheduled Redemption Date until the date paid to the redeeming preferred unitholder).

If Thomas L. Carter, Jr. is no longer chief executive officer of the general partner or any successor general partner of the partnership or is no longer actively involved in the investment decisions, management, and operations of the partnership (a “Key Man Event”), a preferred unitholder may notify the general partner of its objection (“Key Man Objection Notice”), and each preferred unitholder will have the right to require the partnership to redeem its preferred units for a cash price per preferred unit equal to the Holder Redemption Price; provided that if the general partner disputes the occurrence of a Key Man Event, then an independent third-party arbitrator will determine if a Key Man Event occurred. The general partner will provide the preferred unitholders prompt notice following the final determination of the occurrence of a Key Man Event, and for 60 days after the notice, each preferred unitholder will have the right to send a redemption notice to the general partner. Upon receipt of a redemption notice pursuant to this paragraph, the partnership will redeem one-third of the number of

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preferred units for which a preferred unitholder requests redemption on December 31 of each of the calendar year in which a redemption notice is received and the two following calendar years; provided that in the event of a change of control or a liquidation occurring prior to redemption of these preferred units in full pursuant to this paragraph, the partnership will redeem 100% of these unredeemed preferred units on the date of consummation of the change of control or the date of the first liquidating distribution, as applicable, at a cash price per preferred unit equal to the Holder Redemption Price. The Unpaid Preferred Yield will continue to accrue at a rate of 10% per annum (subject to adjustment following certain events of default by the partnership) on each outstanding preferred unit until redeemed.

If on any Redemption Date the partnership is unable to redeem any preferred units designated for redemption in the redemption notice for any reason, then the partnership will redeem, pro rata among the preferred unitholders who have given a redemption notice (based on the number of preferred units held by the redeeming preferred unitholders as of the redemption date), as many of the preferred units as may be redeemed, and as soon thereafter as the partnership is able the partnership will redeem such unredeemed preferred units; provided that the partnership will be deemed to be in default if the partnership is unable all of the preferred units designated for redemption in the redemption notice.

In the event that a preferred unitholder gives a redemption notice with respect to any Scheduled Redemption Date, the partnership will have the option to redeem from a preferred unitholder, for a cash price per preferred unit equal to the greater of (i) the Holder Redemption Price, or (ii) the Interest Fair Market Value of the common units into which the preferred units so redeemed are convertible on such Scheduled Redemption Date (the “Partnership Redemption Price”), a number of preferred units up to the number of preferred units designated for redemption by the preferred unitholder in such redemption notice; provided that the partnership will not exercise the redemption rights pursuant to this paragraph while a default by the partnership is continuing.

In the event of a change of control or anticipated change of control, except with respect to any preferred unit a preferred unitholder elects to convert, the partnership will redeem at the Holder Redemption Price the preferred units upon the consummation of the change of control.

From and after the redemption of any preferred units in full, all rights of the holders (except the right to receive the redemption payment, plus interest if applicable) will cease, and the preferred units will be deemed to no longer be outstanding for any purpose whatsoever.

Anti-Dilution Provisions

The Conversion Price and the Conversion Rate will be subject to adjustment from time to time in accordance with this “Description of Our Preferred Units.”

If we at any time (i) subdivide our outstanding common units, (ii) make a distribution on our outstanding common units payable in common units, or (iii) combine our outstanding preferred units, conversion price for the preferred units will be proportionately decreased (with appropriate adjustments to the Conversion Rate in effect immediately prior to the subdivision or distribution). If we at any time (i) combine our outstanding common units, (ii) subdivide our outstanding preferred units, or (iii) make a distribution on our outstanding preferred units payable in preferred units, the conversion price for our preferred units will be proportionately increased (with appropriate adjustments to the conversion rate in effect immediately prior to the combination).

If as a result of any capital reorganization or reclassification of our common units or consolidation or merger of the partnership with another entity, our common unitholders would receive stock, securities, cash, or other property with respect to or in exchange for common units, then the preferred unitholders will have the right to acquire and receive upon conversion of the preferred units, the shares of stock, securities, cash, or other property issuable or payable (as part of the reorganization, reclassification, consolidation, merger, or sale) with respect to or in exchange for the number of outstanding common units that the preferred unitholders would have received upon conversion of the preferred units at the applicable conversion rate.

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If any event occurs as to which, in the good faith opinion of the general partner, the provisions of this section entitled “Anti-Dilution Provisions” are not strictly applicable or would not fairly protect the rights of the preferred unitholders, then the general partner will make an adjustment, so as to protect these rights.

Voting; Waiver

Except with respect to certain matters requiring the approval of the preferred unitholders, which are set forth in Annex A to our partnership agreement, a form of which is included in this prospectus as Appendix A, at each meeting of the partners (or pursuant to any action by written consent), with respect to any and all matters presented to the partners for their action or consideration, each preferred unitholder will be entitled to vote as a single class with the common units on an “as-converted basis,” meaning that each preferred unit has a number of votes equal to the number of common units into which the preferred unit is convertible at the time of such vote or consent.

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THE PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide investors and prospective investors with a copy of our partnership agreement upon request at no charge.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

• with regard to the duties of our general partner, please read “Fiduciary Duties”;

• with regard to the transfer of common units, please read “Description of Our Common Units—Transfer of Common Units”; and

• with regard to allocations of taxable income and taxable loss, please read “Material U.S. Federal Income Tax Consequences.”

Organization and Duration

We were organized in September 2014 and will have a perpetual existence unless terminated pursuant to the terms of our partnership agreement.

Purpose

Our purpose, as set forth in our partnership agreement, is to engage in any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law; provided that our general partner shall not cause us to take any action that the general partner determines would be reasonably likely to cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

Our general partner is generally authorized to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under “—Limited Liability.”

Adjustments to Capital Accounts Upon Issuance of Additional Common Units

We will make adjustments to capital accounts upon the issuance of additional common units. In doing so, we will generally allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to our unitholders prior to an issuance on a pro rata basis, so that after such issuance, the capital account balances attributable to all common units are equal.

Voting Rights

The following is a summary of the unitholder vote required for approval of the matters specified below. Matters that call for the approval of a “unit majority” require the approval of a majority of the outstanding common units.

In voting their common units, our directors will have no duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or the limited partners. The holders of a majority of the common units represented in person or by proxy shall constitute a quorum at a meeting of such common unitholders, unless any such action requires approval by holders of a greater percentage of the units in which case the quorum shall be the greater percentage.

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The following is a summary of the vote requirements specified for certain matters under our partnership agreement.

Election of directors of our general partner Our limited partners holding common units and preferred units will vote together as a single class for the election of directors to the board of directors of our general partner. The limited partners authorized to vote will elect, by a plurality of the votes cast at such meeting, persons to serve as directors of our general partner who are nominated in accordance with the provisions of our partnership agreement. Limited Partners will be entitled to cumulate their votes for purposes of electing directors. Please read “—Nomination of Directors.”

Issuance of additional units (including units senior to the common units)
No approval right by limited partners holding common units, including units that are senior to the common units. However, our partnership agreement does not authorize us to issue securities having preferences or rights with priority over or on a parity with our outstanding preferred units with respect to rights to share in distributions, redemption obligations or redemption rights.

Amendment of the partnership agreement Certain amendments may be made by our general partner without the approval of any limited partners. Other amendments generally require the approval of a majority of our limited partners holding common units and preferred units. Please read “—Amendment of the Partnership Agreement.”

Merger of our partnership or the sale of all or substantially all of our assets
Unit majority in certain circumstances. Please read “—Merger, Consolidation, Conversion, Sale, or Other Disposition of Assets.”

Dissolution of our partnership Unit majority Please read “—Dissolution.”

Continuation of our business upon dissolution Unit majority. Please read “—Dissolution.”

Withdrawal of our general partner No voluntary withdrawal right. Please read “—Withdrawal or Removal of Our General Partner; Transfer of General Partner Interest.”

Transfer of our general partner interest No transfer right without the consent of a unit majority. Please read “—Withdrawal or Removal of Our General Partner; Transfer of General Partner Interest.”

If any person or group, other than our directors and their affiliates, a limited partner in our predecessor who beneficially owned 15% or more of our common units as of the date of our initial public offering, their transferees, and persons who acquired such units with the prior approval of the board of directors of our general partner, acquires beneficial ownership of 15% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from the limited partners in our predecessor or its affiliates and any transferees of that person or group approved by the board of directors of our general partner or to any person or group who acquires the units with the specific prior approval of the board of directors of our general partner.

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Meetings; Voting

An annual meeting of the limited partners holding common units and preferred units 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. Notice of the annual meeting will be given not less than 10 days nor more than 60 days prior to the date of the meeting.

The limited partners holding common units and preferred units will vote together as a single class for the election of directors. The limited partners authorized to vote will elect by a plurality of the votes cast at a 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. The exercise by a limited partner of the right to elect the directors and any other rights afforded to a limited partner under our partnership agreement will be in the limited partner’s capacity as a limited partner of the partnership and are not intended to cause a limited partner to be deemed to be taking part in the management and control of the business and affairs of the partnership.

Each limited partner entitled to vote at an election for the board of directors will be entitled to cumulate his or her vote and give one candidate, or divide among any number of candidates, a number of votes equal to the product of (x) the number of common units held by the limited partner, multiplied by (y) the number of directors to be elected at the meeting.

Additional limited partner interests having special voting rights could be issued. However, our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to change management without the support of the board of directors of our general partner. If at any time any person or group, other than (a) a person who is one of our directors, his or her affiliates, or a limited partner in our predecessor with beneficial ownership of 15% or more of our common units as of the date of our initial public offering, (b) a transferee of any of the persons described in the preceding clause (a) with the prior approval of the board of directors of our general partner, or (c) a person or group that acquires units with the prior approval of the board of directors of our general partner, acquires, in the aggregate, beneficial ownership of 15% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes, as contemplated in our partnership agreement.

In addition, solely with respect to the election of directors, our partnership agreement provides that our general partner and the partnership will not be entitled to vote their units, if any, and the foregoing units will not be counted when calculating the required votes for a matter and will not be deemed to be outstanding for purposes of determining a quorum for a meeting. These units will not be treated as a separate class of Partnership securities for purposes of our partnership agreement.

Except as described above, unitholders on the record date will be entitled to notice of, and to vote at, meetings of our limited partners, and to act upon matters for which approvals may be solicited. Units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise.

Any action that is required or permitted to be taken by our unitholders may be taken either at a meeting of the unitholders or, if authorized by our general partner, without a meeting if consents in writing describing the action so taken are signed by holders of the number of units as would be necessary to authorize or take that action at a meeting. Special meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting was called (including

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outstanding units deemed owned by the general partner), represented in person or by proxy, will constitute a quorum unless otherwise provided in our partnership agreement in connection with the election of directors to the board of directors of our general partner or unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.

Any notice, demand, request, report, or proxy material required or permitted to be given or made to record holders of units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Nomination of Directors

Nominations of persons for election to the board of directors of our general partner may be made at an annual meeting of the limited partners only (a) pursuant to our general partner’s notice of meeting (or any supplement thereto), (b) by or at the direction of the board of directors or any committee thereof, or (c) by any limited partner or group of limited partners who (1) was a record holder at the time the notice provided for in our partnership agreement is delivered to our general partner, (2) is entitled to vote at the meeting, (3) complies with the notice procedures set forth in our partnership agreement, and (4) either individually or as a group hold units representing at least 10% of the outstanding units (measured on a fully diluted basis) both at the time of giving notice of such nomination and at the meeting.

For any nominations brought before an annual meeting by a limited partner, the limited partner must give timely notice thereof in writing to our general partner. The notice must contain certain information as described in our partnership agreement. To be timely, a limited partner’s notice must be delivered to our general partner not later than the close of business on the 90th day, nor earlier than the close of business on the 120th day, prior to the first anniversary of the preceding year’s annual meeting (provided, however, that in the event that the date of the annual meeting is more than 30 days before or more than 70 days after the anniversary date, notice by the limited partner must be so delivered not earlier than the close of business on the 120th day prior to the annual meeting and not later than the close of business on the later of the 90th day prior to the annual meeting or the 10th day following the day on which public announcement of the date of the meeting is first made by the partnership or our general partner). The public announcement of an adjournment or postponement of an annual meeting will not commence a new time period (or extend any time period) for the giving of a limited partner’s notice as described above.

In the event that the number of directors to be elected to the board of directors of our general partner is increased effective at the annual meeting and there is no public announcement by the partnership or our general partner naming the nominees for the additional directorships at least 100 days prior to the first anniversary of the preceding year’s annual meeting, a limited partner’s notice will also be considered timely, but only with respect to nominees for the additional directorships, if it shall be delivered to our general partner not later than the close of business on the 10th day following the day on which a public announcement is first made by the partnership or our general partner.

Nominations of persons for election to the board of directors also may be made at a special meeting of limited partners at which directors are to be elected in accordance with the provisions of our partnership agreement.

Only persons who are nominated in accordance with the procedures set forth in our partnership agreement will be eligible to be elected at an annual or special meeting of limited partners to serve as directors. Notwithstanding the foregoing, unless otherwise required by law, if the limited partner (or a qualified representative of the limited partner) does not appear at the annual or special meeting of limited partners to present a nomination, the nomination shall be disregarded notwithstanding that proxies in respect of a vote may have been received by our general partner or the partnership.

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In addition to the provisions described above and in our partnership agreement, a limited partner must also comply with all applicable requirements of the Exchange Act and the rules and regulations thereunder; provided, however, that any references in our partnership agreement to the Exchange Act or the rules promulgated thereunder are not intended to and do not limit any requirements applicable to nominations pursuant to our partnership agreement, and compliance with our partnership agreement is the exclusive means for a limited partner to make nominations.

Applicable Law; Forum, Venue, and Jurisdiction

Our partnership agreement is governed by Delaware law. Our partnership agreement requires that any claims, suits, actions, or proceedings:

• arising out of or relating in any way to the partnership agreement (including any claims, suits, or actions to interpret, apply, or enforce the provisions of the partnership agreement or the duties, obligations, or liabilities among limited partners or of limited partners to us, or the rights or powers of, or restrictions on, the limited partners or us);

• brought in a derivative manner on our behalf;

• asserting a claim of breach of a duty owed by any director, officer, or other employee of us or our general partner, or owed by our general partner, to us, or the limited partners;

• asserting a claim arising pursuant to any provision of the Delaware Act; or

• asserting a claim governed by the internal affairs doctrine

shall be exclusively brought in the Court of Chancery of the State of Delaware (or, if such court does not have subject matter jurisdiction thereof, any other court located in the State of Delaware with subject matter jurisdiction), regardless of whether the claims, suits, actions, or proceedings sound in contract, tort, fraud, or otherwise, are based on common law, statutory, equitable, legal, or other grounds, or are derivative or direct claims and irrevocably waives the right to trial by jury.

By purchasing a common unit, a limited partner is irrevocably consenting to these limitations and provisions regarding claims, suits, actions, or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or such other court) in connection with any such claims, suits, actions, or proceedings.

Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of the partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. However, if it were determined that the right, or exercise of the right, by the limited partners as a group:

• to remove or replace our general partner;

• to approve some amendments to our partnership agreement; or

• to take other action under our partnership agreement

constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us under the reasonable belief that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

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Under the Delaware Act, prior to the dissolution of a limited partnership, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Following the dissolution of a limited partnership, the Delaware Act generally requires a limited partnership to satisfy (or make reasonable provision to satisfy) liabilities of the limited partnership prior to making distributions to partners.

Following the completion of this offering, we may have subsidiaries that conduct business in other states or countries in the future. Maintenance of our limited liability as owner of our operating subsidiaries may require compliance with legal requirements in the jurisdictions in which the operating subsidiaries conduct business, including qualifying our subsidiaries to do business there.

Limitations on the liability of members or limited partners for the obligations of a limited liability company or limited partnership have not been clearly established in many jurisdictions. If, by virtue of our ownership interest in our subsidiaries or otherwise, it were determined that we were conducting business in any jurisdiction without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

Issuance of Additional Partnership Interests

Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders (other than, in certain instances, approval of the holders of our outstanding preferred units, if any).

It is possible that we will fund acquisitions through the issuance of additional common units or other partnership interests. Holders of any additional common units we issue will be entitled to share equally with the then-existing common unitholders in our distributions. In addition, the issuance of additional common units or other partnership interests may dilute the value of the interests of the then-existing common unitholders in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership interests that, as determined by our general partner, may have rights to distributions or special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit our subsidiaries from issuing equity interests, which may effectively rank senior to the common units.

Amendment of the Partnership Agreement

General

Amendments to our partnership agreement may be proposed only by our general partner. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or to call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

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Prohibited Amendments

No amendment may be made that would:

• enlarge the obligations of any limited partner without his consent, unless approved by at least a majority of the type or class of limited partner interests so affected;

• enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld in its sole discretion; or

• amend or modify the rights of our preferred unitholders, create certain new classes of preferred units, or cause the partnership to issue certain redeemable securities without the consent of a supermajority of the preferred unitholders.

The provision of our partnership agreement preventing the amendments having the effects described in the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding units, voting as a single class (including units owned by our general partner and its affiliates).

No Unitholder Approval

Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner holding common units to reflect:

• a change in our name, the location of our principal place of business, our registered agent, or our registered office;

• the admission, substitution, withdrawal, or removal of partners in accordance with our partnership agreement;

• a change that our general partner determines to be necessary or appropriate to qualify or continue our qualification as a limited partnership, or other entity in which the limited partners have limited liability under the laws of any state, or to ensure that neither we nor any of our subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed);

• an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents, or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisers Act of 1940 or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974 (“ERISA”) whether or not substantially similar to plan asset regulations currently applied or proposed;

• an amendment that our general partner determines to be necessary, appropriate, or desirable in connection with the creation, authorization, or issuance of additional partnership interests or the right to acquire partnership interests;

• any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

• an amendment effected, necessitated, or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;

• any amendment that our general partner determines to be necessary, appropriate, or desirable for the formation by us of, or our investment in, any corporation, partnership, or other entity, as otherwise permitted by our partnership agreement;

• a change in our fiscal year or taxable year and related changes;

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• conversions into, mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities, or operations at the time of the conversion, merger, or conveyance other than those it receives by way of the conversion, merger, or conveyance; or

• any other amendments substantially similar to any of the matters described in the clauses above.

In addition, our general partner may make amendments to our partnership agreement, without the approval of any limited partner holding common units, if our general partner determines that those amendments:

• do not adversely affect the limited partners (including any particular class of partnership interests as compared to other classes of partnership interests) in any material respect;

• are necessary or appropriate to satisfy any requirements, conditions, or guidelines contained in any opinion, directive, order, ruling, or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

• are necessary, appropriate, or desirable to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline, or requirement of any securities exchange on which the limited partner interests are or will be listed for trading;

• are necessary, appropriate, or desirable for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or

• are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

Opinion of Counsel and Unitholder Approval

Any amendment that our general partner determines adversely affects in any material respect one or more particular classes of limited partners, and is not permitted to be adopted by our general partner without limited partner approval, will require the approval of at least a majority of the class or classes so affected, but no vote will be required by any class or classes of limited partners that our general partner determines are not adversely affected in any material respect. Any such amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any such amendment that would reduce the voting percentage required to take any action other than to remove the general partner or call a meeting of unitholders is required to be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced. Any such amendment that would increase the percentage of units required to remove the general partner or call a meeting of unitholders must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the percentage sought to be increased. For amendments of the type not requiring unitholder approval, our general partner will not be required to obtain an opinion of counsel that an amendment will neither result in a loss of limited liability to the limited partners nor result in our being treated as a taxable entity for federal income tax purposes in connection with any of the amendments. No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units, voting as a single class, unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners.

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

A merger, consolidation, or conversion of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger, consolidation, or conversion and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interest of us or the limited partners.

In addition, our partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us to sell, exchange, or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation, or other combination. Our general partner may, however, mortgage, pledge, hypothecate, or grant a security interest in all or substantially all of our assets without majority approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without majority approval. Finally, our general partner may consummate any merger without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in a material amendment to the partnership agreement (other than an amendment that the general partner could adopt without the consent of other partners), each of our units will be an identical unit of our partnership following the transaction and the partnership interests to be issued do not exceed 20% of our outstanding partnership interests immediately prior to the transaction.

If the conditions specified in our partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity, if the sole purpose of that conversion, merger, or conveyance is to effect a mere change in our legal form into another limited liability entity, we have received an opinion of counsel regarding limited liability and tax matters and the governing instruments of the new entity provide the limited partners and our general partner with the same rights and obligations as contained in our partnership agreement. Our unitholders are not entitled to dissenters’ rights of appraisal under our partnership agreement or applicable Delaware law in the event of a conversion, merger, or consolidation, a sale of substantially all of our assets or any other similar transaction or event.

Dissolution

We will continue as a limited partnership until dissolved under our partnership agreement. We will dissolve upon:

• the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;

• there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law;

• the entry of a decree of judicial dissolution of our partnership; or

• the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or its withdrawal or removal following the approval and admission of a successor.

Upon a dissolution under the last clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing as a successor general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:

• the action would not result in the loss of limited liability under Delaware law of any limited partner; and

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• neither our partnership nor any of our subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue (to the extent not already so treated or taxed).

Liquidation and Distribution of Proceeds

Upon our dissolution, unless such dissolution is revoked, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as set forth in our partnership agreement. The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners. Please read “Description of Our Preferred Units—Distributions.”

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

Our general partner does not have the right to withdraw voluntarily as our general partner, and any such withdrawal would be a breach of our partnership agreement. In addition, our partnership agreement does not permit our general partner, to sell or otherwise transfer its general partner interest in us without the consent of a unit majority.

Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to change our management. If any person or group, other than the initial limited partners in our predecessor, their transferees, and persons who acquired their units with the prior approval of the board of directors of our general partner, acquires beneficial ownership of 15% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply in certain circumstances. Furthermore, a person or group must own at least 10% of our outstanding units (on a fully diluted basis) to nominate persons for election to our board of directors. Please read “—Meetings; Voting.”

Non-Taxpaying Holders; Redemption

To avoid any adverse effect on our ability to operate our assets or generate revenues from our assets, our partnership agreement provides our general partner the power to amend our partnership agreement. If our general partner, with the advice of counsel, determines that the tax status (or lack of proof thereof) of one or more of our limited partners (or type of owners) or their owners, to the extent relevant, creates or is reasonably likely to create, a substantial risk of an adverse effect on the rates we can charge customers, then our general partner may adopt amendments to our partnership agreement as it determines necessary or advisable to:

• obtain proof of the federal income tax status of our limited partners (and their owners, to the extent relevant); and

• permit us to redeem the common units held by any person whose tax status creates or is reasonably likely to create such an adverse effect or who fails to comply with the procedures instituted by our general partner to obtain proof of a person’s federal income tax status.

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Non-Citizen Assignees; Redemption

If our general partner, with the advice of counsel, determines that the nationality, citizenship, or other related status (or lack of proof thereof) of one or more of our limited partners (or type of owners), or their owners, to the extent relevant, creates or is reasonably likely to create a substantial risk of cancellation or forfeiture of any property that we have an interest under any federal, state, or local laws or regulations, then our general partner may adopt such amendments to our partnership agreement as it determines necessary or advisable to:

• obtain proof of the nationality, citizenship, or other related status of our limited partners (or their owners, to the extent relevant); and

• permit us to redeem the common units held by any person whose nationality, citizenship, or other related status creates or is reasonably likely to create, such a substantial risk.

Status as Limited Partner

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Except as described under “—Limited Liability,” the common units will be fully paid, and unitholders will not be required to make additional contributions. For a description of our preferred unitholders’ transfer rights, please read “Description of Our Preferred Units.”

Indemnification

Under our partnership agreement, in most circumstances, we will indemnify the following persons:

• our general partner;

• any departing general partner;

• any person who is or was an affiliate of our general partner or any departing general partner;

• any person who is or was a manager, managing member, general partner, director, officer, fiduciary, or trustee of our partnership, our subsidiaries, our general partner, any departing general partner, or any of their affiliates;

• any person who is or was serving as a manager, managing member, general partner, director, officer, employee, agent, fiduciary, or trustee of another person owing a fiduciary duty to us or our subsidiaries;

• any person who controls our general partner or any departing general partner; and

• any person designated by our general partner.

Any indemnification under these provisions will only be out of our assets. Unless our general partner otherwise agrees, it will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

Reimbursement of Expenses

Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. Our partnership agreement does not set a limit on the amount of expenses for which our general partner may be reimbursed. These expenses include salary, bonus, incentive compensation, and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner. Our general partner is entitled to determine the expenses that are allocable to us.

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Books and Reports

Our general partner is required to keep appropriate books of our business at our principal offices. These books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.

We will furnish or make available to record holders of our common units, within 105 days after the close of each fiscal year, an annual report containing audited consolidated financial statements and a report on those consolidated financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 50 days after the close of each quarter. We will be deemed to have made any such report available if we file such report with the SEC on EDGAR or make the report available on a publicly available website that we maintain.

We will furnish each record holder with information reasonably required for federal and state tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to our unitholders will depend on their cooperation in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and in filing his federal and state income tax returns, regardless of whether he supplies us with the necessary information.

Right to Inspect Our Books and Records

Our partnership agreement provides that a limited partner can, for a purpose reasonably related (as determined by our general partner) to his interest as a limited partner, upon reasonable written demand stating the purpose of the demand and at his own expense, have furnished to him:

• a current list of the name and last known address of each record holder;

• copies of our partnership agreement, our certificate of limited partnership, related amendments, and powers of attorney under which they have been executed; and

• such other information regarding our affairs as our general partner determines is just and reasonable.

Under our partnership agreement, however, each of our limited partners and other persons who acquire interests in our partnership interests, do not have rights to receive information from us or any of the persons we indemnify as described above under “—Indemnification” for the purpose of determining whether to pursue litigation or assist in pending litigation against us or those indemnified persons relating to our affairs, except pursuant to the applicable rules of discovery relating to the litigation commenced by the person seeking information.

Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner determines is not in our best interests or that we are required by law or by agreements with third parties to keep confidential. Our partnership agreement limits the rights to information that a limited partner would otherwise have under Delaware law.

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UNITS ELIGIBLE FOR FUTURE SALE

Our common units sold in this offering and issued to the limited partners of BSMC in connection with the merger will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units held by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

• 1% of the total number of the securities outstanding; or

• the average weekly reported trading volume of our common units for the four weeks prior to the sale.

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned our common units for at least six months (provided we are in compliance with the current public information requirement), or one year (regardless of whether we are in compliance with the current public information requirement), would be entitled to sell those common units under Rule 144, subject only to the current public information requirement. After beneficially owning Rule 144 restricted units for at least one year, a person who is not deemed to have been an affiliate of ours at any time during the 90 days preceding a sale would be entitled to freely sell those common units without regard to the public information requirements, volume limitations, manner of sale provisions, and notice requirements of Rule 144.

Our partnership agreement provides that we may issue an unlimited number of limited partner interests of any type and at any time without a vote of the unitholders (other than, in certain instances, approval of the holders of our preferred units). Any issuance of additional common units or other limited partner interests would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. Please read “The Partnership Agreement—Issuance of Additional Partnership Interests.”

The executive officers and directors of our general partner have agreed not to sell any common units they beneficially own for a period of 180 days from the date of this prospectus, and, 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 for a period of 45 days from the date of this prospectus. Please read “Underwriting” for a description of these lock-up provisions.

Prior to the completion of this offering, we expect to adopt a new long-term incentive plan. If adopted, we intend to file a registration statement on Form S-8 under the Securities Act to register common units issuable under the long-term incentive plan. This registration statement on Form S-8 is expected to be filed following the effective date of the registration statement of which this prospectus is a part and will be effective upon filing. Accordingly, common units issued under the long-term incentive plan will be eligible for resale in the public market without restriction after the effective date of the Form S-8 registration statement, subject to applicable vesting requirements, Rule 144 limitations applicable to affiliates and the lock-up restrictions described above.

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MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES

This section summarizes the material federal income tax consequences that may be relevant to prospective unitholders and is based upon current provisions of the Internal Revenue Code of 1986, as amended (the “Code”), existing and proposed Treasury regulations thereunder (the “Treasury Regulations”), and current administrative rulings and court decisions, all of which are subject to change. Changes in these authorities may cause the federal income tax consequences to a prospective unitholder to vary substantially from those described below, possibly on a retroactive basis. Unless the context otherwise requires, references in this section to “we” or “us” are references to Black Stone Minerals, L.P. and its subsidiaries.

Legal conclusions contained in this section, unless otherwise noted, are the opinion of Vinson & Elkins L.L.P. and are based on the accuracy of representations made by us to them for this purpose. However, this section does not address all federal income tax matters that affect us or our unitholders and does not describe the application of the alternative minimum tax that may be applicable to certain unitholders. Furthermore, this section focuses on unitholders who are individual citizens or residents of the United States (for federal income tax purposes), who have the U.S. dollar as their functional currency, who use the calendar year as their taxable year, and who hold units as capital assets (generally, property that is held for investment). This section has limited applicability to corporations, partnerships (including entities treated as partnerships for federal income tax purposes), estates, trusts, non-resident aliens, or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, non-U.S. persons, IRAs, employee benefit plans, real estate investment trusts, or mutual funds. Accordingly, we encourage each unitholder to consult the unitholder’s own tax advisor in analyzing the federal, state, local, and non-U.S. tax consequences particular to that unitholder resulting from ownership or disposition of units and potential changes in applicable tax laws.

We are relying on opinions and advice of Vinson & Elkins L.L.P. with respect to the matters described herein. An opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or a court. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any such contest of the matters described herein may materially and adversely impact the market for units and the prices at which our units trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders because the costs will reduce cash distributions to unitholders. Furthermore, the tax consequences of an investment in us may be significantly modified by future legislative or administrative changes or court decisions, which may be retroactively applied.

For the reasons described below, Vinson & Elkins L.L.P. has not rendered an opinion with respect to the following federal income tax issues: (1) the treatment of 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) (please read “—Tax Consequences of Unit Ownership—Treatment of Securities Loans”); (2) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “—Disposition of Units—Allocations Between Transferors and Transferees”); and (3) whether our method for taking into account Section 743 adjustments is sustainable in certain cases (please read “—Tax Consequences of Unit Ownership—Section 754 Election” and “—Uniformity of Units”).

Taxation of the Partnership

Partnership Status

We expect to be treated as a partnership for U.S. federal income tax purposes and, therefore, generally will not be liable for entity-level federal income taxes. Instead, as described below, each of our unitholders will take into account its respective share of our items of income, gain, loss, and deduction in computing its federal income tax liability as if the unitholder had earned the income directly, even if we make no cash distributions to the unitholder.

Section 7704 of the Code generally provides that publicly traded partnerships will be treated as corporations for federal income tax purposes. However, if 90% or more of a partnership’s gross income for every taxable year

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it is publicly traded consists of “qualifying income,” the partnership may continue to be treated as a partnership for federal income tax purposes (the “Qualifying Income Exception”). Qualifying income includes income and gains derived from the exploration, production, and marketing of certain natural resources, including oil, natural gas, and products thereof, as well as other types of income such as interest (other than from a financial business) and dividends. We estimate that less than     % of our current gross income is not qualifying income; however, this estimate could change from time to time.

Based upon factual representations made by us and our general partner, Vinson & Elkins L.L.P. is of the opinion that we will be treated as a partnership and our direct and indirect partnership and limited liability company subsidiaries (other than our general partner) will be disregarded as separate from us or treated as partnerships for federal income tax purposes. The representations made by us and our general partner upon which Vinson & Elkins L.L.P. has relied in rendering its opinion include, without limitation:

(a) Neither we nor any of our partnership or limited liability company subsidiaries (other than our general partner) has elected to be treated as a corporation for federal income tax purposes; and

(b) For each taxable year since and including the year of our initial public offering, more than 90% of our gross income has been and will be income of a character that Vinson & Elkins L.L.P. has opined is “qualifying income” within the meaning of Section 7704(d) of the Code.

We believe that these representations are true and will be true in the future.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as transferring all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation and then as distributing that stock to our unitholders in liquidation. This deemed contribution and liquidation should not result in the recognition of taxable income by our unitholders or us so long as our liabilities do not exceed the tax basis of our assets. Thereafter, we would be treated as an association taxable as a corporation for federal income tax purposes.

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative or legislative action or judicial interpretation at any time. For example, from time to time, members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. One such legislative proposal would have eliminated the Qualifying Income Exception upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any such changes will ultimately be enacted. However, it is possible that a change in law could affect us and may be applied retroactively. Any such changes could negatively impact the value of an investment in our units.

If for any reason we are taxable as a corporation in any taxable year, our items of income, gain, loss, and deduction would be taken into account by us in determining the amount of our liability for federal income tax, rather than being passed through to our unitholders. Our taxation as a corporation would materially reduce cash distributions to unitholders and thus would likely substantially reduce the value of our units. Any distribution made to a unitholder at a time we are treated as a corporation would be (i) a taxable dividend to the extent of our current or accumulated earnings and profits, then (ii) a nontaxable return of capital to the extent of the unitholder’s tax basis in its units, and thereafter (iii) taxable capital gain.

The remainder of this discussion is based on the opinion of Vinson & Elkins L.L.P. that we will be treated as a partnership for federal income tax purposes.

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Tax Consequences of Unit Ownership

Limited Partner Status

Unitholders who are admitted as limited partners of the partnership, as well as unitholders whose units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of units, will be treated as partners of the partnership for federal income tax purposes. For a discussion related to the risks of losing partner status as a result of securities loans, please read “—Tax Consequences of Unit Ownership—Treatment of Securities Loans.” Unitholders who are not treated as partners in us as described above are urged to consult their own tax advisors with respect to the tax consequences applicable to them under their particular circumstances.

Flow-Through of Taxable Income

Subject to the discussion below under “—Entity-Level Collections of Unitholder Taxes” with respect to payments we may be required to make on behalf of our unitholders, we will not pay any federal income tax. Rather, each unitholder will be required to report on its federal income tax return each year its share of our income, gains, losses, and deductions for our taxable year or years ending with or within its taxable year. Consequently, we may allocate income to a unitholder even if that unitholder has not received a cash distribution.

Basis of Units

A unitholder’s tax basis in its units initially will be the amount paid for those units increased by the unitholder’s initial allocable share of our liabilities. That basis generally will be (i) increased by the unitholder’s share of our income and any increases in a unitholder’s share of our liabilities, and (ii) decreased, but not below zero, by the amount of all distributions to the unitholder, the unitholder’s share of our losses, and any decreases in the unitholder’s share of our liabilities. The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all of those interests.

Ratio of Taxable Income to Distributions

We estimate that a purchaser of units in this offering who (i) is subject to the passive activity loss limitation and (ii) owns those units from the date of closing of this offering through the record date for distributions for the period ending December 31,         , will be allocated, on a cumulative basis, an amount of federal taxable income that will be approximately     % of the cash expected to be distributed on those units with respect to that period. If a purchaser of units in this offering is not subject to the passive activity loss limitation, we estimate such purchaser will be allocated, on a cumulative basis, an amount of federal taxable income that will be approximately     % of the cash expected to be distributed on those units with respect to that period. See the discussion below under “—Limitations on Deductibility of Losses” with respect to application of the passive activity loss limitation. These estimates are based upon the assumption that earnings from operations will approximate the amount required to make the anticipated quarterly distributions on all units and other assumptions with respect to capital expenditures, cash generated from operations, net working capital, and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive, and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and which could be changed or with which the IRS could disagree. Accordingly, we cannot assure that these estimates will prove to be correct, and our counsel has not opined on the accuracy of these estimates. The actual ratio of taxable income to cash distributions could be higher or lower than expected, and any differences could be material and could affect the value of units. For example, the ratio of taxable income to cash distributions to a purchaser of units in this offering would be higher, and perhaps substantially higher, than our estimate with respect to the period described above if:

• we distribute less cash than we have assumed in making this projection;

• we make a future offering of units and use the proceeds of the offering in a manner that does not produce additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depreciation or

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amortization for federal income tax purposes during the period or that is depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering;

• legislation is enacted that limits or repeals certain U.S. federal income tax preferences currently available to oil and natural gas exploration and production companies (please read “—Tax Treatment of Operations—Recent Legislative Developments”).

Treatment of Distributions

Distributions by us to a unitholder generally will not be taxable to the unitholder unless such distributions exceed the unitholder’s tax basis in its units, in which case the unitholder generally will recognize gain taxable in the manner described below under “—Disposition of Units.”

Any reduction in a unitholder’s share of our “liabilities” will be treated as a distribution by us of cash to that unitholder. A decrease in a unitholder’s percentage interest in us because of our issuance of additional units may decrease the unitholder’s share of our liabilities. For purposes of the foregoing, a unitholder’s share of our nonrecourse liabilities (liabilities for which no partner bears the economic risk of loss) generally will be based upon that unitholder’s share of the unrealized appreciation (or depreciation) in our assets, to the extent thereof, with any excess liabilities allocated based on the unitholder’s share of our profits. Please read “—Disposition of Units.”

A non-pro rata distribution of money or property (including a deemed distribution as a result of the reallocation of our liabilities described above) may cause a unitholder to recognize ordinary income, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation and depletion recapture and substantially appreciated “inventory items,” both as defined in Section 751 of the Code (“Section 751 Assets”). To the extent of such reduction, the unitholder would be deemed to receive its proportionate share of the Section 751 Assets and exchange such assets with us in return for a portion of the non-pro rata distribution. This deemed exchange generally will result in the unitholder’s recognition of ordinary income in an amount equal to the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis (generally zero) in the Section 751 Assets deemed to be relinquished in the exchange.

Limitations on Deductibility of Losses

A unitholder may not be entitled to deduct the full amount of loss we allocate to it because its share of our losses will be limited to the lesser of (i) the unitholder’s tax basis in its units, and (ii) in the case of a unitholder that is an individual, estate, trust, or certain types of closely held corporations, the amount for which the unitholder is considered to be “at risk” with respect to our activities. In general, a unitholder will be at risk to the extent of its tax basis in its units, reduced by (1) any portion of that basis attributable to the unitholder’s share of our liabilities, (2) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or similar arrangement, and (3) any amount of money the unitholder borrows to acquire or hold its units, if the lender of those borrowed funds owns an interest in us, is related to another unitholder or can look only to the units for repayment. A unitholder subject to the at risk limitation must recapture losses deducted in previous years to the extent that distributions (including distributions deemed to result from a reduction in a unitholder’s share of nonrecourse liabilities) cause the unitholder’s at risk amount to be less than zero at the end of any taxable year.

Losses disallowed to a unitholder or recaptured as a result of the basis or at risk limitations will carry forward and will be allowable as a deduction in a later year to the extent that the unitholder’s tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon a taxable disposition of units, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but not losses suspended by the basis limitation. Any loss previously suspended by the at risk limitation in excess of that gain can no longer be used, and will not be available to offset a unitholder’s salary or active business income.

In addition to the basis and at risk limitations, a passive activity loss limitation generally limits the deductibility of losses incurred by individuals, estates, trusts, some closely held corporations and personal service corporations from “passive activities” (generally, trade or business activities in which the taxpayer does not

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materially participate). The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will be available to offset only passive income generated by us. For this purpose, a unitholder’s share of our royalty income will not be treated as passive income. As a result, our unitholders may receive allocations of taxable income from our royalties that cannot be offset by deductions from our working interests. Passive losses that exceed a unitholder’s share of passive income we generate may be deducted in full when the unitholder disposes of all of its units in a fully taxable transaction with an unrelated party. The passive loss rules generally are applied after other applicable limitations on deductions, including the at risk and basis limitations.

Limitations on Interest Deductions

The deductibility of a non-corporate taxpayer’s “investment interest expense” generally is limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:

• interest on indebtedness allocable to property held for investment;

• interest expense allocated against portfolio income; and

• the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent allocable against portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses other than interest directly connected with the production of investment income. Net investment income generally does not include qualified dividend income or gains attributable to the disposition of property held for investment. A unitholder’s share of a publicly traded partnership’s portfolio income and, according to the IRS, net passive income will be treated as investment income for purposes of the investment interest expense limitation.

Entity-Level Collections of Unitholder Taxes

If we are required or elect under applicable law to pay any federal, state, local, or non-U.S. tax on behalf of any current or former unitholder or our general partner, we are authorized to treat the payment as a distribution of cash to the relevant unitholder or general partner. Where the tax is payable on behalf of all unitholders or we cannot determine the specific unitholder on whose behalf the tax is payable, we are authorized to treat the payment as a distribution to all current unitholders. Payments by us as described above could give rise to an overpayment of tax on behalf of a unitholder, in which event the unitholder may be entitled to claim a refund of the overpayment amount. Unitholders are urged to consult their tax advisors to determine the consequences to them of any tax payment we make on their behalf.

Allocation of Income, Gain, Loss, and Deduction

Our items of income, gain, loss, and deduction generally will be allocated amongst our unitholders in accordance with their percentage interests in us.

Specified items of our income, gain, loss, and deduction will be allocated under Section 704(c) of the Code (or the principles of Section 704(c) of the Code) to account for any difference between the tax basis and fair market value of our assets at the time such assets are contributed to us and at the time of any subsequent offering of our units (a “Book-Tax Disparity”). As a result, the federal income tax burden associated with any Book-Tax Disparity immediately prior to an offering generally will be borne by our partners holding interests in us prior to the offering. In addition, items of recapture income will be specially allocated to the extent possible to the unitholder who was allocated the deduction giving rise to that recapture income in order to minimize the recognition of ordinary income by other unitholders.

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An allocation of items of our income, gain, loss, or deduction, other than an allocation required by the Code to eliminate a Book-Tax Disparity, will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss, or deduction only if the allocation has “substantial economic effect.” In any other case, a partner’s share of an item will be determined on the basis of the partner’s interest in us, which will be determined by taking into account all of the facts and circumstances, including (i) the partner’s relative contributions to us, (ii) the interests of all of the partners in profits and losses, (iii) the interest of all of the partners in cash flow, and (iv) the rights of all of the partners to distributions of capital upon liquidation. Vinson & Elkins L.L.P. is of the opinion that, with the exception of the issues described in “—Section 754 Election” and “—Disposition of Units—Allocations Between Transferors and Transferees,” allocations of income, gain, loss, or deduction under our partnership agreement will be given effect for federal income tax purposes.

Treatment of Securities Loans

A unitholder whose units are loaned (for example, a loan to a “short seller” to cover a short sale of units) may be treated as having disposed of those units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period (i) any of our income, gain, loss, or deduction allocated to those units would not be reportable by the lending unitholder, and (ii) any cash distributions received by the unitholder as to those units may be treated as ordinary taxable income.

Due to a lack of controlling authority, Vinson & Elkins L.L.P. has not rendered an opinion regarding the tax treatment of a unitholder that enters into a securities loan with respect to its units. Unitholders desiring to assure their status as partners and avoid the risk of income recognition from a loan of their units are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and lending their units. The IRS has announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please read “—Disposition of Units—Recognition of Gain or Loss.”

Tax Rates

Under current law, the highest marginal federal income tax rates for individuals applicable to ordinary income and long-term capital gains (generally, gains from the sale or exchange of certain investment assets held for more than one year) are 39.6% and 20%, respectively. These rates are subject to change by new legislation at any time.

In addition, a 3.8% net investment income tax (“NIIT”) applies to certain net investment income earned by individuals, estates, and trusts. For these purposes, net investment income generally includes a unitholder’s allocable share of our income and gain realized by a unitholder from a sale of units. In the case of an individual, the tax will be imposed on the lesser of (i) the unitholder’s net investment income from all investments, or (ii) the amount by which the unitholder’s modified adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or a surviving spouse), $125,000 (if married filing separately) or $200,000 (if the unitholder is unmarried or in any other case). In the case of an estate or trust, the tax will be imposed on the lesser of (i) undistributed net investment income, or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

Section 754 Election

We will make the election permitted by Section 754 of the Code that permits us to adjust the tax bases in our assets as to specific purchasers of our units under Section 743(b) of the Code. That election is irrevocable without the consent of the IRS. The Section 743(b) adjustment separately applies to each purchaser of units based upon the values and bases of our assets at the time of the relevant purchase, and the adjustment will reflect the purchase price paid. The Section 743(b) adjustment does not apply to a person who purchases units directly from us.

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Under our partnership agreement, we are authorized to take a position to preserve the uniformity of units even if that position is not consistent with applicable Treasury Regulations. A literal application of Treasury Regulations governing a 743(b) adjustment attributable to properties depreciable under Section 167 of the Code may give rise to differences in the taxation of unitholders purchasing units from us and unitholders purchasing from other unitholders. If we have any such properties, we intend to adopt methods employed by other publicly traded partnerships to preserve the uniformity of units, even if inconsistent with existing Treasury Regulations, and Vinson & Elkins L.L.P. has not opined on the validity of this approach. Please read “—Uniformity of Units.”

The IRS may challenge the positions we adopt with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of units due to lack of controlling authority. Because a unitholder’s tax basis for its units is reduced by its share of our items of deduction or loss, any position we take that understates deductions will overstate a unitholder’s basis in its units, and may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “—Disposition of Units—Recognition of Gain or Loss.” If a challenge to such treatment were sustained, the gain from the sale of units may be increased without the benefit of additional deductions.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. The IRS could seek to reallocate some or all of any Section 743(b) adjustment we allocated to our assets subject to depreciation or depletion to goodwill or nondepreciable assets. Goodwill, as an intangible asset, is generally amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure any unitholder that the determinations we make will not be successfully challenged by the IRS or that the resulting deductions will not be reduced or disallowed altogether. Should the IRS require a different tax basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than it would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year

We will use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in its tax return its share of our income, gain, loss, and deduction for each taxable year ending within or with its taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of its units following the close of our taxable year but before the close of its taxable year must include its share of our income, gain, loss, and deduction in income for its taxable year, with the result that it will be required to include in income for its taxable year its share of more than one year of our income, gain, loss, and deduction. Please read “—Disposition of Units—Allocations Between Transferors and Transferees.”

Depletion Deductions

Subject to the limitations on deductibility of losses discussed above (please read “—Tax Consequences of Unit Ownership—Limitations on Deductibility of Losses”), common unitholders will be entitled to deductions for the greater of either cost depletion or (if otherwise allowable) percentage depletion with respect to our oil and natural gas interests. Although the Code requires each common unitholder to compute its own depletion allowance and maintain records of its share of the adjusted tax basis of the underlying property for depletion and other purposes, we intend to furnish each of our common unitholders with information relating to this computation for federal income tax purposes. Each common unitholder, however, remains responsible for calculating its own depletion allowance and maintaining records of its share of the adjusted tax basis of the underlying property for depletion and other purposes.

Percentage depletion is generally available with respect to common unitholders who qualify under the independent producer exemption contained in Section 613A(c) of the Code. For this purpose, an independent

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producer is a person not directly or indirectly involved in the retail sale of oil, natural gas, or derivative products or the operation of a major refinery. Percentage depletion is calculated as an amount generally equal to 15% (and, in the case of marginal production, potentially a higher percentage) of the common unitholder’s gross income from the depletable property for the taxable year. The percentage depletion deduction with respect to any property is limited to 100% of the taxable income of the common unitholder from the property for each taxable year, computed without the depletion allowance. A common unitholder that qualifies as an independent producer may deduct percentage depletion only to the extent the common unitholder’s average daily production of domestic oil, or the natural gas equivalent, does not exceed 1,000 barrels. This depletable amount may be allocated between oil and natural gas production, with 6,000 cubic feet of domestic natural gas production regarded as equivalent to one barrel of oil. The 1,000-barrel limitation must be allocated among the independent producer and controlled or related persons and family members in proportion to the respective production by these persons during the period in question.

In addition to the foregoing limitations, the percentage depletion deduction otherwise available is limited to 65% of a common unitholder’s total taxable income from all sources for the year, computed without the depletion allowance, net operating loss carrybacks, or capital loss carrybacks. Any percentage depletion deduction disallowed because of the 65% limitation may be deducted in the following taxable year if the percentage depletion deduction for the year plus the deduction carryover does not exceed 65% of the common unitholder’s total taxable income for that year. The carryover period resulting from the 65% net income limitation is unlimited.

Common unitholders that do not qualify under the independent producer exemption are generally restricted to depletion deductions based on cost depletion. Cost depletion deductions are calculated by (i) dividing the common unitholder’s share of the adjusted tax basis in the underlying mineral-property by the number of mineral units (barrels of oil and Mcf of natural gas) remaining as of the beginning of the taxable year and (ii) multiplying the result by the number of mineral units sold within the taxable year. The total amount of deductions based on cost depletion cannot exceed the common unitholder’s share of the total adjusted tax basis in the property.

All or a portion of any gain recognized by a common unitholder as a result of either the disposition by us of some or all of our oil and natural gas interests or the disposition by the common unitholder of some or all of its units may be taxed as ordinary income to the extent of recapture of depletion deductions, except for percentage depletion deductions in excess of the tax basis of the property. The amount of the recapture is generally limited to the amount of gain recognized on the disposition.

The foregoing discussion of depletion deductions does not purport to be a complete analysis of the complex legislation and Treasury Regulations relating to the availability and calculation of depletion deductions by the common unitholders. Further, because depletion is required to be computed separately by each common unitholder and not by us, no assurance can be given, and counsel is unable to express any opinion, with respect to the availability or extent of percentage depletion deductions to the unitholders for any taxable year. We encourage each prospective common unitholder to consult its tax advisor to determine whether percentage depletion would be available to the common unitholder.

Administrative Expenses

Expenses of the partnership will include administrative expenses, the deductibility of which may be subject to limitation. As long as we only own royalty interests, under applicable rules, administrative expenses attributable to common units will be considered miscellaneous itemized deductions that generally will have to be aggregated with an individual unitholder’s other miscellaneous itemized deductions. These rules disallow itemized deductions that are less than 2% of a taxpayer’s adjusted gross income, and the amount of otherwise allowable itemized deductions will be reduced by the lesser of (i) 3% of (A) adjusted gross income over (B) $305,050 ($152,525 if married filing separately), and (ii) 80% of the amount of itemized deductions that are otherwise allowable, or both. It is anticipated that the amount of the administrative expenses will not be significant in relation to the partnership’s income.

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Recent Legislative Developments

The Obama Administration’s budget proposals for fiscal years 2014 and 2015 include proposals that would, among other things, eliminate or reduce certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs (“IDCs”), (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these proposals will be introduced into law and, if so, how soon any resulting changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our units.

Tax Basis, Depreciation and Amortization

The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions, if any, and, ultimately, gain or loss on the disposition of those assets. If we dispose of depreciable or depletable property by sale, foreclosure, or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation and depletion deductions previously taken, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of its interest in us. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss, and Deduction.”

The costs we incur in offering and selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. While there are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us, the underwriting discounts we incur will be treated as syndication expenses. Please read “—Disposition of Units—Recognition of Gain or Loss.”

Valuation and Tax Basis of Our Properties

The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values and the tax bases of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of tax basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss, or deduction previously reported by unitholders could change, and unitholders could be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Units

Recognition of Gain or Loss

A unitholder will be required to recognize gain or loss on a sale of units equal to the difference between the unitholder’s amount realized and tax basis in the units sold. A unitholder’s amount realized generally will equal the sum of the cash and the fair market value of other property it receives plus its share of our liabilities with respect to the units sold. Because the amount realized includes a unitholder’s share of our liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Except as noted below, gain or loss recognized by a unitholder on the sale or exchange of a unit held for more than one year generally will be taxable as long-term capital gain or loss. However, gain or loss recognized

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on the disposition of units will be separately computed and taxed as ordinary income or loss under Section 751 of the Code to the extent attributable to Section 751 Assets, such as depreciation or depletion recapture and our “inventory items,” regardless of whether an inventory item is substantially appreciated in value. Ordinary income attributable to Section 751 Assets may exceed net taxable gain realized on the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and capital gain or loss upon a sale of units. Net capital loss may offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year.

For purposes of calculating gain or loss on the sale of units, the unitholder’s adjusted tax basis will be adjusted by its allocable share of our income or loss in respect of its units for the year of the sale. Furthermore, as described above, the IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all of those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in its entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership.

Treasury Regulations under Section 1223 of the Code allow a selling unitholder who can identify units transferred with an ascertainable holding period to elect to use the actual holding period of the units transferred. Thus, according to the ruling discussed in the paragraph above, a unitholder will be unable to select high or low basis units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, it may designate specific units sold for purposes of determining the holding period of the units transferred. A unitholder electing to use the actual holding period of units transferred must consistently use that identification method for all subsequent sales or exchanges of our units. A unitholder considering the purchase of additional units or a sale of units purchased in separate transactions is urged to consult its tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

Specific provisions of the Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” financial position, including a partnership interest with respect to which gain would be recognized if it were sold, assigned, or terminated at its fair market value, in the event the taxpayer or a related person enters into:

• a short sale;

• an offsetting notional principal contract; or

• a futures or forward contract with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is authorized to issue Treasury Regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees

In general, our taxable income or loss will be determined quarterly, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month (the “Allocation Date”). However, gain or loss realized on a sale or other disposition of our assets or, in the discretion of the general partner, any other extraordinary item of income, gain, loss, or deduction will be allocated among the unitholders on the Allocation Date in the month in which such income, gain, loss, or deduction is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss, and deduction realized after the date of transfer.

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Although simplifying conventions are contemplated by the Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations. The Department of the Treasury 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, although such tax items must be prorated on a daily basis. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the validity of this method of allocating income and deductions between transferee and transferor unitholders. If this method is not allowed under the final Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses could be reallocated among our unitholders. We are authorized to revise our method of allocation between transferee and transferor unitholders, as well as among unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

A unitholder who disposes of units prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss, and deduction attributable to the month of disposition but will not be entitled to receive a cash distribution for that period.

Notification Requirements

A unitholder who sells or purchases any of its units is generally required to notify us in writing of that transaction within 30 days after the transaction (or, if earlier, January 15 of the year following the transaction in the case of a seller). Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a transfer of units may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale through a broker who will satisfy these requirements.

Constructive Termination

We will be considered to have “constructively” terminated as a partnership for federal income tax purposes upon the sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For such purposes, multiple sales of the same unit are counted only once. A constructive termination results 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 result in more than twelve months of our taxable income or loss being includable in a unitholder’s taxable income for the year of termination.

A constructive termination occurring on a date other than December 31 generally would require that we file two tax returns for one fiscal year thereby increasing our administration and tax preparation costs. However, pursuant to an IRS relief procedure the IRS may allow a constructively terminated partnership to provide a single Schedule K-1 for the calendar year in which a termination occurs. Following a constructive termination, we would be required to make new tax elections, including a new election under Section 754 of the Code. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination may either accelerate the application of, or subject us to, any tax legislation enacted before the termination that would not otherwise have been applied to us as a continuing as opposed to a terminating partnership.

Uniformity of Units

Because we cannot match transferors and transferees of units and other reasons, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements. Any non-uniformity could have a negative impact on the value of the units. Please read “—Tax Consequences of Unit Ownership—Section 754 Election.”

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Our partnership agreement permits our general partner to take positions in filing our tax returns that preserve the uniformity of our units. These positions may include reducing the depreciation, amortization, or loss deductions to which a unitholder would otherwise be entitled or reporting a slower amortization of Section 743(b) adjustments for some unitholders than that to which they would otherwise be entitled. Vinson & Elkins L.L.P. is unable to opine as to the validity of such filing positions.

A unitholder’s basis in units is reduced by its share of our deductions (whether or not these deductions were claimed on an individual income tax return) so that any position that we take that understates deductions will overstate the unitholder’s basis in its units, and may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “—Disposition of Units—Recognition of Gain or Loss” above and “—Tax Consequences of Unit Ownership—Section 754 Election” above. The IRS may challenge one or more of any positions we take to preserve the uniformity of units. If such a challenge were sustained, the uniformity of units might be affected, and, under some circumstances, the gain from the sale of units might be increased without the benefit of additional deductions.

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans and other tax-exempt organizations as well as by non-resident alien individuals, non-U.S. corporations and other non-U.S. persons (collectively, “non-U.S. unitholders”) raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them. Prospective unitholders that are tax-exempt entities or non-U.S. unitholders should consult their tax advisors before investing in our units. Employee benefit plans and most other tax-exempt organizations, including IRAs and other retirement plans, are subject to federal income tax on unrelated business taxable income. Because our properties may be financed with debt and because we may own working interests in the future, portions of our income may be unrelated business taxable income and may be taxable to a tax-exempt unitholder.

Non-U.S. unitholders are taxed by the United States on income effectively connected with the conduct of a U.S. trade or business (“effectively connected income”) and on certain types of U.S.-source non-effectively connected income (such as dividends and royalties), unless exempted or further limited by an income tax treaty. At the time of the initial public offering, we will have income from our royalty interests, certain investments in forward contracts, mineral lease bonus and delay rentals, and working interests in oil and natural gas properties. Even though we are not the operator, our ownership of working interests may be treated as effectively connected income. Furthermore, it is probable that we will be deemed to conduct these activities through permanent establishments in the United States within the meaning of applicable tax treaties. Consequently, a non-U.S. unitholder may be required to file federal tax returns to report its share of our income, gain, loss, or deduction, and pay federal income tax on its share of our net income or gain in a manner similar to a taxable U.S. unitholder. Moreover, under rules concerning withholding on effectively connected income applicable to publicly traded partnerships, distributions to non-U.S. unitholders are subject to withholding at the highest applicable effective tax rate. Even though at the time of the initial public offering, not all of our income will be effectively connected income, we will instruct brokers and nominees to withhold on all distributions to non-U.S. holders at the highest applicable effective tax rate based upon the convention for effectively connected income. Non-U.S. unitholders may be entitled to a refund of all or a portion of this amount. Each non-U.S. unitholder that obtains a taxpayer identification number from the IRS and submits that number to our transfer agent on a Form W-8BEN or W-8BEN-E (or applicable substitute form) may obtain credit for these withholding taxes.

In addition, because a non-U.S. unitholder classified as a corporation may be treated as engaged in a U.S. trade or business, that corporation may be subject to the U.S. branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain as adjusted for changes in the foreign corporation’s “U.S. net equity” to the extent reflected in the corporation’s effectively connected earnings and profits. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Code.

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A non-U.S. unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the non-U.S. unitholder. Under a ruling published by the IRS interpreting the scope of “effectively connected income,” gain recognized by a non-U.S. person from the sale of its interest in a partnership that is engaged in a trade or business in the United States will be considered to be effectively connected with a U.S. trade or business. Thus, part or all of a non-U.S. unitholder’s gain from the sale or other disposition of its units may be treated as effectively connected with a unitholder’s indirect U.S. trade or business constituted by its investment in us. Moreover, under the Foreign Investment in Real Property Tax Act, a non-U.S. unitholder generally will be subject to federal income tax upon the sale or disposition of a unit if (i) it owned (directly or indirectly, actually or constructively, applying certain attribution rules) more than 5% of our units at any time during the five-year period ending on the date of such disposition, and (ii) 50% or more of the fair market value of our worldwide real-property interests and our other assets used or held for use in a trade or business consisted of U.S. real-property interests (which include U.S. real estate (including land, improvements, and certain associated personal property) and interests in certain entities holding U.S. real estate) at any time during the shorter of the period during which a unitholder held the units or the five-year period ending on the date of disposition. More than 50% of our assets may consist of U.S. real-property interests. Therefore, non-U.S. unitholders may be subject to federal income tax on gain from the sale or disposition of their units.

Administrative Matters

Information Returns and Audit Procedures

We intend to furnish to each unitholder, within 90 days after the close of each taxable year, specific tax information, including a Schedule K-1, which describes its share of our income, gain, loss, and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss, and deduction. We cannot assure our unitholders that those positions will yield a result that conforms to all of the requirements of the Code, Treasury Regulations or administrative interpretations of the IRS.

The IRS may audit our federal income tax information returns. Neither we nor Vinson & Elkins L.L.P. can assure prospective unitholders that the IRS will not successfully challenge the positions we adopt, and such a challenge could adversely affect the value of the units. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability and may result in an audit of the unitholder’s own return. Any audit of a unitholder’s return could result in adjustments unrelated to our returns.

Publicly traded partnerships generally are treated as entities separate from their owners for purposes of federal income tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss, and deduction are determined in a partnership proceeding rather than in separate proceedings of the partners. The Code requires that one partner be designated as the “Tax Matters Partner” for these purposes, and our partnership agreement designates our general partner.

The Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all of the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review may go forward, and each unitholder with an interest in the outcome may participate in that action.

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A unitholder must file a statement with the IRS identifying the treatment of any item on its federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Nominee Reporting

Persons who hold an interest in us as a nominee for another person are required to furnish to us:

(1) the name, address, and taxpayer identification number of the beneficial owner and the nominee;

(2) a statement regarding whether the beneficial owner is:

(a) a non-U.S. person;

(b) a non-U.S. government, an international organization, or any wholly owned agency or instrumentality of either of the foregoing; or

(c) a tax-exempt entity;

(3) the amount and description of units held, acquired, or transferred for the beneficial owner; and

(4) specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on units they acquire, hold, or transfer for their own account. A penalty of $100 per failure, up to a maximum of $1.5 million per calendar year, is imposed by the Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Accuracy-Related Penalties

Certain penalties may be imposed as a result of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for the underpayment of that portion and that the taxpayer acted in good faith regarding the underpayment of that portion. We do not anticipate that any accuracy related penalties will be assessed against us.

FATCA Withholding Requirements

Under the Foreign Account Tax Compliance Act (“FATCA”), a withholding agent may be required to withhold 30% of any interest, dividends, and other fixed or determinable annual or periodical gains, profits, and income from sources within the United States (“FDAP Income”) or gross proceeds from the sale of any property of a type which can produce interest or dividends from sources within the United States paid to (i) a foreign financial institution (which includes foreign broker-dealers, clearing organizations, investment companies, hedge funds, and certain other investment entities) unless the foreign financial institution agrees to verify, report, and disclose its U.S. account holders and meets certain other specified requirements or (ii) a non-financial foreign entity that is a beneficial owner of the payment unless the entity certifies that it does not have any substantial U.S. owners or provides the name, address, and taxpayer identification number of each substantial U.S. owner and the entity meets certain other specified requirements or otherwise qualifies for an exemption from this withholding.

The withholding provisions described above are scheduled to apply to payments of FDAP Income made on or after July 1, 2014 and to payments of relevant gross proceeds made on or after January 1, 2017. Each prospective unitholder should consult its own tax advisor regarding these withholding provisions.

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State, Local, and Other Tax Considerations

In addition to federal income taxes, unitholders may be subject to other taxes, including state and local income taxes, unincorporated business taxes, and estate, inheritance, or intangibles taxes that may be 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 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. We may also own property or do business in other states in the future that impose income or similar taxes on nonresident individuals. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on its investment in us.

Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. It is your responsibility to file all U.S. federal, foreign, state, and local tax returns. Our counsel has not rendered an opinion on the foreign, state, or local tax consequences of an investment in our common units.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of his investment in us. We strongly recommend that each prospective unitholder consult, and depend upon, its own tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local, and non-U.S., as well as U.S. federal tax returns that may be required of it. Vinson & Elkins L.L.P. has not rendered an opinion on the state, local, alternative minimum tax, or non-U.S. tax consequences of an investment in us.

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

An investment in our common units by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and the prohibited transaction restrictions imposed by Section 4975 of the Internal Revenue Code and may be subject to provisions under certain federal, state, local, non-U.S., or other laws or regulations that are similar to such provisions of the Internal Revenue Code or ERISA (collectively, “Similar Laws”). For these purposes the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, certain Keogh plans, certain simplified employee pension plans and tax deferred annuities or individual retirement accounts or annuities (“IRAs”), and entities whose underlying assets are considered to include “plan assets” of such plans, accounts or arrangements.

General Fiduciary Matters

ERISA and the Internal Revenue Code impose certain duties on persons who are fiduciaries of an employee benefit plan that is subject to Title I of ERISA or Section 4975 of the Internal Revenue Code (an “ERISA Plan”) and prohibit certain transactions involving the assets of an ERISA Plan and its fiduciaries or other interested parties. Under ERISA and the Internal Revenue Code, any person who exercises any discretionary authority or control over the administration of an ERISA Plan or the management or disposition of the assets of an ERISA Plan, or who renders investment advice for a fee or other compensation to an ERISA Plan, is generally considered to be a fiduciary of the ERISA Plan. In considering an investment in our common units, among other things, consideration should be given to:

• whether the investment is prudent under Section 404(a)(1)(B) of ERISA and any other applicable Similar Laws;

• whether, in making the investment, the employee benefit plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA and any other applicable Similar Laws;

• whether the investment is permitted under the terms of the applicable documents governing the employee benefit plan;

• whether making the investment will comply with the delegation of control and prohibited transaction provisions under Section 406 of ERISA, Section 4975 of the Internal Revenue Code and any other applicable Similar Laws (please read the discussion under “—Prohibited Transaction Issues” below);

• whether in making the investment, the employee benefit plan will be considered to hold, as plan assets, (1) only the investment in our common units, or (2) an undivided interest in our underlying assets (please read the discussion under “—Plan Asset Issues” below); and

• whether the investment will result in recognition of unrelated business taxable income by the employee benefit plan and, if so, the potential after-tax investment return. Please read “Material U.S. Federal Income Tax Consequences—Tax-Exempt Organizations and Other Investors.”

The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in our common units is authorized by the appropriate governing instruments and is a proper investment for the employee benefit plan or IRA.

Prohibited Transaction Issues

Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit employee benefit plans and certain IRAs that are not considered part of an employee benefit plan from engaging in specified transactions involving “plan assets” with parties that are “parties in interest” under ERISA or “disqualified persons” under the Internal Revenue Code with respect to the employee benefit plan or IRA, unless an exemption is applicable. A party in interest or disqualified person who engages in a non-exempt prohibited transaction may be subject to

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excise taxes and other penalties and liabilities under ERISA and the Internal Revenue Code. In addition, the fiduciary of the ERISA Plan that engaged in such a prohibited transaction may be subject to excise taxes, penalties and liabilities under ERISA, and the Internal Revenue Code.

Plan Asset Issues

In addition to considering whether the purchase of our common units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether the plan will, by investing in our common units, be deemed to own an undivided interest in our assets, with the result that our general partner also would be a fiduciary of the plan and our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code and any other applicable Similar Laws.

The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets” under certain circumstances. Under these regulations, an entity’s underlying assets generally would not be considered to be “plan assets” if, among other things:

(1) the equity interests acquired by employee benefit plans are publicly offered securities—i.e., the equity interests are part of a class of securities that are widely held by 100 or more investors independent of the issuer and each other, “freely transferable” (as defined in the applicable Department of Labor regulations) and either part of a class of securities registered pursuant to certain provisions of the federal securities laws or sold to the plan as part of a public offering under certain conditions;

(2) the entity is an “operating company”—i.e., it is primarily engaged in the production or sale of a product or service other than the investment of capital either directly or through a majority-owned subsidiary or subsidiaries; or

(3) there is no significant investment by benefit plan investors, which is defined to mean that, immediately after the most recent acquisition of an equity interest in any entity by an employee benefit plan, less than 25% of the total value of each class of equity interest, disregarding certain interests held by our general partner, its affiliates, and certain other persons, is held by the employee benefit plans and IRAs referred to above.

With respect to an investment in our common units, we believe that our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in (1) and (2) above and may also satisfy the requirements in (3) above (although we do not monitor the level of investment by benefit plan investors as required for compliance with (3)).

The foregoing discussion of issues arising for employee benefit plan investments under ERISA, the Internal Revenue Code and applicable Similar Laws is general in nature and is not intended to be all inclusive, nor should it be construed as legal advice. Plan fiduciaries contemplating a purchase of our common units should consult with their own counsel regarding the consequences of a purchase under ERISA, the Internal Revenue Code and Similar Laws in light of the serious penalties, excise taxes, and liabilities imposed on persons who engage in prohibited transactions or other violations.

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UNDERWRITING

Barclays Capital Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated and Citigroup Global Markets Inc. are acting as the representatives of the underwriters and as the joint book-running managers of this offering. Under the terms of an underwriting agreement, which will be filed as an exhibit to the registration statement relating to this prospectus, each of the underwriters named below has severally agreed to purchase from us the respective number of common units shown opposite its name below:

Underwriters	Number of Common Units
Barclays Capital Inc.
Merrill Lynch, Pierce, Fenner & Smith                           Incorporated
Citigroup Global Markets Inc.
Credit Suisse Securities (USA) LLC
Wells Fargo Securities, LLC
J.P. Morgan Securities LLC
Morgan Stanley & Co. LLC
Raymond James & Associates, Inc.
Scotia Capital (USA) Inc.
Simmons & Company International
Total

The underwriting agreement provides that the underwriters’ obligation to purchase the common units depends on the satisfaction of the conditions contained in the underwriting agreement including:

• the obligation to purchase all of the common units offered hereby (other than those common units covered by their option to purchase additional common units as described below), if any of the common units are purchased;

• the representations and warranties made by us to the underwriters are true;

• there is no material change in our business or the financial markets; and

• we deliver customary closing documents to the underwriters.

Commissions and Expenses

The following table summarizes the underwriting discounts we will pay to the underwriters. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional common units. The underwriting fee is the difference between the initial price to the public and the amount the underwriters pay to us for the common units.

	No Exercise	Full Exercise
Per common unit	$	$
Total	$	$

We will pay a structuring fee equal to 0.50% of the gross proceeds from this offering (including any proceeds from the exercise of the option to purchase additional common units) to Barclays Capital Inc. for the evaluation, analysis, and structuring of our partnership. We have also agreed to reimburse the underwriters for up to $20,000 of any fees and expenses of counsel related to the review by the Financial Industry Regulatory Authority, Inc. (“FINRA”) of the terms of the sale of the common units offered by this prospectus.

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The representatives of the underwriters have advised us that the underwriters propose to offer the common units directly to the public at the public offering price on the cover of this prospectus and to selected dealers, which may include the underwriters, at an offering price less a selling concession not in excess of $         per common unit. After the offering, the representatives may change the offering price and other selling terms. Sales of common units made outside of the United States may be made by affiliates of the underwriters. The offering of the common units by the underwriters is subject to receipt and acceptance and subject to the underwriters’ right to reject any order in whole or in part.

We estimate that the expenses of this offering incurred by us will be $         million (excluding the estimated underwriting discount and structuring fee). The underwriters have agreed to reimburse us for certain offering expenses incurred by us in connection with this offering.

Option to Purchase Additional Common Units

We have granted the underwriters an option exercisable for 30 days after the date of the underwriting agreement, to purchase, from time to time, in whole or in part, up to an aggregate of              additional common units at the public offering price less underwriting discounts. This option may be exercised if the underwriters sell more than              common units in connection with this offering. To the extent that this option is exercised, each underwriter will be obligated, subject to certain conditions, to purchase its pro rata portion of these additional common units based on the underwriter’s underwriting commitment in the offering as indicated in the table at the beginning of this Underwriting section.

Lock-Up Agreements

We, our general partner, the directors, and executive officers of our general partner have agreed that, without the prior written consent of Barclays Capital Inc., we and they will not directly or indirectly, for a period of 180 days after the date of this prospectus, and, under the terms of our partnership agreement, the limited partners of BSMC prior to this offering will be restricted, for a period of 45 days after the date of this prospectus, such that they will not directly or indirectly (1) offer for sale, sell, pledge, or otherwise dispose of (or enter into any transaction or device that is designed to, or could be expected to, result in the disposition by any person at any time in the future of) any of our common units (including, without limitation, common units that may be deemed to be beneficially owned by us or them in accordance with the rules and regulations of the SEC and common units that may be issued upon exercise of any options or warrants) or securities convertible into or exercisable or exchangeable for common units (other than (i) the common units being sold in this offering, and (ii) common units issued pursuant to employee benefit plans, qualified option plans, or other employee compensation plans existing on the date hereof), (2) enter into any swap or other derivatives transaction that transfers to another, in whole or in part, any of the economic consequences of ownership of the common units, (3) make any demand for or exercise any right or file or cause to be filed a registration statement, including any amendments thereto, with respect to the registration of any common units or securities convertible, exercisable, or exchangeable into common units or any of our other securities (other than any registration statement on Form S-8), or (4) publicly disclose the intention to do any of the foregoing.

Barclays Capital Inc., in its sole discretion, may release the common units and other securities subject to the lock-up agreements described above in whole or in part at any time with or without notice. When determining whether or not to release common units and other securities from lock-up agreements, Barclays Capital Inc. will consider, among other factors, the holder’s reasons for requesting the release, the number of common units and other securities for which the release is being requested, and market conditions at the time.

Offering Price Determination

Prior to this offering, there has been no public market for our common units. The initial public offering price will be negotiated between the representatives and us. In determining the initial public offering price of our common units, the representatives will consider:

• the history and prospects for the industry in which we compete;

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• our financial information;

• the ability of our management and our business potential and earning prospects;

• the prevailing securities markets at the time of this offering;

• the recent market prices of, and the demand for, publicly traded common units of generally comparable companies; and

• other factors deemed relevant by the underwriters and us.

Indemnification

We have agreed to indemnify the several underwriters against certain liabilities, including liabilities under the Securities Act and liabilities incurred in connection with the directed unit program referred to below, and to contribute to payments that the underwriters may be required to make for these liabilities.

Stabilization, Short Positions, and Penalty Bids

The representatives may engage in stabilizing transactions, short sales, purchases to cover positions created by short sales, and penalty bids or purchases for the purpose of pegging, fixing, or maintaining the price of the common units, in accordance with Regulation M under the Exchange Act:

• Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.

• A short position involves a sale by the underwriters of common units in excess of the number of common units the underwriters are obligated to purchase in the offering, which creates the syndicate short position. This short position may be either a covered short position or a naked short position. In a covered short position, the number of common units involved in the sales made by the underwriters in excess of the number of common units they are obligated to purchase is not greater than the number of common units that they may purchase by exercising their option to purchase additional common units.

In a naked short position, the number of common units involved is greater than the number of common units in their option to purchase additional common units. The underwriters may close out any short position by either exercising their option to purchase additional common units and/or purchasing common units in the open market. In determining the source of common units to close out the short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through their option to purchase additional common units. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in the offering.

• Syndicate covering transactions involve purchases of the common units in the open market after the distribution has been completed in order to cover syndicate short positions.

• Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the common units originally sold by the syndicate member are purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

These stabilizing transactions, syndicate covering transactions, and penalty bids may have the effect of raising or maintaining the market price of our common units or preventing or retarding a decline in the market price of the common units. As a result, the price of the common units may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the NYSE or otherwise and, if commenced, may be discontinued at any time.

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Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the common units. In addition, neither we nor any of the underwriters make any representation that the representatives will engage in these stabilizing transactions or that any transaction, once commenced, will not be discontinued without notice.

Directed Unit Program

At our request, the underwriters have reserved up to     % of the common units being offered by this prospectus (excluding the common units that may be issued upon the underwriters’ exercise of their option to purchase additional common units) for sale at the initial public offering price to persons who are directors, officers, or employees of our general partner, and certain other persons with relationships with us and our affiliates, as designated by us, through a directed unit program. The number of common units available for sale to the general public will be reduced by the number of directed units purchased by participants in the program. Any directed units not purchased will be offered by the underwriters to the general public on the same basis as all other common units offered by this prospectus. We have agreed to indemnify the underwriters against certain liabilities and expenses, including liabilities under the Securities Act, in connection with the sales of the directed units.

Electronic Distribution

A prospectus in electronic format may be made available on the internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of common units for sale to online brokerage account holders. Any allocation for online distributions will be made by the representatives on the same basis as other allocations.

Other than the prospectus in electronic format, the information on any underwriter’s or selling group member’s web site and any information contained in any other web site maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

New York Stock Exchange

We have applied to list our common units on the NYSE under the symbol “BSM.” The underwriters have undertaken to sell the minimum number of common units to the minimum number of beneficial owners necessary to meet the NYSE distribution requirements for trading.

Discretionary Sales

The underwriters have informed us that they do not intend to confirm sales to discretionary accounts that exceed 5% of the total number of common units offered by them.

Stamp Taxes

If you purchase common units offered in this prospectus, you may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover page of this prospectus.

Relationships

The underwriters and their respective affiliates are full-service financial institutions engaged in various activities, which may include sales and trading, commercial and investment banking, advisory, investment management, investment research, principal investment, hedging, market making, brokerage, and other financial

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and non-financial activities and services. The underwriters and their affiliates have in the past, and may in the future, perform investment banking, commercial banking, advisory, and other services for us and our respective affiliates from time to time for which they have received, and may in the future receive, customary fees and expenses.

In addition, in the ordinary course of their various business activities, the underwriters and their respective affiliates may make or hold a broad array of investments, including serving as counterparties to certain derivative and hedging arrangements, and actively trade debt and equity securities (or related derivative securities), and financial instruments (including bank loans) for their own account and for the accounts of their customers. Such investment and securities activities may involve securities and instruments of ours or our affiliates. The underwriters and their respective affiliates may also make investment recommendations or publish or express independent research views in respect of these securities or financial instruments and may hold, or recommend to clients that they acquire, long or short positions in these securities and instruments.

Affiliates of Merrill Lynch, Pierce, Fenner & Smith Incorporated, Wells Fargo Securities, LLC, J.P. Morgan Securities LLC and Scotia Capital (USA) Inc. are lenders under our revolving credit facility and, accordingly, will receive a portion of the net proceeds from this offering.

FINRA

Because FINRA is expected to view the common units offered hereby as interests in a direct participation program, the offering is being made in compliance with Rule 2310 of the FINRA Rules. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

Selling Restrictions

Other than in the United States, no action has been taken by us or the underwriters that would permit a public offering of the securities offered by this prospectus in any jurisdiction where action for that purpose is required. The securities offered by this prospectus may not be offered or sold, directly or indirectly, nor may this prospectus or any other offering material or advertisements in connection with the offer and sale of any such securities be distributed or published in any jurisdiction, except under circumstances that will result in compliance with the applicable rules and regulations of that jurisdiction. Persons into whose possession this prospectus comes are advised to inform themselves about and to observe any restrictions relating to the offering and the distribution of this prospectus. This prospectus does not constitute an offer to sell or a solicitation of an offer to buy any securities offered by this prospectus in any jurisdiction in which such an offer or a solicitation is unlawful.

Singapore

This prospectus has not been and will not be registered as a prospectus with the Monetary Authority of Singapore. Accordingly, this prospectus and any other document or material in connection with the offer or sale, or invitation for subscription or purchase, of the common units may not be circulated or distributed, nor may the common units be offered or sold, or be made the subject of an invitation for subscription or purchase, whether directly or indirectly, to persons in Singapore other than (i) to an institutional investor under Section 274 of the Securities and Futures Act, Chapter 289 of Singapore (the “SFA”), (ii) to a relevant person pursuant to Section 275(1), or any person pursuant to Section 275(1A), and in accordance with the conditions specified in Section 275, of the SFA, or (iii) otherwise pursuant to, and in accordance with the conditions of, any other applicable provision of the SFA.

Where the common units are subscribed or purchased under Section 275 of the SFA by a relevant person which is:

(1) a corporation (which is not an accredited investor (as defined in Section 4A of the SFA)) the sole business of which is to hold investments and the entire share capital of which is owned by one or more individuals, each of whom is an accredited investor; or

178

(2) a trust (where the trustee is not an accredited investor) whose sole purpose is to hold investments and each beneficiary of the trust is an individual who is an accredited investor, securities (as defined in Section 239(1) of the SFA) of that corporation or the beneficiaries’ rights and interest (howsoever described) in that trust shall not be transferred within six months after that corporation or that trust has acquired the common units pursuant to an offer made under Section 275 of the SFA except:

(a) to an institutional investor or to a relevant person defined in Section 275(2) of the SFA, or to any person arising from an offer referred to in Section 275(1A) or Section 276(4)(i)(B) of the SFA;

(b) where no consideration is or will be given for the transfer;

(c) where the transfer is by operation of law;

(d) as specified in Section 276(7) of the SFA; or

(e) as specified in Regulation 32 of the Securities and Futures (Offers of Investments) (Shares and Debentures) Regulations 2005 of Singapore.

Hong Kong

Our common units may not be offered or sold in Hong Kong by means of this prospectus or any other document other than to (a) professional investors as defined in the Securities and Futures Ordinance of Hong Kong (Cap. 571, Laws of Hong Kong) (“SFO”) and any rules made under the SFO, or (b) in other circumstances which do not result in this prospectus being deemed to be a “prospectus,” as defined in the Companies Ordinance of Hong Kong (Cap. 32, Laws of Hong Kong) (“CO”), or which do not constitute an offer to the public within the meaning of the CO or the SFO; and no person has issued or had in possession for the purposes of issue, or will issue or has in possession for the purposes of issue, whether in Hong Kong or elsewhere, any advertisement, invitation or document relating to our common units which is directed at, or the contents of which are likely to be accessed or read by, the public of Hong Kong (except if permitted to do so under the securities laws of Hong Kong) other than with respect to our common units which are or are intended to be disposed of only to persons outside Hong Kong or only to professional investors as defined in the SFO.

179

LEGAL MATTERS

The validity of our common units and certain other legal matters will be passed upon for us by Richards, Layton & Finger, P.A., Wilmington, Delaware. Certain legal matters in connection with this offering will be passed upon for the underwriters by Andrews Kurth LLP.

Jerry V. Kyle, Jr., a member of the board of directors of our general partner, is a Partner at Andrews Kurth LLP. For Mr. Kyle’s beneficial ownership of our common units and preferred units following this offering and the other formation transactions, please see “Security Ownership of Certain Beneficial Owners and Management.”

EXPERTS

The consolidated financial statements of Black Stone Minerals Company, L.P. and Subsidiaries as of December 31, 2013 and 2012, and for the years then ended, included in this prospectus have been audited by UHY LLP, an independent registered public accounting firm as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report, given on the authority of such firm as experts in auditing and accounting.

The balance sheet of Black Stone Minerals, L.P. as of September 16, 2014 included in this prospectus has been audited by UHY LLP, an independent registered public accounting firm as set forth in their report thereon appearing elsewhere herein, and is included in reliance upon such report, given on the authority of such firm as experts in auditing and accounting.

Information included in this prospectus regarding our estimated quantities of oil and natural gas reserves and the discounted present value of future net cash flows therefrom is based upon estimates of such reserves and present values prepared by Pressler Petroleum Consultants, Inc., a third-party petroleum engineering firm, as of December 31, 2013. This information is included herein in reliance upon the authority of said firm as experts in these matters.

Information included in this prospectus regarding our estimated quantities of oil and natural gas reserves and the discounted present value of future net cash flows therefrom is based upon estimates of such reserves and present values prepared by Netherland, Sewell & Associates, Inc., a third-party petroleum engineering firm, as of September 30, 2014. This information is included herein in reliance upon the authority of said firm as experts in these matters.

CHANGE IN ACCOUNTANTS

On December 1, 2014, the Texas based practice of UHY LLP (“UHY”) was acquired by BDO USA, LLP (“BDO”).

On January 13, 2015, the audit committee of BSNR’s board of managers dismissed UHY, our independent auditor, effective as of January 13, 2015.

The audit report of UHY on the consolidated financial statements of BSMC for the years ended December 31, 2013 and 2012 did not contain an adverse opinion or a disclaimer of opinion, and was not qualified or modified as to uncertainty, audit scope or accounting principles. During the years ended December 31, 2013 and 2012 and through the subsequent interim period preceding January 13, 2015, there were no disagreements between UHY and us on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedures, which disagreements, if not resolved to the satisfaction of UHY, would have caused them to make reference thereto in their reports on our financial statements for such years.

180

On January 13, 2015, the audit committee of BSNR’s board of managers engaged BDO as our independent registered public accounting firm. During the years ended December 31, 2013 and 2012 and the subsequent interim period preceding the engagement of BDO, we did not consult with BDO regarding: (1) the application of accounting principles to a specified transaction, either completed or proposed; (2) the type of audit opinion that might be rendered on our financial statements, and BDO did not provide any written report or oral advice that BDO concluded was an important factor considered by us in reaching a decision as to any such accounting, auditing or financial reporting issue; or (3) any matter that was either the subject of a disagreement with UHY on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure or the subject of a reportable event.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 (including the exhibits, schedules, and amendments thereto) under the Securities Act with respect to the common units being offered hereunder. This prospectus does not contain all of the information set forth in the registration statement and the exhibits and schedules to the registration statement. For further information with respect to us and our common units, we refer you to the registration statement and the exhibits filed as a part of the registration statement. Statements contained in this prospectus concerning the contents of any contract or any other documents are not necessarily complete. If a contract or document has been filed as an exhibit to the registration statement, we refer you to the copy of the contract or document that has been filed as an exhibit and reference thereto is qualified in all respects by the terms of the filed exhibit.

As a result of this offering, we will become subject to the full informational requirements of the Exchange Act. We will fulfill our obligations with respect to such requirements by filing period reports and other information with the SEC. Our SEC filings, including the registration statement and any exhibits and schedules thereto, may be inspected without charge at the Public Reference Room of the SEC at 100 F Street, N.E., Washington, D.C. 20549, and copies of these materials may be obtained from that office after payment of fees prescribed by the SEC. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC maintains a web site that contains reports, proxy and information statements, and other information regarding registrants that file electronically with the SEC at http://www.sec.gov. After this offering, documents filed by us can also be inspected at the offices of the NYSE Inc., 20 Broad Street, New York, New York 10002.

181

FORWARD-LOOKING STATEMENTS

Some of the information in this prospectus may contain forward-looking statements. Forward-looking statements give our current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

• our ability to execute our business strategies;

• the volatility of realized oil and natural gas prices;

• the level of production on our properties;

• regional supply and demand factors, delays, or interruptions of production;

• our ability to replace our oil and natural gas reserves;

• our ability to identify, complete, and integrate acquisitions;

• general economic, business, or industry conditions;

• competition in the oil and natural gas industry;

• the ability of our operators to obtain capital or financing needed for development and exploration operations;

• title defects in the properties in which we invest;

• the availability or cost of rigs, equipment, raw materials, supplies, oilfield services, or personnel;

• restrictions on the use of water;

• the availability of transportation facilities;

• the ability of our operators to comply with applicable governmental laws and regulations and to obtain permits and governmental approvals;

• federal and state legislative and regulatory initiatives relating to hydraulic fracturing;

• future operating results;

• exploration and development drilling prospects, inventories, projects, and programs;

• operating hazards faced by our operators;

• the ability of our operators to keep pace with technological advancements; and

• certain factors discussed elsewhere in this prospectus.

All forward-looking statements are expressly qualified in their entirety by the foregoing cautionary statements.

182

INDEX TO FINANCIAL STATEMENTS

PRO FORMA FINANCIAL STATEMENTS
Black Stone Minerals, L.P.
Unaudited Pro Forma Financial Statements
Introduction	F-2
Unaudited Pro Forma Consolidated Balance Sheet as of September 30, 2014	F-4
Unaudited Pro Forma Consolidated Statement of Operations for the Nine Months Ended September 30, 2014	F-6
Unaudited Pro Forma Consolidated Statement of Operations for the Year Ended December 31, 2013	F-7
Notes to Unaudited Pro Forma Consolidated Financial Statements	F-8
HISTORICAL FINANCIAL STATEMENTS
Black Stone Minerals, L.P.
Report of Independent Registered Public Accounting Firm	F-9
Balance Sheet as September 16, 2014	F-10
Notes to Balance Sheet	F-11
Black Stone Minerals Company, L.P.
Interim Period Financial Statements (Unaudited)
Consolidated Balance Sheets as of September 30, 2014 and December 31, 2013	F-12
Consolidated Statements of Operations for the Nine Months Ended September 30, 2014 and 2013	F-14
Consolidated Statement of Equity for the Nine Months Ended September 30, 2014	F-15
Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2014 and 2013	F-16
Notes to Consolidated Financial Statements	F-18
Annual Financial Statements
Report of Independent Registered Public Accounting Firm	F-26
Consolidated Balance Sheets as of December 31, 2013 and 2012	F-27
Consolidated Statements of Operations for the Years Ended December 31, 2013 and 2012	F-29
Consolidated Statements of Equity for the Years Ended December 31, 2013 and 2012	F-30
Consolidated Statements of Cash Flows for the Years Ended December 31, 2013 and 2012	F-31
Notes to Consolidated Financial Statements	F-33

F-1

BLACK STONE MINERALS, L.P.

UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

Introduction

Set forth below are the unaudited pro forma consolidated balance sheet as of September 30, 2014 and the unaudited pro forma consolidated statements of operations for the year ended December 31, 2013 and the nine months ended September 30, 2014 (together with the notes to unaudited pro forma consolidated financial statements, the “pro forma financial statements”), of Black Stone Minerals, L.P. (the “Partnership”). The unaudited pro forma financial statements of the Partnership have been derived from the historical consolidated financial statements of Black Stone Minerals Company, L.P. (“BSMC,” the “Company” or the “Predecessor”). The unaudited pro forma financial statements should be read in conjunction with the Predecessor’s historical consolidated financial statements and the related financial statement notes, included elsewhere in this prospectus.

The Partnership will own and operate the business of the Predecessor effective with the closing of this offering (the “Offering”). The contribution of the Predecessor’s business to the Partnership will be recorded at cost, as it is a reorganization of entities under common control. The pro forma financial statements have been prepared on the assumption that Black Stone Minerals, L.P. will continue to be treated as a partnership for U.S. federal income tax purposes.

The unaudited pro forma adjustments are based on currently available information and certain estimates and assumptions. The actual effects of the events may differ from the unaudited pro forma adjustments. However, management believes the assumptions utilized to prepare the unaudited pro forma adjustments provide a reasonable basis for presenting the significant effects of the events identified above and as more specifically described below.

The unaudited pro forma consolidated balance sheet assumes the transactions to be effected as if the closing of the offering had taken place as of September 30, 2014, and the unaudited pro forma consolidated statements of operations for the year ended December 31, 2013 and the nine months ended September 30, 2014 assume the transactions had taken place as of January 1, 2013.

The pro forma financial statements give pro forma effect to the following transactions:

• the formation by the Partnership of Black Stone Minerals GP, L.L.C. (“New GP”), a new wholly owned subsidiary of the Partnership to function as the general partner of the Partnership, and the transfer of BSNR’s general partner interest in the Partnership to New GP in exchange for cash;

• a cash contribution by Black Stone Natural Resources, L.L.C. (“BSNR”), the general partner and a wholly owned subsidiary of BSMC, to BSMC in exchange for common units representing a 1% limited partner interest in BSMC, and a cash contribution by New GP to the Partnership in exchange for a 1% limited partner interest in the Partnership;

• the merger of BSMC with and into a wholly owned subsidiary of the Partnership (the “Merger Sub”), with BSMC as the surviving entity;

• immediately prior to the merger, the conversion of the limited partner interests of BSMC and New GP in the Partnership into common units of the Partnership;

• in connection with the merger, (i) the redemption of the common units in the Partnership held by BSMC in exchange for a return of its original capital contribution, (ii) the exchange of the common units of BSMC (other than common units of BSMC held by BSNR) for an aggregate of              of common units of the Partnership at a conversion ratio of     :1, and the exchange of the preferred units of BSMC for an aggregate of              of preferred units of the Partnership, (iii) the common units of BSMC held by BSNR continuing to be outstanding as limited partner interests in BSMC, and the retention of New GP’s non-economic general partner interest in the Partnership and common units in the Partnership,

F-2

(iv) the conversion of the Partnership’s 100% equity interest in Merger Sub into a 99% limited partner interest in BSMC, and (v) the retention of BSNR’s non-economic general partner interest in BSMC;

• (i) the formation by the Partnership of New BSMC GP, a new wholly owned subsidiary to function as general partner of BSMC, (ii) the removal by the Partnership of BSNR as general partner of BSMC and appointment of New BSMC GP as general partner of BSMC, and (iii) in connection therewith, the transfer of BSNR’s general partner interest in BSMC to New BSMC GP: and

• the issuance and sale of              common units by the Partnership to the public, and the application of the net proceeds therefrom.

Upon completion of the Offering, the Partnership anticipates incurring incremental general and administrative expenses of approximately $1.5 million as a result of being a publicly traded partnership, consisting of costs 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. The pro forma financial statements do not reflect these incremental selling, general, and administrative expenses.

F-3

BLACK STONE MINERALS, L.P.

UNAUDITED PRO FORMA CONSOLIDATED BALANCE SHEET

September 30, 2014

(in thousands)

	Predecessor Historical			Pro Forma Adjustments			Pro Forma
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	7,992		$		(a)(b)	$
Accounts receivable		91,639			—			91,639
Commodity derivative assets—current portion		2,465						2,465
Prepaid expenses and other current assets		8,687			—			8,687
TOTAL CURRENT ASSETS		110,783
PROPERTY AND EQUIPMENT
Oil and natural gas properties on the basis of the successful efforts method of accounting, includes unproved properties of $668,029 at September 30, 2014		2,376,975			—			2,376,975
Less: Accumulated depreciation, depletion, and amortization		(1,047,928	)		—			(1,047,928	)
Oil and natural gas properties, net		1,329,047			—			1,329,047
Other property and equipment, net of accumulated depreciation and amortization of $12,441 at September 30, 2014		1,702			—			1,702
NET PROPERTY AND EQUIPMENT		1,330,749			—			1,330,749
DEFERRED CHARGES AND OTHER LONG-TERM ASSETS		2,935			—			2,935
TOTAL ASSETS	$	1,444,467		$			$

The accompanying notes to unaudited pro forma consolidated financial statements are an integral part of this statement.

F-4

BLACK STONE MINERALS, L.P.

UNAUDITED PRO FORMA CONSOLIDATED BALANCE SHEET

September 30, 2014

(in thousands)

	Predecessor Historical		Pro Forma Adjustments			Pro Forma
LIABILITIES, MEZZANINE EQUITY AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	39,118	$	—		$	39,118
Accrued liabilities		14,746		—			14,746
Commodity derivative liabilities—current portion		730		—			730
Accrued partners’ distribution payable		51,179		—			51,179
TOTAL CURRENT LIABILITIES		105,773		—			105,773
LONG-TERM LIABILITIES
Credit facility		430,000		(430,000	)(b)		—
Accrued incentive compensation—non-current portion		6,745		—			6,745
Deferred revenue		3,990		—			3,990
Asset retirement obligations		6,484		—			6,484
TOTAL LIABILITIES		552,992		(430,000	)		122,992
COMMITMENTS AND CONTINGENCIES
MEZZANINE EQUITY
Partners’ equity—redeemable preferred units, 157 units authorized and outstanding at September 30, 2014		161,165		—			161,165
EQUITY
General partner		—		—			—
Partners’ equity—common units, 2,129,488 units authorized, issued, and outstanding at September 30, 2014		726,490			(a)
Noncontrolling interests		3,820		—			3,820
TOTAL EQUITY		730,310
TOTAL LIABILITIES, MEZZANINE EQUITY AND EQUITY	$	1,444,467	$			$

The accompanying notes to unaudited pro forma consolidated financial statements are an integral part of this statement.

F-5

BLACK STONE MINERALS, L.P.

UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS

For the Nine Months Ended September 30, 2014

(in thousands, except per unit amounts)

	Predecessor Historical			Pro Forma Adjustments			Pro Forma
REVENUE
Oil and condensate sales	$	195,665		$	—		$	195,665
Natural gas and natural gas liquids sales		156,554			—			156,554
Gain on commodity derivative instruments		339			—			339
Lease bonus and other income		26,586			—			26,586
TOTAL REVENUE		379,144			—			379,144
OPERATING EXPENSE
Lease operating expense and other		16,151			—			16,151
Production and ad valorem taxes		33,589			—			33,589
Depreciation, depletion, and amortization		84,058			—			84,058
General and administrative		45,607			—			45,607
Accretion of asset retirement obligations		443			—			443
TOTAL OPERATING EXPENSE		179,848			—			179,848
INCOME FROM OPERATIONS		199,296			—			199,296
OTHER INCOME (EXPENSE)
Interest and investment income		27			—			27
Interest expense		(10,292	)		7,559	(c)(d)		(2,733	)
Other income		869			—			869
TOTAL OTHER INCOME (EXPENSE)		(9,396	)		7,559			(1,837	)
NET INCOME		189,900			7,559			197,459
LESS: NET LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS		18			—			18
NET INCOME ATTRIBUTABLE TO BLACK STONE MINERALS COMPANY, L.P.		189,918			7,559			197,477
LESS: DIVIDENDS ON PREFERRED UNITS		(11,763	)		—			(11,763	)
NET INCOME ATTRIBUTABLE TO GENERAL PARTNER		—			—			—
NET INCOME ATTRIBUTABLE TO COMMON UNITS	$	178,155		$	7,559		$	185,714
EARNINGS PER UNIT (BASIC AND DILUTED)	$	0.08					$
WEIGHTED AVERAGE UNITS OUTSTANDING (BASIC AND DILUTED)		2,129,939

The accompanying notes to unaudited pro forma consolidated financial statements are an integral part of this statement.

F-6

BLACK STONE MINERALS, L.P.

UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS

For the Year Ended December 31, 2013

(in thousands, except per unit amounts)

	Predecessor Historical			Pro Forma Adjustments			Pro Forma
REVENUE
Oil and condensate sales	$	252,742		$	—		$	252,742
Natural gas and natural gas liquids sales		184,868			—			184,868
Loss on commodity derivative instruments		(5,860	)		—			(5,860	)
Lease bonus and other income		31,809			—			31,809
TOTAL REVENUE		463,559			—			463,559
OPERATING (INCOME) EXPENSE
Lease operating expense and other		21,316			—			21,316
Production and ad valorem taxes		42,813			—			42,813
Depreciation, depletion, and amortization		102,442			—			102,442
Impairment of oil and natural gas properties		57,109			—			57,109
General and administrative		59,501			—			59,501
Accretion of asset retirement obligations		588			—			588
Gain on sale of assets		(18	)		—			(18	)
TOTAL OPERATING EXPENSE		283,751			—			283,751
INCOME FROM OPERATIONS		179,808			—			179,808
OTHER INCOME (EXPENSE)
Interest and investment income		90			—			90
Interest expense		(11,342	)		7,709	(c)(d)		(3,633	)
Other income		407			—			407
TOTAL OTHER INCOME (EXPENSE)		(10,845	)		7,709			(3,136	)
NET INCOME		168,963			7,709		$	176,672
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS		(373	)		—			(373	)
NET INCOME ATTRIBUTABLE TO BLACK STONE MINERALS COMPANY, L.P.		168,590			7,709			176,299
LESS: DIVIDENDS ON PREFERRED UNITS		(15,742	)		—			(15,742	)
NET INCOME ATTRIBUTABLE TO GENERAL PARTNER		—			—			—
NET INCOME ATTRIBUTABLE TO COMMON UNITS	$	152,848		$	7,709		$	160,557
EARNINGS PER UNIT (BASIC AND DILUTED)	$	0.07					$
WEIGHTED AVERAGE UNITS OUTSTANDING (BASIC AND DILUTED)		2,144,599

The accompanying notes to unaudited pro forma consolidated financial statements are an integral part of this statement.

F-7

BLACK STONE MINERALS, L.P.

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Basis of Presentation

The unaudited pro forma balance sheet of the Partnership as of September 30, 2014, and the related unaudited pro forma statements of operations for the year ended December 31, 2013 and the nine months ended September 30, 2014 are derived from the historical consolidated financial statements of the Predecessor.

Upon completion of this offering, the Partnership anticipates incurring incremental general and administrative expenses of approximately $1.5 million as a result of being a publicly traded partnership, consisting of costs 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. The unaudited pro forma financial statements do not reflect these incremental general and administrative expenses.

The unaudited pro forma adjustments included herein assume no exercise of the underwriters’ option to purchase additional common units. Any net proceeds received from the exercise of this option will be used to fund future capital expenditures.

Note 2—Unaudited Pro Forma Adjustments and Assumptions

A summary of the unaudited pro forma adjustments to effect the transactions is as follows:

(a) Reflects the issuance and sale of common units by the Partnership at an assumed initial public offering price of $         per common unit, net of an underwriting discount and offering expenses of          million, and the receipt of the estimated net proceeds therefrom.

(b) Reflects the use of the net proceeds from the Offering to repay all of the debt outstanding under the credit facility with any remaining net proceeds reflected as an addition to cash.

(c) Reflects the elimination of interest expense after repayment of all of the debt outstanding under the credit facility discussed in (b) above.

(d) Reflects the commitment fee related to the credit facility of     % on the $         borrowing base as well as the agency fees related to the credit facility. The fees were $         and $         for the year ended December 31, 2013 and the nine months ended September 30, 2014, respectively.

Note 3—Unaudited Pro Forma Net Income Per Unit

Pro forma net income per unit is determined by dividing the pro forma net income available to common and preferred unitholders by the number of common units to be issued to the Predecessor’s existing limited partners and the number of common units expected to be sold to the public in the Offering. For purposes of this calculation, the number of common units and preferred units outstanding at the closing of the Offering was assumed to be              and             , respectively. All units were assumed to have been outstanding since the beginning of the periods presented.

F-8

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The General Partner of

Black Stone Minerals, L.P.

We have audited the accompanying balance sheet of Black Stone Minerals, L.P. (the “Partnership”) as of September 16, 2014. This balance sheet is the responsibility of the Partnership’s management. Our responsibility is to express an opinion on this balance sheet based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall balance sheet presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the balance sheet referred to above presents fairly, in all material respects, the financial position of the Partnership as of September 16, 2014 in conformity with accounting principles generally accepted in the United States of America.

/s/ UHY LLP

Houston, Texas

October 7, 2014

F-9

BLACK STONE MINERALS, L.P.

BALANCE SHEET

As of September 16, 2014

ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	—
TOTAL ASSETS	$	—
PARTNERS’ CAPITAL
Limited partner’s capital	$	100
General partner’s capital		—
Subscription receivable		(100	)
TOTAL PARTNERS’ CAPITAL	$	—

The accompanying notes are an integral part of this financial statement.

F-10

BLACK STONE MINERALS, L.P.

NOTES TO BALANCE SHEET

Note 1—Organization

Black Stone Minerals, L.P. (the “Partnership”) is a Delaware limited partnership formed on September 16, 2014. The Partnership has adopted a fiscal year-end of December 31. In connection with its formation, the Partnership issued a non-economic general partner interest in the Partnership to Black Stone Natural Resources, L.L.C. (“BSNR”) and a 100% limited partner interest in the Partnership to Black Stone Minerals Company, L.P. (“BSMC”). The limited partner interest will be redeemed in connection with the merger of BSMC with and into a subsidiary of the Partnership, with BSMC as the surviving entity. In connection with the merger, the common units and preferred units of BSMC (other than those common units in BSMC held by BSNR) will be exchanged for common units and preferred units of the Partnership.

The accompanying balance sheet reflects the financial position of the Partnership. As of September 16, 2014, the $100 initial capitalization has not been funded. As a result, the Partnership has presented this as a subscription receivable.

Note 2—Subsequent Events

Subsequent events have been evaluated through the issuance date of the accompanying balance sheet of the Partnership. Any material subsequent events that occurred prior to such date have been properly recognized or disclosed in the balance sheet of the Partnership.

F-11

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

	September 30, 2014			December 31, 2013
	(unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	7,992		$	30,123
Accounts receivable		91,639			91,092
Commodity derivative assets—current portion		2,465			38
Prepaid expenses and other current assets		8,687			4,510
TOTAL CURRENT ASSETS		110,783			125,763
PROPERTY AND EQUIPMENT
Oil and natural gas properties on the basis of the successful efforts method of accounting, includes unproved properties of $668,029 and $640,291 at September 30, 2014 and December 31, 2013, respectively		2,376,975			2,277,514
Less: Accumulated depreciation, depletion, and amortization		(1,047,928	)		(965,371	)
Oil and natural gas properties, net		1,329,047			1,312,143
Other property and equipment, net of accumulated depreciation and amortization of $12,441 and $10,940 at September 30, 2014 and December 31, 2013, respectively		1,702			2,891
NET PROPERTY AND EQUIPMENT		1,330,749			1,315,034
DEFERRED CHARGES AND OTHER LONG-TERM ASSETS		2,935			3,616
TOTAL ASSETS	$	1,444,467		$	1,444,413

F-12

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

	September 30, 2014		December 31, 2013
	(unaudited)
LIABILITIES, MEZZANINE EQUITY AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	39,118	$	30,722
Accrued liabilities		14,746		13,198
Commodity derivative liabilities—current portion		730		1,552
Accrued partners’ distribution payable		51,179		52,333
TOTAL CURRENT LIABILITIES		105,773		97,805
LONG-TERM LIABILITIES
Credit facilities		430,000		451,000
Accrued incentive compensation—non-current portion		6,745		2,374
Commodity derivative liabilities—non-current portion		—		315
Deferred revenue		3,990		9,163
Asset retirement obligations		6,484		5,961
TOTAL LIABILITIES		552,992		566,618
COMMITMENTS AND CONTINGENCIES (Note 7)
MEZZANINE EQUITY
Partners’ equity—redeemable preferred units, 157 units authorized, issued, and outstanding at September 30, 2014 and December 31, 2013		161,165		161,392
EQUITY
Partners’ equity—common units, 2,129,488 units and 2,124,944 units authorized, issued, and outstanding at September 30, 2014 and December 31, 2013, respectively		726,490		712,313
Noncontrolling interests		3,820		4,090
TOTAL EQUITY		730,310		716,403
TOTAL LIABILITIES, MEZZANINE EQUITY AND EQUITY	$	1,444,467	$	1,444,413

The accompanying notes to consolidated financial statements are an integral part of this statement.

F-13

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited)

(in thousands, except per unit amounts)

	Nine Months Ended September 30,
	2014			2013
REVENUE
Oil and condensate sales	$	195,665		$	193,534
Natural gas and natural gas liquids sales		156,554			138,226
Gain (loss) on commodity derivative instruments		339			(3,441	)
Lease bonus and other income		26,586			11,964
TOTAL REVENUE		379,144			340,283
OPERATING (INCOME) EXPENSE
Lease operating expense and other		16,151			15,952
Production and ad valorem taxes		33,589			29,910
Depreciation, depletion, and amortization		84,058			75,213
Impairment of oil and natural gas properties		—			27,630
General and administrative		45,607			45,789
Accretion of asset retirement obligations		443			461
Gain on sale of assets		—			(18	)
TOTAL OPERATING EXPENSE		179,848			194,937
INCOME FROM OPERATIONS		199,296			145,346
OTHER INCOME (EXPENSE)
Interest and investment income		27			79
Interest expense		(10,292	)		(7,922	)
Other income		869			274
TOTAL OTHER EXPENSE		(9,396	)		(7,569	)
NET INCOME		189,900			137,777
LESS: NET (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS		18			(382	)
NET INCOME ATTRIBUTABLE TO BLACK STONE MINERALS COMPANY, L.P.		189,918			137,395
LESS: DIVIDENDS ON PREFERRED UNITS		(11,763	)		(11,774	)
NET INCOME ATTRIBUTABLE TO COMMON UNITS	$	178,155		$	125,621
EARNINGS PER UNIT (BASIC AND DILUTED)	$	0.08		$	0.06
WEIGHTED AVERAGE UNITS OUTSTANDING (BASIC AND DILUTED)		2,129,939			2,154,698

The accompanying notes to consolidated financial statements are an integral part of this statement.

F-14

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF EQUITY

(unaudited)

(in thousands)

	Class A common units			Class B common units			Partners’ equity— common units			Noncontrolling interests			Total
BALANCE AT DECEMBER 31, 2013		1,172,174			952,770		$	712,313		$	4,090		$	716,403
Conversion of preferred units		—			201			221			—			221
Issuance of common units for acquisition of oil and natural gas properties		—			1,340			2,258			—			2,258
Repurchases of common units		(2,618	)		(476	)		(5,199	)		—			(5,199	)
Restricted common units granted, net of forfeitures		6,097			—			—			—			—
Equity-based compensation		—			—			7,452			—			7,452
Distributions		—			—			(168,710	)		(252	)		(168,962	)
Net income (loss)		—			—			189,918			(18	)		189,900
Dividends on preferred units		—			—			(11,763	)		—			(11,763	)
BALANCE AT SEPTEMBER 30, 2014		1,175,653			953,835		$	726,490		$	3,820		$	730,310

The accompanying notes to consolidated financial statements are an integral part of this statement.

F-15

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(in thousands)

	Nine Months Ended September 30,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	189,900		$	137,777
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, and amortization		84,058			75,213
Impairment of oil and natural gas properties		—			27,630
Accretion of asset retirement obligations		443			461
Amortization of debt issue costs		726			728
Gain (loss) on commodity derivative instruments		339			(3,441	)
Net cash received (paid) on settlement of commodity instruments		(4,047	)		8,398
Equity-based compensation		7,452			3,292
Gain on sale of assets		—			(18	)
Changes in operating assets and liabilities:
Accounts receivable		(133	)		(25,148	)
Prepaid expenses and other current assets		(4,178	)		(1,790	)
Accounts payable and accrued liabilities		6,373			(4,772	)
Deferred revenue		(2,516	)		—
Settlement of asset retirement obligations		(19	)		(25	)
NET CASH PROVIDED BY OPERATING ACTIVITIES		278,398			218,305
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and natural gas properties		(52,417	)		(57,838	)
Purchase of other property and equipment		(312	)		(412	)
Proceeds from sales of assets		—			74
Acquisitions of oil and natural gas properties		(39,816	)		(112,270	)
NET CASH USED IN INVESTING ACTIVITIES		(92,545	)		(170,446	)

F-16

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(in thousands)

	Nine Months Ended September 30,
	2014			2013
CASH FLOWS FROM FINANCING ACTIVITIES
Contributions from common equity owners		—			191,611
Distributions to common equity owners		(170,117	)		(173,040	)
Repurchase of common equity units		(5,199	)		(93,806	)
Preferred equity dividends		(11,769	)		(11,764	)
Repayments of revolving credit facilities		—			(46,100	)
Borrowings (repayments) under senior line of credit		(21,000	)		117,000
Note receivable—officers		101			101
Debt issue costs		—			(1,235	)
Purchases of noncontrolling interests		—			(60,719	)
NET CASH USED IN FINANCING ACTIVITIES		(207,984	)		(77,952	)
NET CHANGE IN CASH AND CASH EQUIVALENTS		(22,131	)		(30,093	)
CASH AND CASH EQUIVALENTS—beginning of the period		30,123			47,301
CASH AND CASH EQUIVALENTS—end of the period	$	7,992		$	17,208
SUPPLEMENTAL DISCLOSURE
Interest paid	$	9,721		$	6,684
NON-CASH ACTIVITIES
Property additions financed through accounts payable and accrued liabilities	$	22,086		$	19,613
Acquisitions of oil and natural gas properties financed through issuance of common units	$	2,258		$	227,119
Distributions—property	$	—		$	19,029
Accrued repurchases of common units	$	—		$	24,302
Contributions through exchanges	$	—		$	1,019,340
Conversion of preferred equity	$	(221	)	$	—
Deferred revenue used as consideration for oil and natural gas property acquired	$	2,657		$	902
Asset retirement obligations	$	99		$	159

The accompanying notes to consolidated financial statements are an integral part of this statement.

F-17

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

NOTE 1—BUSINESS AND BASIS OF PRESENTATION

Description of the Business: Black Stone Minerals Company, L.P., a Delaware limited partnership, and its subsidiaries (collectively referred to as “BSMC” or the “Company”) own oil and natural gas mineral interests in the United States. In addition to mineral interests, the Company’s assets include nonparticipating royalty interests and overriding royalty interests. These non-cost-bearing interests are collectively referred to as “mineral and royalty interests.” The Company’s mineral and royalty interests are located in most of the major onshore oil and natural gas producing basins spread across 41 states and 62 onshore oil and natural gas producing basins in the continental United States (“U.S.”). The Company also owns non-operating working interests primarily related to its mineral interests.

Black Stone Natural Resources, L.L.C., a Delaware limited liability company (“BSNR”), was the 1% general partner of BSMC. Effective December 31, 2013, BSMC acquired all shares of BSNR, and BSNR became a wholly owned subsidiary of BSMC. BSNR and BSMC have common ownership and management. This transaction was accounted for as a transaction under common control. The change in the reporting entity has been retrospectively reflected; however, there is no impact on the consolidated financial statements of the Company.

Basis of Presentation: The accompanying financial statements of the Company have been prepared in accordance with generally accepted accounting principles (“GAAP”) in the U.S. and pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Certain information and note disclosures commonly included in annual financial statements have been omitted pursuant to the rules and regulations of the SEC. Accordingly, the accompanying financial statements and notes should be read in conjunction with the Company’s annual consolidated financial statements and notes to consolidated financial statements. In the opinion of management, all material adjustments, which are of a normal and recurring nature necessary for a fair presentation of the results for the periods presented, have been reflected.

The Company evaluates significant terms of its investments to determine the method of accounting applied to the investments. Investments in which the Company has less than a 20% ownership interest and does not have control or exercise significant influence are accounted for under the cost method. The Company’s cost method investment is included in deferred charges and other long-term assets in the consolidated balance sheets. The Company does not have any equity method investments as of the periods ended September 30, 2014 and December 31, 2013. Investments in which the Company exercises control are consolidated, and the noncontrolling interests of such investments, which are not attributable directly or indirectly to the Company, are presented as a separate component of net income and equity in the accompanying consolidated financial statements.

The consolidated financial statements include undivided interests in oil and natural gas property rights. The Company accounts for its share of oil and natural gas property rights by reporting its proportionate share of assets, liabilities, revenues, costs and cash flows within the relevant lines on the accompanying consolidated balance sheets, statements of operations and cash flow statements.

Segment Reporting: The Company operates in a single operating and reportable segment. Operating segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assessing performance. The Company’s chief operating decision maker allocates resources and assesses performance based upon financial information at the consolidated level.

F-18

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Significant Accounting Policies: Our significant accounting policies are disclosed in the consolidated financial statements for the years ended December 31, 2013 and 2012. There have been no changes in such policies or the application of such policies during the nine month period ended September 30, 2014.

New Accounting Pronouncements: In April 2014, the Financial Accounting Standards Board (“FASB”) issued accounting standards updates to Accounting Standard Codification (“ASC”) 205, Presentation of Financial Statements, and to ASC 360, Property, Plant, and Equipment, to change the criteria for reporting discontinued operations. The amendments modify the definition of discontinued operations by limiting discontinued operations reporting to disposals of components of an entity that represent strategic shifts that have or will have a major effect on an entity’s operations and financial results. These amendments require additional disclosures about discontinued operations and new disclosures for other disposals of individually material components of an organization that do not meet the definition of a discontinued operation. In addition, the guidance allows companies to have significant continuing involvement and continuing cash flows with the discontinued operation. These provisions are effective for public companies prospectively for annual reporting periods beginning on or after December 15, 2014, and interim periods within those annual periods, with early adoption permitted. The adoption of this guidance, effective January 1, 2015, will not affect the Company’s consolidated financial position or results of operations; however, it may result in changes to the manner in which future dispositions of operations or assets, if any, are presented in the Company’s financial statements, or it may require additional disclosures.

In May 2014, the FASB issued an accounting standards update, FASB Staff Accounting Bulletin Topic 606, on a comprehensive new revenue recognition standard that will supersede the existing revenue recognition guidance. The new accounting guidance creates a framework under which an entity will allocate the transaction price to separate performance obligations and recognize revenue when each performance obligation is satisfied. Under the new standard, entities will be required to use judgment and make estimates, including identifying performance obligations in a contract, estimating the amount of variable consideration to include in the transaction price, allocating the transaction price to each separate performance obligation and determining when an entity satisfies its performance obligations. The standard allows for either “full retrospective” adoption, meaning that the standard is applied to all of the periods presented with a cumulative catch-up as of the earliest period presented, or “modified retrospective” adoption, meaning the standard is applied only to the most current period presented in the financial statements with a cumulative catch-up as of the current period. The accounting standard will be effective for reporting periods beginning after December 15, 2016 for public companies. The Company is in the process of evaluating the impact that the new accounting guidance will have on its consolidated financial position, results of operations, cash flows, and related disclosures.

F-19

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

NOTE 3—ASSET RETIREMENT OBLIGATIONS

Asset retirement obligations (“AROs”) consist primarily of estimated costs of dismantlement, removal, site reclamation, and similar activities associated with oil and natural gas properties. Changes in AROs during the periods presented are as follows:

	September 30, 2014			December 31, 2013
	(in thousands)
Beginning asset retirement obligations	$	5,961		$	5,242
Liabilities incurred		99			164
Liabilities settled		(19	)		(33	)
Accretion expense		443			588
Ending asset retirement obligations	$	6,484		$	5,961

NOTE 4—DERIVATIVES AND FINANCIAL INSTRUMENTS

The Company’s ongoing operations expose it to changes in the market price for oil and natural gas. To mitigate the given commodity price risk associated with its operations, the Company uses 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, the Company currently utilizes only costless collars. The Company does not enter into derivative instruments for speculative purposes.

With a costless collar, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the exercise price of the purchased put. The Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the exercise price for the sold call of the collar. The settlement paid or received is the difference between the market price on the settlement date and the related exercise price. All derivative instruments are reflected as either assets or liabilities at fair value in the Company’s accompanying consolidated balance sheets as of September 30, 2014 and December 31, 2013. See Note 5 for further discussion of fair value. The table below summarizes the fair value and classification of the Company’s derivative instruments:

As of September 30, 2014 (in thousands)
Classification	Balance Sheet Location	Gross Fair Value		Effect of Counter-party Netting			Net Carrying Value on Balance Sheet
Assets:
Current asset	Commodity derivative assets	$	2,625	$	(160	)	$	2,465
Non-current asset	Deferred charges and other long-term assets		110		—			110
Total assets		$	2,735	$	(160	)	$	2,575
Liabilities:
Current liability	Commodity derivative liabilities	$	890	$	(160	)	$	730
Non-current liability	Commodity derivative liabilities		—		—			—
Total liabilities		$	890	$	(160	)	$	730

F-20

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

As of December 31, 2013 (in thousands)
Classification	Balance Sheet Location	Gross Fair Value		Effect of Counter-party Netting			Net Carrying Value on Balance Sheet
Assets:
Current asset	Commodity derivative assets	$	2,888	$	(2,850	)	$	38
Non-current asset	Deferred charges and other long-term assets		1,521		(1,504	)		17
Total assets		$	4,409	$	(4,354	)	$	55
Liabilities:
Current liability	Commodity derivative liabilities	$	4,402	$	(2,850	)	$	1,552
Non-current liability	Commodity derivative liabilities		1,819		(1,504	)		315
Total liabilities		$	6,221	$	(4,354	)	$	1,867

Changes in the fair values of the Company’s derivative instruments (both assets and liabilities) are presented on a net basis in the accompanying consolidated statements of operations. The following table details the unrealized and realized gains (losses) recognized from the Company’s derivative instruments and where these components are recorded on the Company’s accompanying consolidated statements of operations for the nine months ended September 30, 2014 and 2013:

Derivatives not designated as hedging instruments under ASC 815	Location of Gain (Loss)	Classification of Gain (Loss)	Nine Months Ended September 30,
			2014			2013
			(in thousands)
Oil commodity contracts	Gain (loss) on commodity derivative instruments	Realized	$	(932	)	$	(178	)
Natural gas commodity contracts	Gain (loss) on commodity derivative instruments	Realized		(2,437	)		1,694
Total realized gains (losses) from derivatives not designated as hedges			$	(3,369	)	$	1,516
Oil commodity contracts	Gain (loss) on commodity derivative instruments	Unrealized	$	1,765		$	(4,908	)
Natural gas commodity contracts	Gain (loss) on commodity derivative instruments	Unrealized		1,943			(49	)
Total unrealized gains (losses) from derivatives not designated as hedges			$	3,708		$	(4,957	)
Gain (loss) on commodity derivative instruments .			$	339		$	(3,441	)

F-21

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The Company had the following open derivative contracts for oil at September 30, 2014:

	Volume in bbl		Weighted Average		Range
Period and Type of Contract					Low		High
2014
Collar contracts:
Call Options		268,000	$	100.54	$	100.00	$	103.30
Put Options		268,000	$	82.19	$	80.00	$	90.00
2015
Collar contracts:
Call Options		879,000	$	101.71	$	99.05	$	104.00
Put Options		879,000	$	84.14	$	80.00	$	90.00

The Company had the following open derivative contracts for natural gas at September 30, 2014:

	Volume in MMBtu		Weighted Average		Range
Period and Type of Contract					Low		High
2014
Collar contracts:
Call Options		4,620,000	$	5.00	$	4.55	$	5.40
Put Options		4,620,000	$	3.79	$	3.50	$	4.50
2015
Collar contracts:
Call Options		8,870,000	$	4.96	$	4.60	$	5.60
Put Options		8,870,000	$	3.76	$	3.50	$	4.50

NOTE 5—FAIR VALUE DISCLOSURE

ASC 820, Fair Value Measurement, defines fair value as the amount at which an asset (or liability) could be bought (or incurred) or sold (or settled) in a current transaction between willing parties other than in a forced or liquidation sale. Further, ASC 820 establishes a framework for measuring fair value, establishes a fair-value hierarchy based on the quality of inputs used to measure fair value, and includes certain disclosure requirements. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk.

ASC 820 establishes a three level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:

Level 1—Quoted prices (unadjusted) for identical assets or liabilities in active markets.

Level 2—Quoted prices for similar assets or liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

Level 3—Inputs that are unobservable and significant to the fair value measurement (including the Company’s own assumptions in determining fair value).

F-22

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. There were no transfers into, or out of, the three levels of the fair value hierarchy for the nine months ended September 30, 2014 or the year ended December 31, 2013.

The Company estimated the fair value of derivative instruments using the market approach via a model that uses inputs that are observable in the market or can be derived from, or corroborated by, observable data. See Note 4 for further discussion on derivatives and financial instruments.

The following table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis:

	Level 1		Level 2		Level 3		Effect of Counter- party Netting			Total
	(in thousands)
At September 30, 2014:
Financial Assets
Commodity derivative instruments	$	—	$	2,735	$	—	$	(160	)	$	2,575
Financial Liabilities
Commodity derivative instruments	$	—	$	890	$	—	$	(160	)	$	730
At December 31, 2013:
Financial Assets
Commodity derivative instruments	$	—	$	4,409	$	—	$	(4,354	)	$	55
Financial Liabilities
Commodity derivative instruments	$	—	$	6,221	$	—	$	(4,354	)	$	1,867

The determination of the fair values of proved and unproved properties acquired in purchase transactions are prepared by estimating discounted cash flow projections. The factors used to determine fair value include estimates of: (i) economic reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital.

Oil and natural gas properties are measured at fair value on a nonrecurring basis using the income approach. Proved and unproved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of those properties. Significant Level 3 assumptions used to determine fair value include estimates of proved reserves, future commodity prices, the timing and amount of future production and capital expenditures, and a discount rate commensurate with the risk associated with the respective oil and natural gas properties.

The Company’s estimates of fair value have been determined at discrete points in time based on relevant market data. These estimates involve uncertainty and cannot be determined with precision. There were no changes in valuation techniques or related inputs as of September 30, 2014 or December 31, 2013.

F-23

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

NOTE 6—RELATED PARTY TRANSACTIONS

The Company executed promissory notes dated April 15, 2010 in the amount of $0.5 million to officers of the Company. The promissory notes related to the acquisition of a partnership interest in Ivory Acquisitions Partners, L.P. by the officers, and the notes were collateralized by a security interest in the Company. The promissory notes provided for quarterly payments of interest equaling the rate at which the Company paid interest on its borrowings. At December 31, 2013, the aggregated note balance was $0.1 million with less than $0.1 million of accrued interest income, which are both included in current assets on the consolidated balance sheet. For the year ended December 31, 2013, the promissory notes had a weighted average interest rate of 2.73%. These promissory notes were paid in full by the maturity date in April 2014.

NOTE 7—COMMITMENTS AND CONTINGENCIES

Environmental Matters

The Company’s business includes activities that are subject to U.S. federal, state and local environmental regulations with regard to air, land, and water quality and other environmental matters.

The Company does not consider the estimated remediation costs that could result from any environmental site assessments to be significant to the consolidated balance sheets or statements of operations of the Company. No provision for potential remediation costs is reflected in the consolidated financial statements.

Litigation

From time to time, the Company is involved in legal actions and claims arising in the ordinary course of business. The Company believes these claims will be resolved without material adverse effect to the Company’s consolidated balance sheets, statements of operations or cash flows.

NOTE 8—EARNINGS PER UNIT

Class A common units and Class B common units have been combined as a single class for purposes of basic and diluted earnings per unit (“EPU”) as they contain the same economic rights and preferences. The holders of the Company’s restricted common units have all the rights of a unit holder, including non-forfeitable distribution rights. As participating securities, the restricted common units are included in the calculation of basic earnings per unit using the two-class method. For the periods presented, the amount of earnings allocated to the participating restricted common units was not material. The Series A preferred units (the “Preferred Units”) can be converted into 142.6 million and 142.8 million common units as of September 30, 2014 and 2013, respectively. At September 30, 2014 and 2013, if the redeemable Preferred Units were converted to common units, their effect would be anti-dilutive; therefore, the redeemable Preferred Units are not included in the diluted EPU calculation.

F-24

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The following table sets forth the computation of basic and diluted earnings per unit (in thousands, except per unit amounts):

	Nine Months Ended September 30,
	2014			2013
	(in thousands)
Net income	$	189,900		$	137,777
Less: Net (income) loss attributable to noncontrolling interests		18			(382	)
Net income attributable to Black Stone Minerals Company, L.P.		189,918			137,395
Less: Dividends on preferred units		(11,763	)		(11,774	)
Net income attributable to common units	$	178,155		$	125,621
Weighted average units outstanding (basic and diluted)		2,129,939			2,154,698
Earnings per unit (basic and diluted)	$	0.08		$	0.06

NOTE 9—SUBSEQUENT EVENTS

On October 15, 2014 the Company paid distributions of $56.3 million to holders of BSMC’s common units and $4.0 million to the owners of Preferred Units.

F-25

REPORT OF INDEPENDENT REGISTERED ACCOUNTING FIRM

The General Partner of

Black Stone Minerals Company, L.P.

We have audited the accompanying consolidated balance sheets of Black Stone Minerals Company, L.P. and Subsidiaries (collectively referred to as the “Company”), as of December 31, 2013 and 2012, and the related consolidated statements of operations, equity, and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of the Company as of December 31, 2013 and 2012, and the consolidated results of their operations and their cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

/s/ UHY LLP

Houston, Texas

October 7, 2014

F-26

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

	As of December 31,
	2013			2012
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	30,123		$	47,301
Accounts receivable		91,092			68,869
Commodity derivative assets—current portion		38			5,212
Prepaid expenses and other current assets		4,510			3,254
TOTAL CURRENT ASSETS		125,763			124,636
PROPERTY AND EQUIPMENT
Oil and natural gas properties on the basis of the successful efforts method of accounting, includes unproved properties of $640,291 and $369,071 at December 31, 2013 and 2012, respectively		2,277,514			1,884,919
Less: Accumulated depreciation, depletion and amortization		(965,371	)		(817,950	)
Oil and natural gas properties, net		1,312,143			1,066,969
Other property and equipment, net of accumulated depreciation and amortization of $10,940 and $9,121 at December 31, 2013 and 2012, respectively		2,891			4,217
NET PROPERTY AND EQUIPMENT		1,315,034			1,071,186
DEFERRED CHARGES AND OTHER LONG-TERM ASSETS		3,616			3,365
TOTAL ASSETS	$	1,444,413		$	1,199,187

F-27

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

	As of December 31,
	2013		2012
LIABILITIES, MEZZANINE EQUITY AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	30,722	$	34,202
Accrued liabilities		13,198		13,447
Commodity derivative liabilities—current portion		1,552		—
Credit facilities—current portion		—		19,100
Accrued fund repurchases		—		23,319
Accrued partners’ distribution payable		52,333		42,950
TOTAL CURRENT LIABILITIES		97,805		133,018
LONG-TERM LIABILITIES
Credit facilities—non-current portion		451,000		344,000
Accrued incentive compensation—non-current portion		2,374		—
Commodity derivative liabilities—non-current portion		315		—
Deferred partner contributions		—		220,622
Deferred revenue		9,163		8,261
Asset retirement obligations		5,961		5,242
TOTAL LIABILITIES		566,618		711,143
COMMITMENTS AND CONTINGENCIES (Note 13)
MEZZANINE EQUITY
Partners’ equity—redeemable preferred units, 157 units authorized, issued, and outstanding at December 31, 2013 and 2012		161,392		161,381
EQUITY
Partners’ equity (deficit)—common units, 2,124,944 and 1,210,473 units authorized, issued, and outstanding at December 31, 2013 and 2012, respectively		712,313		(1,158	)
Noncontrolling interests		4,090		327,821
TOTAL EQUITY		716,403		326,663
TOTAL LIABILITIES, MEZZANINE EQUITY AND EQUITY	$	1,444,413	$	1,199,187

The accompanying notes to consolidated financial statements are an integral part of this statement.

F-28

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit amounts)

	Year Ended December 31,
	2013			2012
REVENUE
Oil and condensate sales	$	252,742		$	202,104
Natural gas and natural gas liquids sales		184,868			166,849
Gain (loss) on commodity derivative instruments		(5,860	)		12,275
Lease bonus and other income		31,809			53,918
TOTAL REVENUE		463,559			435,146
OPERATING (INCOME) EXPENSE
Lease operating expense and other		21,316			20,527
Production and ad valorem taxes		42,813			36,680
Depreciation, depletion and amortization		102,442			104,059
Impairment of oil and natural gas properties		57,109			62,987
General and administrative		59,501			50,348
Accretion of asset retirement obligations		588			608
Gain on sale of assets		(18	)		(363	)
TOTAL OPERATING EXPENSE		283,751			274,846
INCOME FROM OPERATIONS		179,808			160,300
OTHER INCOME (EXPENSE)
Interest and investment income		90			209
Interest expense		(11,342	)		(9,166	)
Other income		407			467
TOTAL OTHER EXPENSE		(10,845	)		(8,490	)
NET INCOME		168,963			151,810
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS		(373	)		(44,343	)
NET INCOME ATTRIBUTABLE TO BLACK STONE MINERALS COMPANY, L.P.		168,590			107,467
LESS: DIVIDENDS ON PREFERRED UNITS		(15,742	)		(15,742	)
NET INCOME ATTRIBUTABLE TO COMMON UNITS	$	152,848		$	91,725
EARNINGS PER UNIT (BASIC AND DILUTED)	$	0.07		$	0.08
WEIGHTED AVERAGE UNITS OUTSTANDING (BASIC AND DILUTED)		2,144,599			1,212,885

The accompanying notes to consolidated financial statements are an integral part of this statement.

F-29

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

(in thousands)

	Class A common units			Class B common units			Partners’ equity— common units			Noncontrolling interests			Total
BALANCE AT DECEMBER 31, 2011		1,209,296			—		$	147,387		$	510,351		$	657,738
Repurchases of common units		(4,651	)		—			(9,052	)		—			(9,052	)
Restricted common units granted, net of forfeitures		5,828			—			—			—			—
Equity-based compensation		—			—			7,247			—			7,247
Payments under promissory notes		—			—			118			—			118
Distributions		—			—			(119,996	)		(122,599	)		(242,595	)
Purchases of noncontrolling interests		—			—			(118,587	)		(104,274	)		(222,861	)
Net income		—			—			107,467			44,343			151,810
Dividends on preferred units		—			—			(15,742	)		—			(15,742	)
BALANCE AT DECEMBER 31, 2012		1,210,473			—		$	(1,158	)	$	327,821		$	326,663
Contributions—cash		—			243,411			412,233			—			412,233
Contributions—limited partner interests		1,306			600,456			1,019,340			—			1,019,340
Issuance of common units for acquisition of oil and natural gas properties		—			134,107			227,119			—			227,119
Repurchases of common units		(44,834	)		(25,204	)		(118,108	)		—			(118,108	)
Restricted common units granted, net of forfeitures		5,229			—			—			—			—
Equity-based compensation		—			—			6,782			—			6,782
Distributions		—			—			(234,311	)		(767	)		(235,078	)
Distributions—property		—			—			—			(19,029	)		(19,029	)
Purchases of noncontrolling interests		—			—			(22,696	)		(14,704	)		(37,400	)
Exchange of noncontrolling interests		—			—			(729,736	)		(289,604	)		(1,019,340	)
Net income		—			—			168,590			373			168,963
Dividends on preferred units		—			—			(15,742	)		—			(15,742	)
BALANCE AT DECEMBER 31, 2013		1,172,174			952,770		$	712,313		$	4,090		$	716,403

The accompanying notes to consolidated financial statements are an integral part of this statement.

F-30

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOW

(in thousands)

	Year Ended December 31,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	168,963		$	151,810
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization		102,442			104,059
Impairment of oil and natural gas properties		57,109			62,987
Accretion of asset retirement obligations		588			608
Amortization of debt issue costs		968			655
Gain (loss) on commodity derivative instruments		(5,860	)		12,275
Net cash received (paid) on settlement of commodity instruments		13,210			(1,578	)
Equity-based compensation		6,782			7,247
Gain on sale of assets		(18	)		(363	)
Changes in operating assets and liabilities:
Accounts receivable		(15,046	)		13,535
Prepaid expenses and other current assets		(1,256	)		(617	)
Accounts payable and accrued liabilities		(7,085	)		(466	)
Deferred revenue		—			7,881
Settlement of asset retirement obligations		(33	)		(31	)
NET CASH PROVIDED BY OPERATING ACTIVITIES		320,764			358,002
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and natural gas properties		(73,650	)		(89,291	)
Purchase of other property and equipment		(493	)		(330	)
Proceeds from sales of assets		74			1,048
Acquisitions of oil and natural gas properties		(121,562	)		(110,402	)
NET CASH USED IN INVESTING ACTIVITIES		(195,631	)		(198,975	)

F-31

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOW

(in thousands)

	Year Ended December 31,
	2013			2012
CASH FLOWS FROM FINANCING ACTIVITIES
Contributions from common equity partners		191,611			220,622
Repayments of promissory notes		—			118
Distributions to common equity owners		(225,704	)		(222,815	)
Repurchase of common equity units		(118,108	)		(9,052	)
Preferred equity dividends		(15,732	)		(15,753	)
Repayments of revolving credit facilities		(46,100	)		—
Borrowings under senior line of credit		134,000			90,350
Note receivable—officers		101			152
Debt issue costs		(1,660	)		(2,252	)
Purchase of noncontrolling interests		(60,719	)		(199,542	)
NET CASH USED IN FINANCING ACTIVITIES		(142,311	)		(138,172	)
NET CHANGE IN CASH AND CASH EQUIVALENTS		(17,178	)		20,855
CASH AND CASH EQUIVALENTS—beginning of the year		47,301			26,446
CASH AND CASH EQUIVALENTS—end of the year	$	30,123		$	47,301
SUPPLEMENTAL DISCLOSURE
Interest paid	$	10,344		$	8,351
NON-CASH ACTIVITIES
Property additions financed through accounts payable and accrued liabilities	$	23,029		$	16,210
Acquisition of oil and natural gas properties through exchanges	$	227,119		$	—
Contributions through exchange of noncontrolling interests	$	1,019,340		$	—
Accrued repurchases of noncontrolling interests	$	—		$	23,319
Distributions—property	$	19,029		$	—
Accrued distribution payable	$	9,374		$	19,780
Deferred revenue used as consideration for oil and natural gas property acquired	$	902		$	381
Asset retirement obligations	$	164		$	199

The accompanying notes to consolidated financial statements are an integral part of this statement.

F-32

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—BUSINESS AND BASIS OF PRESENTATION

Description of the Business: Black Stone Minerals Company, L.P., a Delaware limited partnership, and its subsidiaries (collectively referred to as “BSMC” or the “Company”) own oil and natural gas mineral interests in the United States. In addition to mineral interests, the Company’s assets include nonparticipating royalty interests and overriding royalty interests. These non-cost-bearing interests are collectively referred to as “mineral and royalty interests”. The Company’s mineral and royalty interests are located in most of the major onshore oil and natural gas producing basins spread across 41 states and 62 onshore oil and natural gas producing basins of the continental United States (“U.S.”). The Company also owns non-operated working interests.

For the years ended December 31, 2013 and 2012, Black Stone Natural Resources, L.L.C., a Delaware limited liability company (“BSNR”), was the 1% general partner of BSMC. Effective December 31, 2013, BSMC acquired all shares of BSNR, and BSNR became a wholly owned subsidiary of BSMC. BSNR and BSMC have common ownership and management. This transaction was accounted for as a transaction under common control. The change in the reporting entity has been retrospectively reflected; however, there is no impact on the consolidated financial statements of the Company.

Basis of Presentation: The accompanying financial statements of the Company have been prepared in accordance with generally accepted accounting principles (“GAAP”) in the U.S. The financial statements include the consolidated results of the Company. All intercompany balances and transactions have been eliminated.

The Company evaluates significant terms of its investments to determine the method of accounting applied to the investments. Investments in which the Company has less than a 20% ownership interest and does not have control or exercise significant influence are accounted for under the cost method. The Company’s cost method investments are included in deferred charges and other long-term assets in the consolidated balance sheets. The Company does not have any equity method investments as of December 31, 2013 and 2012. Investments in which the Company exercises control are consolidated, and the noncontrolling interests of such investments, which are not attributable directly or indirectly to the Company, are presented as a separate component of net income and equity in the accompanying consolidated financial statements.

The consolidated financial statements include undivided interests in oil and natural gas property rights. The Company accounts for its share of oil and natural gas property rights by reporting its proportionate share of assets, liabilities, revenues, costs and cash flows within the relevant lines on the accompanying consolidated balance sheets, statements of operations and cash flow statements.

Segment Reporting: The Company operates in a single operating and reportable segment. Operating segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assessing performance. The Company’s chief operating decision maker allocates resources and assesses performance based upon financial information at the consolidated level.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates: The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.

The Company’s consolidated financial statements are based on a number of significant estimates including oil and natural gas reserve quantities that are the basis for the calculations of depreciation, depletion, and amortization (“DD&A”) and impairment of oil and natural gas properties. Reservoir engineering is a subjective

F-33

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

process of estimating underground accumulations of oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may differ from the quantities of oil and natural gas that are ultimately recovered. The Company’s reserve estimates are determined by an independent petroleum engineering firm. Other items subject to significant estimates and assumptions include the carrying amount of oil and natural gas properties, valuation of derivative instruments, and determination of the fair value of equity-based awards (see Note 11 for further discussion).

The Company evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. The volatility of commodity prices results in increased uncertainty inherent in such estimates and assumptions. A significant decline in natural gas prices or in oil prices could result in a reduction in the Company’s fair value estimates and cause the Company to perform analyses to determine if its oil and natural gas properties are impaired. As future commodity prices cannot be determined accurately, actual results could differ significantly from estimates. See Supplemental Oil and Gas Information (Unaudited).

Cash and Cash Equivalents: The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

Concentration of Credit Risk: Financial instruments that potentially subject the Company to credit risk consist principally of cash and cash equivalent balances, accounts receivable and derivative financial instruments. The Company maintains cash and cash equivalent balances with major financial institutions. At times, those balances exceed federally insured limits; however, no losses have been incurred. The Company attempts to limit the amount of credit exposure to any one company through procedures that include credit approvals, credit limits and terms, and prepayments. The Company’s customer base is made up of its lessees, which are primarily major integrated and international oil and natural gas companies and other operators, though the Company’s credit risk may extend to the eventual purchasers of oil and natural gas produced from the Company’s properties. The Company believes the credit quality of its customer base is high and has not experienced significant write-offs in its accounts receivable balances. See Note 9—Significant Customers for further discussion.

Accounts Receivable: The Company’s accounts receivable balance results primarily from operators’ sales of oil and natural gas to their customers. Accounts receivable is recorded at the contractual amounts and do not bear interest. Any concentration of customers may impact the Company’s overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions affecting the oil and natural gas industry.

Derivatives and Financial Instruments: The Company’s ongoing operations expose it to changes in the market price for oil and natural gas. To mitigate the given commodity price risk associated with its operations, the Company uses derivative instruments. From time to time, such instruments may include fixed-price contracts, variable to fixed price swaps, costless collars, and other contractual arrangements. However, we currently utilize only costless collars. The Company does not enter into derivative instruments for speculative purposes.

In accordance with Accounting Standard Codification (“ASC”) 815, Derivatives and Hedging, derivative instruments are initially recognized at fair value on the date on which a derivative contract is entered into and are subsequently remeasured at fair value. If a right of offset exists under master netting arrangements and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on the consolidated balance sheet. Gains and losses arising from changes in the fair value of derivatives are recognized on a net basis in the accompanying consolidated statements of operations within gain (loss) on commodity derivative instruments.

F-34

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Although these derivative instruments may expose the Company to credit risk, the Company monitors the creditworthiness of its counterparties.

Oil and Natural Gas Properties: The Company follows the successful efforts method of accounting for oil and natural gas operations. Under this method, costs to acquire interests in oil and natural gas properties are capitalized. The cost of property acquisitions, successful exploratory wells, development costs, and support equipment and facilities are capitalized when incurred. Other exploratory costs, including annual delay rentals and geological and geophysical costs, are charged to expense when incurred. Acquired mineral and royalty interests and working interests are recorded at cost at the time of acquisition.

The costs of unproved leaseholds and mineral interests are capitalized as unproved properties pending the results of exploration and leasing efforts. As unproved leaseholds are determined to be producing, the related costs are transferred to producing properties. The remaining net book values of unproved leaseholds associated with unsuccessful drilling activities or that have expired, are charged to exploration expense, which is included in lease operating expense and other in the consolidated statements of operations.

As exploration and development work progresses and the reserves on the Company’s properties are proven, capitalized costs attributed to the properties are charged as an operating expense through DD&A. DD&A of producing oil and natural gas properties is recorded based on units of production. Acquisition costs of proved properties are amortized on the basis of all proved reserves, developed and undeveloped, and capitalized development costs are amortized on the basis of proved developed reserves. DD&A expense related to the Company’s producing oil and natural gas properties was $102.4 million and $104.1 million for the years ended December 31, 2013 and 2012, respectively.

The Company evaluates impairment of producing properties whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. See Note 5 for further discussion of impairment of oil and natural gas properties.

The cost of properties sold, or otherwise disposed of, and the related accumulated depreciation is removed from the accounts and any gains or losses are reflected in current operations.

Other Property and Equipment: Other property and equipment includes furniture, fixtures, office equipment, leasehold improvements, and computer software and are stated at cost. Depreciation and amortization are calculated using the straight-line method over the expected useful lives ranging from three to seven years. Depreciation and amortization expense totaled $1.8 million and $1.7 million for the years ended December 31, 2013 and 2012, respectively.

Repairs and Maintenance: The cost of normal maintenance and repairs is charged to expense as incurred. Material expenditures that increase the life of an asset are capitalized and depreciated over the shorter of the estimated remaining useful life of the asset or the term of the lease.

Accrued Partners’ Distributions Payable: Accrued partners’ distributions payable consist of distributions due to the Company’s partners based on the partnership agreement that have not been paid out as of the respective balance sheet dates.

Debt Issue Costs: Debt issue costs consist of costs directly associated with obtaining credit with financial institutions. These costs have been capitalized and are generally amortized on a straight-line basis over the life of the credit agreement, which approximates the effective-interest method. Any unamortized debt issue costs are written off in the year when the associated debt instrument is terminated. Amortization expense for debt issue costs was $1.0 million and $0.7 million for the years ended December 31, 2013 and 2012, respectively, and is included in interest expense in the consolidated statements of operations.

F-35

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Asset Retirement Obligations: Fair values of legal obligations to retire and remove long-lived assets are recorded when the obligation is incurred. When the liability is initially recorded, the Company capitalizes this cost by increasing the carrying amount of the related property and equipment. Over time, the liability is increased for the change in its present value, and the capitalized cost in property and equipment is depreciated over the useful life of the related asset or group of assets.

Revenue Recognition: The Company recognizes revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller’s price to the buyer is fixed or determinable and (iv) collectability is reasonably assured.

The Company recognizes oil and natural gas revenue from its interests in producing wells when the associated production is sold. The volumes of natural gas sold may differ from the volumes to which the Company is entitled based on its interests in the properties. These differences create imbalances that are recognized as a liability only when the properties’ estimated remaining reserves net to the Company will not be sufficient to enable the under-produced owner to recoup its entitled share through production; however, such amounts are de minimis. Other sources of revenue received by the Company includes mineral lease bonuses and delay rentals. The Company generates lease bonus revenue from leasing its mineral interests to other exploration and production companies. The lease agreements transfer the rights to any oil or natural gas discovered, grant the Company a right to a specified royalty interest, and require that drilling be done within a specified time period. The Company recognizes such lease bonus revenue at which time the lease agreement has been executed, payment has been collected, and the Company has no further obligation to refund the payment. The Company also recognizes revenue from delay rentals to the extent drilling has not started within the specified period, payment has been collected, and the Company has no further obligation to refund the payment.

Income Taxes: The Company is organized as a pass-through entity for income tax purposes. As a result, the Company’s unitholders are responsible for federal and state income taxes on their share of the Company’s taxable income. The Company is subject to certain state-based taxes; however, those taxes are not material.

Limited partnerships that receive at least 90% of their gross income from designated passive sources, including royalties from mineral properties and other non-operated mineral interest income, and do not receive more than 10% of their income from operating an active trade or business, are generally exempt from the Texas margin tax as “passive entities”. The Company believes that it meets the requirements for being considered a “passive entity” for Texas margin tax purposes and, therefore, it is exempt from the Texas margin tax. As a result, each unitholder that is considered a taxable entity under the Texas margin tax would generally be required to include its portion of the Company’s revenues in its own Texas margin tax computation. The Texas Administrative Code provides such income is sourced according to the principal place of business of the Company, which would be the state of Texas.

Fair Value of Financial Instruments: The carrying values of the Company’s current financial instruments, which include cash and cash equivalents, accounts receivable, accounts payable, and accrued liabilities, approximate their fair value at December 31, 2013 and 2012 because of the short-term maturity of these instruments. For non-current financial instruments, the Company uses quoted market prices or, to the extent that there are no available quoted market prices, market prices for similar instruments. For credit facilities, since the interest rate is variable and aligns with market rates, the carrying value of debt approximates fair value. See Note 7 for further discussion on the fair value of the Company’s financial instruments.

Incentive Compensation: Incentive compensation includes both equity-based awards and liability awards. The Company recognizes compensation expense associated with its equity-based compensation awards granted on a straight-line basis over the requisite service period (generally the vesting period of the awards) based on their fair values on the dates of grant in general and administrative expense.

F-36

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Liability awards are awards that are expected to be settled in cash on their vesting dates. Liability awards are recorded as accrued liabilities based on the vested portion of the estimated fair value of the awards as of the grant date, which is subject to revision based on the impact of certain performance conditions associated with its incentive plans. The Company may also recognize liability awards as a result of repurchase options given to the recipients of certain incentive plans.

Subsequent Events: Subsequent events have been evaluated through the issuance date of these financial statements. Any material subsequent events that occurred prior to such date have been properly recognized or disclosed in the consolidated financial statements. See Note 18—Subsequent Events.

New Accounting Pronouncements: In April 2014, the Financial Accounting Standards Board (“FASB”) issued accounting standards updates to ASC 205, Presentation of Financial Statements, and to ASC 360, Property, Plant, and Equipment, to change the criteria for reporting discontinued operations. The amendments modify the definition of discontinued operations by limiting discontinued operations reporting to disposals of components of an entity that represent strategic shifts that have or will have a major effect on an entity’s operations and financial results. These amendments require additional disclosures about discontinued operations and new disclosures for other disposals of individually material components of an organization that do not meet the definition of a discontinued operation. In addition, the guidance allows companies to have significant continuing involvement and continuing cash flows with the discontinued operation. These provisions are effective for public companies prospectively for annual reporting periods beginning on or after December 15, 2014, and interim periods within those annual periods, with early adoption permitted. The adoption of this guidance, effective January 1, 2015, will not affect the Company’s consolidated financial position or results of operations; however, it may result in changes to the manner in which future dispositions of operations or assets, if any, are presented in the Company’s financial statements, or it may require additional disclosures.

In May 2014, the FASB issued an accounting standards update on a comprehensive new revenue recognition standard that will supersede the existing revenue recognition guidance. The new accounting guidance creates a framework under which an entity will allocate the transaction price to separate performance obligations and recognize revenue when each performance obligation is satisfied. Under the new standard, entities will be required to use judgment and make estimates, including identifying performance obligations in a contract, estimating the amount of variable consideration to include in the transaction price, allocating the transaction price to each separate performance obligation and determining when an entity satisfies its performance obligations. The standard allows for either “full retrospective” adoption, meaning that the standard is applied to all of the periods presented with a cumulative catch-up as of the earliest period presented, or “modified retrospective” adoption, meaning the standard is applied only to the most current period presented in the financial statements with a cumulative catch-up as of the current period. The accounting standard will be effective for reporting periods beginning after December 15, 2016 for public companies. The Company is in the process of evaluating the impact that the new accounting guidance will have on its consolidated financial position, results of operations, and cash flows.

F-37

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 3—ASSET RETIREMENT OBLIGATIONS

Asset retirement obligations (“AROs”) consist primarily of estimated costs of dismantlement, removal, site reclamation, and similar activities associated with oil and natural gas properties. Changes in AROs during the years presented are as follows:

	As of December 31,
	2013			2012
	(in thousands)
Beginning asset retirement obligations	$	5,242		$	4,466
Liabilities incurred		164			199
Liabilities settled		(33	)		(31	)
Accretion expense		588			608
Ending asset retirement obligations	$	5,961		$	5,242

NOTE 4—ACQUISITION

Acquisitions of producing oil and natural gas properties are recorded at their estimated fair value as of the acquisition date.

In 2004, the Company and third-party investors acquired an undivided interest in mineral fee estates and royalty interests related to producing and non-producing oil and natural gas properties formerly owned by Pure Partners, L.P. and Pure Resources, L.P. (“Pure”). As of January 1, 2012, the Company owned 80.7% of the undivided interest and third-party investors owned the remaining 19.3% of the undivided interest. Effective December 31, 2012 and January 1, 2013, the Company purchased the remaining ownership interest in the Pure oil and natural gas properties for $323.0 million, which consisted of $95.9 million of cash paid on December 31, 2012 and the issuance of $227.1 million of common units of BSMC on January 1, 2013.

The fair value of the assets acquired was determined based on discounted cash flows, including assumptions as to the estimated ultimate recovery of oil and natural gas reserves, expectations for timing of future development and operating costs, and risk adjusted discount rates. The following table summarizes the fair values assigned to the assets acquired as of the Pure acquisition dates:

	(in thousands)
Proved oil and natural gas properties	$	73,352
Unproved oil and natural gas properties		240,579
Net working capital		9,088
Total net assets acquired	$	323,019

Summarized below are the consolidated results of operations of the Company for the year ended December 31, 2012, on an unaudited pro forma basis, as if the entire Pure acquisition had occurred on January 1, 2012.

	Year Ended December 31, 2012
	Actual		Pro Forma
	(unaudited)
	(in thousands)
Revenue	$	435,146	$	458,842
Net income attributable to common units		91,725		113,792
Net income per common unit (basic and diluted)	$	0.08	$	0.08

F-38

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 5—IMPAIRMENT OF OIL AND NATURAL GAS PROPERTIES

The Company evaluates the impairment of its proved oil and natural gas properties on a field-by-field basis at least annually or whenever events or changes in circumstances indicate that the carrying amount may not be recoverable.

The Company compares the undiscounted projected future cash flows expected in connection with the field to the carrying amount to determine recoverability. When the carrying amount of a field exceeds its estimated undiscounted future cash flows, the carrying amount is written down to its fair value, which is measured as the present value of the projected future cash flows of such properties. The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing, future production, future capital expenditures, and a risk-adjusted discount rate.

Impairment of proved oil and natural gas properties was $57.1 million and $63.0 million for the years ended December 31, 2013 and 2012, respectively. The impairment primarily resulted from decreasing commodity prices in certain regions and changes in the projections based on the recent historical operating characteristics at the field level. The charges are included in impairment of oil and natural gas properties on the consolidated statements of operations.

The carrying value of unproved properties, including unleased mineral rights, is periodically assessed for impairment via comparison to management’s assessment of value. The factors used to determine fair value are similar to those noted previously for proved properties. No impairment associated with unproved properties has been recorded for the years ended December 31, 2013 and 2012.

F-39

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 6—DERIVATIVES AND FINANCIAL INSTRUMENTS

The Company’s ongoing operations expose it to changes in the market price for oil and natural gas. To mitigate the given commodity price risk associated with its operations, the Company uses 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, the Company currently utilizes only costless collars. The Company does not enter into derivative instruments for speculative purposes.

With a costless collar, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the exercise price of the purchased put. The Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the exercise price for the sold call of the collar. The settlement paid or received is the difference between the market price on the settlement date and the related exercise price. All derivative instruments are reflected as either assets or liabilities in the Company’s accompanying consolidated balance sheets as of December 31, 2013 and 2012, respectively (see Note 7 for further discussion of fair value). The table below summarizes the fair value (see note 5 for further discussion of fair value) and classification of the Company’s derivative instruments:

As of December 31, 2013 (in thousands)
Classification	Balance Sheet Location	Gross Fair Value		Effect of Counter-party Netting			Net Carrying Value on Balance Sheet
Assets:
Current asset	Commodity derivative asset	$	2,888	$	(2,850	)	$	38
Non-current asset	Deferred charges and other long-term assets		1,521		(1,504	)		17
Total assets		$	4,409	$	(4,354	)	$	55
Liabilities:
Current liability	Commodity derivative liability	$	4,402	$	(2,850	)	$	1,552
Non-current liability	Commodity derivative liability		1,819		(1,504	)		315
Total liabilities		$	6,221	$	(4,354	)	$	1,867

As of December 31, 2012 (in thousands)
Classification	Balance Sheet Location	Gross Fair Value		Effect of Counter-party Netting			Net Carrying Value on Balance Sheet
Assets:
Current asset	Commodity derivative asset	$	8,158	$	(2,946	)	$	5,212
Non-current asset	Deferred charges and other long-term assets		820		(494	)		326
Total assets		$	8,978	$	(3,440	)	$	5,538
Liabilities:
Current liability	Commodity derivative liability	$	2,946	$	(2,946	)	$	—
Non-current liability	Commodity derivative liability		494		(494	)		—
Total liabilities		$	3,440	$	(3,440	)	$	—

F-40

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Changes in the fair values of the Company’s derivative instruments (both assets and liabilities) are presented on a net basis in the accompanying consolidated statements of operations. The following table details the unrealized and realized gains (losses) recognized from the Company’s derivative instruments and where these components are recorded on the Company’s accompanying consolidated statements of operations for the years ended December 31, 2013 and 2012:

Derivatives not designated as hedging instruments under ASC 815	Location of Gain (Loss)	Classification of Gain(Loss)	Year Ended December 31,
			2013			2012
			(in thousands)
Oil commodity contracts	Gain (loss) on commodity derivative instruments	Realized	$	(505	)	$	(1,040	)
Natural gas commodity contracts	Gain (loss) on commodity derivative instruments	Realized		1,995			24,012
Total realized gains from derivatives not designated as hedges			$	1,490		$	22,972
Oil commodity contracts	Gain (loss) on commodity derivative instruments	Unrealized	$	(2,964	)	$	4,076
Natural gas commodity contracts	Gain (loss) on commodity derivative instruments	Unrealized		(4,386	)		(14,773	)
Total unrealized losses from derivatives not designated as hedges			$	(7,350	)	$	(10,697	)
Gain (loss) on commodity derivative instruments			$	(5,860	)	$	12,275

The Company had the following open derivative contracts for oil at December 31, 2013:

	Volume in bbl		Weighted Average		Range
Period and Type of Contract					Low		High
2014
Collar Contracts:
Call Options		1,457,000	$	102.25	$	96.25	$	114.15
Put Options		1,457,000	$	82.49	$	75.00	$	95.00
2015
Collar Contracts:
Call Options		249,000	$	100.38	$	99.05	$	101.25
Put Options		249,000	$	80.08	$	80.00	$	81.00

The Company had the following open derivative contracts for natural gas at December 31, 2013:

	Volume in MMBtu		Weighted Average		Range
Period and Type of Contract					Low		High
2014
Collar contracts:
Call Options		27,360,000	$	4.83	$	4.40	$	5.57
Put Options		27,360,000	$	3.59	$	3.30	$	4.25
2015
Collar contracts:
Call Options		5,860,000	$	4.95	$	4.60	$	5.05
Put Options		5,860,000	$	3.66	$	3.50	$	3.80

F-41

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 7—FAIR VALUE DISCLOSURE

ASC 820, Fair Value Measurement, defines fair value as the amount at which an asset (or liability) could be bought (or incurred) or sold (or settled) in a current transaction between willing parties other than in a forced or liquidation sale. Further, ASC 820 establishes a framework for measuring fair value, establishes a fair value hierarchy based on the quality of inputs used to measure fair value and includes certain disclosure requirements. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk.

ASC 820 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:

Level 1—Quoted prices (unadjusted) for identical assets or liabilities in active markets.

Level 2—Quoted prices for similar assets or liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

Level 3—Inputs that are unobservable and significant to the fair value measurement (including the Company’s own assumptions in determining fair value).

A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. There were no transfers into, or out of, the three levels of the fair value hierarchy for the years ended December 31, 2013 and 2012.

The Company estimated the fair value of derivative instruments using the market approach via a model that uses inputs that are observable in the market or can be derived from, or corroborated by, observable data. See Note 6 for further discussion on derivatives and financial instruments.

The following table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis:

	Level 1		Level 2		Level 3		Effect of Netting			Total
	(in thousands)
At December 31, 2013
Financial Assets
Commodity derivative instruments	$	—	$	4,409	$	—	$	(4,354	)	$	55
Financial Liabilities
Commodity derivative instruments		—		6,221		—		(4,354	)	$	1,867
At December 31, 2012
Financial Assets
Commodity derivative instruments	$	—	$	8,978	$	—	$	(3,440	)	$	5,538
Financial Liabilities
Commodity derivative instruments		—		3,440		—		(3,440	)	$	—

The determination of the fair values of proved and unproved properties acquired in purchase transactions are prepared by estimating discounted cash flow projections. The factors used to determine fair value include estimates of: (i) economic reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital.

F-42

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Oil and natural gas properties are measured at fair value on a nonrecurring basis using the income approach as described in Note 2. Proved and unproved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of those properties. Significant Level 3 assumptions used to determine fair value include estimates of proved reserves, future commodity prices, the timing and amount of future production and capital expenditures, and a discount rate commensurate with the risk associated with the respective oil and natural gas properties.

The Company’s estimates of fair value have been determined at discrete points in time based on relevant market data. These estimates involve uncertainty and cannot be determined with precision. There were no changes in valuation techniques or related inputs for the years ended December 31, 2013 and 2012.

The following table presents information about the Company’s assets measured at fair value on a non-recurring basis:

	Fair Value Measurements  Using (in thousands)						Net Book Value		Total Impairment Loss
	Level 1		Level 2		Level 3
Year Ended December 31, 2013
Impaired oil and natural gas properties	$	—	$	—	$	56,318	$	113,427	$	57,109
Year Ended December 31, 2012
Impaired oil and natural gas properties	$	—	$	—	$	49,307	$	112,294	$	62,987

NOTE 8—RELATED PARTY TRANSACTIONS

The Company executed a promissory note dated January 1, 2009 in the aggregate amount of $0.4 million to a member of the Board of Managers (the “Board”) of BSNR. The promissory note was secured by security interests in 451,951 common units in BSMC and 456,516 shares in BSNR. The promissory notes provided for (i) accrual of interest at a rate of 2.06% and (ii) a payment schedule of $0.1 million plus accrued interest on each of the following dates: April 15, 2010, April 15, 2011, and April 15, 2012. This promissory note was paid in full in April 2012.

The Company executed promissory notes dated April 15, 2010, in the amount of $0.5 million to officers of the Company. The promissory notes related to the acquisition of a partnership interest in Ivory Acquisitions Partners, L.P. by the officers and the notes were collateralized by a security interest in the Company. The promissory notes provided for quarterly payments of interest at a blended rate of 2.73% and 2.83% at December 31, 2013 and 2012, respectively, equal to the rate at which the Company paid interest on its borrowings. At December 31, 2013 and 2012, less than $0.1 million of interest receivable on the notes was included in prepaid expenses and other current assets on the consolidated balance sheets. At December 31, 2013 and 2012, the aggregated note balances were $0.1 million and $0.2 million, respectively, and were included in prepaid expenses and other current assets, respectively, on the consolidated balance sheets. These promissory notes were paid in full on the maturity date of April 15, 2014. See Note 18 for further discussion on subsequent events.

NOTE 9—SIGNIFICANT CUSTOMERS

The Company leases mineral interests to exploration and production companies and participates in non-operated working interests when economic conditions are favorable. One company represented 10.9% and 12.3% of total revenue for the years ended December 31, 2013 and 2012, respectively.

F-43

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

If the Company were to lose a significant customer, the loss could impact revenue derived from its mineral and royalty interests and working interests. The loss of any single lessee is mitigated by the Company’s diversified customer base.

NOTE 10—CREDIT FACILITIES

Senior Line of Credit

In September 2006, the Company entered into a credit agreement (“Senior Line of Credit”) with a syndicate of lenders. During the first quarter of 2012, the current Senior Line of Credit was executed to extend the term of the facility to February 3, 2017, at which time all unpaid principal and interest is due. On June 28, 2013, the terms of the Senior Line of Credit were amended to increase the maximum credit amount from the original $600.0 million to $1.0 billion. The borrowing base was $700.0 million and $340.0 million at December 31, 2013 and 2012, respectively. The borrowing base is based on the value of the Company’s oil and natural gas properties. Proceeds from the Senior Line of Credit are used for the acquisition of oil and natural gas properties and for other general business purposes.

Borrowings under the Senior Line of Credit bear interest at LIBOR plus a margin between 1.75% and 2.75%, or prime rate plus a margin between 0.75% and 1.75%, with the margin depending on the borrowing base utilization percentage of the loan. The prime rate is determined to be the higher of the financial institution’s prime rate or the federal funds effective rate plus one-half of 1% per annum. The weighted average interest rate of the Senior Line of Credit was 2.42% and 3.87% as of December 31, 2013 and 2012, respectively. Accrued interest is payable at the end of each calendar quarter or at the end of each interest period, unless the interest period is longer than 90 days in which case interest is payable at the end of every 90-day period. In addition, a commitment fee is payable at the end of each calendar quarter based on either a rate of 0.375%, if the borrowing base utilization percentage is less than 50%, or 0.50% per annum, if the borrowing base utilization percentage is equal to or greater than 50%. The Senior Line of Credit is secured by substantially all of the Company’s oil and natural gas production and assets and is guaranteed by certain operating subsidiaries.

The Senior Line of Credit contains various restrictions on future borrowings, leases and sales of assets. Additionally, the Senior Line of Credit requires the Company to maintain a current ratio of not less than 1.0 and a ratio of total debt to EBITDAX (Earnings before Interest, Taxes, Depreciation, Amortization, and Exploration) of not more than 3.5. At December 31, 2013, the Company was in compliance with all financial covenants in the Senior Line of Credit.

The aggregate principal balance outstanding was $451.0 million and $317.0 million at December 31, 2013 and 2012, respectively. The unused portion of the available borrowings under the Senior Line of Credit was $249.0 million and $23.0 million at December 31, 2013 and 2012, respectively.

Fund II-B Revolving Credit Facility

Black Stone Natural Resources II-B, L.P., a consolidated subsidiary of the Company, obtained a $50.0 million five-year revolving credit facility dated November 9, 2005, as amended, on November 3, 2010, (“Fund II-B Revolving Credit Facility”) with a financial institution as the administrative agent and the lender. The Fund II-B Revolving Credit Facility required a 0.5% annual commitment fee that is payable at the end of each calendar quarter. The outstanding balance was $19.1 million at December 31, 2012, with a weighted average interest rate of 3.0%.

The Company repaid the outstanding principal balance on March 28, 2013, and the Fund II-B Revolving Credit Facility was terminated on April 30, 2013.

F-44

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Fund III-B Revolving Credit Facility

Black Stone Natural Resources III-B, L.P., a consolidated subsidiary of the Company, obtained a $100.0 million revolving credit facility dated October 10, 2008 (“Fund III-B Revolving Credit Facility”), with a financial institution as the administrative agent and the lender. On December 27, 2012, the Fund III-B Revolving Credit Facility was amended and extended through November 30, 2017. The amendment includes a 0.5% annual commitment fee that is payable at the end of each calendar quarter. The outstanding balance was $27.0 million at December 31, 2012 with a weighted-average interest rate of 3.0%.

The Company repaid the outstanding principal balance and terminated the Fund III-B Revolving Credit Facility on May 15, 2013.

NOTE 11—INCENTIVE COMPENSATION

Overview and Valuation Assumptions

The Company has long-term incentive plans for its employees and the Board under which awards can be granted in the form of time-based restricted units and cash awards based on the Company’s historical performance. The plans provide that all awards are granted on January 1 of each year. There are no performance criteria or market criteria associated with any of the Company’s equity-based awards. The incentive awards vest based on a predetermined schedule as approved by the Board. Compensation expense is included in general and administrative expense on the consolidated statements of operations in the year earned. There is no limit to the number of equity awards that are authorized or issued under the plans. The total compensation expense related to the time-based restricted unit grants is measured as the number of units granted multiplied by the grant-date fair value per unit. Compensation expense is recognized on a straight-line basis over the service period (generally equivalent to the vesting period).

Determining the fair value of the Company is required under the Company’s limited partnership agreement for purposes of the Company purchasing common units from those limited partners who exercise their right under the limited partnership agreement to annually sell a portion of their common units. As the Company is privately held, determining the fair value requires the Company to make complex and subjective judgments. The Board determined the fair value of the equity-based awards’ unit price by considering various objective and subjective factors, along with input from management. To determine the fair value of the Company, the Company considers information provided by third-party consultants and relies on generally accepted valuation techniques, which include, but are not limited to, the net asset value method under the asset approach, the guideline public company method under the market approach, and the dividend discount method of the income approach. These methods are dependent upon various assumptions to develop the estimates in the Company’s operating results, commodity prices, and market-based discount rates. The Company also considers publicly available information on comparable public companies and the Company’s historical transactions and performance in making these estimates. There is inherent uncertainty in making these estimates. The Company utilizes the same valuation for issuances of equity, if any, and as the basis for calculating fair value of its equity awards under its long-term incentive plans.

Prior to December 31, 2013, one unit of the equity-based awards under all effective incentive plans consisted of 1 share of BSNR and 0.99 Class A common units of BSMC. On December 31, 2013, the Company simplified its corporate structure, and BSNR became a 100% owned subsidiary of BSMC. Accordingly, the underlying interest in one unit of the equity-based awards of the Company did not change as a result of the transaction. See Note 1 for further discussion of the business and basis of presentation.

F-45

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Employee Long-Term Incentive Plans

Effective January 1, 2006, the Company adopted an Employee Long-Term Incentive Plan, as amended, (“ELTI Plan”), in which employees other than management and senior management are entitled to earn cash bonuses based on the growth in the fair value of the Company in the preceding year (the “Incentive Year). The fair value of the Company is determined by the Board. The ELTI Plan has a service period of five years. Payments under the ELTI Plan are disbursed 25% per year over a four-year period on December 31 of each year following the incentive year.

Effective January 1, 2012, the Company adopted an amended version of its long-term incentive plan for employees (“New ELTI Plan”). Under the New ELTI Plan, employees are entitled to earn cash bonuses over a four-year service period. Payments under the New ELTI Plan are disbursed one-third per year over three years beginning on the first anniversary of the award date.

Management and Senior Management Long-Term Incentive Plans

Effective January 1, 2009, the Company adopted a Management Employee Long-Term Incentive Plan, as amended, (“MLTI Plan”), in which members of management other than senior management are eligible to earn cash bonuses based on the growth in the fair value of the Company in the Incentive Year. The fair value of the Company is determined by the Board. The participants may choose to receive up to 20% of their cash bonus in restricted common units in the Company at the end of the Incentive Year, under the condition that the Company has the right to repurchase these restricted common units. Election has to be made within 120 days after the last day of an Incentive Year. The number of restricted common units is determined based on the value of the cash bonus elected to be converted to the equity-based awards and the fair value of a common unit of the Company on the date of grant. The equity bonuses under the MLTI Plan vest on a graded schedule over a five year service period. Payments under the MLTI Plan are disbursed equally over a four-year period, with one-fourth payable every December 31 beginning on the first anniversary of the last day of an Incentive Year.

Effective January 1, 2009, the Company adopted a Senior Management Long-Term Incentive Plan, as amended, (“SMLTI Plan”), under which senior management is eligible to earn cash and equity bonuses based on the growth in fair value of the Company during the Incentive Year, the annual total returns during the three-year period preceding the award date, and a Board determined discretionary amount believed to approximate compensation offered to senior executives of comparable companies. Fifty percent of the bonus is immediately expensed upon a lump-sum cash payment, and the remaining fifty percent is made in restricted common units of the Company, that vest ratably over three years. Payments under the SMLTI Plan are disbursed on March 15 immediately following the Incentive Year for the portion of the award.

Effective January 1, 2012, the Company adopted a new long-term incentive plan that combines both its management and senior management long-term incentive plans (“New MLTI Plan”). Under the New MLTI Plan, half of the incentive compensation is payable in cash and determined based on achieving specific production and reserves targets as set by the Board. The remainder is determined based on continued employment with the Company. Cash award compensation under the New MLTI Plan cliff vests on the third anniversary of the award date, subject to satisfaction of the performance targets. For the awards granted in 2012, the Company made a modification to the vesting terms of the New MLTI Plan to conform the cash vesting schedule to the equity vesting schedule described below.

Equity compensation under the New MLTI Plan is paid in the form of restricted common units of BSMC. The restricted common units awarded are subject to restrictions on transferability, customary forfeiture provisions and time vesting provisions. One-third of each award vests on the first, second, and third anniversaries of the date of grant. Award recipients have all the rights of a unitholder in BSMC with respect to the restricted

F-46

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

common units vested, including the right to receive distributions thereon, if and when distributions are made by the BSMC to its limited partners. Award recipients may request that the Company, at its discretion, repurchase up to 50% of the restricted common units that are vested. As a result of the repurchase option, 50% of the equity awards to be vested on each vesting date are classified as a liability during the corresponding year prior to the vesting date until a request for the Company to repurchase is made by the recipient, or the repurchase option period ends, which is 30 days prior to the vesting date. The liability is measured periodically at fair value. At year-end, the balance of the liability equals the fair value of the equity awards that have been elected and approved for repurchase on the vesting date. At December 31, 2013, and 2012, the liability balances related to these equity-based awards were zero, and all vested awards were classified as equity. During the years ended December 31, 2013 and 2012, no election was made to settle the equity-based awards in cash, and the Company made no payment on the equity-based liabilities.

The aggregate fair value of the restricted common units awarded to the Company’s management and senior management during the years ended December 31, 2013 and 2012, was $7.4 million and $7.4 million, respectively.

Management and Senior Management Long-Term Incentive Plans	Common Units (in  millions)			Weighted- Average Grant Date Fair Value per Share(1)
Unvested at December 31, 2011		2.1		$	1.84
Granted(2)		4.6		$	1.61
Vested		(3.1	)	$	1.74
Unvested at December 31, 2012		3.6		$	1.65
Granted(3)		4.6		$	1.60
Vested		(3.1	)	$	1.62
Forfeited		(0.6	)	$	1.61
Unvested at December 31, 2013		4.5		$	1.61

(1) Determined by dividing the aggregate grant-date fair value of awards by the number of awards issued.

(2) The aggregate grant-date fair value of restricted common unit awards issued in 2012 was $7.4 million.

(3) The aggregate grant-date fair value of restricted common unit awards issued in 2013 was $7.4 million.

The unrecognized compensation cost associated with restricted common unit awards was $7.2 million and $6.0 million at December 31, 2013 and 2012, respectively, which the Company expects to recognize over a weighted-average period of 2.0 years and 1.7 years, respectively. During the year ended December 31, 2013, an executive of the Company resigned, resulting in the forfeiture of 0.6 million restricted common units. This resulted in the reversal of $0.5 million in equity-based compensation recognized in 2013 and reduced unearned compensation expense by $0.5 million as of December 31, 2013.

F-47

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Board of Managers Long-Term Incentive Plan

Effective January 1, 2009, the Company adopted a Board of Managers Incentive Plan, as amended, (“BMI Plan”), under which the Board is entitled to cash and restricted common unit bonuses for each year of service. The restricted common units awarded are subject to restrictions on transferability.

The aggregate fair value of the restricted common units awarded to the Board during the years ended December 31, 2013 and 2012 was $2.1 million and $1.9 million, respectively. The restricted common units granted are accounted for as equity-based awards. The grant-date fair value is recognized as compensation cost on a straight-line basis over the service period (generally equivalent to the vesting period).

Board of Managers Long-Term Incentive Plans	Common Units (in millions)			Weighted- Average Grant Date Fair Value per unit(1)
Unvested at December 31, 2011		1.2		$	1.72
Granted(2)		1.2		$	1.61
Vested		(1.2	)	$	1.71
Unvested at December 31, 2012		1.2		$	1.70
Granted(3)		1.3		$	1.60
Vested		(1.2	)	$	1.62
Unvested at December 31, 2013		1.3		$	1.60

(1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued.

(2) The aggregate grant date fair value of restricted common unit awards issued in 2012 was $1.9 million.

(3) The aggregate grant date fair value of restricted common unit awards issued in 2013 was $2.1 million.

There were no forfeitures during the years ended December 31, 2013 and 2012 in relation to the BMI Plan. The unrecognized compensation cost associated with restricted common unit awards was an aggregate $2.1 million and $2.0 million at December 31, 2013 and 2012, respectively, which the Company expects to recognize over a weighted-average period of 1.7 years.

The table below summarizes incentive compensation expenses recorded in general and administrative expenses in the consolidated statements of operations for the years ended December 31, 2013 and 2012, respectively.

	Year Ended December 31,
	2013		2012
	(in thousands)
Employee Long-term Incentive Plans, net of estimated forfeiture of $0.3 and $0.2, respectively	$	5,924	$	4,565
Cash—Management and Senior Management Long-term Incentive Plan, net of forfeiture of $1.0 and $0, respectively		4,281		5,307
Equity-based Compensation—Management and Senior Management Long-term Incentive Plan, net of estimated forfeiture of $0.3 and $0, respectively		4,754		5,251
Board of Managers Long-term Incentive Plans, net of estimated forfeiture of $0 and $0, respectively		2,028		1,997
Total compensation expense	$	16,987	$	17,120

F-48

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 12—EMPLOYEE BENEFIT PLANS

The Company sponsors a 401(k) Profit Sharing Plan (the “Plan”), a defined contribution plan, for the benefit of substantially all employees of the Company. The Plan became effective on January 1, 2001 and allows eligible employees to make tax-deferred contributions up to 100% of their annual compensation, not to exceed annual limits established by the Internal Revenue Service. The Company makes matching contributions of 100% of employee contributions, up to 5% of compensation. These matching contributions are subject to a graded vesting schedule, with 33% vested after one year, 66% vested after two years and 100% vested after the initial three years of employment with the Company. Following three years of employment, future Company matching contributions vest immediately. The Company’s contributions were $0.5 million for both the years ended December 31, 2013 and 2012.

NOTE 13—COMMITMENTS AND CONTINGENCIES

Leases

The Company leases certain office space and equipment under cancelable and non-cancelable operating leases. The Company recognizes rent expense on a straight-line basis over the lease term. Rent expense under such arrangements was $1.9 million and $1.6 million for the years ended December 31, 2013 and 2012, respectively. Such amounts are included in general and administrative expense on the consolidated statements of operations.

Future minimum lease commitments, in thousands, under non-cancelable leases are as follows:

Year Ending December 31,	(in thousands)
2014	$	1,294
2015		1,337
2016		1,319
2017		11
	$	3,961

Environmental Matters

The Company’s business includes activities that are subject to U.S. federal, state and local environmental regulations with regard to air, land, and water quality and other environmental matters.

The Company does not consider the estimated remediation costs that could result from any environmental site assessments to be significant to the consolidated balance sheet or statement of operations of the Company. No provision for potential remediation costs is reflected in the consolidated financial statements.

Litigation

From time to time, the Company is involved in legal actions and claims arising in the ordinary course of business. The Company believes these claims will be resolved without material adverse effect to the Company’s consolidated balance sheet, statement of operations or cash flows.

F-49

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 14—REDEEMABLE PREFERRED UNITS

As of December 31, 2013 and 2012, the Company has outstanding 157,424 Series A preferred units (the “Preferred Units”) for $161.4 million (which includes accrued and unpaid dividends of $4.0 million as of both December 31, 2013 and 2012). The Preferred Units are classified as mezzanine equity on the consolidated balance sheets since redemption is outside the control of the Company. The owners of Preferred Units are entitled to an annual dividend coupon of 10% for the funded capital of the Preferred Units payable on a quarterly basis in arrears. For each of the years ended December 31, 2013 and 2012, the Company paid dividends on preferred units of $15.7 million and $15.8 million, respectively.

The Preferred Units are convertible into common units at any time at the option of the preferred unitholders. The Preferred Units have an initial conversion price of $1.1020948 and an initial conversion rate of 907.36296 common units per Preferred Unit. In the event the preferred unitholders have not converted all of the Preferred Units by December 31, 2014, the owners of the Preferred Units can elect to have the Company redeem up to 25% per year of its Preferred Units at face value, plus any accrued and unpaid dividends, on December 31 of each year from 2014 to 2017. The Company shall have the right, at its sole option, to redeem an amount of Preferred Units equal to the units being redeemed by an owner of Preferred Units on each December 31. Any amount of a given year’s 25% of Preferred Units not redeemed on December 31 shall automatically convert to common units on January 1 of the following year. No Preferred Units were converted into common units during the years ended December 31, 2013 and 2012.

NOTE 15—EXCHANGE OFFER AND EQUITY OFFERING

During 2012, the Company presented a proposal to purchase the noncontrolling interests in certain subsidiaries in exchange for cash or common units of BSMC (the “Exchange Offer”). The Exchange Offer resulted in a majority of the noncontrolling investors electing to exchange their interests in the subsidiaries for cash or common units of BSMC, substantially all of which were Class B common units. The interests purchased totaled approximately $222.9 million in December 31, 2012. The consolidated balance sheets include $23.3 million of accrued noncontrolling interest repurchases as of December 31, 2012. The Company used borrowings under the Senior Line of Credit and proceeds from a concurrent $412.2 million common unit offering (“Equity Offering”), effective January 1, 2013, to fund the cash used to purchase the noncontrolling interests. Cash from the Equity Offering above the amounts needed for the Exchange Offer was used to repay a portion of the Senior Line of Credit and provide additional resources for future acquisitions. The Exchange Offer also consisted of the issuance of $1,017 million of Class B common units and $2 million of Class A common units.

Significant terms for the Class B common units include Board and committee representation, conversion rights to Class A common units upon the occurrence of certain events and registration rights. Other than Board and committee representation, the Class A common units and Class B common units contain the same rights and preferences. As a result, they are collectively referred to as the “common units”. Proceeds from the Equity Offering that were received prior to January 1, 2013, are classified as deferred partner contributions in the consolidated balance sheet at December 31, 2012.

NOTE 16—NONCONTROLLING INTERESTS

The Company has ownership interests in multiple partnerships that are consolidated in the Company’s financial statements. At the end of 2012 and the beginning of 2013, the Company purchased a majority of the interests held by the third-party partners with cash or equity of BSMC through the Exchange Offer and Equity Offering discussed in Note 15. Cash purchases of noncontrolling interests were effective on December 31, 2012, and equity exchanges or new issuances were effective as of January 1, 2013.

F-50

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On January 1, 2013, the Company dissolved Black Stone Natural Resources I, LP (“BSNR I”) and Black Stone Natural Resources Raptor, L.P. (“BSNR Raptor”) and distributed the underlying assets to unrelated third-party investors on a pro rata basis, which resulted in a distribution of property. In August 2013, BSMC purchased the remaining third-party investors’ interests in Black Stone Natural Resources II, L.P. (“BSNR II”) for $37.4 million. As a result of the transactions, the only remaining noncontrolling interest at December 31, 2013 was the 10.6% interest in O’Connell Partners, L.P., as discussed in Note 15.

As a result of the aforementioned transaction and the Exchange Offer described in Note 15 above, BSMC owns all of the limited partnership interests in its consolidated subsidiaries as of December 31, 2013, except for an 89.4% interest in O’Connell Partners, L.P., one of the subsidiaries consolidated by the Company.

The following table summarizes the effects of changes in the noncontrolling interest on the Company’s equity for the years ended December 31, 2013 and 2012:

	Year Ended December 31,
	2013			2012
	(in thousands)
Net income attributable to common units	$	152,848		$	91,725
Transfers from noncontrolling interests:
Increase in the Company’s ownership due to Exchange Offer (Note 15)		289,604			(118,587	)
Increase in the Company’s ownership due to purchase of BSNR II noncontrolling interests		(22,696	)		—
Net transfers (to) from noncontrolling interests		266,908			(118,587	)
Change from net income attributable to unitholders and transfers from noncontrolling interests	$	419,756		$	(26,862	)

NOTE 17—EARNINGS PER UNIT

Class A common units and Class B common units have been combined as a single class for purposes of basic and diluted earnings per unit (“EPU”) as they contain the same economic rights and preferences. The holders of the Company’s restricted common units have all the rights of a unitholder, including non-forfeitable distribution rights. As participating securities, the restricted common units are included in the calculation of basic earnings per unit using the two-class method. For the periods presented, the amount of earnings allocated to the participating restricted common units was not material. The redeemable Preferred Units can be converted into 142.8 million common units as of both December 31, 2013 and 2012. At December 31, 2013 and 2012, if the redeemable Preferred Units were converted to common units, their effect would be anti-dilutive; therefore, the redeemable Preferred Units are not included in the diluted EPU calculation.

F-51

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table sets forth the computation of basic and diluted earnings per unit (in thousands, except per unit amounts):

	Year Ended December 31,
	2013			2012
	(in thousands)
Net income	$	168,963		$	151,810
Less: Net income attributable to noncontrolling interests		(373	)		(44,343	)
Net income attributable to Black Stone Minerals Company, L.P.		168,590			107,467
Less: Dividends on preferred units		(15,742	)		(15,742	)
Net income available to common units	$	152,848		$	91,725
Weighted average units outstanding (basic and diluted)		2,144,599			1,212,885
Basic and diluted earnings per unit	$	0.07		$	0.08

NOTE 18—SUBSEQUENT EVENTS

On January 15, 2014, the Company paid distributions of approximately $0.6 million and $54.5 million to BSNR and the holders of BSMC common units, respectively, and approximately $4.0 million to the owners of the Preferred Units. These payments were netted with receivables from the partners of the Company and accrued in accrued partners’ distribution payable—related party on the consolidated balance sheet as of December 31, 2013. See Note 8 for further discussion of related party transactions.

On January 24, 2014, the Company purchased an undivided mineral interest in approximately 6,300 acres in McMullen County, Texas. The adjusted purchase price was approximately $11.9 million.

On March 12, 2014, the Company acquired producing properties and leasehold interests in San Augustine County, Texas, from Encana Corporation for $24.6 million. Additionally, as part of the transaction, the Company assumed Encana’s position in the Comanche prospect in Shackelford and Throckmorton Counties, Texas.

On April 14, 2014, the Company paid distributions of approximately $56.3 million to the holders of BSMC’s common units and approximately $3.9 million to the owners of the Preferred Units.

On July 15, 2014, the Company paid distributions of approximately $56.3 million to the holders of BSMC’s common units and approximately $3.9 million to the owners of the Preferred Units.

On July 17, 2014, the Company acquired producing properties and leasehold interests in Reagan and Upton Counties, Texas, for $12.5 million.

F-52

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Supplemental Oil and Gas Disclosures—UNAUDITED

Geographic Area of Operation

All of our proved reserves are located within the continental United States, with the majority concentrated in Kentucky, Louisiana, North Dakota, Oklahoma, Pennsylvania, Texas, West Virginia and Wyoming; however, the Company also owns mineral and royalty interests and non-operated working interests in various producing and non-producing oil and natural gas properties in several other areas throughout the United States. Therefore, the following disclosures about our costs incurred and proved reserves are on a total company basis.

Costs Incurred in Oil and Natural Gas Property Acquisitions, Exploration, and Development Activities

Costs incurred in oil and natural gas property acquisition, exploration and development, whether capitalized or expensed, are presented below:

	Year ended December 31,
	2013		2012
Acquisition Costs of Properties:(1)
Proved	$	77,580	$	23,501
Unproved		264,710		84,204
Exploration Costs		357		455
Development Costs		50,440		80,134
Total	$	393,087	$	188,294

(1) See Note 4 for details about the Company’s significant acquisitions.

Oil and Natural Gas Capitalized Costs

Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, and amortization are presented below:

	Year ended December 31,
	2013			2012
Proved properties	$	1,637,223		$	1,515,848
Unproved properties		640,291			369,071
Total		2,277,514			1,884,919
Accumulated depreciation, depletion and amortization		(965,371	)		(817,950	)
Net capitalized costs	$	1,312,143		$	1,066,969

F-53

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Oil and Gas Natural Reserve Information

The following sets forth estimated quantities of our net proved, proved developed and proved undeveloped oil and natural gas reserves. These reserve estimates exclude insignificant NGL quantities owned by the Company. Estimated reserves for the periods presented are based on the unweighted average of first-day-of-the-month commodity prices over the period January through December for the year in accordance with definitions and guidelines set forth by the SEC and the FASB.

	Crude Oil (Mbbl)			Natural Gas (Mmcf)			Total(8) (MBoe)
Net proved reserves at December 31, 2011		12,992			285,964			60,653
Revisions of previous estimates(1)		1,698			(14,000	)		(635	)
Purchases of minerals in place(2)		122			4,451			864
Extensions, discoveries and other additions(3)		2,172			50,350			10,563
Production		(2,173	)		(52,965	)		(11,001	)
Net proved reserves at December 31, 2012		14,811			273,800			60,444
Revisions of previous estimates(1)		1,616			(16,762	)		(1,177	)
Purchases of minerals in place(4)		883			5,472			1,795
Extensions, discoveries and other additions(5)		4,265			22,850			8,073
Production		(2,626	)		(45,400	)		(10,193	)
Net proved reserves at December 31, 2013		18,949			239,960			58,942
Net Proved Developed Reserves(6)
December 31, 2011		12,662			269,778			57,625
December 31, 2012		14,395			242,814			54,864
December 31, 2013		17,290			232,777			56,086
Net Proved Undeveloped Reserves(7)
December 31, 2011		330			16,186			3,028
December 31, 2012		416			30,986			5,580
December 31, 2013		1,659			7,183			2,856

(1) Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and other factors. The most notable technical revisions are related to well performance in certain Haynesville shale wells.

(2) Includes the acquisition of Pure mineral interests as part of the Exchange Offer and other mineral acreage located in Louisiana and Texas. See Note 4—Acquisitions and Note 15—Exchange Offer and Equity Offering for additional details.

(3) Include discoveries and additions primarily related to active drilling in the Haynesville, Bakken, Wilcox, Granite Wash, and Lance-Mesavede plays.

(4) Includes the acquisition of Pure mineral interests as part of the Exchange Offer and other mineral acreage located in the Eagle Ford Shale in Texas. Additionally, this line includes adjustments to reserves related to the distribution of the assets in Fund I and BSNR Raptor to unrelated third-party investors. See Note 4—Acquisitions, Note 15—Exchange Offer and Equity Offering and Note 16—Noncontrolling Interest for additional details.

(5) Includes discoveries and additions primarily related to active drilling in the Haynesville, Bakken, Wilcox, Granite Wash, and Fayetteville shale plays.

(6) Proved developed reserves of 119 MBoe, 19,534 MBoe, and 30,909 MBoe as of December 31, 2013, 2012, and 2011, respectively, were attributable to noncontrolling interests in our consolidated subsidiaries.

(7) As of December 31, 2013, no proved undeveloped reserves were attributable to noncontrolling interests. Proved undeveloped reserves of 2,398 MBoe and 1,605 MBoe as of December 31, 2012 and 2011, respectively, were attributable to noncontrolling interests in our consolidated subsidiaries.

F-54

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(8) The conversion to barrels of oil equivalent and cubic feet equivalent were determined using the energy-equivalent ratio of six Mcf of natural gas to one Bbl of crude oil (totals may not compute due to rounding). The energy-equivalent ratio does not assume price equivalency, and the energy-equivalent prices for oil and natural gas may differ significantly.

Standardized Measure of Discounted Future Net Cash Flows

Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the unweighted average of first-day-of-the-month commodity prices for the periods presented. All prices are adjusted by field for quality, transportation fees, energy content and regional price differentials. Future cash inflows are computed by applying applicable prices relating to the Company’s proved reserves to the year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions. There are no future income tax expenses because the Company is not subject to federal income taxes. The Company is subject to certain state based taxes; however, these amounts are not material. See Note 2 for additional information about income taxes.

	Year ended December 31,
	2013			2012
	(In thousands)
Future cash inflows	$	2,693,511		$	2,138,461
Future production costs		(393,347	)		(329,646	)
Future development costs		(53,160	)		(55,089	)
Future net cash flows (undiscounted)		2,247,004			1,753,726
Annual discount 10% for estimated timing		(1,061,747	)		(825,209	)
Total(1)	$	1,185,257		$	928,517

(1) Includes standardized measure of discounted future net cash flows of approximately $1.4 million and $271.1 million as of December 31, 2013 and 2012, respectively, are attributable to noncontrolling interests in our consolidated subsidiaries.

The following summarizes the principal sources of change in the standardized measure of discounted future net cash flows:

	For the years ended December 31,
	2013			2012
	(In thousands)
Standardized measure, beginning of year	$	928,518		$	1,071,848
Sales, net of production costs		(373,655	)		(312,201	)
Net changes in prices and production costs related to future production		208,291			(82,200	)
Extensions, discoveries and improved recovery, net of future production and development costs		223,482			138,841
Previously estimated development costs incurred during the period		22,456			17,702
Revisions of estimated future development costs		1,620			(3,399	)
Revisions of previous quantity estimates, net of related costs		(22,687	)		(10,881	)
Accretion of discount		92,852			107,185
Purchases of reserves in place, less related costs		62,887			12,418
Other		41,493			(10,796	)
Standardized measure, end of year	$	1,185,257		$	928,517

F-55

BLACK STONE MINERALS COMPANY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.

F-56

Appendix A

FORM OF FIRST AMENDED AND RESTATED

AGREEMENT OF LIMITED PARTNERSHIP

OF

BLACK STONE MINERALS, L.P.

A-i

TABLE OF CONTENTS

		Page
ARTICLE I DEFINITIONS
Section 1.1	Definitions		A-1
Section 1.2	Construction		A-12
ARTICLE II ORGANIZATION
Section 2.1	Formation		A-12
Section 2.2	Name		A-12
Section 2.3	Registered Office; Registered Agent; Principal Office; Other Offices		A-13
Section 2.4	Purpose and Business		A-13
Section 2.5	Powers		A-13
Section 2.6	Term		A-13
Section 2.7	Title to Partnership Assets		A-13
Section 2.8	Power of Attorney		A-14
ARTICLE III RIGHTS OF LIMITED PARTNERS
Section 3.1	Limitation of Liability		A-15
Section 3.2	Management of Business		A-15
Section 3.3	Outside Activities of the Limited Partners		A-15
Section 3.4	Rights of Limited Partners		A-15
ARTICLE IV
CERTIFICATES; RECORD HOLDERS; TRANSFER OF PARTNERSHIP INTERESTS; REDEMPTION OF PARTNERSHIP INTERESTS
Section 4.1	Certificates		A-16
Section 4.2	Mutilated, Destroyed, Lost or Stolen Certificates		A-16
Section 4.3	Record Holders		A-17
Section 4.4	Transfer Generally		A-17
Section 4.5	Registration and Transfer of Limited Partner Interests		A-18
Section 4.6	Transfer of the General Partner Interest		A-18
Section 4.7	Restrictions on Transfers		A-19
Section 4.8	Eligibility Certificates; Ineligible Holders		A-19
Section 4.9	Redemption of Partnership Interests of Ineligible Holders		A-20
ARTICLE V
CAPITAL CONTRIBUTIONS AND ISSUANCE OF PARTNERSHIP INTERESTS
Section 5.1	Contributions by the General Partner and its Affiliates		A-21
Section 5.2	Contributions by Underwriters		A-21
Section 5.3	Interest and Withdrawal		A-22
Section 5.4	Capital Accounts		A-22
Section 5.5	Issuances of Additional Partnership Interests and Derivative Instruments		A-24

A-ii

		Page
Section 5.6	Splits and Combinations		A-25
Section 5.7	Fully Paid and Non-Assessable Nature of Limited Partner Interests		A-25
Section 5.8	Deemed Capital Contributions by Partners		A-25
ARTICLE VI
ALLOCATIONS AND DISTRIBUTIONS
Section 6.1	Allocations for Capital Account Purposes		A-26
Section 6.2	Allocations for Tax Purposes		A-29
Section 6.3	Distributions to Record Holders		A-30
ARTICLE VII
MANAGEMENT AND OPERATION OF BUSINESS
Section 7.1	Management		A-31
Section 7.2	Replacement of Fiduciary Duties		A-33
Section 7.3	Certificate of Limited Partnership		A-33
Section 7.4	Restrictions on the General Partner’s Authority		A-34
Section 7.5	Reimbursement of the General Partner		A-34
Section 7.6	Outside Activities		A-34
Section 7.7	Indemnification		A-35
Section 7.8	Limitation of Liability of Indemnitees		A-37
Section 7.9	Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties		A-37
Section 7.10	Other Matters Concerning Standards of Conduct		A-38
Section 7.11	Purchase or Sale of Partnership Interests		A-39
Section 7.12	Reliance by Third Parties		A-39
ARTICLE VIII
BOOKS, RECORDS, ACCOUNTING AND REPORTS
Section 8.1	Records and Accounting		A-39
Section 8.2	Fiscal Year		A-40
Section 8.3	Reports		A-40
ARTICLE IX
TAX MATTERS
Section 9.1	Tax Returns and Information		A-40
Section 9.2	Tax Elections		A-40
Section 9.3	Tax Controversies		A-41
Section 9.4	Withholding		A-41
ARTICLE X
ADMISSION OF PARTNERS
Section 10.1	Admission of Limited Partners		A-41
Section 10.2	Admission of Successor General Partner		A-42
Section 10.3	Amendment of Agreement and Certificate of Limited Partnership		A-42

A-iii

		Page
ARTICLE XI
WITHDRAWAL OF PARTNERS
Section 11.1	Withdrawal of the General Partner		A-42
Section 11.2	Interest of Departing General Partner and Successor General Partner		A-43
Section 11.3	Withdrawal of Limited Partners		A-43
ARTICLE XII
DISSOLUTION AND LIQUIDATION
Section 12.1	Dissolution		A-43
Section 12.2	Continuation of the Business of the Partnership After Dissolution		A-44
Section 12.3	Liquidator		A-44
Section 12.4	Liquidation		A-45
Section 12.5	Cancellation of Certificate of Limited Partnership		A-45
Section 12.6	Return of Contributions		A-45
Section 12.7	Waiver of Partition		A-45
Section 12.8	Capital Account Restoration		A-45
ARTICLE XIII
AMENDMENT OF PARTNERSHIP AGREEMENT; MEETINGS; RECORD DATE
Section 13.1	Amendments to be Adopted Solely by the General Partner		A-46
Section 13.2	Amendment Procedures		A-47
Section 13.3	Amendment Requirements		A-47
Section 13.4	Amendments to Organizational Documents of General Partner and Other Subsidiaries		A-48
Section 13.5	Special Meetings; Annual Meetings; Election of Directors		A-48
Section 13.6	Notice of a Meeting		A-52
Section 13.7	Record Date		A-52
Section 13.8	Adjournment		A-52
Section 13.9	Waiver of Notice; Approval of Meeting; Approval of Minutes		A-53
Section 13.10	Quorum and Voting		A-53
Section 13.11	Conduct of a Meeting		A-53
Section 13.12	Action Without a Meeting		A-54
Section 13.13	Right to Vote and Related Matters		A-54
ARTICLE XIV
MERGER
Section 14.1	Authority		A-55
Section 14.2	Procedure for Merger, Consolidation or Conversion		A-55
Section 14.3	Approval by Partners of Merger or Consolidation		A-56
Section 14.4	Certificate of Merger or Conversion		A-57
Section 14.5	Amendment of Partnership Agreement		A-57
Section 14.6	Effect of Merger or Consolidation		A-57

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		Page
ARTICLE XV
GENERAL PROVISIONS
Section 15.1	Addresses and Notices; Written Communications		A-58
Section 15.2	Further Action		A-58
Section 15.3	Binding Effect		A-58
Section 15.4	Integration		A-58
Section 15.5	Creditors		A-58
Section 15.6	Waiver		A-58
Section 15.7	Counterparts		A-59
Section 15.8	Applicable Law; Forum, Venue and Jurisdiction; Waiver of Trial by Jury; Attorney Fees		A-59
Section 15.9	Invalidity of Provisions		A-59
Section 15.10	Consent of Partners		A-60
Section 15.11	Facsimile and Email Signatures		A-60
Section 15.12	Third Party Beneficiaries		A-60
Exhibit A			A-1

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FORM OF FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED

PARTNERSHIP OF BLACK STONE MINERALS, L.P.

THIS FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF BLACK STONE MINERALS, L.P., dated as of                 , 2015 and is effective immediately prior to the Effective Time, is entered into by and among BLACK STONE MINERALS GP, L.L.C., a Delaware limited liability company, as the General Partner, and the Initial Limited Partners together with any other Persons who become Partners in the Partnership or parties hereto as provided herein. In consideration of the covenants, conditions and agreements contained herein, the parties hereto hereby agree as follows:

ARTICLE I

DEFINITIONS

Section 1.1 Definitions. The following definitions shall be for all purposes, unless otherwise clearly indicated to the contrary, applied to the terms used in this Agreement.

“Adjusted Capital Account” means, with respect to any Partner, the balance in such Partner’s Capital Account at the end of each taxable period of the Partnership, after giving effect to the following adjustments:

(a) Credit to such Capital Account any amounts which such Partner is (x) obligated to restore under the standards set by Treasury Regulation Section 1.704-1(b)(2)(ii)(c) or (y) deemed obligated to restore pursuant to the penultimate sentences of Treasury Regulation Sections 1.704-2(g)(1) and 1.704-2(i)(5); and

(b) Debit to such Capital Account the items described in Treasury Regulation Sections 1.704-1(b)(2)(ii)(d)(4), 1.704-1(b)(2)(ii)(d)(5) and 1.704-1(b)(2)(ii)(d)(6).

The foregoing definition of Adjusted Capital Account is intended to comply with the provisions of Treasury Regulation Section 1.704-1(b)(2)(ii)(d) and shall be interpreted consistently therewith. The “Adjusted Capital Account” of a Partner in respect of any Partnership Interest shall be the amount that such Adjusted Capital Account would be if such Partnership Interest were the only interest in the Partnership held by such Partner from and after the date on which such Partnership Interest was first issued.

“Adjusted Property” means any property the Carrying Value of which has been adjusted pursuant to Sections 5.4(d)(i) or 5.4(d)(ii).

“Affiliate” means, with respect to any Person, any other Person that directly or indirectly through one or more intermediaries Controls, is Controlled by or is under common Control with, the Person in question.

“Agreed Allocation” means any allocation, other than a Required Allocation, of an item of income, gain, loss or deduction pursuant to the provisions of Section 6.1, including a Curative Allocation (if appropriate to the context in which the term “Agreed Allocation” is used).

“Agreed Value” of (a) a Contributed Property means the fair market value of such property at the time of contribution and (b) an Adjusted Property means the fair market value of such Adjusted Property on the date of the Revaluation Event as described in Section 5.4(d), in each case as determined by the General Partner.

“Agreement” means this First Amended and Restated Agreement of Limited Partnership of the Partnership including the Exhibits and Annexes hereto, as it may be amended, supplemented or restated from time to time.

“Associate” means, when used to indicate a relationship with any Person, (a) any other Person of which such Person is a director, officer, manager, general partner or managing member or is, directly or indirectly, the owner of 20% or more of any class of voting stock or other voting interest; (b) any trust or other estate in which such Person has at least a 20% beneficial interest or as to which such Person serves as trustee or in a similar fiduciary capacity; and (c) any relative or spouse of such Person, or any relative of such spouse, who has the same principal residence as such Person.

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“Bad Faith” means, with respect to any determination, action or omission, of any Person, board or committee, that such Person, board or committee reached such determination, or engaged in or failed to engage in such act or omission, with the belief that such determination, action or omission was adverse to the interest of the Partnership.

“Board of Directors” means the board of directors of the General Partner.

“Book-Tax Disparity” means with respect to any item of Contributed Property or Adjusted Property, as of the date of any determination, the difference between the Carrying Value of such Contributed Property or Adjusted Property and the adjusted basis thereof for U.S. federal income tax purposes as of such date. A Partner’s share of the Partnership’s Book-Tax Disparities in all of its Contributed Property and Adjusted Property will be reflected by the difference between such Partner’s Capital Account balance as maintained pursuant to Section 5.4 and the hypothetical balance of such Partner’s Capital Account computed as if it had been maintained strictly in accordance with U.S. federal income tax accounting principles.

“Business Day” means Monday through Friday of each week, except that a legal holiday recognized as such by the government of the United States of America or the State of Texas shall not be regarded as a Business Day.

“Capital Account” means the capital account maintained for a Partner pursuant to Section 5.4. The “Capital Account” of a Partner in respect of any Partnership Interest shall be the amount that such Capital Account would be if such Partnership Interest were the only interest in the Partnership held by such Partner from and after the date on which such Partnership Interest was first issued.

“Capital Contribution” means any cash, cash equivalents or the Net Agreed Value of a Contributed Property that a Partner contributes to the Partnership or that is contributed to the Partnership on behalf of a Partner (including, in the case of an underwritten offering of Units, the amount of any underwriting discounts or commissions).

“Carrying Value” means (a) with respect to a Contributed Property or an Adjusted Property, the Agreed Value of such property reduced (but not below zero) by all depreciation, Simulated Depletion, amortization and other cost recovery deductions charged to the Partners’ Capital Accounts in respect of such property, and (b) with respect to any other Partnership property, the adjusted basis of such property for U.S. federal income tax purposes, all as of the time of determination and as determined by the General Partner. In the case of any oil and gas property (as defined in Section 614 of the Code), adjusted basis shall be determined pursuant to Treasury Regulation Section 1.613A–3(e)(3)(iii)(C). The Carrying Value of any property shall be adjusted from time to time in accordance with Section 5.4(d) and to reflect changes, additions or other adjustments to the Carrying Value for dispositions and acquisitions of Partnership properties, as deemed appropriate by the General Partner.

“Cause” means a court of competent jurisdiction has entered a final, non-appealable judgment finding the General Partner liable to the Partnership or any Limited Partner for actual fraud or willful misconduct in its capacity as a general partner of the Partnership.

“Certificate” means a certificate in such form (including in global form if permitted by applicable rules and regulations) as may be adopted by the General Partner, issued by the Partnership evidencing ownership of one or more Partnership Interests or Derivative Instruments.

“Certificate of Limited Partnership” means the Certificate of Limited Partnership of the Partnership filed with the Secretary of State of the State of Delaware as referenced in Section 7.3, as such Certificate of Limited Partnership may be amended, supplemented or restated from time to time.

“Citizenship Eligibility Trigger” has the meaning assigned to such term in Section 4.8(a)(ii).

“Closing Date” means the first date on which Common Units are issued and delivered by the Partnership to the Underwriters pursuant to the provisions of the Underwriting Agreement in connection with the Initial Offering.

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“Closing Price” means, in respect of any class of Limited Partner Interests, as of the date of determination, the last sale price on such day, regular way, or in case no such sale takes place on such day, the average of the closing bid and asked prices on such day, regular way, in either case as reported in the principal consolidated transaction reporting system with respect to securities listed or admitted to trading on the principal National Securities Exchange on which such Limited Partner Interests are listed or admitted to trading or, if such Limited Partner Interests are not listed or admitted to trading on any National Securities Exchange, the last quoted price on such day or, if not so quoted, the average of the high bid and low asked prices on such day in the over-the-counter market, as reported by the primary reporting system then in use in relation to such Limited Partner Interests of such class, or, if on any such day such Limited Partner Interests of such class are not quoted by any such organization, the average of the closing bid and asked prices on such day as furnished by a professional market maker making a market in such Limited Partner Interests of such class selected by the General Partner, or if on any such day no market maker is making a market in such Limited Partner Interests of such class, the fair value of such Limited Partner Interests on such day as determined by the General Partner.

“Code” means the U.S. Internal Revenue Code of 1986, as amended and in effect from time to time. Any reference herein to a specific section or sections of the Code shall be deemed to include a reference to any corresponding provision of any successor law.

“Commission” means the United States Securities and Exchange Commission.

“Common Unit” means an interest in the Partnership having the rights and obligations specified with respect to Common Units in this Agreement.

“Conflicts Committee” means a committee of the Board of Directors composed entirely of one or more directors, each of whom is determined by the Board of Directors, after reasonable inquiry, (a) to not be an officer or employee of the General Partner (b) to not be an officer or employee of any Affiliate of the General Partner, or a director of any Affiliate of the General Partner (other than any Group Member), (c) to not be a holder of any ownership interest in the General Partner or any of its Affiliates, including any Group Member, that would be likely to have an adverse impact on the ability of such director to act in an independent manner with respect to the matter submitted to the Conflicts Committee, other than Common Units and awards that are granted to such director under the Long-Term Incentive Plan, and (d) to be independent under the independence standards for directors who serve on an audit committee of a board of directors established by the Securities Exchange Act and the rules and regulations of the Commission thereunder and by the National Securities Exchange on which any class of Partnership Interests is listed or admitted to trading.

“Contributed Property” means each property, in such form as may be permitted by the Delaware Act, but excluding cash, contributed to the Partnership. Once the Carrying Value of a Contributed Property is adjusted pursuant to Section 5.4(d), such property shall no longer constitute a Contributed Property, but shall be deemed an Adjusted Property.

“Control” or “control” (including the terms “controlled” and “controlling”) means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise.

“Cumulative Majority” means with respect to the removal of a Director by any group of Unitholders, that number of votes determined by the following formula:

(	1	1	)	× B + 1
		A + 1

A = The aggregate number of Directors; and

B = The number of votes of the Units then Outstanding that would be entitled to vote for the election of such Director, measured on a Fully Diluted Basis.

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“Curative Allocation” means any allocation of an item of income, gain, deduction, loss or credit pursuant to the provisions of Section 6.1(b)(x).

“Current Market Price” means, in respect of any class of Partnership Interests, as of the date of determination, the average of the daily Closing Prices per Partnership Interest of such class for the 20 consecutive Trading Days immediately prior to such date.

“Delaware Act” means the Delaware Revised Uniform Limited Partnership Act, 6 Del C. Section 17-101, et seq., as amended, supplemented or restated from time to time, and any successor to such statute.

“Departing General Partner” means a former General Partner from and after the effective date of any withdrawal of such former General Partner pursuant to Section 11.1.

“Derivative Instruments” means options, rights, warrants, appreciation rights, tracking, profit and phantom interests and other derivative instruments (other than equity interests in the Partnership) relating to, convertible into or exchangeable for Partnership Interests.

“Designated Persons” has the meaning given in Section 7.9(a).

“Director” means a member of the Board of Directors.

“Economic Risk of Loss” has the meaning set forth in Treasury Regulation Section 1.752-2(a).

“Effective Time” means effective time of the merger of the Organizational Limited Partner into Merger Sub pursuant to the Merger and Contribution Agreement.

“Eligibility Certificate” has the meaning assigned to such term in Section 4.8(b).

“Eligibility Certification” means a properly completed certificate in such form as may be specified by the General Partner by which a Partner certifies that he (and if he is a nominee holding for the account of another Person, that to the best of his knowledge such other Person) is an Eligible Holder.

“Eligible Holder” means a Person that satisfies the eligibility requirements established by the General Partner for Partners pursuant to Section 4.8.

“Event Issue Value” means, with respect to any Common Unit as of any date of determination, (a) in the case of a Revaluation Event that includes the issuance of Common Units pursuant to a public offering and solely for cash, the price paid for such Common Units, or (b) in the case of any other Revaluation Event, the Closing Price of the Common Units on the date of such Revaluation Event or, if the General Partner determines that a value for the Common Unit other than such Closing Price more accurately reflects the Event Issue Value, the value determined by the General Partner.

“Event of Withdrawal” has the meaning assigned to such term in Section 11.1(a).

“Fully Diluted Basis” means, with respect to the Partnership Interests at any time of determination, the number of Common Units that would be issued and outstanding at such time, assuming that all options, rights, warrants or other convertible or derivative securities or instruments or other rights to acquire Common Units have been exercised or converted, as applicable, in full, regardless of whether any such options, rights, warrants, convertible or derivative securities or instruments or other rights are then vested or exercisable or convertible in accordance with their terms; provided, however, that for purposes of determining the “Fully Diluted Basis” of the Partnership Interests at any time, any redeemable Partnership Interests that are also by their terms convertible

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into or exchangeable for any Partnership Interests shall be treated as being (1) converted if, as of the relevant date, the current value of the Partnership Interests into or for which such redeemable Partnership Interests are convertible or exchangeable is greater than the value of the consideration for which such Partnership Interests may be redeemed or (2) redeemed if the condition in clause (1) is not met.

“Fully Diluted Percentage Interest” means, with respect to any Partner or other holder of Partnership Interests, as of any date, the number of Common Units held by such Partner or other holder (determined on a Fully Diluted Basis) divided by the total number of Common Units that are then Outstanding on a Fully Diluted Basis.

“General Partner” means Black Stone Minerals GP, L.L.C., a Delaware limited liability company, and its successors and permitted assigns that are admitted to the Partnership as the general partner of the Partnership, in their capacity as the general partner of the Partnership.

“General Partner Interest” means the management interest of the General Partner in the Partnership (in its capacity as general partner and without reference to any Limited Partner Interest held by it), which includes any and all rights, powers and benefits to which the General Partner is entitled as provided in this Agreement, together with all obligations of the General Partner to comply with the terms and provisions of this Agreement. The General Partner Interest does not include any rights to profits or losses or any rights to receive distributions from operations or upon the liquidation or winding-up of the Partnership.

“Good Faith” means, with respect to any determination, action or omission, of any Person, board or committee, that such determination, action or omission was not taken in Bad Faith.

“GP Available Cash” means all cash and cash equivalents on hand derived from or attributable to the Partnership’s ownership of, or sale or other disposition of, the membership interests of the General Partner.

“GP Items” means the income, gains, losses, deductions and credits which are attributable to the Partnership’s ownership of, or sale or other disposition of, the membership interests of the General Partner.

“Gross Liability Value” means, with respect to any Liability of the Partnership described in Treasury Regulation Section 1.752-7(b)(3)(i), the amount of cash that a willing assignor would pay to a willing assignee to assume such Liability in an arm’s-length transaction.

“Group” means two or more Persons that with or through any of their respective Affiliates or Associates have any contract, arrangement, understanding or relationship for the purpose of acquiring, holding, voting (except voting pursuant to a revocable proxy or consent given to such Person in response to a proxy or consent solicitation made to 10 or more Persons), exercising investment power or disposing of any Partnership Interests with any other Person that beneficially owns, or whose Affiliates or Associates beneficially own, directly or indirectly, Partnership Interests.

“Group Member” means a member of the Partnership Group.

“Group Member Agreement” means the partnership agreement of any Group Member, other than the Partnership, that is a limited or general partnership, the limited liability company agreement of any Group Member that is a limited liability company, the certificate of incorporation and bylaws or similar organizational documents of any Group Member that is a corporation, the joint venture agreement or similar governing document of any Group Member that is a joint venture and the governing or organizational or similar documents of any other Group Member that is a Person other than a limited or general partnership, limited liability company, corporation or joint venture, as such may be amended, supplemented or restated from time to time.

“Indemnitee” means (a) any General Partner, (b) any Departing General Partner, (c) any Person who is or was an Affiliate of the General Partner or any Departing General Partner, (d) any Person who is or was a

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manager, managing member, general partner, director, officer, employee, agent, fiduciary or trustee of any Group Member, a General Partner, any Departing General Partner or any of their respective Affiliates, (e) any Director, and any Person who is or was serving at the request of a General Partner, any Departing General Partner or any of their respective Affiliates as an officer, director, manager, managing member, general partner, employee, agent, fiduciary or trustee of another Person owing a fiduciary or similar duty to any Group Member; provided that a Person shall not be an Indemnitee by reason of providing, on a fee-for-services basis, trustee, fiduciary or custodial services, (f) any Person (other than the Partnership) who controls a General Partner or Departing General Partner and (g) any Person the General Partner designates as an “Indemnitee” for purposes of this Agreement because such Person’s service, status or relationship exposes such Person to potential claims, demands, actions, suits or proceedings relating to the Partnership Group’s business and affairs.

“Ineligible Holder” has the meaning assigned to such term in Section 4.8(c).

“Initial Limited Partners” means the limited partners of the Partnership prior to the Initial Offering.

“Initial Offering” means the initial offering and sale of Common Units to the public, as described in the Registration Statement, including any offer and sale of Common Units pursuant to an exercise of the Over-Allotment Option.

“Liability” means any liability or obligation of any nature, whether accrued, contingent or otherwise.

“Limited Partner” means, unless the context otherwise requires, the Initial Limited Partners, the General Partner (in its capacity as a limited partner) and each additional Person that becomes a Limited Partner pursuant to the terms of this Agreement and any Departing General Partner upon the change of its status from General Partner to Limited Partner pursuant to Section 11.2, in each case in such Person’s capacity as a limited partner of the Partnership; provided, however, that when the term “Limited Partner” is used herein in the context of any vote or other approval, including without limitation Articles XIII and XIV, such term shall not, solely for such purpose, include any Units owned by the General Partner except as may otherwise be required by any non-waivable provision of law.

“Limited Partner Interest” means the ownership interest of a Limited Partner in the Partnership, which may be evidenced by Common Units, Preferred Units, or other Partnership Interests or a combination thereof or interest therein (but excluding Derivative Instruments), and includes any and all benefits to which such Limited Partner is entitled as provided in this Agreement, together with all obligations of such Limited Partner hereunder; provided, however, that when the term “Limited Partner Interest” is used herein in the context of any vote or other approval, including without limitation Articles XIII and XIV, such term shall not, solely for such purpose, include any Units owned by the General Partner except as may otherwise be required by any non-waivable provision of law.

“Liquidation Date” means (a) in the case of an event giving rise to the dissolution of the Partnership of the type described in clauses (a) and (b) of the first sentence of Section 12.2, the date on which the applicable time period during which the Partners have the right to elect to continue the business of the Partnership has expired without such an election being made, and (b) in the case of any other event giving rise to the dissolution of the Partnership, the date on which such event occurs.

“Liquidator” means one or more Persons selected by the General Partner to perform the functions described in Section 12.4 as liquidating trustee of the Partnership within the meaning of the Delaware Act.

“Long-Term Incentive Plan” means the Black Stone Minerals, L.P. Long-Term Incentive Plan, as it may be amended, restated or modified from time to time, or any equity compensation plan successor thereto.

“Merger Agreement” has the meaning assigned to such term in Section 14.1.

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“Merger and Contribution Agreement” means that certain Merger and Contribution Agreement, dated as of                     , 2015, among the Organizational Limited Partner, the Partnership and the other parties thereto, together with the additional conveyance documents and instruments contemplated or referenced thereunder.

“Merger Sub” means Black Stone Minerals Merger Sub LLC, a Delaware limited liability company and a wholly owned subsidiary of the Partnership.

“National Securities Exchange” means an exchange registered with the Commission under Section 6(a) of the Securities Exchange Act (or any successor to such Section) and any other securities exchange (whether or not registered with the Commission under Section 6(a) of the Securities Exchange Act (or successor to such Section)) that the General Partner shall designate as a National Securities Exchange for purposes of this Agreement.

“Net Agreed Value” means, (a) in the case of any Contributed Property, the Agreed Value of such property reduced by any Liabilities either assumed by the Partnership upon such contribution or to which such property is subject when contributed and (b) in the case of any property distributed to a Partner by the Partnership, the Partnership’s Carrying Value of such property (as adjusted pursuant to Section 5.4(d)(ii)) at the time such property is distributed, reduced by any Liabilities either assumed by such Partner upon such distribution or to which such property is subject at the time of distribution.

“Net Income” means, for any taxable period, the excess, if any, of the Partnership’s items of income and gain for such taxable period over the Partnership’s items of loss and deduction for such taxable period. The items included in the calculation of Net Income shall be determined in accordance with Section 5.4(b) and shall include Simulated Gain (as provided in Section 6.1(c)(iii)), but shall not include Simulated Depletion, Simulated Loss, or items specially allocated under Section 6.1(b).

“Net Loss” means, for any taxable period, the excess, if any, of the Partnership’s items of loss and deduction for such taxable period over the Partnership’s items of income and gain for such taxable period. The items included in the calculation of Net Loss shall be determined in accordance with Section 5.4(b) and shall include Simulated Gain (as provided in Section 6.1(c)(iii)), but shall not include Simulated Depletion, Simulated Loss, or any items specially allocated under Section 6.1(b).

“Nominating Limited Partner Group” has the meaning given in Section 13.5(b)(vii).

“Nomination Notice” has the meaning given in Section 13.5(b)(vii).

“Nomination Period” has the meaning given in Section 13.5(b)(vii).

“Noncompensatory Option” has the meaning set forth in Treasury Regulation Section 1.721-2(f).

“Nonrecourse Built-in Gain” means with respect to any Contributed Properties or Adjusted Properties that are subject to a mortgage or pledge securing a Nonrecourse Liability, the amount of any taxable gain that would be allocated to the Partners pursuant to Section 6.2(c) if such properties were disposed of in a taxable transaction in full satisfaction of such liabilities and for no other consideration.

“Nonrecourse Deductions” means any and all items of loss, deduction or expenditure (including any expenditure described in Section 705(a)(2)(B) of the Code), Simulated Depletion or Simulated Loss that, in accordance with the principles of Treasury Regulation Section 1.704-2(b), are attributable to a Nonrecourse Liability.

“Nonrecourse Liability” has the meaning set forth in Treasury Regulation Section 1.752-1(a)(2).

“Opinion of Counsel” means a written opinion of counsel (who may be regular counsel to the Partnership or the General Partner or any of its Affiliates) acceptable to the General Partner.

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“Option Closing Date” means the date or dates on which any Common Units are sold by the Partnership to the Underwriters upon exercise of the Over-Allotment Option.

“Organizational Limited Partner” means Black Stone Minerals Company, LP, in its capacity as the organizational limited partner of the Partnership pursuant to this Agreement.

“Organizational LP Partnership Agreement” has the meaning given in Section 15.9(a).

“Original Director” means a Person who is a Director on the date of the Initial Offering.

“Original General Partner” means Black Stone Natural Resources, L.L.C.

“Outstanding” means, with respect to Partnership Interests, all Partnership Interests that are issued by the Partnership and reflected as outstanding on the Partnership’s books and records as of the date of determination; provided, however, that if at any time any Person or Group beneficially owns 15% or more of the Partnership Interests of any class, none of the Partnership Interests owned by such Person or Group shall be entitled to be voted on any matter or be considered to be Outstanding when sending notices of a meeting of Limited Partners to vote on any matter (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under this Agreement (such Partnership Interests shall not, however, be treated as a separate class of Partnership Interests for purposes of this Agreement or the Delaware Act); provided, further, that the foregoing limitation shall not apply to (i) Partnership Interests owned by an Initial Limited Partner who, as of the date of the Initial Offering, owned 15% or more of the Partnership Interests, (ii) any Person or Group who acquired 15% or more of the Partnership Interests that were owned by an Initial Limited Partner as of the date of the Initial Offering; provided that the Board of Directors shall have notified such Person or Group in writing that such limitation shall not apply, or (iii) any Person or Group who acquired 15% or more of any Partnership Interests issued by the Partnership provided that the Board of Directors shall have notified such Person or Group in writing that such limitation shall not apply; provided, further, however that Restricted Common Units shall not be treated as Outstanding for purposes of Section 6.1.

“Over-Allotment Option” means the over-allotment option granted to the Underwriters by the Partnership pursuant to the Underwriting Agreement.

“Partner Nonrecourse Debt” has the meaning given to such term in Treasury Regulation Section 1.704-2(b)(4).

“Partner Nonrecourse Debt Minimum Gain” has the meaning given to such term in Treasury Regulation Section 1.704-2(i)(2).

“Partner Nonrecourse Deductions” means any and all items of loss, deduction or expenditure (including any expenditure described in Section 705(a)(2)(B) of the Code), Simulated Depletion or Simulated Loss that, in accordance with the principles of Treasury Regulation Section 1.704-2(i)(1), are attributable to a Partner Nonrecourse Debt.

“Partners” means the General Partner and the Limited Partners.

“Partnership” means Black Stone Minerals, L.P., a Delaware limited partnership.

“Partnership Group” means the Partnership and its Subsidiaries.

“Partnership Interest” means any class or series of equity interest (or, in the case of the General Partner, management interest) in the Partnership, which shall include any General Partner Interest and Limited Partner Interests but shall exclude Derivative Instruments.

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“Partnership Minimum Gain” means that amount determined in accordance with the principles of Treasury Regulation Sections 1.704-2(b)(2) and 1.704-2(d).

“Percentage Interest” means as of any date of determination, as to any Unitholder with respect to Units, the quotient obtained by dividing (i) the number of Units held by such Unitholder by (ii) the total number of Outstanding Units. The Percentage Interest with respect to the General Partner Interest shall at all times be zero.

“Person” means an individual or a corporation, firm, limited liability company, partnership, joint venture, trust, unincorporated organization, association, government agency or political subdivision thereof or other entity.

“Preferred Unit” means a Partnership Interest, designated as a “Preferred Unit,” which entitles the holder thereof to a preference with respect to the payment of liquidating or nonliquidating distributions over Common Units.

“Privately Placed Units” means any Partnership Interests issued for cash or property other than pursuant to a public offering.

“Pro Rata” means when used with respect to (a) Units or any class thereof, apportioned equally among all designated Units in accordance with their relative Percentage Interests, (b) all Partners or Record Holders, apportioned among all Partners or Record Holders in accordance with their relative Percentage Interests, and (c) some but not all Partners or Record Holders, apportioned among such Partners or Record Holders in accordance with their relative Percentage Interests.

“Qualified Nominee” means an individual who has an educational background and business experience that, taken together, are reasonably commensurate with, or more extensive than, the educational background and business experience of any of the then-current Directors.

“Quarter” means, unless the context requires otherwise, a fiscal quarter of the Partnership, or, with respect to the fiscal quarter of the Partnership in which the Closing Date occurs, the portion of such fiscal quarter after the Closing Date.

“Rate Eligibility Trigger” has the meaning assigned to such term in Section 4.8(a)(i).

“Recapture Income” means any gain recognized by the Partnership (computed without regard to any adjustment required by Section 734 or Section 743 of the Code) upon the disposition of any property or asset of the Partnership, which gain is characterized as ordinary income because it represents the recapture of deductions previously taken with respect to such property or asset.

“Record Date” means the date established by the General Partner or otherwise in accordance with this Agreement for determining (a) the identity of the Record Holders entitled to notice of, or to vote at, any meeting of Limited Partners or entitled to vote by ballot or give approval of Partnership action in writing without a meeting or entitled to exercise rights in respect of any lawful action of Limited Partners or (b) the identity of Record Holders entitled to receive any report or distribution or to participate in any offer.

“Record Holder” means (a) with respect to Partnership Interests of any class for which a Transfer Agent has been appointed, the Person in whose name a Partnership Interest of such class is registered on the books of the Transfer Agent as of the opening of business on a particular Business Day, or (b) with respect to other classes of Partnership Interests, the Person in whose name any such other Partnership Interest is registered on the books that the General Partner has caused to be kept as of the opening of business on such Business Day.

“Redeemable Interests” means any Partnership Interests for which a redemption notice has been given, and has not been withdrawn, pursuant to Section 4.9.

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“Registration Statement” means the Registration Statement on Form S-1 (File No. 333-                    ) as it has been or as it may be amended or supplemented from time to time, filed by the Partnership with the Commission under the Securities Act to register the offering and sale of the Common Units in the Initial Offering, including any related registration statement filed pursuant to Rule 462(b) under the Securities Act.

“Required Allocations” means any allocation of an item of income, gain, loss and deduction pursuant to Sections 6.1(b)(i), 6.1(b)(ii), 6.1(b)(iii), 6.1(b)(iv), 6.1(b)(v), 6.1(b)(vi) or 6.1(b)(viii), or Section 6.1(c).

“Required Provision” has the meaning assigned to such term in Section 15.9(b).

“Restricted Common Unit” means a Common Unit (i) that was granted to the holder thereof in connection with such holder’s performance of services for the Partnership or its Affiliates, (ii) that remains subject to a “substantial risk of forfeiture” within the meaning of Section 83 of the Code and (iii) with respect to which no election was made pursuant to Section 83(b) of the Code. As set forth in the final proviso in the definition of “Outstanding,” Restricted Common Units are not treated as Outstanding for purposes of Section 6.1. Upon the lapse of the “substantial risk of forfeiture” with respect to a Restricted Common Unit, for U.S. federal income tax purposes such Common Unit will be treated as having been newly issued in consideration for the performance of services and will thereafter be considered to be Outstanding for purposes of Section 6.1.

“Revaluation Event” means an event that results in an adjustment of the Carrying Value of each Partnership property pursuant to Section 5.4(d).

“Securities Act” means the Securities Act of 1933, as amended, supplemented or restated from time to time and any successor to such statute.

“Securities Exchange Act” means the Securities Exchange Act of 1934, as amended, supplemented or restated from time to time and any successor to such statute.

“Simulated Basis” means the Carrying Value of any oil and gas property (as defined in Section 614 of the Code).

“Simulated Depletion” means, with respect to an oil and gas property (as defined in Section 614 of the Code), a depletion allowance computed in accordance with federal income tax principles set forth in Treasury Regulation Section 1.611-2(a)(1) (as if the Simulated Basis of the property was its adjusted tax basis) and in the manner specified in Treasury Regulation Section 1.704-1(b)(2)(iv)(k)(2), applying the cost depletion method. For purposes of computing Simulated Depletion with respect to any oil and gas property (as defined in Section 614 of the Code), the Simulated Basis of such property shall be deemed to be the Carrying Value of such property, and in no event shall such allowance for Simulated Depletion, in the aggregate, exceed such Simulated Basis. If the Carrying Value of an oil and gas property is adjusted pursuant to Section 5.4(d) during a taxable period, following such adjustment Simulated Depletion shall thereafter be calculated under the foregoing provisions based upon such adjusted Carrying Value.

“Simulated Gain” means the excess, if any, of the amount realized from the sale or other disposition of an oil or gas property (as defined in Section 614 of the Code) over the Carrying Value of such property and determined pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(k)(2).

“Simulated Loss” means the excess, if any, of the Carrying Value of an oil or gas property (as defined in Section 614 of the Code) over the amount realized from the sale or other disposition of such property and determined pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(k)(2).

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“Special Approval” means approval by a majority of the members of the Conflicts Committee, whether in the form of approval or approval and recommendation to the Board of Directors.

“Subsidiary” means, with respect to any Person, (a) a corporation of which more than 50% of the voting power of shares entitled (without regard to the occurrence of any contingency) to vote in the election of directors or other governing body of such corporation is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person or a combination thereof, (b) a partnership (whether general or limited) in which such Person or a Subsidiary of such Person is, at the date of determination, a general partner of such partnership, but only if such Person, directly or by one or more Subsidiaries of such Person, or a combination thereof, controls such partnership at the date of determination or (c) any other Person in which such Person, one or more Subsidiaries of such Person, or a combination thereof, directly or indirectly, at the date of determination, has (i) a majority ownership interest or (ii) the power to elect or direct the election of a majority of the directors or other governing body of such Person.

“Supermajority Vote of the Board of Directors” means the affirmative vote of not less than seventy-five percent (75%) of all Directors.

“Supermajority Vote of the Unitholders” means the affirmative vote of holders of a two-thirds majority of the Outstanding Common Units.

“Supplemental Terms Annex” has the meaning assigned to such term in Section 5.5(b).

“Surviving Business Entity” has the meaning assigned to such term in Section 14.2(b)(ii).

“Trading Day” means a day on which the principal National Securities Exchange on which the referenced Partnership Interests of any class are listed or admitted to trading is open for the transaction of business or, if such Partnership Interests are not listed or admitted to trading on any National Securities Exchange, a day on which banking institutions in New York City generally are open.

“transfer” has the meaning assigned to such term in Section 4.4(a).

“Transfer Agent” means such bank, trust company or other Person (including the General Partner or one of its Affiliates) as may be appointed from time to time by the Partnership to act as registrar and transfer agent for any class of Partnership Interests; provided that if no Transfer Agent is specifically designated for any class of Partnership Interests, the General Partner shall act in such capacity.

“Treasury Regulation” means the United States Treasury regulations promulgated under the Code.

“Underwriter” means each Person named as an underwriter in the Underwriting Agreement who purchases Common Units pursuant thereto.

“Underwriting Agreement” means that certain Underwriting Agreement dated                     , 2015, by and among the representatives of the Underwriters, the Partnership, the General Partner and the other parties thereto, providing for the purchase of Common Units by the Underwriters.

“Unit” means a Partnership Interest that is designated as a “Unit” and shall include Common Units; provided, however, that when the term “Units” is used herein in the context of any vote or other approval, including without limitation Articles XIII and XIV, such term shall not, solely for such purpose, include any Unit owned by the General Partner except as may otherwise be required by any non-waivable provision of law.

“Unit Majority” means a majority of the Outstanding Units.

“Unitholders” means the holders of Units.

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“Unrealized Gain” attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the fair market value of such property as of such date (as determined under Section 5.4(d)) over (b) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.4(d) as of such date).

“Unrealized Loss” attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.4(d) as of such date) over (b) the fair market value of such property as of such date (as determined under Section 5.4(d)).

“Unrestricted Person” means each Indemnitee, each Partner and each Person who is or was a member, partner, director, officer, employee or agent of any Group Member, the General Partner or any Departing General Partner or any Affiliate of any Group Member, the General Partner or any Departing General Partner and any Person the General Partner designates as an “Unrestricted Person” for purposes of this Agreement but excluding in each case, (a) current Directors who are also employees of the Partnership, the General Partner or any of their respective Controlled Affiliates and (b) any Affiliates of such Directors.

“U.S. GAAP” means United States generally accepted accounting principles, as in effect from time to time, consistently applied.

Section 1.2 Construction. Unless the context requires otherwise: (a) any pronoun used in this Agreement shall include the corresponding masculine, feminine or neuter forms; (b) references to Articles and Sections refer to Articles and Sections of this Agreement; (c) the terms “include”, “includes”, “including” and words of like import shall be deemed to be followed by the words “without limitation”; (d) the terms “hereof”, “herein” and “hereunder” refer to this Agreement as a whole and not to any particular provision of this Agreement and (e) the exhibits and annexes attached to this Agreement constitute a part of this Agreement and are incorporated herein for all purposes. The table of contents and headings contained in this Agreement are for reference purposes only, and shall not affect in any way the meaning or interpretation of this Agreement. The General Partner has the power to construe and interpret this Agreement and to act upon any such construction or interpretation. Any construction or interpretation of this Agreement by the General Partner and any action taken pursuant thereto and any determination made by the General Partner in good faith shall, in each case, be conclusive and binding on all Record Holders and all other Persons for all purposes.

ARTICLE II

ORGANIZATION

Section 2.1 Formation. The Partnership was formed as a limited partnership pursuant to the provisions of the Delaware Act. The parties hereto hereby amend and restate the original Agreement of Limited Partnership of the Partnership (as heretofore amended) in its entirety. This amendment and restatement shall become effective immediately prior to the Effective Time on the date of this Agreement. Except as expressly provided to the contrary in this Agreement, the rights, duties (including fiduciary duties), liabilities and obligations of the Partners and the administration, dissolution and termination of the Partnership shall be governed by the Delaware Act.

Section 2.2 Name. The name of the Partnership shall be “Black Stone Minerals, L.P.” The Partnership’s business may be conducted under any other name or names as determined by the General Partner, including the name of the General Partner. The words “Limited Partnership,” the letters “LP,” or “Ltd.” or similar words or letters shall be included in the Partnership’s name where necessary for the purpose of complying with the laws of any jurisdiction that so requires. The General Partner may change the name of the Partnership at any time and from time to time and shall notify the Partners of such change in the next regular communication to the Partners.

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Section 2.3 Registered Office; Registered Agent; Principal Office; Other Offices. Unless and until changed by the General Partner, the registered office of the Partnership in the State of Delaware shall be located at 1209 Orange Street, Wilmington, Delaware 19801, and the registered agent for service of process on the Partnership in the State of Delaware at such registered office shall be Corporation Trust Company. The principal office of the Partnership shall be located at 1001 Fannin Street, Suite 2100, Houston, Texas 77002 or such other place as the General Partner may from time to time designate by notice to the Partners. The Partnership may maintain offices at such other place or places within or outside the State of Delaware as the General Partner determines to be necessary or appropriate. The address of the General Partner shall be 1001 Fannin Street, Suite 2100, Houston, Texas 77002 or such other place as the General Partner may from time to time designate by notice to the Partners.

Section 2.4 Purpose and Business. The purpose and nature of the business to be conducted by the Partnership shall be to (a) engage directly in, or enter into or form, hold and dispose of any corporation, partnership, joint venture, limited liability company or other arrangement to engage indirectly in, any business activity that is approved by the General Partner, in its sole discretion, and that lawfully may be conducted by a limited partnership organized pursuant to the Delaware Act and, in connection therewith, to exercise all of the rights and powers conferred upon the Partnership pursuant to the agreements relating to such business activity, and (b) do anything necessary or appropriate to the foregoing, including the making of capital contributions or loans to a Group Member; provided, however, that the General Partner shall not cause the Partnership to engage, directly or indirectly, in any business activity that the General Partner determines would be reasonably likely to cause the Partnership to be treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes. To the fullest extent permitted by law, the General Partner shall have no duty or obligation to propose or approve, and may, in its sole discretion, decline to propose or approve, the conduct by the Partnership Group of any business.

Section 2.5 Powers. The Partnership shall be empowered to do any and all acts and things necessary, appropriate, proper, advisable, incidental to or convenient for the furtherance and accomplishment of the purposes and business described in Section 2.4 and for the protection and benefit of the Partnership.

Section 2.6 Term. The term of the Partnership commenced upon the filing of the Certificate of Limited Partnership in accordance with the Delaware Act and shall continue in existence until the dissolution of the Partnership in accordance with the provisions of Article XII. The existence of the Partnership as a separate legal entity shall continue until the cancellation of the Certificate of Limited Partnership as provided in the Delaware Act.

Section 2.7 Title to Partnership Assets. Title to Partnership assets, whether real, personal or mixed and whether tangible or intangible, shall be deemed to be owned by the Partnership as an entity, and no Partner, individually or collectively, shall have any ownership interest in such Partnership assets or any portion thereof. Title to any or all of the Partnership assets may be held in the name of the Partnership, the General Partner, one or more of its Affiliates or one or more nominees, as the General Partner may determine. The General Partner hereby declares and warrants that any Partnership assets for which record title is held in the name of the General Partner or one or more of its Affiliates or one or more nominees shall be held by the General Partner or such Affiliate or nominee for the use and benefit of the Partnership in accordance with the provisions of this Agreement; provided, however, that the General Partner shall use reasonable efforts to cause record title to such assets (other than those assets in respect of which the General Partner determines that the expense and difficulty of conveyancing makes transfer of record title to the Partnership impracticable) to be vested in the Partnership or one or more of the Partnership’s designated Affiliates as soon as reasonably practicable; provided, further, that, prior to the withdrawal of the General Partner or as soon thereafter as practicable, the General Partner shall use reasonable efforts to effect the transfer of record title to the Partnership and, prior to any such transfer, will provide for the use of such assets in a manner satisfactory to the General Partner. All Partnership assets shall be recorded as the property of the Partnership in its books and records, irrespective of the name in which record title to such Partnership assets is held.

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Section 2.8 Power of Attorney.

(a) Each Limited Partner and each Assignee hereby constitutes and appoints the General Partner and, if a Liquidator shall have been selected pursuant to Section 12.3, the Liquidator (and any successor to the Liquidator by merger, transfer, assignment, election or otherwise) and each of their authorized officers and attorneys-in-fact, as the case may be, with full power of substitution, as his true and lawful agent and attorney-in-fact, with full power and authority in his name, place and stead, to:

(i) execute, swear to, acknowledge, deliver, file and record in the appropriate public offices (A) all certificates, documents and other instruments (including this Agreement and the Certificate of Limited Partnership and all amendments or restatements hereof or thereof) that the General Partner or the Liquidator determines to be necessary or appropriate to form, qualify or continue the existence or qualification of the Partnership as a limited partnership (or a partnership in which the limited partners have limited liability) in the State of Delaware and in all other jurisdictions in which the Partnership may conduct business or own property; (B) all certificates, documents and other instruments that the General Partner or the Liquidator determines to be necessary or appropriate to reflect, in accordance with its terms, any amendment, change, modification or restatement of this Agreement; (C) all certificates, documents and other instruments (including conveyances and a certificate of cancellation) that the General Partner or the Liquidator determines to be necessary or appropriate to reflect the dissolution and liquidation of the Partnership pursuant to the terms of this Agreement; (D) all certificates, documents and other instruments relating to the admission, withdrawal, removal or substitution of any Partner pursuant to, or other events described in, Article IV, X, XI, or XII; (E) all certificates, documents and other instruments relating to the determination of the rights, preferences and privileges of any class or series of Partnership Interests issued pursuant to Section 5.5; and (F) all certificates, documents and other instruments (including agreements and a certificate of merger) relating to a merger, consolidation or conversion of the Partnership pursuant to Section 5.1(b) or Article XIV; and

(ii) execute, swear to, acknowledge, deliver, file and record all ballots, consents, approvals, waivers, certificates, documents and other instruments that the General Partner or the Liquidator determines to be necessary or appropriate to (A) make, evidence, give, confirm or ratify any vote, consent, approval, agreement or other action that is made or given by the Partners hereunder or is consistent with the terms of this Agreement or (B) effectuate the terms or intent of this Agreement; provided, that when required by Section 13.3 or any other provision of this Agreement that establishes a percentage of the Limited Partners or of the Limited Partners of any class or series required to take any action, the General Partner and the Liquidator may exercise the power of attorney made in this Section 2.8(a)(ii) only after the necessary vote, consent or approval of the Limited Partners or of the Limited Partners of such class or series, as applicable.

Nothing contained in this Section 2.8(a) shall be construed as authorizing the General Partner to amend this Agreement except in accordance with Article XIII or as may be otherwise expressly provided for in this Agreement.

(b) The foregoing power of attorney is hereby declared to be irrevocable and a power coupled with an interest, and it shall survive and, to the maximum extent permitted by law, not be affected by the subsequent death, incompetency, disability, incapacity, dissolution, bankruptcy or termination of any Limited Partner or Assignee and the transfer of all or any portion of such Limited Partner’s or Assignee’s Partnership Interest and shall extend to such Limited Partner’s or Assignee’s heirs, successors, assigns and personal representatives. Each such Limited Partner or Assignee hereby agrees to be bound by any representation made by the General Partner or the Liquidator acting in Good Faith pursuant to such power of attorney; and each such Limited Partner or Assignee, to the maximum extent permitted by law, hereby waives any and all defenses that may be available to contest, negate or disaffirm the action of the General Partner or the Liquidator taken in Good Faith under such power of attorney. Each Limited Partner or Assignee shall execute and deliver to the General Partner or the Liquidator, within 15 days after receipt of the request therefor, such further designation, powers of attorney and other instruments as the General Partner or the Liquidator may request in order to effectuate this Agreement and the purposes of the Partnership.

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ARTICLE III

RIGHTS OF LIMITED PARTNERS

Section 3.1 Limitation of Liability. The Limited Partners shall have no liability under this Agreement except as expressly provided in this Agreement or the Delaware Act.

Section 3.2 Management of Business. No Limited Partner, in its capacity as such, shall participate in the operation, management or control (within the meaning of the Delaware Act) of the Partnership’s business, transact any business in the Partnership’s name or have the power to sign documents for or otherwise bind the Partnership. No action taken by any Affiliate of the General Partner or any officer, director, employee, manager, member, general partner, agent or trustee of the General Partner or any of its Affiliates, or any officer, director, employee, manager, member, general partner, agent or trustee of a Group Member, in its capacity as such, shall be considered participating in the control of the business of the Partnership by a limited partner of the Partnership (within the meaning of Section 17-303(a) of the Delaware Act) nor shall any such action affect, impair or eliminate the limitations on the liability of the Limited Partners under this Agreement.

Section 3.3 Outside Activities of the Limited Partners. Subject to the provisions of Section 7.6, which shall continue to be applicable to the Persons referred to therein, regardless of whether such Persons shall also be Limited Partners, each Limited Partner shall be entitled to and may have business interests and engage in business activities in addition to those relating to the Partnership, including business interests and activities in direct competition with the Partnership Group. Neither the Partnership nor any of the other Partners shall have any rights by virtue of this Agreement in any business ventures of any Limited Partner.

Section 3.4 Rights of Limited Partners.

(a) Each Limited Partner shall have the right, for a purpose that is reasonably related, as determined by the General Partner, to such Limited Partner’s interest as a Limited Partner in the Partnership, upon reasonable written demand stating the purpose of such demand and at such Limited Partner’s own expense to obtain:

(i) true and full information regarding the status of the business and financial condition of the Partnership (provided that the requirements of this Section 3.4(a)(i) shall be satisfied to the extent the Limited Partner is furnished the Partnership’s most recent annual report and any subsequent quarterly or periodic reports required to be filed (or which would be required to be filed) with the Commission pursuant to Section 13 of the Exchange Act) prior to the date of such written demand;

(ii) a current list of the name and last known business, residence or mailing address of each Record Holder;

(iii) a copy of this Agreement and the Certificate of Limited Partnership and all amendments thereto, together with copies of the executed copies of all powers of attorney pursuant to which this Agreement, the Certificate of Limited Partnership and all amendments thereto have been executed; and

(iv) such other information regarding the affairs of the Partnership as the General Partner determines is just and reasonable.

(b) The rights pursuant to Section 3.4(a) replace in their entirety any rights to information provided for in Section 17-305(a) of the Delaware Act and each of the Partners, each other Person who acquires an interest in a Partnership Interest and each other Person bound by this Agreement hereby agrees to the fullest extent permitted by law that they do not have any rights as Partners to receive any information either pursuant to Sections 17-305(a) of the Delaware Act or otherwise except for the information identified in Section 3.4(a).

(c) The General Partner may keep confidential from the Limited Partners, for such period of time as the General Partner deems reasonable, (i) any information that the General Partner reasonably believes to be in the

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nature of trade secrets or (ii) other information the disclosure of which the General Partner believes (A) is not in the best interests of the Partnership Group, (B) could damage the Partnership Group or its business or (C) that any Group Member is required by law or by agreement with any third party to keep confidential.

(d) Notwithstanding any other provision of this Agreement or Section 17-305 of the Delaware Act, each of the Partners, each other Person who acquires an interest in a Partnership Interest and each other Person bound by this Agreement hereby agrees to the fullest extent permitted by law that they do not have rights to receive information from the Partnership or any Indemnitee for the purpose of determining whether to pursue litigation or assist in pending litigation against the Partnership or any Indemnitee relating to the affairs of the Partnership except pursuant to the applicable rules of discovery relating to litigation commenced by such Person.

ARTICLE IV

CERTIFICATES; RECORD HOLDERS; TRANSFER OF PARTNERSHIP INTERESTS;

REDEMPTION OF PARTNERSHIP INTERESTS

Section 4.1 Certificates. Notwithstanding anything to the contrary herein, unless the General Partner shall determine otherwise in respect of some or all of any or all classes of Partnership Interests or Derivative Instruments, Partnership Interests and Derivative Instruments shall not be evidenced by Certificates. Certificates that are issued shall be executed on behalf of the Partnership by the Chairman of the Board, President, Chief Executive Officer or any Executive Vice President or Vice President and the Chief Financial Officer or the Secretary or any Assistant Secretary of the General Partner. The signatures of such officers upon a Certificate may, to the extent permitted by law, be facsimiles. In case any officer who has signed or whose signature has been placed upon such Certificate shall have ceased to be such officer before such Certificate is issued, it may be issued by the Partnership with the same effect as if he or she were such officer at the date of its issuance. No Certificate for any class of Partnership Interests or Derivative Instruments shall be valid for any purpose until it has been countersigned by the Transfer Agent for such class of Partnership Interests or Derivative Instruments, provided, however, that, if the General Partner elects to cause the Partnership to issue Partnership Interests or Derivative Instruments of such class in global form, the Certificate shall be valid upon receipt of a certificate from the Transfer Agent certifying that the Partnership Interests or Derivative Instruments, as the case may be, have been duly registered in accordance with the directions of the Partnership. With respect to any Partnership Interests or Derivative Instruments that are represented by physical Certificates, the General Partner may determine that such Partnership Interests or Derivative Instruments, as the case may be, will no longer be represented by physical Certificates and may, upon written notice to the holders of such Partnership Interests or Derivative Instruments, as the case may be, and subject to applicable law, take whatever actions it deems necessary or appropriate to cause such Partnership Interests or Derivative Instruments, as the case may be, to be registered in book entry or global form and may cause such Certificates to be cancelled or deemed cancelled.

Section 4.2 Mutilated, Destroyed, Lost or Stolen Certificates.

(a) If any mutilated Certificate is surrendered to the Transfer Agent, the appropriate officers of the General Partner on behalf of the Partnership shall execute, and the Transfer Agent shall countersign and deliver in exchange therefor, a new Certificate evidencing the same number and type of Partnership Interests or Derivative Instruments as the Certificate so surrendered.

(b) The appropriate officers of the General Partner on behalf of the Partnership shall execute and deliver, and the Transfer Agent shall countersign, a new Certificate in place of any Certificate previously issued if the Record Holder of the Certificate:

(i) makes proof by affidavit, in form and substance satisfactory to the General Partner, that a previously issued Certificate has been lost, destroyed or stolen;

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(ii) requests the issuance of a new Certificate before the General Partner has notice that the Certificate has been acquired by a purchaser for value in good faith and without notice of an adverse claim;

(iii) if requested by the General Partner, delivers to the General Partner a bond, in form and substance satisfactory to the General Partner, with surety or sureties and with fixed or open penalty as the General Partner may direct, to indemnify the Partnership, the Partners, the General Partner and the Transfer Agent against any claim that may be made on account of the alleged loss, destruction or theft of the Certificate; and

(iv) satisfies any other reasonable requirements imposed by the General Partner or the Transfer Agent.

If a Limited Partner fails to notify the General Partner within a reasonable period of time after such Limited Partner has notice of the loss, destruction or theft of a Certificate, and a transfer of the Partnership Interests or Derivative Instruments represented by the Certificate is registered before the Partnership, the General Partner or the Transfer Agent receives such notification, the Limited Partner shall be precluded from making any claim against the Partnership, the General Partner or the Transfer Agent for such transfer or for a new Certificate.

(c) As a condition to the issuance of any new Certificate under this Section 4.2, the General Partner may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed in relation thereto and any other expenses (including the fees and expenses of the Transfer Agent) reasonably connected therewith.

Section 4.3 Record Holders. The Partnership and the General Partner shall be entitled to recognize the Record Holder as the Partner with respect to any Partnership Interest and, accordingly, shall not be bound to recognize any equitable or other claim to, or interest in, such Partnership Interest on the part of any other Person, regardless of whether the Partnership shall have actual or other notice thereof, except as otherwise provided by law or any applicable rule, regulation, guideline or requirement of any National Securities Exchange on which such Partnership Interests are listed or admitted to trading. Without limiting the foregoing, when a Person (such as a broker, dealer, bank, trust company or clearing corporation or an agent of any of the foregoing) is acting as nominee, agent or in some other representative capacity for another Person in acquiring and/or holding Partnership Interests, as between the Partnership on the one hand, and such other Persons on the other, such representative Person shall be (a) the Record Holder of such Partnership Interest and (b) bound by this Agreement and shall have the rights and obligations of a Partner hereunder as, and to the extent, provided herein.

Section 4.4 Transfer Generally.

(a) The term “transfer,” when used in this Agreement with respect to a Partnership Interest, shall mean a transaction (i) by which the General Partner assigns its General Partner Interest to another Person, and includes a sale, assignment, gift, pledge, grant of security interest, encumbrance, hypothecation, mortgage, exchange or any other disposition by law or otherwise, or (ii) by which the holder of a Limited Partner Interest assigns such Limited Partner Interest to another Person who is or becomes a Limited Partner, and includes a sale, assignment, gift, exchange or any other disposition by law or otherwise (but not the pledge, grant of security interest, encumbrance, hypothecation or mortgage), including any transfer upon foreclosure or other exercise of remedies of any pledge, security interest, encumbrance, hypothecation or mortgage.

(b) No Partnership Interest shall be transferred, in whole or in part, except in accordance with the terms and conditions set forth in this Article IV. Any transfer or purported transfer of a Partnership Interest not made in accordance with this Article IV shall be, to the fullest extent permitted by law, null and void.

(c) Nothing contained in this Agreement shall be construed to prevent a disposition by any stockholder, member, partner or other owner of any Partner of any or all of the shares of stock, membership interests, partnership interests or other ownership interests in such Partner and the term “transfer” shall not mean any such disposition.

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Section 4.5 Registration and Transfer of Limited Partner Interests.

(a) The General Partner shall keep or cause to be kept on behalf of the Partnership a register in which, subject to such reasonable regulations as it may prescribe, the Partnership will provide for the registration and transfer of Limited Partner Interests in compliance with the terms of this Agreement.

(b) The Partnership shall not recognize any transfer of Limited Partner Interests evidenced by Certificates until the Certificates evidencing such Limited Partner Interests are surrendered for registration of transfer. No charge shall be imposed by the General Partner for such transfer; provided, that as a condition to the issuance of any new Certificate under this Section 4.5, the General Partner may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed in relation thereto and any other expenses (including the fees and expenses of the Transfer Agent) reasonably connected therewith. Upon surrender of a Certificate for registration of transfer of any Limited Partner Interests evidenced by a Certificate, and subject to the provisions hereof, the appropriate officers of the General Partner on behalf of the Partnership shall execute and deliver, and in the case of Certificates evidencing Limited Partner Interests, the Transfer Agent shall countersign and deliver, in the name of the holder or the designated transferee or transferees, as required pursuant to the holder’s instructions, one or more new Certificates evidencing the same aggregate number and type of Limited Partner Interests as was evidenced by the Certificate so surrendered. Upon the proper surrender of a Certificate, such transfer shall be recorded in the Partnership register.

(c) Upon the receipt by the General Partner of proper transfer instructions from the Record Holder of uncertificated Partnership Interests, such transfer shall be recorded in the Partnership register.

(d) Except as provided in Section 4.9, by acceptance of any Limited Partner Interests pursuant to a transfer in accordance with this Article IV, each transferee of a Limited Partner Interest (including any nominee, or agent or representative acquiring such Limited Partner Interests for the account of another Person or Group) acknowledges and agrees to the provisions of Section 10.1.

(e) To the fullest extent permitted by law, Initial Limited Partners shall not, for a period of 45 days following the Initial Offering, offer for sale, sell, pledge, transfer, or otherwise dispose of (or enter into any transaction or device that is designed to, or could be expected to, result in the disposition by any Person at any time in the future of) any of the Common Units held by such Person or enter into any swap or other derivatives transaction that transfers to another, in whole or in part, any of the economic consequences of ownership of such Common Units, except as expressly permitted by the General Partner in writing.

(f) Subject to (i) the foregoing provisions of this Section 4.5, (ii) Section 4.3, (iii) Section 4.7, (iv) Section 4.8, (v) with respect to any class or series of Limited Partner Interests, the provisions of any Supplemental Terms Annex, (vi) any contractual provisions binding on any Limited Partner, and (vii) provisions of applicable law including the Securities Act, Limited Partner Interests shall be freely transferable.

Section 4.6 Transfer of the General Partner Interest.

(a) The General Partner shall not transfer all or any part of its General Partner Interest to another Person without the consent of a Supermajority Vote of the Unitholders.

(b) Notwithstanding anything herein to the contrary, no transfer by the General Partner of all or any part of its General Partner Interest to another Person shall be permitted unless (i) the transferee agrees to assume the rights and duties of the General Partner under this Agreement and to be bound by the provisions of this Agreement, (ii) the Partnership receives an Opinion of Counsel that such transfer would not result in the loss of limited liability under the Delaware Act of any Limited Partner or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for U.S. federal income tax purposes (to the extent not already so treated or taxed) and (iii) such transferee also agrees to purchase all (or the appropriate portion thereof, if applicable) of the partnership or membership interest held by the General Partner as the general partner or managing member, if any, of each other Group Member. In the case of a transfer pursuant to

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and in compliance with this Section 4.6, the transferee or successor (as the case may be) shall, subject to compliance with the terms of Section 10.2, be admitted to the Partnership as the General Partner effective immediately prior to the transfer of the General Partner Interest, and the business of the Partnership shall continue without dissolution.

Section 4.7 Restrictions on Transfers.

(a) Notwithstanding the other provisions of this Article IV, no transfer of any Partnership Interests shall be made if such transfer would (i) violate the then applicable U.S. federal or state securities laws or rules and regulations of the Commission, any state securities commission or any other governmental authority with jurisdiction over such transfer, (ii) terminate the existence or qualification of the Partnership under the laws of the jurisdiction of its formation, or (iii) cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for U.S. federal income tax purposes (to the extent not already so treated or taxed).

(b) The General Partner may impose restrictions on the transfer of Partnership Interests if the General Partner determines, with the advice of counsel, that such restrictions are necessary or advisable to (i) avoid a significant risk of the Partnership becoming taxable as a corporation or otherwise becoming taxable as an entity for U.S. federal income tax purposes or (ii) preserve the uniformity of Limited Partner Interests (or any class or classes thereof). The General Partner may impose such restrictions by amending this Agreement; provided, however, that any amendment that would result in the delisting or suspension of trading of any class of Limited Partner Interests on the principal National Securities Exchange on which such class of Limited Partner Interests is then listed or admitted to trading must be approved, prior to such amendment being effected, by the holders of a majority of the Outstanding Limited Partner Interests of such class.

(c) Nothing contained in this Agreement, other than Section 4.7(a), shall preclude the settlement of any transactions involving Partnership Interests entered into through the facilities of any National Securities Exchange on which such Partnership Interests are listed or admitted to trading.

Section 4.8 Eligibility Certificates; Ineligible Holders.

(a) If at any time the General Partner determines, with the advice of counsel, that:

(i) the U.S. federal income tax status (or lack of proof of the U.S. federal income tax status) of one or more Limited Partners (or type of Limited Partners) or their owners creates or is reasonably likely to create a substantial risk of an adverse effect on the rates that can be charged to customers by any Group Member with respect to assets that are subject to regulation by the Federal Energy Regulatory Commission or similar regulatory body (a “Rate Eligibility Trigger”); or

(ii) the nationality, citizenship or other related status (or lack of proof thereof) of one or more Limited Partners (or type of Limited Partners) or their owners creates or is reasonably likely to create a substantial risk of cancellation or forfeiture of any property in which the Group Member has an interest under any federal, state or local law or regulation (a “Citizenship Eligibility Trigger”);

then, the General Partner may adopt such amendments to this Agreement as it determines to be necessary or appropriate to (x) in the case of a Rate Eligibility Trigger, obtain such proof of the U.S. federal income tax status of the Limited Partners and, to the extent relevant, their owners, as the General Partner determines to be necessary or appropriate to reduce the risk of occurrence of a material adverse effect on the rates that can be charged to customers by any Group Member or (y) in the case of a Citizenship Eligibility Trigger, obtain such proof of the nationality, citizenship or other related status of the Limited Partners and, to the extent relevant, their owners as the General Partner determines to be necessary or appropriate to eliminate or mitigate the risk of cancellation or forfeiture of any properties or interests therein.

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(b) Such amendments may include provisions requiring all Partners to certify as to their (and their owners’) status as Eligible Holders upon demand and on a regular basis, as determined by the General Partner, and may require transferees of Units to so certify prior to being admitted to the Partnership as Partners (any such required certificate, an “Eligibility Certificate”).

(c) Such amendments may provide that any Partner who fails to furnish to the General Partner within a reasonable period requested proof of its (and its owners’) status as an Eligible Holder or if upon receipt of such Eligibility Certificate or other requested information the General Partner determines that a Limited Partner (or its owner) is not an Eligible Holder (an “Ineligible Holder”), the Partnership Interests owned by such Limited Partner shall be subject to redemption in accordance with the provisions of Section 4.9. In addition, the General Partner shall be substituted and treated as the owner of all Partnership Interests owned by an Ineligible Holder.

(d) The General Partner shall, in exercising voting rights in respect of Partnership Interests held by it on behalf of Ineligible Holders, cast such votes in the same manner and in the same ratios as the votes of Partners (including the General Partner and its Affiliates) in respect of Partnership Interests other than those of Ineligible Holders are cast.

(e) Upon dissolution of the Partnership, an Ineligible Holder shall have no right to receive a distribution in kind pursuant to Section 12.4 but shall be entitled to the cash equivalent thereof, and the Partnership shall provide cash in exchange for an assignment of the Ineligible Holder’s share of any distribution in kind. Such payment and assignment shall be treated for purposes hereof as a purchase by the Partnership from the Ineligible Holder of the portion of his Partnership Interest representing his right to receive his share of such distribution in kind.

(f) At any time after he can and does certify that he has become an Eligible Holder, an Ineligible Holder may, upon application to the General Partner, request that with respect to any Partnership Interests of such Ineligible Holder not redeemed pursuant to Section 4.9, such Ineligible Holder be admitted as a Partner, and upon approval of the General Partner, such Ineligible Holder shall be admitted as a Partner and shall no longer constitute an Ineligible Holder and the General Partner shall cease to be deemed to be the owner in respect of such Ineligible Holder’s Partnership Interests.

Section 4.9 Redemption of Partnership Interests of Ineligible Holders.

(a) If at any time a Partner fails to furnish an Eligibility Certificate or other information requested within the period of time specified in amendments adopted pursuant to Section 4.8 or if upon receipt of such Eligibility Certificate, the General Partner determines, with the advice of counsel, that a Partner is an Ineligible Holder, the Partnership may, unless the Partner establishes to the satisfaction of the General Partner that such Partner is an Eligible Holder or has transferred his Limited Partner Interests to a Person who is an Eligible Holder and who furnishes an Eligibility Certificate to the General Partner prior to the date fixed for redemption as provided below, redeem the Partnership Interest of such Partner as follows:

(i) The General Partner shall, not later than the 30th day before the date fixed for redemption, give notice of redemption to the Partner, at his last address designated on the records of the Partnership or the Transfer Agent, as applicable, by registered or certified mail, postage prepaid. The notice shall be deemed to have been given when so mailed. The notice shall specify the Redeemable Interests, the date fixed for redemption, the place of payment, that payment of the redemption price will be made upon redemption of the Redeemable Interests (or, if later in the case of Redeemable Interests evidenced by Certificates, upon surrender of the Certificate evidencing the Redeemable Interests) and that on and after the date fixed for redemption no further allocations or distributions to which the Partner would otherwise be entitled in respect of the Redeemable Interests will accrue or be made.

(ii) The aggregate redemption price for Redeemable Interests shall be an amount equal to the Current Market Price (the date of determination of which shall be the date fixed for redemption) of Partnership Interests of the class to be so redeemed multiplied by the number of Partnership Interests of each such class included among the Redeemable Interests. The redemption price shall be paid, as determined by the General

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Partner, in cash or by delivery of a promissory note of the Partnership in the principal amount of the redemption price, bearing interest at the rate of 8% annually and payable in three equal annual installments of principal together with accrued interest, commencing one year after the redemption date.

(iii) The Partner or his duly authorized representative shall be entitled to receive the payment for the Redeemable Interests at the place of payment specified in the notice of redemption on the redemption date (or, if later in the case of Redeemable Interests evidenced by Certificates, upon surrender by or on behalf of the Partner at the place specified in the notice of redemption, of the Certificate evidencing the Redeemable Interests, duly endorsed in blank or accompanied by an assignment duly executed in blank).

(iv) After the redemption date, Redeemable Interests shall no longer constitute issued and Outstanding Limited Partner Interests.

(b) The provisions of this Section 4.9 shall also be applicable to Partnership Interests held by a Partner as nominee of a Person determined to be an Ineligible Holder.

(c) Nothing in this Section 4.9 shall prevent the recipient of a notice of redemption from transferring his Partnership Interest before the redemption date if such transfer is otherwise permitted under this Agreement. Upon receipt of notice of such a transfer, the General Partner shall withdraw the notice of redemption, provided that the transferee of such Partnership Interest certifies to the satisfaction of the General Partner that he is an Eligible Holder. If the transferee fails to make such certification, such redemption will be effected from the transferee on the original redemption date.

ARTICLE V

CAPITAL CONTRIBUTIONS AND ISSUANCE OF PARTNERSHIP INTERESTS

Section 5.1 Contributions by the General Partner and its Affiliates.

(a) In connection with the formation of the Partnership under the Delaware Act, Black Stone Natural Limited Resources, L.L.C. (the “Original General Partner”) was admitted as the sole general partner of the Partnership and the Organizational Limited Partner was admitted as the sole Limited Partner in exchange for a Capital Contribution of $                    . On                     , 2014, the Original General Partner transferred its non-economic general partner interest in the Partnership to the General Partner pursuant to that certain Assignment of Partnership Interest, dated as of                     , 2014 between the Original General Partner and the General Partner (which was consented to by the Organizational Limited Partner) and pursuant to such assignment, the General Partner was admitted as the sole general partner of the Partnership and the Partnership was continued without dissolution. On                     , 2014, the General Partner made a Capital Contribution to the Partnership in the amount of $         in exchange for a 1% limited partner interest and was admitted as a Limited Partner. At the Effective Time, the General Partner’s 1% limited partner interest is hereby converted into          Common Units and the Organizational Limited Partner’s limited partner interest is hereby converted into          Common Units.

(b) At the Effective Time, pursuant to this Agreement and/or the Merger and Contribution Agreement, (i) the Common Units held by the Organizational Limited Partner shall be redeemed and cancelled in exchange for a return of the Organizational Limited Partner’s initial Capital Contribution to the Partnership; (ii) the Organizational Limited Partner shall merge with and into Merger Sub; and (iii) the Partnership shall issue an aggregate of          Common Units to the common unitholders of the Organizational Limited Partner and an aggregate of          Series A Preferred Units with the terms set forth on the Supplemental Terms Annex attached hereto as Annex A and dated as of the date hereof to the preferred unitholders of the Organizational Limited Partner.

Section 5.2 Contributions by Underwriters.

(a) On the Closing Date and pursuant to the Underwriting Agreement, each Underwriter shall contribute cash to the Partnership in exchange for the issuance by the Partnership of Common Units to each Underwriter, all as set forth in the Underwriting Agreement.

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(b) Upon the exercise, if any, of the Over-Allotment Option, each Underwriter shall contribute cash to the Partnership in exchange for the issuance by the Partnership of Common Units to each Underwriter, all as set forth in the Underwriting Agreement.

(c) No Limited Partner will be required to make any additional Capital Contribution to the Partnership pursuant to this Agreement.

Section 5.3 Interest and Withdrawal. No interest on Capital Contributions shall be paid by the Partnership. No Partner shall be entitled to the withdrawal or return of its Capital Contribution, except to the extent, if any, that distributions made pursuant to this Agreement or upon dissolution of the Partnership may be considered as the withdrawal or return of its Capital Contribution by law and then only to the extent provided for in this Agreement. Except to the extent expressly provided in this Agreement, no Partner shall have priority over any other Partner either as to the return of Capital Contributions or as to profits, losses or distributions.

Section 5.4 Capital Accounts.

(a) The Partnership shall maintain for each Partner (or a beneficial owner of Partnership Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method acceptable to the General Partner) owning a Partnership Interest a separate Capital Account with respect to such Partnership Interest in accordance with the rules of Treasury Regulation Section 1.704-1(b)(2)(iv). Such Capital Account shall be increased by (i) the amount of all Capital Contributions made by the Partner with respect to such Partnership Interest, (ii) all items of Partnership income and gain computed in accordance with Section 5.4(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1, and (iii) the portion of any amount realized from the disposition of an oil and gas property that constitutes Simulated Gain allocated with respect to such Partnership Interest in accordance with Section 6.1(c)(iii) and decreased by (x) the amount of cash or Net Agreed Value of all actual and deemed distributions to the Partner of cash or property made with respect to such Partnership Interest, provided that the Capital Account of a Partner shall not be reduced by the amount of any distributions made with respect to Restricted Common Units held by such Partner, (y) all items of Partnership deduction and loss computed in accordance with Section 5.4(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1, and (z) Simulated Depletion and Simulated Loss in accordance with Section 6.1(c)(ii).

(b) For purposes of computing the amount of any item of income, gain, loss, deduction, Simulated Depletion, Simulated Gain or Simulated Loss that is to be allocated pursuant to Article VI and is to be reflected in the Partners’ Capital Accounts, the determination, recognition and classification of any such item shall be the same as its determination, recognition and classification for U.S. federal income tax purposes (including any method of depreciation, cost recovery or amortization used for that purpose), provided, that:

(i) Solely for purposes of this Section 5.4, the Partnership shall be treated as owning directly its proportionate share (as determined by the General Partner based upon the provisions of the applicable Group Member Agreement) of all property owned by (x) any other Group Member that is classified as a partnership for U.S. federal income tax purposes and (y) any other partnership, limited liability company, unincorporated business or other entity classified as a partnership for U.S. federal income tax purposes of which a Group Member is, directly or indirectly, a partner, member or other equity holder.

(ii) All fees and other expenses incurred by the Partnership to promote the sale of (or to sell) a Partnership Interest that can neither be deducted nor amortized under Section 709 of the Code, if any, shall, for purposes of Capital Account maintenance, be treated as an item of deduction at the time such fees and other expenses are incurred and shall be allocated among the Partners pursuant to Section 6.1.

(iii) The computation of all items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss shall be made (x) except as otherwise provided in this Agreement and Treasury Regulation Section 1.704-1(b)(2)(iv)(m), without regard to any election under Section 754 of the Code that

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may be made by the Partnership, and (y) as to those items described in Section 705(a)(1)(B) or 705(a)(2)(B) of the Code, without regard to the fact that such items are not includable in gross income or are neither currently deductible nor capitalized for U.S. federal income tax purposes.

(iv) To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) of the Code (including pursuant to Treasury Regulation Section 1.734-2(b)(l)) is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment in the Capital Accounts shall be treated as an item of gain or loss.

(v) In the event the Carrying Value of Partnership property is adjusted pursuant to Section 5.4(d), any Unrealized Gain resulting from such adjustment shall be treated as an item of gain and any Unrealized Loss resulting from such adjustment shall be treated as an item of loss.

(vi) Any income, gain, loss, Simulated Gain or Simulated Loss attributable to the taxable disposition of any Partnership property shall be determined as if the adjusted basis of such property as of such date of disposition were equal in amount to the property’s Carrying Value as of such date.

(vii) Any deductions for depreciation, amortization or other cost recovery attributable to any Contributed Property or Adjusted Property shall be determined under the rules prescribed by Treasury Regulation Section 1.704-3(d)(2) as if the adjusted basis of such property were equal to the Carrying Value of such property immediately following such adjustment. Simulated Depletion will be computed in accordance with the provisions of the definition of Simulated Depletion.

(viii) The Gross Liability Value of each Liability of the Partnership described in Treasury Regulation Section 1.752-7(b)(3)(i) shall be adjusted at such times as provided in this Agreement for an adjustment to Carrying Values. The amount of any such adjustment shall be treated for purposes hereof as an item of loss (if the adjustment increases the Carrying Value of such Liability of the Partnership) or an item of gain (if the adjustment decreases the Carrying Value of such Liability of the Partnership).

(c) A transferee of a Partnership Interest shall succeed to a pro rata portion of the Capital Account of the transferor relating to the Partnership Interest so transferred.

(d) (i) Consistent with Treasury Regulation Section 1.704-1(b)(2)(iv)(f) and 1.704-1(b)(2)(iv)(h)(2), on an issuance of additional Partnership Interests for cash or Contributed Property, the issuance of a Noncompensatory Option, the issuance of Partnership Interests as consideration for the provision of services (including upon the lapse of a “substantial risk of forfeiture” with respect to a Restricted Common Unit) or the conversion of any Partnership Interests or Derivative Instruments issued pursuant to Section 5.5 to Common Units, the Carrying Value of each Partnership property immediately prior to such issuance shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property; provided, however, that in the event of the issuance of a Partnership Interest pursuant to the exercise of a Noncompensatory Option where the right to share in Partnership capital represented by such Partnership Interest differs from the consideration paid to acquire and exercise such option, the Carrying Value of each Partnership property immediately after the issuance of such Partnership Interest shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property and the Capital Accounts of the Partners shall be adjusted in a manner consistent with Treasury Regulation Section 1.704-1(b)(2)(iv)(s); provided further, however, that in the event of an issuance of Partnership Interests for a de minimis amount of cash or Contributed Property, in the event of an issuance of a Noncompensatory Option to acquire a de minimis Partnership Interest, or in the event of an issuance of a de minimis amount of Partnership Interests as consideration for the provision of services, the General Partner may determine that such adjustments are unnecessary for the proper administration of the Partnership. If, upon the occurrence of a Revaluation Event described in this Section 5.4(d), a Noncompensatory Option of the Partnership is outstanding, the Partnership shall adjust the Carrying Value of each Partnership Property in accordance with Treasury Regulation Sections 1.704-1(b)(2)(iv)(f)(1) and 1.704-1(b)(2)(iv)(h)(2). In determining such Unrealized Gain or Unrealized Loss, the aggregate fair market value of all

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Partnership property (including cash or cash equivalents) immediately prior to the issuance of additional Partnership Interests (or, in the case of a Revaluation Event resulting from the exercise of a Noncompensatory Option, immediately after the issuance of the Partnership Interest acquired pursuant to the exercise of such Noncompensatory Option) shall be determined by the General Partner using such method of valuation as it may adopt. In making its determination of the fair market values of individual properties, the General Partner may first determine an aggregate value for the assets of the Partnership that takes into account the current trading price of the Common Units, the fair market value of all other Partnership Interests at such time, and the amount of Partnership Liabilities. The General Partner may allocate such aggregate value among the individual properties of the Partnership (in such manner as it determines appropriate). Absent a contrary determination by the General Partner, the aggregate fair market value of all Partnership assets (including, without limitation, cash or cash equivalents) immediately prior to a Revaluation Event shall be the value that would result in the Capital Account for each Common Unit that is Outstanding prior to such Revaluation Event being equal to the Event Issue Value.

(ii) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), immediately prior to any distribution to a Partner of any Partnership property (other than a distribution of cash that is not in redemption or retirement of a Partnership Interest), the Carrying Value of all Partnership property shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property. In determining such Unrealized Gain or Unrealized Loss the aggregate fair market value of all Partnership property (including cash or cash equivalents) immediately prior to a distribution shall (A) in the case of a distribution other than one made pursuant to Section 12.4 be determined in the same manner as that provided in Section 5.4(d)(i) or (B) in the case of a liquidating distribution pursuant to Section 12.4, be determined by the Liquidator using such method of valuation as it may adopt.

Section 5.5 Issuances of Additional Partnership Interests and Derivative Instruments.

(a) The Partnership may issue additional Partnership Interests (other than General Partner Interests) and Derivative Instruments for any Partnership purpose at any time and from time to time to such Persons for such consideration and on such terms and conditions as the General Partner shall determine, all without the approval of any Limited Partner.

(b) Each additional Partnership Interest authorized to be issued by the Partnership pursuant to Section 5.5(a) may be issued in one or more classes, or one or more series of any such classes, with such designations, preferences, rights, powers and duties (which may be senior or junior to, or pari passu with existing classes and series of Partnership Interests), as shall be fixed by the General Partner, including (i) the right to share in Partnership profits and losses or items thereof; (ii) the right to share in Partnership distributions; (iii) the rights upon dissolution and liquidation of the Partnership; (iv) whether, and the terms and conditions upon which, the Partnership may, or shall be required to, redeem the Partnership Interest (including sinking fund provisions); (v) whether such Partnership Interest is issued with the privilege of conversion or exchange and, if so, the terms and conditions of such conversion or exchange; (vi) the terms and conditions upon which each Partnership Interest will be issued, evidenced by certificates and assigned or transferred; (vii) the method for determining the Percentage Interest as to such Partnership Interest; and (viii) the right, if any, of each such Partnership Interest to vote on Partnership matters, including matters relating to the relative rights, preferences and privileges of such Partnership Interest. The rights and preferences of any additional class of Partnership Interests issued pursuant to this Section 5.5 shall be set forth in an annex to this Agreement, including the terms of the Series A Preferred Units as set forth in Supplemental Terms Annex A (each, a “Supplemental Terms Annex”), the provisions of which shall supplement and, to the extent inconsistent with any other provision of this Agreement, supersede the provisions hereof. To the extent that more than one Supplemental Terms Annex is in effect at any time and the terms of such Supplemental Terms Annexes conflict with each other, then the terms set forth in the most recently adopted Supplemental Terms Annex shall control.

(c) The General Partner shall take all actions that it determines to be necessary or appropriate in connection with (i) each issuance of Partnership Interests and Derivative Instruments pursuant to this Section 5.5, (ii) the conversion of the General Partner’s general partner interest to Common Units pursuant to the terms of this

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Agreement, (iii) reflecting the admission of such additional Partners in the books and records of the Partnership as the Record Holder of such Partnership Interests, and (iv) all additional issuances of Partnership Interests. The General Partner shall do all things necessary to comply with the Delaware Act and is authorized and directed to do all things that it determines to be necessary or appropriate in connection with any future issuance of Partnership Interests or in connection with the conversion of the General Partner’s general partner interest into Common Units pursuant to the terms of this Agreement, including compliance with any statute, rule, regulation or guideline of any federal, state or other governmental agency or any National Securities Exchange on which the Units or other Partnership Interests are listed or admitted to trading.

(d) No fractional Units shall be issued by the Partnership.

Section 5.6 Splits and Combinations.

(a) Subject to Section 5.6(d), the Partnership may make a Pro Rata distribution of Partnership Interests to all Record Holders or may effect a subdivision or combination of Partnership Interests so long as, after any such event, each Partner shall have the same Percentage Interest in the Partnership as before such event, and any amounts calculated on a per Unit basis or stated as a number of Units are proportionately adjusted retroactively to the beginning of the Partnership.

(b) Whenever such a distribution, subdivision or combination of Partnership Interests is declared, the General Partner shall select a Record Date as of which the distribution, subdivision or combination shall be effective and shall send notice thereof at least 20 days prior to such Record Date to each Record Holder as of a date not less than 10 days prior to the date of such notice.

(c) Promptly following any such distribution, subdivision, or combination, the Partnership may issue Certificates or uncertificated Partnership Interests to the Record Holders of Partnership Interests as of the applicable Record Date representing the new number of Partnership Interests held by such Record Holders, or the General Partner may adopt such other procedures that it determines to be necessary or appropriate to reflect such changes. If any such combination results in a smaller total number of Partnership Interests Outstanding, the Partnership shall require, as a condition to the delivery to a Record Holder of Partnership Interests represented by a Certificate, the surrender of any Certificate held by such Record Holder immediately prior to such Record Date.

(d) The Partnership shall not issue fractional Units upon any distribution, subdivision or combination of Partnership Interests. If a distribution, subdivision, combination or reorganization of Partnership Interests would result in the issuance of fractional Units but for the provisions of Section 5.5(d) and this Section 5.6(d), each fractional Unit shall be rounded to the nearest whole Unit (fractional units equal to or greater than a 0.5 Unit shall be rounded to the next higher Unit).

Section 5.7 Fully Paid and Non-Assessable Nature of Limited Partner Interests. All Limited Partner Interests issued pursuant to, and in accordance with the requirements of, this Article V shall be fully paid and non-assessable Limited Partner Interests in the Partnership, except as such non-assessability may be affected by Sections 17-303, 17-607 or 17-804 of the Delaware Act.

Section 5.8 Deemed Capital Contributions by Partners. Consistent with the provisions of Treasury Regulation Section 1.83-6(d), if any Partner (or its successor) transfers property (including cash) to any employee or other service provider of the Partnership Group and such Partner is not entitled to be reimbursed by (or otherwise elects not to seek reimbursement from) the Partnership for the value of such property, then (a) such property shall be treated as having been contributed to the Partnership by such Partner and (b) immediately thereafter the Partnership shall be treated as having transferred such property to the employee or other service provider.

Section 5.9 No Preemptive Rights. Except as may be provided in a separate agreement between the Partnership and another Person, no Person shall have any preemptive, preferential or other similar right with respect to the issuance of any Partnership Interest, whether unissued, held in the treasury or hereafter created.

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ARTICLE VI

ALLOCATIONS AND DISTRIBUTIONS

Section 6.1 Allocations for Capital Account Purposes. Subject to the terms of any Supplemental Terms Annex, for purposes of maintaining the Capital Accounts and in determining the rights of the Partners among themselves, the Partnership’s items of income, gain, loss, deduction, amount realized and Simulated Gain (computed in accordance with Section 5.4(b)) for each taxable period shall be allocated among the Partners, and the Capital Accounts of the Partners shall be adjusted for Simulated Depletion and Simulated Loss, as provided herein below. As set forth in the definition of “Outstanding,” Restricted Common Units shall not be considered to be Outstanding Common Units for purposes of this Section 6.1 and references herein to Unitholders holding Common Units shall be to such Unitholders solely with respect to their Common Units other than Restricted Common Units.

(a) Net Income and Net Loss. After giving effect to the special allocations set forth in Section 6.1(b) and Capital Account adjustments pursuant to Section 6.1(c)(ii), Net Income and Net Loss for each taxable period and all items of income, gain, loss, deduction and, to the extent provided in Section 6.1(c)(iii), Simulated Gain taken into account in computing Net Income and Net Loss for such taxable period shall be allocated 100% to all Unitholders, Pro Rata.

(b) Special Allocations. Notwithstanding any other provision of this Section 6.1, the following special allocations shall be made for each taxable period in the following order:

(i) Partnership Minimum Gain Chargeback. Notwithstanding any other provision of this Section 6.1, if there is a net decrease in Partnership Minimum Gain during any Partnership taxable period, each Partner shall be allocated items of Partnership income, gain and Simulated Gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(f)(6), 1.704-2(g)(2) and 1.704-2(j)(2)(i), or any successor provision. For purposes of this Section 6.1(b), each Partner’s Adjusted Capital Account balance shall be determined, and the allocation of income, gain and Simulated Gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(b) with respect to such taxable period (other than an allocation pursuant to Section 6.1(b)(v) and 6.1(b)(vi)). This Section 6.1(b)(i) is intended to comply with the Partnership Minimum Gain chargeback requirement in Treasury Regulation Section 1.704-2(f) and shall be interpreted consistently therewith.

(ii) Chargeback of Partner Nonrecourse Debt Minimum Gain. Notwithstanding the other provisions of this Section 6.1 (other than Section 6.1(b)(i)), except as provided in Treasury Regulation Section 1.704-2(i)(4), if there is a net decrease in Partner Nonrecourse Debt Minimum Gain during any Partnership taxable period, any Partner with a share of Partner Nonrecourse Debt Minimum Gain at the beginning of such taxable period shall be allocated items of Partnership income, gain and Simulated Gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(i)(4) and 1.704-2(j)(2)(ii), or any successor provisions. For purposes of this Section 6.1(b), each Partner’s Adjusted Capital Account balance shall be determined, and the allocation of income, gain and Simulated Gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(b), other than Section 6.1(b)(i) and other than an allocation pursuant to Sections 6.1(b)(v) and 6.1(b)(vi), with respect to such taxable period. This Section 6.1(b)(ii) is intended to comply with the chargeback of items of income and gain requirement in Treasury Regulation Section 1.704-2(i)(4) and shall be interpreted consistently therewith.

(iii) Qualified Income Offset. In the event any Partner unexpectedly receives any adjustments, allocations or distributions described in Treasury Regulation Sections 1.704-1(b)(2)(ii)(d)(4), 1.704-1(b)(2)(ii)(d)(5), or 1.704-1(b)(2)(ii)(d)(6), items of Partnership gross income and gain shall be specially allocated to such Partner in an amount and manner sufficient to eliminate, to the extent required by the Treasury Regulations promulgated under Section 704(b) of the Code, the deficit balance, if any, in its

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Adjusted Capital Account created by such adjustments, allocations or distributions as quickly as possible; provided, that an allocation pursuant to this Section 6.1(b)(iii) shall be made only if and to the extent that such Partner would have a deficit balance in its Adjusted Capital Account after all other allocations provided for in this Section 6.1 have been tentatively made as if this Section 6.1(b)(iii) were not in this Agreement.

(iv) Gross Income Allocations. In the event any Partner has a deficit balance in its Capital Account at the end of any taxable period in excess of the sum of (A) the amount such Partner is required to restore pursuant to the provisions of this Agreement and (B) the amount such Partner is deemed obligated to restore pursuant to Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5), such Partner shall be specially allocated items of Partnership gross income, gain and Simulated Gain in the amount of such excess as quickly as possible; provided, that an allocation pursuant to this Section 6.1(b)(iv) shall be made only if and to the extent that such Partner would have a deficit balance in its Capital Account after all other allocations provided for in this Section 6.1 have been tentatively made as if Section 6.1(b)(iii) and this Section 6.1(b)(iv) were not in this Agreement.

(v) Nonrecourse Deductions. Nonrecourse Deductions for any taxable period shall be allocated to the Partners, Pro Rata. If the General Partner determines that the Partnership’s Nonrecourse Deductions should be allocated in a different ratio to satisfy the safe harbor requirements of the Treasury Regulations promulgated under Section 704(b) of the Code, the General Partner is authorized, upon notice to the other Partners, to revise the prescribed ratio to the numerically closest ratio that does satisfy such requirements.

(vi) Partner Nonrecourse Deductions. Partner Nonrecourse Deductions for any taxable period shall be allocated 100% to the Partner that bears the Economic Risk of Loss with respect to the Partner Nonrecourse Debt to which such Partner Nonrecourse Deductions are attributable in accordance with Treasury Regulation Section 1.704-2(i). If more than one Partner bears the Economic Risk of Loss with respect to a Partner Nonrecourse Debt, such Partner Nonrecourse Deductions attributable thereto shall be allocated between or among such Partners in accordance with the ratios in which they share such Economic Risk of Loss. This Section 6.1(b)(vi) is intended to comply with Treasury Regulations Section 1.704-2(i)(1) and shall be interpreted consistently therewith.

(vii) Nonrecourse Liabilities. For purposes of Treasury Regulation Section 1.752-3(a)(3), the Partners agree that Nonrecourse Liabilities of the Partnership in excess of the sum of (A) the amount of Partnership Minimum Gain and (B) the total amount of Nonrecourse Built-in Gain shall be allocated among the Partners, Pro Rata.

(viii) Code Section 754 Adjustments. To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) of the Code (including pursuant to Treasury Regulation Section 1.734-2(b)(1)) is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts as a result of a distribution to a Partner in complete liquidation of such Partner’s interest in the Partnership, the amount of such adjustment to the Capital Accounts shall be treated as an item of gain or Simulated Gain (if the adjustment increases the basis of the asset) or loss or Simulated Loss (if the adjustment decreases such basis) taken into account pursuant to Section 5.4, and such item of gain, loss, Simulated Gain or Simulated Loss shall be specially allocated to the Partners in a manner consistent with the manner in which their Capital Accounts are required to be adjusted pursuant to such Section of the Treasury Regulations.

(ix) Economic Uniformity; Changes in Law. For the proper administration of the Partnership and for the preservation of uniformity of the Limited Partner Interests (or any class or classes thereof), the General Partner shall (i) adopt such conventions as it deems appropriate in determining the amount of depreciation, amortization and cost recovery deductions; (ii) make special allocations of income, gain, loss, deduction, Unrealized Gain or Unrealized Loss; and (iii) amend the provisions of this Agreement as appropriate (x) to reflect the proposal or promulgation of Treasury Regulations under Section 704(b) or Section 704(c) of the Code or (y) otherwise to preserve or achieve uniformity of the Limited Partner Interests (or any class or classes thereof). The General Partner may adopt such conventions, make such allocations and make such

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amendments to this Agreement as provided in this Section 6.1(b)(ix) only if such conventions, allocations or amendments would not have a material adverse effect on the Partners, the holders of any class or classes of Outstanding Limited Partner Interests or the Partnership.

(x) Curative Allocation.

(A) Notwithstanding any other provision of this Section 6.1, other than the Required Allocations, the Required Allocations shall be taken into account in making the Agreed Allocations so that, to the extent possible, the net amount of items of gross income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss allocated to each Partner pursuant to the Required Allocations and the Agreed Allocations, together, shall be equal to the net amount of such items that would have been allocated to each such Partner under the Agreed Allocations had the Required Allocations and the related Curative Allocation not otherwise been provided in this Section 6.1 and Simulated Depletion and Simulated Loss had been included in the definition of Net Income and Net Loss. In exercising its discretion under this Section 6.1(b)(x)(A), the General Partner may take into account future Required Allocations that, although not yet made, are likely to offset other Required Allocations previously made. Allocations pursuant to this Section 6.1(b)(x)(A) shall only be made with respect to Required Allocations to the extent the General Partner determines that such allocations will otherwise be inconsistent with the economic agreement among the Partners.

(B) The General Partner shall, with respect to each taxable period, (1) apply the provisions of Section 6.1(b)(x)(A) in whatever order is most likely to minimize the economic distortions that might otherwise result from the Required Allocations, and (2) divide all allocations pursuant to Section 6.1(b)(x)(A) among the Partners in a manner that is likely to minimize such economic distortions.

(xi) Allocations of GP Items. All GP Items shall, to the maximum extent possible, be allocated to the holders (other than the General Partner) of the Common Units, Pro Rata.

(xii) Equalization of Capital Accounts With Respect to Privately Placed Units. Unrealized Gain or Unrealized Loss deemed recognized as a result of a Revaluation Event shall first be allocated to the (A) Unitholders holding Privately Placed Units, Pro Rata, or (B) Unitholders holding Common Units (other than Privately Placed Units), Pro Rata, as applicable, to the extent necessary to cause the Capital Account in respect of each Privately Placed Unit then Outstanding to equal the Capital Account in respect of each Common Unit (other than Privately Placed Units) then Outstanding.

(xiii) Allocations Regarding Certain Payments Made to Employees and Other Service Providers. Consistent with the provisions of Treasury Regulation Section 1.83-6(d), if any Partner (or its successor) transfers property (including cash) to any employee or other service provider of the Partnership Group and such Partner is not entitled to be reimbursed by (or otherwise elects not to seek reimbursement from) the Partnership for the value of such property, then any items of deduction or loss resulting from or attributable to such transfer shall be allocated to the Partner (or its successor) that made such transfer and was deemed to have contributed such property to the Partnership pursuant to Section 5.8.

(c) Simulated Basis; Simulated Depletion and Simulated Loss; Simulated Gain; Amount Realized.

(i) Simulated Basis. For purposes of determining and maintaining the Partners’ Capital Accounts, (i) the initial Simulated Basis of each oil and gas property (as defined in Section 614 of the Code) of the Partnership shall be allocated among the Partners, Pro Rata and (ii) if the Carrying Value of an oil and gas property (as defined in Section 614 of the Code) is adjusted pursuant to Section 5.4(d), the Simulated Basis of such property (as adjusted to reflect the adjustment to the Carrying Value of such property), shall be allocated to the Partners, Pro Rata.

(ii) Simulated Depletion and Simulated Loss. For purposes of applying clause (z) of the second sentence of Section 5.4(a), Simulated Depletion and Simulated Loss with respect to each oil and gas property (as defined in Section 614 of the Code) of the Partnership shall reduce each Partner’s Capital Account in proportion to the manner in which the Simulated Basis of such property is allocated among the Partners pursuant to Section 6.1(c)(i).

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(iii) Simulated Gain. For purposes of applying clause (iii) of the second sentence of Section 5.4(a), Simulated Gain for any taxable period will be treated as included in either Net Income or Net Loss and allocated pursuant to Section 6.1(a).

(iv) Amount Realized. For purposes of Treasury Regulation Sections 1.704-1(b)(2)(iv)(k)(2) and 1.704-1(b)(4)(iii), the amount realized on the disposition of any oil and gas property (as defined in Section 614 of the Code) of the Partnership shall be allocated (i) first to the Partners in an amount equal to the remaining Simulated Basis of such property in the same proportions as the Simulated Basis of such property was allocated among the Partners pursuant to Section 6.1(c)(i), and (ii) any remaining amount realized shall be allocated to the Partners in the same ratio as Simulated Gain from the disposition of such oil and gas property is allocated pursuant to Section 6.1(a).

Section 6.2 Allocations for Tax Purposes. Subject to the terms of any Supplemental Terms Annex, allocations for U.S. federal income tax purposes shall be made as set forth in this Section 6.2.

(a) Except as otherwise provided herein, for U.S. federal income tax purposes, each item of income, gain, loss and deduction shall be allocated among the Partners in the same manner as its correlative item of “book” income, gain, loss or deduction is allocated pursuant to Section 6.1.

(b) The deduction for depletion with respect to each separate oil and gas property (as defined in Section 614 of the Code) shall be computed for federal income tax purposes separately by the Partners rather than by the Partnership in accordance with Section 613A(c)(7)(D) of the Code. Except as provided in Section 6.2(c), for purposes of such computation (before taking into account any adjustments resulting from an election made by the Partnership under Section 754 of the Code), the adjusted tax basis of each oil and gas property (as defined in Section 614 of the Code) that is (i) a Contributed Property shall initially be allocated among the non-contributing Partners, Pro Rata, but not in excess of any such Partner’s share of Simulated Basis as determined pursuant to Section 6.1(c)(i), and (ii) not a Contributed Property or an Adjusted Property shall initially be allocated to the Partners in proportion to each such Partner’s share of Simulated Basis as determined pursuant to Section 6.1(c)(i). If there is an event described in Section 5.4(d), the General Partner shall reallocate the adjusted tax basis of each oil and gas property in a manner (i) consistent with the principles of Section 704(c) of the Code and (ii) that maintains the federal income tax fungibility of the Units.

Each Partner shall separately keep records of his share of the adjusted tax basis in each oil and gas property, allocated as provided above, adjust such share of the adjusted tax basis for any cost or percentage depletion allowable with respect to such property, and use such adjusted tax basis in the computation of its cost depletion or in the computation of his gain or loss on the disposition of such property by the Partnership

(c) In an attempt to eliminate Book-Tax Disparities attributable to a Contributed Property or Adjusted Property, items of income, gain, loss, depreciation, amortization and cost recovery deductions shall be allocated for U.S. federal income tax purposes among the Partners in the manner provided under Section 704(c) of the Code, and the Treasury Regulations promulgated under Section 704(b) and 704(c) of the Code, as determined appropriate by the General Partner (taking into account the General Partner’s discretion under Section 6.1(b)(ix)); provided that, in all events, the General Partner shall apply the “remedial allocation method” in accordance with the principles of Treasury Regulation Section 1.704-3(d). For purposes of applying the “remedial allocation method” to oil and gas properties (i) the amount by which any Partner’s Capital Account is adjusted for Simulated Depletion shall be treated as an amount of book depletion allocated to such Partner and (ii) the amount of cost depletion computed by such Partner under Section 613A(c)(7)(D) of the Code shall be treated as an amount of tax depletion allocated to such Partner.

(d) The General Partner may determine to depreciate or amortize the portion of an adjustment under Section 743(b) of the Code attributable to unrealized appreciation in any Adjusted Property (to the extent of the unamortized Book-Tax Disparity) using a predetermined rate derived from the depreciation or amortization method and useful life applied to the unamortized Book-Tax Disparity of such property, despite any

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inconsistency of such approach with Treasury Regulation Section 1.167(c)-l(a)(6) or any successor regulations thereto. If the General Partner determines that such reporting position cannot reasonably be taken, the General Partner may adopt depreciation and amortization conventions under which all purchasers acquiring Limited Partner Interests in the same month would receive depreciation and amortization deductions, based upon the same applicable rate as if they had purchased a direct interest in the Partnership’s property. If the General Partner chooses not to utilize such aggregate method, the General Partner may use any other depreciation and amortization conventions to preserve the uniformity of the intrinsic tax characteristics of any Units, so long as such conventions would not have a material adverse effect on the Limited Partners or Record Holders of any class or classes of Limited Partner Interests.

(e) In accordance with Treasury Regulation Sections 1.1245-1(e) and 1.1250-1(f), any gain allocated to the Partners upon the sale or other taxable disposition of any Partnership asset shall, to the extent possible, after taking into account other required allocations of gain pursuant to this Section 6.2, be characterized as Recapture Income in the same proportions and to the same extent as such Partners (or their predecessors in interest) have been allocated any deductions directly or indirectly giving rise to the treatment of such gains as Recapture Income.

(f) All items of income, gain, loss, deduction and credit recognized by the Partnership for U.S. federal income tax purposes and allocated to the Partners in accordance with the provisions hereof shall be determined without regard to any election under Section 754 of the Code that may be made by the Partnership; provided, however, that such allocations, once made, shall be adjusted (in the manner determined by the General Partner) to take into account those adjustments permitted or required by Sections 734 and 743 of the Code.

(g) Each item of Partnership income, gain, loss and deduction shall, for U.S. federal income tax purposes, be determined for each Quarter and prorated on a monthly basis and shall be allocated to the Partners as of the opening of the National Securities Exchange on which the Partnership’s Units are listed or admitted to trading on the first Business Day of each month; provided, however, such items for the period beginning on the Closing Date and ending on the last day of the month in which the Closing Date occurs shall be allocated to the Partners who are issued Units as a result of the transactions contemplated by the Contribution Agreement and the Underwriting Agreement; and provided, further, that each item of Partnership income, gain, loss and deduction for the period beginning on the Contribution Date and ending the date immediately before the Closing Date shall be allocated to the Partners holding Units on the date immediately before the Closing Date; and provided, further, that gain or loss on a sale or other disposition of any assets of the Partnership or any other extraordinary item of income, gain, loss or deduction, as determined by the General Partner, shall be allocated to the Partners as of the opening of the National Securities Exchange on which the Partnership’s Units are listed or admitted to trading on the first Business Day of the month in which such item is recognized for U.S. federal income tax purposes. The General Partner may revise, alter or otherwise modify such methods of allocation to the extent permitted or required by Section 706 of the Code and the regulations or rulings promulgated thereunder.

(h) Allocations that would otherwise be made to a Partner under the provisions of this Article VI shall instead be made to the beneficial owner of Partnership Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method determined by the General Partner.

(i) If, as a result of an exercise of a Noncompensatory Option, a Capital Account reallocation is required under Treasury Regulation Section 1.704-1(b)(2)(iv)(s)(3), the General Partner shall make corrective allocations pursuant to Treasury Regulation Section 1.704-1(b)(4)(x).

Section 6.3 Distributions to Record Holders.

(a) The General Partner may adopt a cash distribution policy, which it may change from time to time without amendment to this Agreement.

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(b) Subject to the terms of any Supplemental Terms Annex, the Partnership will make distributions of (i) cash (other than GP Available Cash), if any, to Unitholders, Pro Rata, and (ii) GP Available Cash, if any, to the holders (other than the General Partner) of Common Units, Pro Rata.

(c) All distributions required to be made under this Agreement shall be made subject to Sections 17-607 and 17-804 of the Delaware Act.

(d) Notwithstanding Section 6.3(b), in the event of the dissolution and liquidation of the Partnership, cash shall be applied and distributed solely in accordance with, and subject to the terms and conditions of, Section 12.4.

(e) Each distribution in respect of a Partnership Interest shall be paid by the Partnership, directly or through any Transfer Agent or through any other Person or agent, only to the Record Holder of such Partnership Interest as of the Record Date established for such distribution. Such payment shall constitute full payment and satisfaction of the Partnership’s liability in respect of such payment, regardless of any claim of any Person who may have an interest in such payment by reason of an assignment or otherwise.

ARTICLE VII

MANAGEMENT AND OPERATION OF BUSINESS

Section 7.1 Management.

(a) The General Partner shall conduct, direct and manage all activities of the Partnership. Except as otherwise expressly provided in this Agreement, but without limitation on the ability of the General Partner to delegate its rights and power to other Persons, all management powers over the business and affairs of the Partnership shall be exclusively vested in the General Partner, and no other Partner shall have any management power over the business and affairs of the Partnership. In addition to the powers now or hereafter granted to a general partner of a limited partnership under applicable law or that are granted to the General Partner under any other provision of this Agreement, the General Partner, subject to Section 7.4, shall have full power and authority to do all things and on such terms as it determines to be necessary or appropriate to conduct the business of the Partnership, to exercise all powers set forth in Section 2.5 and to effectuate the purposes set forth in Section 2.4, including the following:

(i) the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of, or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible or exchangeable into Partnership Interests, and the incurring of any other obligations;

(ii) the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over the business or assets of the Partnership;

(iii) the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of the assets of the Partnership or the merger or other combination of the Partnership with or into another Person (the matters described in this clause (iii) being subject, however, to any prior approval that may be required by Section 7.4 or Article XIV);

(iv) the use of the assets of the Partnership (including cash on hand) for any purpose consistent with the terms of this Agreement, including the financing of the conduct of the operations of the Partnership Group; the lending of funds to other Persons (including other Group Members); the repayment or guarantee of obligations of any Group Member; the making of capital contributions to any Group Member; and the redemption or repurchase of outstanding Partnership Interests or other securities issued by the Partnership from time to time;

(v) the negotiation, execution and performance of any contracts, conveyances or other instruments (including instruments that limit the liability of the Partnership under contractual arrangements to all or

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particular assets of the Partnership, with the other party to the contract to have no recourse against the General Partner or its assets other than its interest in the Partnership, even if the same results in the terms of the transaction being less favorable to the Partnership than would otherwise be the case);

(vi) the distribution of cash or cash equivalents by the Partnership;

(vii) the selection, employment, retention and dismissal of employees (including employees having titles such as “chief executive officer,” “president,” “chief financial officer,” “chief operating officer,” “general counsel,” “vice president,” “secretary” and “treasurer”) and agents, outside attorneys, accountants, consultants and contractors of the General Partner or the Partnership Group and the determination of their compensation and other terms of employment or hiring;

(viii) the maintenance of insurance for the benefit of the Partnership Group, the Partners and Indemnitees;

(ix) the formation of, or acquisition of an interest in, and the contribution of property and the making of loans to, any limited or general partnerships, joint ventures, corporations, limited liability companies or other Persons (including the acquisition of interests in, and the contributions of property to, any Group Member from time to time);

(x) the control of any matters affecting the rights and obligations of the Partnership, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation;

(xi) the indemnification of any Person against liabilities and contingencies to the extent permitted by law;

(xii) the entering into of listing agreements with any National Securities Exchange and the delisting of some or all of the Partnership Interests from, or requesting that trading be suspended on, any such exchange;

(xiii) the purchase, sale or other acquisition or disposition of Partnership Interests, or the issuance of Derivative Instruments;

(xiv) the undertaking of any action in connection with the Partnership’s participation in the management of any Group Member;

(xv) the entering into of agreements with any of its Affiliates, including any agreements to render services to a Group Member or to itself in the discharge of its duties as General Partner of the Partnership;

(xvi) the delegation of any of its duties or authority to appoint, employ or contract with any Person for the transaction of the business of the Partnership, which Person may, under the supervision of the General Partner, (i) act as broker, escrow agent or in any other capacity deemed by the General Partner to be necessary or desirable or (ii) perform such other acts or services for the Partnership as the General Partner may approve; and

(xvii) the dissolution and winding up of the Partnership.

(b) Notwithstanding any other provision of this Agreement, any Group Member Agreement, the Delaware Act or any applicable law, rule or regulation, each of the Partners, each other Person who acquires an interest in a Partnership Interest and each other Person bound by this Agreement hereby (i) approves, ratifies and confirms the execution, delivery and performance by the parties thereto of this Agreement, the Underwriting Agreement, the Merger and Contribution Agreement, and the other agreements described in or filed as exhibits to the Registration Statement that are related to the transactions contemplated by the Registration Statement (in the case of each agreement other than this Agreement, without giving effect to any amendments, supplements or restatements after the date hereof); (ii) agrees that the General Partner (on its own behalf or on behalf of the Partnership) is authorized to execute, deliver and perform the agreements referred to in clause (i) of this sentence and the other agreements, acts, transactions and matters described in or contemplated by the Registration Statement on behalf of the Partnership without any further act, approval or vote of the Partners, the other Persons

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who may acquire an interest in Partnership Interests or are otherwise bound by this Agreement; and (iii) agrees that the execution, delivery or performance by the General Partner, any Group Member or any Affiliate of any of them of this Agreement or any agreement authorized or permitted under this Agreement shall not constitute a breach by the General Partner of any duty that the General Partner may owe the Partnership or the Partners or any other Persons under this Agreement (or any other agreements) or of any duty existing at law, in equity or otherwise.

Section 7.2 Replacement of Fiduciary Duties. Notwithstanding any other provision of this Agreement, to the extent that, at law or in equity, the General Partner or any other Indemnitee would have duties (including fiduciary duties) to the Partnership, to another Partner, to any Person who acquires an interest in a Partnership Interest or to any other Person bound by this Agreement, all such duties (including fiduciary duties) are hereby eliminated, to the fullest extent permitted by law, and replaced with the duties expressly set forth herein. The elimination of duties (including fiduciary duties) and replacement thereof with the duties expressly set forth herein are approved by the Partnership, each of the Partners, each other Person who acquires an interest in a Partnership Interest and each other Person bound by this Agreement.

In furtherance of this replacement of fiduciary duties, but not by way of limitation, the following provisions shall apply:

(a) It will not constitute a breach of fiduciary or other duty for the General Partner or the Partnership’s or the General Partner’s Officers or employees to engage attorneys, accountants and other advisors on behalf of the Partnership, even though such Persons may also be retained from time to time by the General Partner, any of its officers, members, or the Directors, or any of the Partnership’s or the General Partner’s Officers or employees, and such Persons may be engaged with respect to any matter in which the interest of the Partnership and the General Partner, any of its officers, members, or the Directors, or any of the Partnership’s or the General Partner’s Officers or employees, may differ, or may be engaged by both the Partnership and the General Partner or the Officers or employees of the Partnership or the General Partner with respect to any other matter. The General Partner shall not be responsible for any misconduct or negligence on the part of any such attorney, accountant or other advisor so long as the engagement of such Person was not made in Bad Faith;

(b) It will not constitute a breach of fiduciary or other duty for the General Partner, the Partnership’s or the General Partner’s Officers or employees, or any of their respective Affiliates, to contract or enter into any agreement or arrangement with the Partnership with respect to any Property or any aspect of the operations of the Partnership; and

(c) It will not constitute a breach of fiduciary or other duty for the General Partner or an Officer or employee of the Partnership or the General Partner to devote any amount of time to any other matters not related to the operations of the Partnership, and the General Partner or an Officer or employee of the Partnership or the General Partner may devote such time to the business and affairs of the Partnership as it determines necessary in its sole discretion.

Section 7.3 Certificate of Limited Partnership. The General Partner has caused the Certificate of Limited Partnership to be filed with the Secretary of State of the State of Delaware as required by the Delaware Act. The General Partner shall use all reasonable efforts to cause to be filed such other certificates or documents that the General Partner determines to be necessary or appropriate for the formation, continuation, qualification and operation of a limited partnership (or a partnership in which the limited partners have limited liability) in the State of Delaware or any other state in which the Partnership may elect to do business or own property. To the extent the General Partner determines such action to be necessary or appropriate, the General Partner shall file amendments to and restatements of the Certificate of Limited Partnership and do all things to maintain the Partnership as a limited partnership (or a partnership or other entity in which the limited partners have limited liability) under the laws of the State of Delaware or of any other state in which the Partnership may elect to do business or own property. Subject to the terms of Section 3.4(a), the General Partner shall not be required, before or after filing, to deliver or mail a copy of the Certificate of Limited Partnership, any qualification document or any amendment thereto to any Partner.

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Section 7.4 Restrictions on the General Partner’s Authority. Except as provided in Articles XII and XIV, the General Partner may not sell, exchange or otherwise dispose of all or substantially all of the assets of the Partnership Group, taken as a whole, in a single transaction or a series of related transactions without the approval of a Unit Majority; provided, however, that this provision shall not preclude or limit the General Partner’s ability to mortgage, pledge, hypothecate or grant a security interest in all or substantially all of the assets of the Partnership Group and shall not apply to any sale of any or all of the assets of the Partnership Group pursuant to the foreclosure of, or other realization upon, any such encumbrance.

Section 7.5 Reimbursement of the General Partner.

(a) The General Partner and its Affiliates shall be reimbursed on a monthly basis, or such other basis as the General Partner may determine, for (i) all direct and indirect expenses they incur or payments they make on behalf of the Partnership Group (including salary, bonus, incentive compensation and other amounts paid to any Person (including Affiliates of the General Partner) to perform services for the Partnership Group or for the General Partner in the discharge of its duties to the Partnership Group), and (ii) all other expenses allocable to the Partnership Group or otherwise incurred by the General Partner in connection with operating the Partnership Group’s business (including expenses allocated to the General Partner by its Affiliates). The General Partner shall determine the expenses that are allocable to the Partnership Group. Reimbursements pursuant to this Section 7.5 shall be in addition to any reimbursement to the General Partner as a result of indemnification pursuant to Section 7.7.

(b) The General Partner and its Affiliates may charge any member of the Partnership Group a management fee to the extent necessary to allow the Partnership Group to reduce the amount of any state franchise or income tax or any tax based upon the revenues or gross margin of any member of the Partnership Group if the tax benefit produced by the payment for such management fee of such management fee or fees exceeds the amount of such fee or fees.

(c) The General Partner, without the approval of the Limited Partners (who shall have no right to vote in respect thereof), may propose and adopt on behalf of the Partnership benefit plans, programs and practices (including plans, programs and practices involving the issuance of Partnership Interests or Derivative Instruments), or cause the Partnership to issue Partnership Interests or Derivative Instruments in connection with, or pursuant to, any benefit plan, program or practice maintained or sponsored by the General Partner or any of its Affiliates, any Group Member or their Affiliates, or any of them, in each case for the benefit of employees, officers, consultants and directors of the General Partner or its Affiliates, in respect of services performed, directly or indirectly, for the benefit of the Partnership Group. The Partnership agrees to issue and sell to the General Partner or any of its Affiliates any Partnership Interests or Derivative Instruments that the General Partner or such Affiliates are obligated to provide to any employees, officers, consultants and directors pursuant to any such benefit plans, programs or practices. Expenses incurred by the General Partner in connection with any such plans, programs and practices (including the net cost to the General Partner or such Affiliates of Partnership Interests or Derivative Instruments purchased by the General Partner or such Affiliates, from the Partnership or otherwise, to fulfill awards under such plans, programs and practices) shall be reimbursed in accordance with Section 7.5(a). Any and all obligations of the General Partner under any benefit plans, programs or practices adopted by the General Partner as permitted by this Section 7.5(c) shall constitute obligations of the General Partner hereunder and shall be assumed by any successor General Partner approved pursuant to Section 11.1 or the transferee of or successor to all of the General Partner’s General Partner Interest pursuant to Section 4.6.

Section 7.6 Outside Activities.

(a) The General Partner, for so long as it is the General Partner of the Partnership, shall not engage in any business or activity or incur any debts or liabilities except in connection with or incidental to (i) its performance as general partner or managing member, if any, of one or more Group Members or as described in or contemplated by the Registration Statement, (ii) the acquiring, owning or disposing of debt securities or equity interests in any Group Member or (iii) the direct or indirect provision of management, advisory, and administrative services to its Affiliates or to other Persons.

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(b) Each Unrestricted Person (other than the Persons described in Section 7.6(e)) shall have the right to engage in businesses of every type and description and other activities for profit and to engage in and possess an interest in other business ventures of any and every type or description, whether in businesses engaged in or anticipated to be engaged in by any Group Member, independently or with others, including business interests and activities in direct competition with the business and activities of any Group Member. No such business interest or activity shall constitute a breach of this Agreement, any fiduciary or other duty existing at law, in equity or otherwise, or obligation of any type whatsoever to the Partnership or other Group Member, to another Partner, to any Person who acquires an interest in a Partnership Interest or to any other Person bound by this Agreement.

(c) Notwithstanding anything to the contrary in this Agreement, the doctrine of corporate opportunity, or any analogous doctrine, shall not apply to any Unrestricted Person (including the Persons described in Section 7.6(e)). No Unrestricted Person (including the Persons described in Section 7.6(e)) who acquires knowledge of a potential transaction, agreement, arrangement or other matter that may be an opportunity for the Partnership, shall have any duty to communicate or offer such opportunity to any Group Member, and such Unrestricted Person (including the Persons described in Section 7.6(e)) shall not be liable to the Partnership or other Group Member, to another Partner, to any Person who acquires an interest in a Partnership Interest or to any other Person bound by this Agreement for breach of any fiduciary or other duty existing at law, in equity or otherwise by reason of the fact that such Unrestricted Person (including the Persons described in Section 7.6(e)) pursues or acquires such opportunity for itself, directs such opportunity to another Person or does not communicate such opportunity or information to any Group Member.

(d) Subject to the terms of Section 7.6(a), Section 7.6(b), Section 7.6(c), and Section 7.6(e), but otherwise notwithstanding anything to the contrary in this Agreement, (i) the engaging in competitive activities by any Unrestricted Person in accordance with the provisions of this Section 7.6 is hereby approved by the Partnership and all Partners, and (ii) it shall be deemed not to be a breach of any fiduciary duty or any other duty or obligation of any type whatsoever of the General Partner or of any other Unrestricted Person for the Unrestricted Person to engage in such business interests and activities in preference to or to the exclusion of the Partnership; provided such Unrestricted Person does not engage in such business or activity as a result of or using confidential or proprietary information provided by or on behalf of the Partnership to such Unrestricted Person.

(e) Neither the General Partner nor any Director who is also an employee of the Partnership, the General Partner or any of their respective controlled Affiliates, nor any Affiliate of any such Director, may engage in, conduct or participate in any business or activity which may be competitive with the business of the Partnership; provided, however, that any such Director or Affiliate may own a financial interest in a competitor of the Partnership if that interest is in the form of ownership of less than 5% of the outstanding stock of a company whose securities are listed on a National Securities Exchange. Notwithstanding the foregoing, if an employee who is a Director has presented a business opportunity to the Partnership and the General Partner has determined not to pursue such business opportunity, then such Director, or his or her Affiliates, shall be permitted to pursue and conduct such business opportunity with the approval of the Board of Directors.

Section 7.7 Indemnification.

(a) To the fullest extent permitted by law, all Indemnitees shall be indemnified and held harmless by the Partnership from and against any and all losses, claims, damages, liabilities (joint or several), expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all threatened, pending or completed claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, and whether formal or informal and including appeals, in which any Indemnitee may be involved, or is threatened to be involved, as a party or otherwise, by reason of its status as an Indemnitee and acting (or refraining to act) in such capacity; provided, that the Indemnitee shall not be indemnified and held harmless if there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter for which the Indemnitee is seeking indemnification pursuant to this Agreement, the Indemnitee acted in Bad Faith or engaged in willful misconduct

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or fraud or, in the case of a criminal matter, acted with knowledge that the Indemnitee’s conduct was unlawful. Any indemnification pursuant to this Section 7.7 shall be made only out of the assets of the Partnership, it being agreed that the General Partner shall not be personally liable for such indemnification and shall have no obligation to contribute or loan any monies or property to the Partnership to enable it to effectuate such indemnification.

(b) To the fullest extent permitted by law, expenses (including legal fees and expenses) incurred by an Indemnitee who is indemnified pursuant to Section 7.7(a) in appearing at, participating in or defending any claim, demand, action, suit or proceeding shall, from time to time, on a monthly basis be advanced by the Partnership prior to a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter for which the Indemnitee is seeking indemnification pursuant to this Section 7.7, the Indemnitee is not entitled to be indemnified upon receipt by the Partnership of any undertaking by or on behalf of the Indemnitee to repay such amount if it shall be ultimately determined that the Indemnitee is not entitled to be indemnified as authorized by this Section 7.7.

(c) The indemnification provided by this Section 7.7 shall be in addition to any other rights to which an Indemnitee may be entitled under any agreement, pursuant to any vote of the holders of Outstanding Limited Partner Interests, as a matter of law, in equity or otherwise, both as to actions in the Indemnitee’s capacity as an Indemnitee and as to actions in any other capacity, and shall continue as to an Indemnitee who has ceased to serve in such capacity and shall inure to the benefit of the heirs, successors, assigns and administrators of the Indemnitee.

(d) The Partnership may purchase and maintain (or reimburse the General Partner or its Affiliates for the cost of) insurance, on behalf of the General Partner, its Affiliates, the Indemnitees and such other Persons as the General Partner shall determine, against any liability that may be asserted against, or expense that may be incurred by, such Person in connection with the Partnership’s activities or such Person’s activities on behalf of the Partnership, regardless of whether the Partnership would have the power to indemnify such Person against such liability under the provisions of this Agreement.

(e) For purposes of this Section 7.7, the Partnership shall be deemed to have requested an Indemnitee to serve as fiduciary of an employee benefit plan whenever the performance by it of its duties to the Partnership also imposes duties on, or otherwise involves services by, it to the plan or participants or beneficiaries of the plan; excise taxes assessed on an Indemnitee with respect to an employee benefit plan pursuant to applicable law shall constitute “fines” within the meaning of Section 7.7(a); and action taken or omitted by an Indemnitee with respect to any employee benefit plan in the performance of its duties for a purpose reasonably believed by it to be in the best interest of the participants and beneficiaries of the plan shall be deemed to be for a purpose that is in the best interests of the Partnership.

(f) In no event may an Indemnitee subject the Limited Partners to personal liability by reason of the indemnification provisions set forth in this Agreement.

(g) An Indemnitee shall not be denied indemnification in whole or in part under this Section 7.7 because the Indemnitee had an interest in the transaction with respect to which the indemnification applies if the transaction was otherwise permitted by the terms of this Agreement.

(h) The provisions of this Section 7.7 are for the benefit of the Indemnitees and their heirs, successors, permitted assigns, executors and administrators and shall not be deemed to create any rights for the benefit of any other Persons.

(i) No amendment, modification or repeal of this Section 7.7 or any provision hereof shall in any manner terminate, reduce or impair the right of any past, present or future Indemnitee to be indemnified by the Partnership, nor the obligations of the Partnership to indemnify any such Indemnitee under and in accordance

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with the provisions of this Section 7.7 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

Section 7.8 Limitation of Liability of Indemnitees.

(a) Notwithstanding anything to the contrary set forth in this Agreement, any Group Member Agreement, or under the Delaware Act or any other law, rule or regulation or at equity, no Indemnitee shall be liable for monetary damages or otherwise to the Partnership, to another Partner, to any other Person who acquires an interest in a Partnership Interest or to any other Person bound by this Agreement, for losses sustained or liabilities incurred, of any kind or character, as a result of its or any of any other Indemnitee’s determinations, act(s) or omission(s) in their capacities as Indemnitees; provided however, that an Indemnitee shall be liable for losses or liabilities sustained or incurred by the Partnership, the other Partners, any other Persons who acquire an interest in a Partnership Interest or any other Person bound by this Agreement, if it is determined by a final and non-appealable judgment entered by a court of competent jurisdiction that such losses or liabilities were the result of the conduct of that Indemnitee engaged in by it 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.

(b) The General Partner may exercise any of the powers granted to it by this Agreement and perform any of the duties imposed upon it hereunder either directly or by or through its agents, and the General Partner shall not be responsible for any misconduct or negligence on the part of any such agent appointed by the General Partner if such appointment was not made in Bad Faith.

(c) To the extent that, at law or in equity, an Indemnitee has duties (including fiduciary duties) and liabilities relating thereto to the Partnership, to the Partners, to any Person who acquires an interest in a Partnership Interest or to any other Person bound by this Agreement, the General Partner and any other Indemnitee acting in connection with the Partnership’s business or affairs shall not be liable to the Partnership, to any Partner, to any Person who acquires an interest in a Partnership Interest or to any other Person bound by this Agreement for its reliance on the provisions of this Agreement.

(d) Any amendment, modification or repeal of this Section 7.8 or any provision hereof shall be prospective only and shall not in any way affect the limitations on the liability of the Indemnitees under this Section 7.8 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

Section 7.9 Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties.

(a) Whenever the General Partner, any Director, the Board of Directors or any committee of the Board of Directors (including the Conflicts Committee), or any Officer of the General Partner (collectively, the “Designated Persons”) causes the General Partner to make a determination or take or omit to take any action in its capacity as general partner of the Partnership, whether or not under this Agreement, any Group Member Agreement or any other agreement contemplated hereby, then, unless another lesser standard is provided for in this Agreement, such Designated Person, shall make such determination, or take or omit to take such action, in Good Faith. The foregoing and other lesser standards provided for in this Agreement are the sole and exclusive standards governing any such determinations, actions and omissions of the Designated Persons and no such Person shall be subject to any fiduciary duty or other duty or obligation, or any other, different or higher standard (all of which duties, obligations and standards are hereby waived and disclaimed), under this Agreement, any Group Member Agreement or any other agreement contemplated hereby, or under the Delaware Act or any other law, rule or regulation or at equity. Any such determination, action or omission by a Designated Person, will for all purposes be presumed to have been in Good Faith. In any proceeding brought by or on behalf of the Partnership, any Limited Partner, or any other Person who acquires an interest in a Partnership Interest or any

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other Person who is bound by this Agreement, challenging such determination, act or omission, the Person bringing or prosecuting such proceeding shall have the burden of proving that such determination, action or omission was not in Good Faith.

(b) A Designated Person may in its discretion submit any determination, action or omission that would otherwise be decided by such Designated Person pursuant to Section 7.9(a) (i) for Special Approval or (ii) for approval by the vote of a majority of the Common Units (excluding Common Units owned by the General Partner or its Affiliates). If a Designated Person does not submit the determination, action or omission as provided in either clauses (i) or (ii) in the preceding sentence, then any such determination, action or omission shall be governed by Section 7.9(a) above. If any determination, action or omission: (A) receives Special Approval; or (B) receives approval of a majority of the Common Units, then such determination, action or omission shall be conclusively deemed to be approved by the Partnership, all the Partners, each Person who acquires an interest in a Partnership Interest and each other Person who is bound by this Agreement, and shall not constitute a breach of this Agreement, of any Group Member Agreement, of any agreement contemplated herein or therein, or of any fiduciary or other duty or obligation existing at law, in equity or otherwise or obligation of any type whatsoever. If Special Approval is not sought and the Board of Directors of the General Partner determines that the resolution or course of action taken with respect to a conflict of interest is either on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties or is fair and reasonable to the Partnership, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Partnership), then it shall be presumed that, in making its decision, the General Partner and the Board of Directors acted in good faith, and in any proceeding brought by any Limited Partner or Assignee or by or on behalf of such Limited Partner or Assignee or the Partnership challenging such approval, the Person bringing or prosecuting such proceeding shall have the burden of overcoming such presumption. Notwithstanding anything to the contrary in this Agreement or any duty otherwise existing at law or equity, the existence of the conflicts of interest described in the Registration Statement are hereby approved by all Partners and shall not constitute a breach of this Agreement.

(c) Notwithstanding anything to the contrary in this Agreement, the General Partner and its Affiliates or any other Indemnitee shall have no duty or obligation, express or implied, to (i) sell or otherwise dispose of any asset of the Partnership Group or (ii) permit any Group Member to use any facilities or assets of the General Partner and its Affiliates, except as may be provided in contracts entered into from time to time specifically dealing with such use. Any determination by the General Partner or any of its Affiliates to enter into such contracts or transactions shall be in its sole discretion.

(d) The Partners, and each Person who acquires an interest in a Partnership Interest or is otherwise bound by this Agreement hereby authorize the General Partner, on behalf of the Partnership as a partner or member of a Group Member, to approve actions by the general partner or managing member of such Group Member similar to those actions permitted to be taken by the General Partner pursuant to this Section 7.9.

(e) For the avoidance of doubt, whenever any Designated Person makes a determination on behalf of the General Partner, or causes the General Partner to take or omit to take any action, whether in the General Partner’s capacity as the General Partner or in its individual capacity, the standards of care applicable to the General Partner shall apply to such Person, and such Person shall be entitled to all benefits and rights of the General Partner hereunder, including waivers and modifications of duties, protections and presumptions, as if such Person were the General Partner hereunder.

Section 7.10 Other Matters Concerning Standards of Conduct.

(a) Each Designated Person may rely, and shall be protected in acting or refraining from acting upon, any resolution, certificate, statement, instrument, opinion, report, notice, request, consent, order, bond, debenture or other paper or document believed by it to be genuine and to have been signed or presented by the proper party or parties.

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(b) Each Designated Person may consult with legal counsel, accountants, appraisers, management consultants, investment bankers and other consultants and advisers selected by it (collectively, “Experts”), and any act taken or omitted to be taken in reliance upon the advice or opinion (including an Opinion of Counsel) of such Experts as to matters that the Designated Person reasonably believes to be within such Person’s professional or expert competence shall be conclusively presumed to have been done or omitted in Good Faith and in accordance with such advice or opinion.

(c) The General Partner shall have the right, in respect of any of its powers or obligations hereunder, to act through any of its or the Partnership’s duly authorized officers, a duly appointed attorney or attorneys-in-fact.

Section 7.11 Purchase or Sale of Partnership Interests. The General Partner may cause the Partnership to purchase or otherwise acquire Partnership Interests or Derivative Instruments. As long as any Partnership Interests are held by any Group Member, such Partnership Interests shall not be entitled to any vote and shall not be considered to be Outstanding.

Section 7.12 Reliance by Third Parties. Notwithstanding anything to the contrary in this Agreement, any Person dealing with the Partnership shall be entitled to assume that the General Partner and any officer of the General Partner authorized by the General Partner to act on behalf of and in the name of the Partnership has full power and authority to encumber, sell or otherwise use in any manner any and all assets of the Partnership and to enter into any authorized contracts on behalf of the Partnership, and such Person shall be entitled to deal with the General Partner or any such officer as if it were the Partnership’s sole party in interest, both legally and beneficially. Each Partner hereby waives, to the fullest extent permitted by law, any and all defenses or other remedies that may be available to such Partner to contest, negate or disaffirm any action of the General Partner or any such officer in connection with any such dealing. In no event shall any Person dealing with the General Partner or any such officer or its representatives be obligated to ascertain that the terms of this Agreement have been complied with or to inquire into the necessity or expedience of any act or action of the General Partner or any such officer or its representatives. Each and every certificate, document or other instrument executed on behalf of the Partnership by the General Partner or its representatives shall be conclusive evidence in favor of any and every Person relying thereon or claiming thereunder that (a) at the time of the execution and delivery of such certificate, document or instrument, this Agreement was in full force and effect, (b) the Person executing and delivering such certificate, document or instrument was duly authorized and empowered to do so for and on behalf of the Partnership and (c) such certificate, document or instrument was duly executed and delivered in accordance with the terms and provisions of this Agreement and is binding upon the Partnership.

ARTICLE VIII

BOOKS, RECORDS, ACCOUNTING AND REPORTS

Section 8.1 Records and Accounting. The General Partner shall keep or cause to be kept at the principal office of the Partnership appropriate books and records with respect to the Partnership’s business, including all books and records necessary to provide to the Partners any information required to be provided pursuant to Section 3.4(a). Any books and records maintained by or on behalf of the Partnership in the regular course of its business, including the record of the Record Holders of Units or other Partnership Interests, books of account and records of Partnership proceedings, may be kept on, or be in the form of, computer disks, hard drives, magnetic tape, photographs, micrographics or any other information storage device; provided, that the books and records so maintained are convertible into clearly legible written form within a reasonable period of time. The books of the Partnership shall be maintained, for financial reporting purposes, on an accrual basis in accordance with U.S. GAAP. The Partnership shall not be required to keep books maintained on a cash basis and the General Partner shall be permitted to calculate cash-based measures by making such adjustments to its accrual basis books to account for non-cash items and other adjustments as the General Partner determines to be necessary or appropriate.

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Section 8.2 Fiscal Year. The fiscal year of the Partnership shall be a fiscal year ending December 31.

Section 8.3 Reports.

(a) As soon as practicable, but in no event later than 105 days after the close of each fiscal year of the Partnership, the General Partner shall cause to be mailed or made available, by any reasonable means, to each Record Holder of a Unit or other Partnership Interest as of a date selected by the General Partner, an annual report containing financial statements of the Partnership for such fiscal year of the Partnership, presented in accordance with U.S. GAAP, including a balance sheet and statements of operations, Partnership equity and cash flows, such statements to be audited by a firm of independent public accountants selected by the General Partner, and such other information as may be required by applicable law, regulation or rule of any National Securities Exchange on which the Units are listed or admitted to trading, or as the General Partner determines to be necessary or appropriate.

(b) As soon as practicable, but in no event later than 50 days after the close of each Quarter except the last Quarter of each fiscal year, the General Partner shall cause to be mailed or made available, by any reasonable means to each Record Holder of a Unit or other Partnership Interest, as of a date selected by the General Partner, a report containing unaudited financial statements of the Partnership and such other information as may be required by applicable law, regulation or rule of any National Securities Exchange on which the Units are listed or admitted to trading, or as the General Partner determines to be necessary or appropriate.

(c) The General Partner shall be deemed to have made a report available to each Record Holder as required by this Section 8.3 if it has either (i) filed such report with the Commission via its Electronic Data Gathering, Analysis and Retrieval system and such report is publicly available on such system or (ii) made such report available on any publicly available website maintained by the Partnership.

ARTICLE IX

TAX MATTERS

Section 9.1 Tax Returns and Information. The Partnership shall timely file all returns of the Partnership that are required for U.S. federal, state and local income tax purposes on the basis of the accrual method and the taxable period or year that it is required by law to adopt, from time to time, as determined by the General Partner. If the Partnership is required to use a taxable period other than a year ending on December 31, the General Partner shall use reasonable efforts to change the taxable period of the Partnership to a year ending on December 31. The tax information reasonably required by Record Holders for federal, state and local income tax reporting purposes with respect to a taxable period shall be furnished to them within 90 days of the close of the calendar year in which the Partnership’s taxable period ends. The classification, realization and recognition of income, gain, losses and deductions and other items shall be on the accrual method of accounting for U.S. federal income tax purposes.

Section 9.2 Tax Elections.

(a) The Partnership shall make the election under Section 754 of the Code in accordance with applicable regulations thereunder, subject to the reservation of the right to seek to revoke any such election upon the General Partner’s determination that such revocation is in the best interests of the Partners. Notwithstanding any other provision herein contained, for the purposes of computing the adjustments under Section 743(b) of the Code, the General Partner shall be authorized (but not required) to adopt a convention whereby the price paid by a transferee of a Partnership Interest will be deemed to be the lowest quoted closing price of the Partnership Interests on any National Securities Exchange on which such Partnership Interests are listed or admitted to trading during the calendar month in which such transfer is deemed to occur pursuant to Section 6.2(g) without regard to the actual price paid by such transferee.

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(b) Except as otherwise provided herein, the General Partner shall determine whether the Partnership should make any other elections permitted by the Code.

Section 9.3 Tax Controversies. Subject to the provisions hereof, the General Partner, or such other Partner as the General Partner shall designate, shall act as the Tax Matters Partner (as defined in the Code) and is authorized and required to represent the Partnership (at the Partnership’s expense) in connection with all examinations of the Partnership’s affairs by tax authorities, including resulting administrative and judicial proceedings, and to expend Partnership funds for professional services and costs associated therewith. Each Partner agrees to cooperate with the Tax Matters Partner and to do or refrain from doing any or all things reasonably required by the Tax Matters Partner to conduct such proceedings. Each Partner agrees that notice of or updates regarding tax controversies shall be deemed conclusively to have been given or made by the Tax Matters Partner if the Partnership has either (i) filed the information for which notice is required with the Commission via its Electronic Data Gathering, Analysis and Retrieval system and such information is publicly available on such system or (ii) made the information for which notice is required available on any publicly available website maintained by the Partnership, whether or not such Partner remains a Partner in the Partnership at the time such information is made publicly available.

Section 9.4 Withholding. Notwithstanding any other provision of this Agreement, the General Partner is authorized to take any action that may be required to cause the Partnership and other Group Members to comply with any withholding requirements established under the Code or any other U.S. federal, state or local law, including pursuant to Sections 1441, 1442, 1445 and 1446 of the Code. To the extent that the Partnership is required or elects to withhold and pay over to any taxing authority any amount resulting from the allocation or distribution of income to any Partner (including by reason of Section 1446 of the Code), the General Partner may treat the amount withheld as a distribution of cash pursuant to Section 6.3 in the amount of such withholding from such Partner.

ARTICLE X

ADMISSION OF PARTNERS

Section 10.1 Admission of Limited Partners.

(a) By acceptance of the transfer of any Limited Partner Interests or the issuance of any Limited Partner Interests in accordance herewith, and except as provided in Section 4.8, each transferee or other recipient of a Limited Partner Interest (including any nominee holder or an agent or representative acquiring such Limited Partner Interests for the account of another Person) (i) shall be admitted to the Partnership as a Limited Partner with respect to the Limited Partner Interests so transferred or issued to such Person when any such transfer or issuance is reflected in the books and records of the Partnership, (ii) shall become bound by the terms of, and shall be deemed to have agreed to be bound by, this Agreement, (iii) shall become the Record Holder of the Limited Partner Interests so transferred or issued, (iv) represents that the transferee or other recipient has the capacity, power and authority to enter into this Agreement, and (v) makes the consents, acknowledgments and waivers contained in this Agreement, all with or without execution of this Agreement. The transfer of any Limited Partner Interests and/or the admission of any new Limited Partner shall not constitute an amendment to this Agreement. A Person may become a Record Holder without the consent or approval of any of the Partners. A Person may not become a Limited Partner without acquiring a Limited Partner Interest. The rights and obligations of a Person who is an Ineligible Holder shall be determined in accordance with Section 4.8.

(b) The name and mailing address of each Record Holder shall be listed on the books and records of the Partnership maintained for such purpose by the General Partner or the Transfer Agent. The General Partner shall update its books and records from time to time as necessary to reflect accurately the information therein (or shall cause the Transfer Agent to do so, as applicable). A Limited Partner Interest may be represented by a Certificate, as provided in Section 4.1.

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(c) Any transfer of a Limited Partner Interest shall not entitle the transferee to share in the profits and losses, to receive distributions, to receive allocations of income, gain, loss, deduction or credit or any similar item or to any other rights to which the transferor was entitled until the transferee becomes a Limited Partner pursuant to Section 10.1(a).

Section 10.2 Admission of Successor General Partner. A successor General Partner approved pursuant to Section 11.1 or the transferee of or successor to all of the General Partner Interest pursuant to Section 4.6 who is proposed to be admitted as a successor General Partner shall be admitted to the Partnership as the General Partner, effective immediately prior to the withdrawal of the predecessor or transferring General Partner, pursuant to Section 11.1 or the transfer of the General Partner Interest pursuant to Section 4.6, provided, however, that no such successor shall be admitted to the Partnership until compliance with the terms of Section 4.6 has occurred and such successor has executed and delivered such other documents or instruments as may be required to effect such admission. Any such successor shall, subject to the terms hereof, carry on the business of the members of the Partnership Group without dissolution.

Section 10.3 Amendment of Agreement and Certificate of Limited Partnership. To effect the admission to the Partnership of any Partner, the General Partner shall take all steps necessary under the Delaware Act to amend the records of the Partnership to reflect such admission and, if necessary, to prepare as soon as practicable an amendment to this Agreement and, if required by law, the General Partner shall prepare and file an amendment to the Certificate of Limited Partnership.

ARTICLE XI

WITHDRAWAL OF PARTNERS

Section 11.1 Withdrawal of the General Partner.

(a) The General Partner shall be deemed to have withdrawn from the Partnership upon the occurrence of any one of the following events (each such event herein referred to as an “Event of Withdrawal”):

(i) The General Partner transfers all of its rights as General Partner pursuant to Section 4.6;

(ii) The General Partner (A) makes a general assignment for the benefit of creditors; (B) files a voluntary bankruptcy petition for relief under Chapter 7 of the United States Bankruptcy Code; (C) files a petition or answer seeking for itself a liquidation, dissolution or similar relief (but not a reorganization) under any law; (D) files an answer or other pleading admitting or failing to contest the material allegations of a petition filed against the General Partner in a proceeding of the type described in clauses (A) through (C) of this Section 11.1(a)(ii); or (E) seeks, consents to or acquiesces in the appointment of a trustee (but not a debtor-in-possession), receiver or liquidator of the General Partner or of all or any substantial part of its properties;

(iii) A final and non-appealable order of relief under Chapter 7 of the United States Bankruptcy Code is entered by a court with appropriate jurisdiction pursuant to a voluntary or involuntary petition by or against the General Partner; or

(iv) (A) if the General Partner is a corporation, a certificate of dissolution or its equivalent is filed for the General Partner, or 90 days expire after the date of notice to the General Partner of revocation of its charter without a reinstatement of its charter, under the laws of its state of incorporation; (B) if the General Partner is a limited liability company or a partnership, the dissolution and commencement of winding up of the General Partner; (C) if the General Partner is acting in such capacity by virtue of being a trustee of a trust, the termination of the trust; and (D) if the General Partner is a natural person, his death or adjudication of incompetency.

If an Event of Withdrawal occurs, the withdrawing General Partner shall give notice to the Partners within 30 days after such occurrence. The Partners hereby agree that only the Events of Withdrawal described in this Section 11.1 shall result in the withdrawal of the General Partner from the Partnership.

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(b) Withdrawal of the General Partner from the Partnership upon the occurrence of an Event of Withdrawal shall not constitute a breach of this Agreement. The withdrawal of the General Partner from the Partnership upon the occurrence of an Event of Withdrawal shall also constitute the withdrawal of the General Partner as general partner or managing member, if any, to the extent applicable, of the other Group Members. If the General Partner gives notice of withdrawal pursuant to Section 11.1(a), the holders of a Unit Majority, may, prior to the effective date of such withdrawal, elect a successor General Partner. The Person so elected as successor General Partner shall automatically become the successor general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. If, prior to the effective date of the General Partner’s withdrawal, a successor is not selected by the Partners as provided herein, the Partnership shall be dissolved in accordance with Section 12.1, unless the business of the Partnership is continued pursuant to Section 12.2. Any successor General Partner elected in accordance with the terms of this Section 11.1 shall be subject to the provisions of Section 10.2.

Section 11.2 Interest of Departing General Partner and Successor General Partner.

(a) If the General Partner withdraws as General Partner (other than by transfer of its general partner interest), it shall become a Limited Partner and its general partner interest shall be converted into Common Units with a value equivalent to the value of its general partner interest as agreed between the departing General Partner and the successor General Partner or, if they cannot agree or if there is no successor General Partner, pursuant to a valuation made by an investment banking firm or other independent expert, without reduction in such Partnership Interest (but subject to proportionate dilution by reason of the admission of its successor). For purposes of this Agreement, conversion of a general partner interest to Common Units will be characterized as if the Departing General Partner (or its Affiliates) contributed the its general partner interest to the Partnership in exchange for the newly issued Common Units.

(b) If a successor General Partner is elected in accordance with the terms of Section 11.1 (or if the business of the Partnership is continued pursuant to Section 12.2 and the successor General Partner is not the former General Partner), such successor General Partner shall be entitled to its Percentage Interest of all Partnership allocations and distributions to which the Departing General Partner was entitled. In addition, the successor General Partner shall cause this Agreement to be amended to reflect that, from and after the date of such successor General Partner’s admission, the successor General Partner’s interest in all Partnership distributions and allocations shall be its Percentage Interest.

Section 11.3 Withdrawal of Limited Partners. No Limited Partner shall have any right to withdraw from the Partnership; provided, however, that when a transferee of a Limited Partner’s Partnership Interest becomes a Record Holder of the Partnership Interest so transferred, such transferring Limited Partner shall cease to be a Limited Partner with respect to the Partnership Interest so transferred.

ARTICLE XII

DISSOLUTION AND LIQUIDATION

Section 12.1 Dissolution. The Partnership shall not be dissolved by the admission of additional Partners or by the admission of a successor General Partner in accordance with the terms of this Agreement. Upon the withdrawal of the General Partner, if a successor General Partner is elected pursuant to Section 11.1, the Partnership shall not be dissolved and such successor General Partner shall continue the business of the Partnership. The Partnership shall dissolve, and (subject to Section 12.2) its affairs shall be wound up, upon:

(a) an Event of Withdrawal of the General Partner as provided in Section 11.1(a) or a withdrawal of the General Partner in violation of this Agreement, unless a successor is elected and such successor is admitted to the Partnership pursuant to Section 10.2;

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(b) an election to dissolve the Partnership by the General Partner that is approved by the holders of a Unit Majority;

(c) the entry of a decree of judicial dissolution of the Partnership pursuant to the provisions of the Delaware Act; or

(d) at any time there are no Limited Partners, unless the Partnership is continued without dissolution in accordance with the Delaware Act.

Section 12.2 Continuation of the Business of the Partnership After Dissolution. Upon an Event of Withdrawal caused by the withdrawal of the General Partner as provided in Section 11.1(a)(iv) and the failure of the Partners to select a successor to such Departing General Partner pursuant to Section 11.1 then, to the maximum extent permitted by law, within 180 days thereafter, a Unit Majority may elect to continue the business of the Partnership on the same terms and conditions set forth in this Agreement by appointing as the successor General Partner a Person approved by a Unit Majority. Unless such an election is made within the applicable time period as set forth above, the Partnership shall conduct only activities necessary to wind up its affairs. If such an election is so made, then:

(i) the Partnership shall continue without dissolution unless earlier dissolved in accordance with this Article XII;

(ii) if the successor General Partner is not the former General Partner, then the interest of the former General Partner shall be treated in the manner provided in Section 11.2; and

(iii) the successor General Partner shall be admitted to the Partnership as General Partner, effective as of the Event of Withdrawal, by agreeing in writing to be bound by this Agreement;

provided, that the right of a Unit Majority to approve a successor General Partner and to continue the business of the Partnership shall not exist and may not be exercised unless the Partnership has received an Opinion of Counsel that (x) the exercise of the right would not result in the loss of the limited liability of any Limited Partner under the Delaware Act and (y) neither the Partnership nor any successor limited partnership would be treated as an association taxable as a corporation or otherwise be taxable as an entity for U.S. federal income tax purposes upon the exercise of such right to continue (to the extent not already so treated or taxed).

Section 12.3 Liquidator. Upon dissolution of the Partnership, unless the business of the Partnership is continued pursuant to Section 12.2, the General Partner shall select one or more Persons to act as Liquidator. The Liquidator (if other than the General Partner) shall be entitled to receive such compensation for its services as may be approved by holders of a Unit Majority. The Liquidator (if other than the General Partner) shall agree not to resign at any time without 15 days’ prior notice and may be removed at any time, with or without cause, by notice of removal approved by holders of a Unit Majority. Upon dissolution, removal or resignation of the Liquidator, a successor and substitute Liquidator (who shall have and succeed to all rights, powers and duties of the original Liquidator) shall within 30 days thereafter be approved by holders of a majority of the Outstanding Common Units. The right to approve a successor or substitute Liquidator in the manner provided herein shall be deemed to refer also to any such successor or substitute Liquidator approved in the manner herein provided. Except as expressly provided in this Article XII, the Liquidator approved in the manner provided herein shall have and may exercise, without further authorization or consent of any of the parties hereto, all of the powers conferred upon the General Partner under the terms of this Agreement (but subject to all of the applicable limitations, contractual and otherwise, upon the exercise of such powers, other than the limitation on sale set forth in Section 7.4) necessary or appropriate to carry out the duties and functions of the Liquidator hereunder for and during the period of time required to complete the winding up and liquidation of the Partnership as provided for herein.

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Section 12.4 Liquidation. The Liquidator shall proceed to dispose of the assets of the Partnership, discharge its liabilities, and otherwise wind up its affairs in such manner and over such period as determined by the Liquidator, subject to Section 17-804 of the Delaware Act and the following:

(a) The assets may be disposed of by public or private sale or by distribution in kind to one or more Partners on such terms as the Liquidator and such Partner or Partners may agree. If any property is distributed in kind, the Partner receiving the property shall be deemed for purposes of Section 12.4(c) to have received cash equal to its fair market value; and contemporaneously therewith, appropriate cash distributions must be made to the other Partners. The Liquidator may defer liquidation or distribution of the Partnership’s assets for a reasonable time if it determines that an immediate sale or distribution of all or some of the Partnership’s assets would be impractical or would cause undue loss to the Partners. The Liquidator may distribute the Partnership’s assets, in whole or in part, in kind if it determines that a sale would be impractical or would cause undue loss to the Partners.

(b) Liabilities of the Partnership include amounts owed to the Liquidator as compensation for serving in such capacity (subject to the terms of Section 12.3) and amounts to Partners otherwise than in respect of their distribution rights under Article VI. With respect to any liability that is contingent, conditional or unmatured or is otherwise not yet due and payable, the Liquidator shall either settle such claim for such amount as it thinks appropriate or establish a reserve of cash or other assets to provide for its payment. When paid, any unused portion of the reserve shall be distributed as additional liquidation proceeds.

(c) Subject to the terms of any Supplemental Terms Annex, all property and all cash in excess of that required to discharge liabilities as provided in Section 12.4(b) shall be distributed to the Partners in accordance with, and to the extent of, the positive balances in their respective Capital Accounts, as determined after taking into account all Capital Account adjustments (other than those made by reason of distributions pursuant to this Section 12.4(c)) for the taxable period of the Partnership during which the liquidation of the Partnership occurs (with such date of occurrence being determined pursuant to Treasury Regulation Section 1.704-1(b)(2)(ii)(g)), and such distribution shall be made by the end of such taxable period (or, if later, within 90 days after said date of such occurrence).

Section 12.5 Cancellation of Certificate of Limited Partnership. Upon the completion of the distribution of Partnership cash and property as provided in Section 12.4 in connection with the liquidation of the Partnership, the Certificate of Limited Partnership and all qualifications of the Partnership as a foreign limited partnership in jurisdictions other than the State of Delaware shall be canceled and such other actions as may be necessary to terminate the Partnership shall be taken.

Section 12.6 Return of Contributions. The General Partner shall not be personally liable for, and shall have no obligation to contribute or loan any monies or property to the Partnership to enable it to effectuate, the return of the Capital Contributions of the Partners or Unitholders, or any portion thereof, it being expressly understood that any such return shall be made solely from Partnership assets.

Section 12.7 Waiver of Partition. To the maximum extent permitted by law, each Partner hereby waives any right to partition of the Partnership property.

Section 12.8 Capital Account Restoration. No Limited Partner shall have any obligation to restore any negative balance in its Capital Account upon liquidation of the Partnership. The General Partner shall be obligated to restore any negative balance in its Capital Account upon liquidation of its interest in the Partnership by the end of the taxable period of the Partnership during which such liquidation occurs, or, if later, within 90 days after the date of such liquidation.

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ARTICLE XIII

AMENDMENT OF PARTNERSHIP AGREEMENT; MEETINGS; RECORD DATE

Section 13.1 Amendments to be Adopted Solely by the General Partner. Each Partner agrees that the General Partner, without the approval of any other Partner, may amend any provision of this Agreement and execute, swear to, acknowledge, deliver, file and record whatever documents may be required in connection therewith, to reflect:

(a) a change in the name of the Partnership, the location of the principal place of business of the Partnership, the registered agent of the Partnership or the registered office of the Partnership;

(b) admission, substitution, withdrawal or removal of Partners in accordance with this Agreement;

(c) a change that the General Partner determines to be necessary or appropriate to qualify or continue the qualification of the Partnership as a limited partnership or a partnership in which the Limited Partners have limited liability under the laws of any state or to ensure that the Group Members will not be treated as associations taxable as corporations or otherwise taxed as entities for U.S. federal income tax purposes;

(d) a change that the General Partner determines (i) does not adversely affect the Limited Partners (including any particular class of Partnership Interests as compared to other classes of Partnership Interests) in any material respect, (ii) to be necessary, appropriate or desirable to (A) satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute (including the Delaware Act) or (B) facilitate the trading of the Units (including the division of any class or classes of Outstanding Units into different classes to facilitate uniformity of tax consequences within such classes of Units) or comply with any rule, regulation, guideline or requirement of any National Securities Exchange on which any class of Partnership Interests are or will be listed or admitted to trading, (iii) to be necessary or appropriate in connection with action taken by the General Partner pursuant to Section 5.6 or (iv) is required to effect the intent expressed in the Registration Statement or the intent of the provisions of this Agreement or is otherwise contemplated by this Agreement or is required to effect any Required Provision;

(e) a change in the fiscal year or taxable period of the Partnership and any other changes that the General Partner determines to be necessary or appropriate as a result of a change in the fiscal year or taxable period of the Partnership including, if the General Partner shall so determine, a change in the definition of “Quarter” and the dates on which distributions are to be made by the Partnership;

(f) an amendment that is necessary, in the Opinion of Counsel, to prevent the Partnership, or the General Partner or their directors, officers, trustees or agents from in any manner being subjected to the provisions of the Investment Company Act of 1940, as amended, the Investment Advisers Act of 1940, as amended, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, as amended, regardless of whether such are substantially similar to plan asset regulations currently applied or proposed by the United States Department of Labor;

(g) an amendment that the General Partner determines to be necessary or appropriate in connection with the creation, authorization or issuance of any class or series of Partnership Interests or any Derivative Instruments pursuant to Section 5.5, including, without limitation, adopting the Supplemental Terms Annex for such class or series;

(h) any amendment expressly permitted in this Agreement to be made by the General Partner acting alone;

(i) an amendment effected, necessitated or contemplated by a Merger Agreement approved in accordance with Section 14.3;

(j) an amendment that the General Partner determines to be necessary or appropriate to reflect and account for the formation by the Partnership of, or investment by the Partnership in, any corporation, partnership, joint venture, limited liability company or other entity, in connection with the conduct by the Partnership of activities permitted by the terms of Section 2.4 or Section 7.1(a);

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(k) a merger or conveyance pursuant to Section 14.3(d); or

(l) any other amendments substantially similar to the foregoing.

Section 13.2 Amendment Procedures. Amendments to this Agreement may be proposed only by the General Partner. To the fullest extent permitted by law, the General Partner shall have no duty or obligation to propose or approve any amendment to this Agreement and may decline to do so in its sole discretion. An amendment shall be effective upon its approval by the General Partner and, except as otherwise provided by Sections 13.1 or 13.3, a Unit Majority, unless a greater or different percentage is required under this Agreement or by Delaware law. Each proposed amendment that requires the approval of the holders of a specified percentage of Outstanding Units shall be set forth in a writing that contains the text of the proposed amendment. If such an amendment is proposed, the General Partner shall seek the written approval of the requisite percentage of Outstanding Units or call a meeting of the Unitholders to consider and vote on such proposed amendment. The General Partner shall notify all Record Holders upon final adoption of any amendments. The General Partner shall be deemed to have notified all Record Holders as required by this Section 13.2 if it has either (a) filed such amendment with the Commission via its Electronic Data Gathering, Analysis and Retrieval system and such amendment is publicly available on such system or (b) made such amendment available on any publicly available website maintained by the Partnership.

Section 13.3 Amendment Requirements.

(a) Notwithstanding the provisions of Section 13.1 (other than Section 13.1(d)(iv)) and Section 13.2, no provision of this Agreement (other than Section 13.5) that establishes a percentage of Outstanding Common Units (including Common Units deemed owned by the General Partner) or requires a vote or approval of Partners (or a subset of Partners) holding a specified Percentage Interest to take any action shall be amended, altered, changed, repealed or rescinded in any respect that would have the effect of reducing or increasing such percentage, unless such amendment is approved by the written consent or the affirmative vote of holders of Outstanding Common Units whose aggregate Outstanding Common Units constitute not less than the voting requirement sought to be reduced or increased, as applicable, or the affirmative vote of Partners whose aggregate Percentage Interests constitute not less than the voting requirement sought to be reduced or increased, as applicable.

(b) Notwithstanding the provisions of Section 13.1 (other than Section 13.1(d)(iv)) and Section 13.2, no amendment to this Agreement may (i) enlarge the obligations of (including requiring any holder of a class of Partnership Interests to make additional Capital Contributions to the Partnership) any Limited Partner without its consent, unless such shall be deemed to have occurred as a result of an amendment approved pursuant to Section 13.3(c), or (ii) enlarge the obligations of, restrict, change or modify in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable to, the General Partner or any of its Affiliates without its consent, which consent may be given or withheld at its option.

(c) Except as provided in Sections 13.1 or 14.3, any amendment that would have a material adverse effect on the rights or preferences of any class of Partnership Interests in relation to other classes of Partnership Interests must be approved by the holders of not less than a majority of the Outstanding Partnership Interests of the class affected. If the General Partner determines an amendment does not satisfy the requirements of Section 13.1(d)(i) because it adversely affects one or more classes of Partnership Interests, as compared to other classes of Partnership Interests, in any material respect, such amendment shall only be required to be approved by the adversely affected class or classes.

(d) Notwithstanding any other provision of this Agreement, except for amendments pursuant to Section 13.1 and except as otherwise provided by Section 14.3(b), no amendments shall become effective without the approval of the holders of at least 90% of the Percentage Interests of all Limited Partners voting as a single class unless the Partnership obtains an Opinion of Counsel to the effect that such amendment will not affect the limited liability of any Limited Partner under applicable partnership law of the state under whose laws the Partnership is organized.

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(e) Except as provided in Section 13.1, this Section 13.3 shall only be amended with the approval of Partners (including the General Partner and its Affiliates) holding at least 90% of the Percentage Interests of all Limited Partners.

Section 13.4 Amendments to Organizational Documents of General Partner and Other Subsidiaries. Each Partner agrees that the General Partner, without the approval of any other Partner, may amend any provision of the organizational documents of any direct or indirect subsidiary of the Partnership (including the General Partner and the Original General Partner) and execute, swear to, acknowledge, deliver, file and record whatever documents may be required in connection therewith.

Section 13.5 Special Meetings; Annual Meetings; Election of Directors.

(a) All acts of Limited Partners to be taken pursuant to this Agreement shall be taken in the manner provided in this Article XIII. Special meetings of the Limited Partners may be called by the General Partner or by Limited Partners owning 20% or more of the Outstanding Units of the class or classes for which a meeting is proposed. Limited Partners shall call a special meeting by delivering to the General Partner one or more requests in writing stating that the signing Limited Partners wish to call a special meeting and indicating the specific purposes for which the special meeting is to be called and the class or classes of Units for which the meeting is proposed. No business may be brought by any Limited Partner before such special meeting except the business listed in the related request. Within 60 days after receipt of such a call from Limited Partners or within such greater time as may be reasonably necessary for the Partnership to comply with any statutes, rules, regulations, listing agreements or similar requirements governing the holding of a meeting or the solicitation of proxies for use at such a meeting, the General Partner shall send a notice of the meeting to the Limited Partners either directly or indirectly through the Transfer Agent. A meeting shall be held at a time and place determined by the General Partner on a date not less than 10 days nor more than 60 days after the time notice of the meeting is given as provided in Section 15.1. Limited Partners shall not vote on matters that would cause the Limited Partners to be deemed to be taking part in the management and control of the business and affairs of the Partnership so as to jeopardize the Limited Partners’ limited liability under the Delaware Act or the law of any other state in which the Partnership is qualified to do business.

(b) (i) An annual meeting of the Limited Partners for the election of Directors to the Board of Directors of the General Partner and such other matters as the Board of Directors shall submit to a vote of the Limited Partners shall be held at such date and time as may be fixed from time to time by the General Partner at such place within or without the State of Delaware as may be fixed from time to time by the General Partner and all as stated in the notice of the meeting. Notice of the annual meeting shall be given in accordance with Section 13.6 not less than 10 days nor more than 60 days prior to the date of such meeting.

(ii) The Limited Partners entitled to vote at the annual meeting shall vote together as a single class. The Limited Partners entitled to vote shall elect by a plurality of the votes cast at such meeting persons to serve on the Board of Directors of the General Partner who are nominated in accordance with the provisions of this Section 13.5(b). The exercise by a Limited Partner of the right to elect the Directors and any other rights afforded to such Limited Partner under this Section 13.5(b) shall be in such Limited Partner’s capacity as a limited partner of the Partnership and shall not cause a Limited Partner to be deemed to be taking part in the management and control of the business and affairs of the Partnership so as to jeopardize such Limited Partner’s limited liability under the Delaware Act or the law of any other state in which the Partnership is qualified to do business.

(iii) Solely with respect to the election of Directors to the Board of Directors, the General Partner and the Partnership shall not be entitled to vote Units that are otherwise entitled to vote at any meeting of the Unitholders and the foregoing Units shall not be counted when calculating the required votes for such matter and shall not be deemed to be Outstanding for purposes of determining a quorum for such meeting pursuant to Section 13.10 (but such Units shall not, however, be treated as a separate class of Partnership Interests for purposes of this Agreement).

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(iv) At all elections of the Board of Directors, each Limited Partner entitled to vote at such an election will be entitled to cumulate his 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 such Limited Partner entitled to vote for the election of Board Members, multiplied by (y) the number of Board Members to be elected at such meeting by such class or classes of Unitholders.

(v) The number of Directors that shall constitute the whole Board of Directors of the General Partner shall not be less than nine and not more than thirteen as shall be established from time to time by a resolution adopted by a majority of the Directors, provided that no decrease shall shorten the term of any incumbent Director. At each annual meeting of the Limited Partners, Directors to replace those whose terms expire at such annual meeting shall be elected to hold office until the next succeeding annual meeting.

(vi) Each Director shall hold office for the term for which such Director is elected and thereafter until such Director’s successor shall have been duly elected and qualified, or until such Director’s earlier death, resignation or removal. Any vacancies may be filled, until the next annual meeting at which the term of such class expires, by a majority of the remaining Directors then in office. Each Director may, during his or her term of office, be removed at any time, with or without cause, by the written consent of the holders of record of a Cumulative Majority of the Common Units then Outstanding, and any vacancy created by such removal may also be filled by the holders of record of a Cumulative Majority of the Common Units then outstanding pursuant to a written consent or at the next annual or special meeting of Limited Partners.

(vii) Nominations of persons for election to the Board of Directors of the General Partner may be made at an annual meeting of the Limited Partners only (a) pursuant to the General Partner’s notice of meeting (or any supplement thereto), (b) by or at the direction of the Board of Directors or any committee thereof or (c) if such nominee is a Qualified Nominee, by any Limited Partner or group of Limited Partners (either, a “Nominating Limited Partner Group”) who (x) together hold Units representing at least ten percent (10%) of the Fully Diluted Percentage Interests both at the time of giving of notice of such nominations and at the time of the meeting, (y) are each entitled to vote for the election of the class of Director so nominated and (z) comply with the notice procedures set forth in Section 13.5(b)(viii). No Limited Partner may participate in more than one Nominating Limited Partner Group nominating Directors for election by holders of the same class or classes of Units at any annual or special meeting. Nominations by Limited Partners of any individuals for election to the Board shall be made pursuant to timely notice in writing and in proper form (the “Nomination Notice”) to the General Partner. Any Nomination Notice shall include information about the Nominating Limited Partner Group and the individuals nominated by such Nominating Limited Partner Group for election to the Board as may reasonably be requested by the Board in policies or procedures delivered to the Limited Partners not less than thirty (30) days prior to the commencement of the Nomination Period. For each election, each Nominating Limited Partner Group may nominate for election to the Board of Directors a number of individuals equal to the number of Directors to be elected at such annual or special meeting. In the event that more than one Nominating Limited Partner Group nominates individuals for election to the Board in accordance with this Section 13.5(b)(vii) for any election, and the total number of individuals nominated for election to the Board by all Nominating Limited Partner Groups exceeds the number of Board Members to be elected at such annual or special meeting, the number of individuals each Nominating Limited Partner Group will be permitted to nominate will be proportionately reduced, based on the relative Fully Diluted Percentage Interests of all such Nominating Limited Partner Groups, until the total number of individuals nominated by Nominating Limited Partner Groups is equal to the number of Directors to be elected at such annual or special meeting. Notwithstanding the foregoing, the number of individuals nominated by any Nominating Limited Partner Group for any election shall not be reduced to less than one nominee. Any Director that has been removed by the Board in accordance with Section 13.5(b)(x) is not eligible to be a Qualified Nominee nominated by any Nominating Limited Partner Group until such time as the Board determines that his or her service on the Board would no longer be detrimental to the interests of the Company or the Partnership.

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(viii) (A) For any nominations brought before an annual meeting by a Limited Partner pursuant to Section 13.5(b)(vii), the Limited Partner must have given timely notice thereof in writing to the General Partner. To be timely, a Limited Partner’s notice shall be delivered to the General Partner not later than the close of business on the ninetieth (90th) day, nor earlier than the close of business on the one hundred twentieth (120th) day, prior to the first anniversary of the preceding year’s annual meeting (provided, however, that in the event that the date of the annual meeting is more than thirty (30) days before or more than seventy (70) days after such anniversary date, notice by the Limited Partner must be so delivered not earlier than the close of business on the one hundred twentieth (120th) day prior to such annual meeting and not later than the close of business on the later of the ninetieth (90th) day prior to such annual meeting or the tenth (10th) day following the day on which public announcement of the date of such meeting is first made by the Partnership or the General Partner)(such period, the “Nomination Period”). In no event shall the public announcement of an adjournment or postponement of an annual meeting commence a new time period (or extend any time period) for the giving of a Limited Partner’s notice as described above. Such Limited Partner’s notice shall set forth: (a) as to each person whom the Limited Partner proposes to nominate for election as a Director (i) all information relating to such person that is required to be disclosed in solicitations of proxies for election of directors in an election contest, or is otherwise required, in each case pursuant to and in accordance with Regulation 14A under the Securities Exchange Act and (ii) such person’s written consent to being named in the proxy statement as a nominee and to serving as a Director if elected; and (b) as to the Limited Partner giving the notice and the beneficial owner, if any, on whose behalf the nomination is made (i) the name and address of such Limited Partner, as they appear on the Partnership’s books and records, and of such beneficial owner, (ii) the class or series and number of Units which are owned beneficially and of record by such Limited Partner and such beneficial owner, (iii) a description of any agreement, arrangement or understanding with respect to the nomination between or among such Limited Partner and such beneficial owner, any of their respective Affiliates or associates, and any others acting in concert with any of the foregoing, (iv) a description of any agreement, arrangement or understanding (including any derivative or short positions, profit interests, options, warrants, stock appreciation or similar rights, hedging transactions, and borrowed or loaned Units) that has been entered into as of the date of the Limited Partner’s notice by, or on behalf of, such Limited Partner and such beneficial owners, the effect or intent of which is to mitigate loss to, manage risk or benefit of Unit price changes for, or increase or decrease the voting power of, such Limited Partner and such beneficial owner, with respect to Units, (v) a representation that the Limited Partner is a Record Holder entitled to vote at such meeting and intends to appear in person or by proxy at the meeting to propose such nomination, and (vi) a representation whether the Limited Partner or the beneficial owner, if any, intends or is part of a group which intends (a) to deliver a proxy statement and/or form of proxy to holders of at least the percentage of the Partnership’s Outstanding Common Units required to elect the nominee and/or (b) otherwise to solicit proxies from Limited Partners in support of such nomination. The General Partner may require any proposed nominee to furnish such other information as it may reasonably require to determine the eligibility of such proposed nominee to serve as a Director of the General Partner.

(B) Notwithstanding anything in the second sentence of Section 13.5(b)(viii)(A) to the contrary, in the event that the number of Directors to be elected to the Board of Directors of the General Partner is increased effective at the annual meeting and there is no public announcement by the Partnership or the General Partner naming the nominees for the additional directorships at least one hundred (100) days prior to the first anniversary of the preceding year’s annual meeting, a Limited Partner’s notice required by this Section 13.5(b)(vi) shall also be considered timely, but only with respect to nominees for the additional directorships, if it shall be delivered to the General Partner not later than the close of business on the tenth (10th) day following the day on which such public announcement is first made by the Partnership or the General Partner.

(C) Nominations of persons for election to the Board of Directors may be made at a special meeting of Limited Partners at which Directors are to be elected pursuant to the General Partner’s notice of meeting (1) by or at the direction of the Board of Directors or any committee thereof or (2) provided that the Board of Directors or the Limited Partners hereof has determined that Directors shall be elected at such meeting, by any Limited Partner who is a Record Holder at the time the notice

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provided for in this Section 13.5(b)(vi) is delivered to the General Partner, who is entitled to vote at the meeting and upon such election and who complies with the notice procedures set forth in this Section 13.5(b)(vi). In the event the General Partner calls a special meeting of Limited Partners for the purpose of electing one or more Directors to the Board of Directors, any such Limited Partner entitled to vote in such election of Directors may nominate a person or persons (as the case may be) for election to such position(s) as specified in the General Partner’s notice of meeting, if the Limited Partner’s notice required by paragraph 13.5(b)(vii) shall be delivered to the General Partner not earlier than the close of business on the one hundred twentieth (120th) day prior to such special meeting and not later than the close of business on the later of the ninetieth (90th) day prior to such special meeting or the tenth (10th) day following the day on which public announcement is first made of the date of the special meeting and of the nominees proposed by the Board of Directors to be elected at such meeting. In no event shall the public announcement of an adjournment or postponement of a special meeting commence a new time period (or extend any time period) for the giving of a Limited Partner’s notice as described above.

(D) (1) Only such persons who are nominated in accordance with the procedures set forth in this Section 13.5(b)(vi) shall be eligible to be elected at an annual or special meeting of Limited Partners to serve as Directors. Except as otherwise provided by law, the chairman designated by the General Partner pursuant to Section 13.11 shall have the power and duty (a) to determine whether a nomination was made in accordance with the procedures set forth in this Section 13.5(b)(vi) and (b) if any proposed nomination was not made in compliance with this Section 13.5(b)(vi), to declare that such nomination shall be disregarded. Notwithstanding the foregoing provisions of this Section 13.5(b)(vi), unless otherwise required by law, if the Limited Partner (or a qualified representative of the Limited Partner) does not appear at the annual or special meeting of Limited Partners to present a nomination, such nomination shall be disregarded notwithstanding that proxies in respect of such vote may have been received by the General Partner or the Partnership. For purposes of this Section 13.5(b)(vi), to be considered a qualified representative of the Limited Partner, a person must be a duly authorized officer, manager or partner of such Limited Partner or must be authorized by a writing executed by such Limited Partner or an electronic transmission delivered by such Limited Partner to act for such Limited Partner as proxy at the meeting of Limited Partners and such person must produce such writing or electronic transmission, or a reliable reproduction of the writing or electronic transmission, at the meeting of Limited Partners.

(2) For purposes of this Section 13.5(b)(vi), “public announcement” shall include disclosure in a press release reported by the Dow Jones News Service, Associated Press or other national news service or in a document publicly filed by the Partnership or the General Partner with the Commission pursuant to Section 13, 14 or 15(d) of the Securities Exchange Act.

(3) Notwithstanding the foregoing provisions of this Section 13.5(b)(vi), a Limited Partner shall also comply with all applicable requirements of the Securities Exchange Act and the rules and regulations thereunder with respect to the matters set forth in this Section 13.5(b)(vi); provided however, that any references in this Agreement to the Securities Exchange Act or the rules promulgated thereunder are not intended to and shall not limit any requirements applicable to nominations pursuant to this Section 13.5(b)(vi), and compliance with this Section 13.5(b)(vi) shall be the exclusive means for a Limited Partner to make nominations.

(ix) Notwithstanding any other provision of this Section 13.5(b), the General Partner and the members of the General Partner are authorized, and shall use their commercially reasonable best efforts, to take such action (including, without limitation, the removal and appointment of Directors) as shall be necessary or appropriate to cause a majority of the Board of Directors of the General Partner to consist of individuals other than individuals who are officers, directors, employees or agents of the General Partner; provided, however, that this provision shall not preclude the election of individuals who are Directors of the General Partner and who are not otherwise affiliated with the General Partner; provided further, however, that this provision shall be subject to the compliance with any rule or listing standard of a National Securities Exchange on which any Units or other Partnership Interests are listed or quoted.

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(x) In the event that the Board of Directors determines, by a Supermajority Vote of the Board of Directors, that the service of any Director is detrimental to the interests of the General Partner or the Partnership, including because such Board member or any of his or her controlled Affiliates is actively engaged in a business or activity (as opposed to passive investments) which is detrimentally competitive in any material respect with the business of the General Partner or the Partnership or any of their respective controlled Affiliates, the Board of Directors may remove such Director by Supermajority Vote of the Board of Directors and any vacancy created by such removal shall be filled by the holders of the Units (voting in accordance with the cumulative voting provisions set forth in Section 13.5(b)(iv)) then Outstanding and entitled to elect such Director by written consent or at the next annual or special meeting of Limited Partners.

(xi) This Section 13.5(b) shall not be deemed in any way to limit or impair the ability of the Board of Directors of the General Partner to adopt a “poison pill” or unitholder or other similar rights plan with respect to the Partnership, whether such poison pill or plan contains “dead hand” provisions, “no hand” provisions or other provisions relating to the redemption of the poison pill or plan, in each case as such terms are used under Delaware common law.

(xii) The General Partner shall use its commercially reasonable best efforts to take such action as shall be necessary or appropriate to give effect to and implement the provisions of this Section 13.5(b), including, without limitation, amending the limited liability company agreement of the General Partner.

(xiii) Except as set forth in Section 13.5(b)(iii), this Section 13.5(b) may not be amended except upon the prior approval of Limited Partners that hold two-thirds of the Outstanding Common Units.

(c) If the General Partner delegates to an existing or newly formed wholly-owned subsidiary the power and authority to manage and control the business and affairs of the Partnership Group, the provisions of Section 13.5(b) shall be applicable with respect to the board of directors or other governing body of such subsidiary.

Section 13.6 Notice of a Meeting. Notice of a meeting called pursuant to Section 13.5 shall be given to the Record Holders of the class or classes of Units for which a meeting is proposed in writing by mail or other means of written communication in accordance with Section 15.1. The notice shall be deemed to have been given at the time when deposited in the mail or sent by other means of written communication.

Section 13.7 Record Date. For purposes of determining the Limited Partners entitled to notice of or to vote at a meeting of the Limited Partners or to give approvals without a meeting as provided in Section 13.12 the General Partner may set a Record Date, which shall not be less than 10 nor more than 60 days before (a) the date of the meeting (unless such requirement conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are listed or admitted to trading or U.S. federal securities laws, in which case the rule, regulation, guideline or requirement of such National Securities Exchange or U.S. federal securities laws shall govern) or (b) in the event that approvals are sought without a meeting, the date by which Limited Partners are requested in writing by the General Partner to give such approvals. If the General Partner does not set a Record Date, then (a) the Record Date for determining the Limited Partners entitled to notice of or to vote at a meeting of the Limited Partners shall be the close of business on the day next preceding the day on which notice is given, and (b) the Record Date for determining the Limited Partners entitled to give approvals without a meeting shall be the date the first written approval is deposited with the Partnership in care of the General Partner in accordance with Section 13.12.

Section 13.8 Adjournment. Prior to the date upon which any meeting of Limited Partners is to be held, the General Partner may postpone such meeting one or more times for any reason by giving notice to each Limited Partner entitled to vote at the meeting so postponed of the place, date and hour at which such meeting would be held. Such notice shall be given not fewer than two days before the date of such meeting and otherwise in accordance with this Article XIII. When a meeting is postponed, a new Record Date need not be fixed unless such postponement shall be for more than 45 days. Any meeting of Limited Partners may be adjourned by the

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General Partner one or more times for any reason, including the failure of a quorum to be present at the meeting with respect to any proposal or the failure of any proposal to receive sufficient votes for approval. No Limited Partner vote shall be required for any adjournment. A meeting of Limited Partners may be adjourned by the General Partner as to one or more proposals regardless of whether action has been taken on other matters. When a meeting is adjourned to another time or place, notice need not be given of the adjourned meeting and a new Record Date need not be fixed, if the time and place thereof are announced at the meeting at which the adjournment is taken, unless such adjournment shall be for more than 45 days. At the adjourned meeting, the Partnership may transact any business which might have been transacted at the original meeting. If the adjournment is for more than 45 days or if a new Record Date is fixed for the adjourned meeting, a notice of the adjourned meeting shall be given in accordance with this Article XIII.

Section 13.9 Waiver of Notice; Approval of Meeting; Approval of Minutes. The transaction of business at any meeting of Limited Partners, however called and noticed, and whenever held, shall be as valid as if it had occurred at a meeting duly held after regular call and notice, if a quorum is present either in person or by proxy. Attendance of a Limited Partner at a meeting shall constitute a waiver of notice of the meeting, except when the Limited Partner attends the meeting for the express purpose of objecting, at the beginning of the meeting, to the transaction of any business because the meeting is not lawfully called or convened; and except that attendance at a meeting is not a waiver of any right to disapprove the consideration of matters required to be included in the notice of the meeting, but not so included, if the disapproval is expressly made at the meeting.

Section 13.10 Quorum and Voting. The holders of a majority, by Percentage Interest, of Partnership Interests of the class or classes for which a meeting has been called (including Partnership Interests deemed owned by the General Partner) represented in person or by proxy shall constitute a quorum at a meeting of Partners of such class or classes unless any such action by the Partners requires approval by holders of a greater Percentage Interest, in which case the quorum shall be such greater Percentage Interest. Abstentions and broker non-votes in respect of such Units shall be deemed to be Units present at such meeting for purposes of establishing a quorum. For all matters presented to the Limited Partners holding Outstanding Common Units at a meeting at which a quorum is present for which no minimum or other vote of Limited Partners is required by any other provision of this Agreement, the rules or regulations of any National Securities Exchange on which the Common Units are admitted to trading, or applicable law or pursuant to any regulation applicable to the Partnership or its Partnership Interests, a majority of the votes cast by the Limited Partners holding Outstanding Common Units shall be deemed to constitute the act of all Limited Partners (with abstentions and broker non-votes being deemed to not have been cast with respect to such matter). On any matter where a minimum or other vote of Limited Partners holding Outstanding Common Units is provided by any other provision of this Agreement or required by the rules or regulations of any National Securities Exchange on which the Common Units are admitted to trading, or applicable law or pursuant to any regulation applicable to the Partnership or its Partnership Interests, such minimum or other vote shall be the vote of Limited Partners required to approve such matter (with the effect of abstentions and broker non-votes to be determined based on the vote of Limited Partners required to approve such matter; provided that if the effect of abstentions and broker non-votes is not specified by such applicable rule, regulation or law, and there is no prevailing interpretation of such effect, then abstentions and broker non-votes shall be deemed to not have been cast with respect to such matter; provided further, that, for the avoidance of doubt, with respect to any matter on which this Agreement requires the approval of a specified percentage of the Outstanding Common Units, abstentions and broker non-votes shall be counted as votes against such matter). The Partners present at a duly called or held meeting at which a quorum is present may continue to transact business until adjournment, notwithstanding the withdrawal of enough Partners to leave less than a quorum, if any action taken (other than adjournment) is approved by holders of the required Percentage Interest specified in this Agreement.

Section 13.11 Conduct of a Meeting. The General Partner shall have full power and authority concerning the manner of conducting any meeting of the Limited Partners or solicitation of approvals in writing, including the determination of Persons entitled to vote, the existence of a quorum, the satisfaction of the requirements of Section 13.5, the conduct of voting, the validity and effect of any proxies and the determination of any

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controversies, votes or challenges arising in connection with or during the meeting or voting. The General Partner shall designate a Person to serve as chairman of any meeting and shall further designate a Person to take the minutes of any meeting. All minutes shall be kept with the records of the Partnership maintained by the General Partner. The General Partner may make such other regulations consistent with applicable law and this Agreement as it may deem advisable concerning the conduct of any meeting of the Limited Partners or solicitation of approvals in writing, including regulations in regard to the appointment of proxies, the appointment and duties of inspectors of votes and approvals, the submission and examination of proxies and other evidence of the right to vote, and the revocation of approvals in writing.

Section 13.12 Action Without a Meeting. If authorized by the General Partner, any action that may be taken at a meeting of the Limited Partners may be taken without a meeting, without a vote and without prior notice, if an approval in writing setting forth the action so taken is signed by Limited Partners owning not less than the minimum percentage, by Percentage Interest, of the Partnership Interests of the class or classes for which a meeting has been called (including Partnership Interests deemed owned by the General Partner), as the case may be, that would be necessary to authorize or take such action at a meeting at which all the Limited Partners entitled to vote at such meeting were present and voted (unless such provision conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are listed or admitted to trading, in which case the rule, regulation, guideline or requirement of such National Securities Exchange shall govern). Prompt notice of the taking of action without a meeting shall be given to the Limited Partners who have not approved in writing. The General Partner may specify that any written ballot submitted to Limited Partners for the purpose of taking any action without a meeting shall be returned to the Partnership within the time period, which shall be not less than 20 days, specified by the General Partner. If a ballot returned to the Partnership does not vote all of the Units held by the Limited Partners, the Partnership shall be deemed to have failed to receive a ballot for the Units that were not voted. If approval of the taking of any action by the Limited Partners is solicited by any Person other than by or on behalf of the General Partner, the written approvals shall have no force and effect unless and until (a) they are deposited with the Partnership in care of the General Partner and (b) an Opinion of Counsel is delivered to the General Partner to the effect that the exercise of such right and the action proposed to be taken with respect to any particular matter (i) will not cause the Limited Partners to be deemed to be taking part in the management and control of the business and affairs of the Partnership so as to jeopardize the Limited Partners’ limited liability, and (ii) is otherwise permissible under the state statutes then governing the rights, duties and liabilities of the Partnership and the Partners. Nothing contained in this Section 13.12 shall be deemed to require the General Partner to solicit all Limited Partners in connection with a matter approved by the holders of the requisite percentage of Units acting by written consent without a meeting.

Section 13.13 Right to Vote and Related Matters.

(a) Only those Record Holders of the Outstanding Common Units on the Record Date set pursuant to Section 13.7 shall be entitled to notice of, and to vote at, a meeting of Limited Partners or to act with respect to matters as to which the holders of the Outstanding Common Units have the right to vote or to act. All references in this Agreement to votes of, or other acts that may be taken by, the Outstanding Common Units shall be deemed to be references to the votes or acts of the Record Holders of such Outstanding Common Units.

(b) With respect to Units that are held for a Person’s account by another Person (such as a broker, dealer, bank, trust company or clearing corporation, or an agent of any of the foregoing), in whose name such Units are registered, such other Person shall, in exercising the voting rights in respect of such Units on any matter, and unless the arrangement between such Persons provides otherwise, vote such Units in favor of, and at the direction of, the Person who is the beneficial owner, and the Partnership shall be entitled to assume it is so acting without further inquiry. The provisions of this Section 13.13(b) (as well as all other provisions of this Agreement) are subject to the provisions of Section 4.3.

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ARTICLE XIV

MERGER

Section 14.1 Authority. The Partnership may merge or consolidate with or into one or more corporations, limited liability companies, business trusts or associations, real estate investment trusts, common law trusts or unincorporated businesses, including a general partnership or limited partnership, or convert into any such entity, formed under the laws of the State of Delaware or any other state of the United States of America, pursuant to a written agreement of merger or consolidation (“Merger Agreement”) or a written plan of conversion (“Plan of Conversion”), as the case may be, in accordance with this Article XIV.

Section 14.2 Procedure for Merger, Consolidation or Conversion.

(a) Merger, consolidation or conversion of the Partnership pursuant to this Article XIV requires the prior consent of the General Partner, provided, however, that, to the fullest extent permitted by law, the General Partner, in declining to consent to a merger, consolidation or conversion, may act in its sole discretion.

(b) If the General Partner shall determine to consent to the merger or consolidation, the General Partner shall approve the Merger Agreement, which shall set forth:

(i) the name and jurisdiction of formation or organization of each of the business entities proposing to merge or consolidate;

(ii) the name and jurisdiction of formation or organization of the business entity that is to survive the proposed merger or consolidation (the “Surviving Business Entity”);

(iii) the terms and conditions of the proposed merger or consolidation;

(iv) the manner and basis of exchanging or converting the equity interests of each constituent business entity for, or into, cash, property or interests, rights, securities or obligations of the Surviving Business Entity; and (i) if any general or limited partner interests, securities or rights of any constituent business entity are not to be exchanged or converted solely for, or into, cash, property or general or limited partner interests, rights, securities or obligations of the Surviving Business Entity, the cash, property or general or limited partner interests, rights, securities or obligations of any limited partnership, corporation, trust or other entity (other than the Surviving Business Entity) which the holders of such general or limited partner interests, securities or rights are to receive in exchange for, or upon conversion of their general or limited partner interests, securities or rights, and (ii) in the case of equity interests represented by certificates, upon the surrender of such certificates, which cash, property or general or limited partner interests, rights, securities or obligations of the Surviving Business Entity or any general or limited partnership, corporation, trust or other entity (other than the Surviving Business Entity), or evidences thereof, are to be delivered;

(v) a statement of any changes in the constituent documents or the adoption of new constituent documents (the articles or certificate of incorporation, articles of trust, declaration of trust, certificate or agreement of limited partnership or other similar charter or governing document) of the Surviving Business Entity to be effected by such merger or consolidation;

(vi) the effective time of the merger, which may be the date of the filing of the certificate of merger pursuant to Section 14.4 or a later date specified in or determinable in accordance with the Merger Agreement (provided, that if the effective time of the merger is to be later than the date of the filing of the certificate of merger, the effective time shall be fixed no later than the time of the filing of the certificate of merger and stated therein); and

(vii) such other provisions with respect to the proposed merger or consolidation that the General Partner determines to be necessary or appropriate.

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(c) If the General Partner shall determine to consent to the conversion, the General Partner shall approve the Plan of Conversion, which shall set forth:

(i) the name of the Partnership and the converted entity;

(ii) a statement that the Partnership is continuing its existence in the organizational form of the converted entity;

(iii) a statement as to the type of entity that the converted entity is to be and the state or country under the laws of which the converted entity is to be incorporated, formed or organized;

(iv) the manner and basis of exchanging or converting Partnership Interests for, or into, cash, property or interests, rights, securities or obligations of the converted entity;

(v) in an attachment or exhibit, the certificate of limited partnership of the Partnership;

(vi) in an attachment or exhibit, the certificate of limited partnership, articles of incorporation or other organizational documents of the converted entity;

(vii) the effective time of the conversion, which may be the date of the filing of the certificate of conversion or a later date specified in or determinable in accordance with the Plan of Conversion (provided, that if the effective time of the conversion is to be later than the date of the filing of such certificate of conversion, the effective time shall be fixed at a date or time certain at or prior to the time of the filing of such certificate of conversion and stated therein); and

(viii) such other provisions with respect to the proposed conversion that the General Partner determines to be necessary or appropriate.

Section 14.3 Approval by Partners of Merger or Consolidation.

(a) Except as provided in Section 14.3(d) and Section 14.3(e), the General Partner, upon its approval of the Merger Agreement or Plan of Conversion, as the case may be, shall direct that the Merger Agreement or Plan of Conversion, as applicable, be submitted to a vote of Partners, whether at a special meeting or by written consent, in either case in accordance with the requirements of Article XIII. A copy or a summary of the Merger Agreement or the Plan of Conversion, as applicable, shall be included in or enclosed with the notice of a special meeting or the written consent.

(b) Except as provided in Section 14.3(d) and Section 14.3(e), the Merger Agreement or Plan of Conversion shall be approved upon receiving the affirmative vote or consent of the holders of a Unit Majority unless the Merger Agreement or Plan of Conversion effects an amendment to any provision of this Agreement that, if contained in an amendment to this Agreement adopted pursuant to Article XIII, would require for its approval the vote or consent of a greater percentage of the Outstanding Common Units or of any class of Limited Partners, in which case such greater percentage vote or consent shall be required for approval of the Merger Agreement or Plan of Conversion.

(c) Except as provided in Section 14.3(d) and Section 14.3(e), after such approval by vote or consent of the Limited Partners, and at any time prior to the filing of the certificate of merger or certificate of conversion pursuant to Section 14.4, the merger, consolidation or conversion may be abandoned pursuant to provisions therefor, if any, set forth in the Merger Agreement or Plan of Conversion.

(d) Notwithstanding anything else contained in this Article XIV or in this Agreement, the General Partner is permitted, without Limited Partner approval, to convert the Partnership or any Group Member into a new limited liability entity, to merge the Partnership or any Group Member into, or convey all of the Partnership’s assets to, another limited liability entity that shall be newly formed and shall have no assets, liabilities or operations at the time of such merger or conveyance other than those it receives from the Partnership or other Group Member if (i) the General Partner has received an Opinion of Counsel that the conversion, merger or conveyance, as the

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case may be, would not result in the loss of the limited liability of any Limited Partner or any Group Member under the Delaware Act or cause the Partnership or any Group Member to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for U.S. federal income tax purposes (to the extent not already treated as such), (ii) the sole purpose of such conversion, merger or conveyance is to effect a mere change in the legal form of the Partnership into another limited liability entity and (iii) the General Partner determines that the governing instruments of the new entity provide the Limited Partners and the General Partner with substantially the same rights and obligations as are contained in this Agreement.

(e) Additionally, notwithstanding anything else contained in this Article XIV or in this Agreement, the General Partner is permitted, without Limited Partner approval, to merge or consolidate the Partnership with or into another entity if (A) the General Partner has received an Opinion of Counsel that the merger or consolidation, as the case may be, would not result in the loss of the limited liability under the Delaware Act of any Limited Partner or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for U.S. federal income tax purposes (to the extent not already treated as such), (B) the merger or consolidation would not result in an amendment to this Agreement, other than any amendments that could be adopted pursuant to Section 13.1, (C) the Partnership is the Surviving Business Entity in such merger or consolidation, (D) each Partnership Interest outstanding immediately prior to the effective date of the merger or consolidation is to be an identical Partnership Interest of the Partnership after the effective date of the merger or consolidation, and (E) the number of Partnership Interests to be issued by the Partnership in such merger or consolidation does not exceed 20% of the Partnership Interests Outstanding immediately prior to the effective date of such merger or consolidation.

Section 14.4 Certificate of Merger or Conversion. Upon the required approval by the General Partner and the Unitholders of a Merger Agreement or a Plan of Conversion, as the case may be, a certificate of merger or certificate of conversion, as applicable, shall be executed and filed with the Secretary of State of the State of Delaware in conformity with the requirements of the Delaware Act.

Section 14.5 Amendment of Partnership Agreement. Pursuant to Section 17-211(g) of the Delaware Act, an agreement of merger or consolidation approved in accordance with this Article XIV may (a) effect any amendment to this Agreement or (b) effect the adoption of a new partnership agreement for the Partnership if it is the Surviving Business Entity. Any such amendment or adoption made pursuant to this Section 14.5 shall be effective at the effective time or date of the merger or consolidation.

Section 14.6 Effect of Merger or Consolidation.

(a) At the effective time of the certificate of merger:

(i) all of the rights, privileges and powers of each of the business entities that has merged or consolidated, and all property, real, personal and mixed, and all debts due to any of those business entities and all other things and causes of action belonging to each of those business entities, shall be vested in the Surviving Business Entity and after the merger or consolidation shall be the property of the Surviving Business Entity to the extent they were of each constituent business entity;

(ii) the title to any real property vested by deed or otherwise in any of those constituent business entities shall not revert and is not in any way impaired because of the merger or consolidation;

(iii) all rights of creditors and all liens on or security interests in property of any of those constituent business entities shall be preserved unimpaired; and

(iv) all debts, liabilities and duties of those constituent business entities shall attach to the Surviving Business Entity and may be enforced against it to the same extent as if the debts, liabilities and duties had been incurred or contracted by it.

(b) A merger or consolidation effected pursuant to this Article shall not, for purposes of this Agreement, be deemed to result in a transfer or assignment of assets or liabilities from one entity to another.

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ARTICLE XV

GENERAL PROVISIONS

Section 15.1 Addresses and Notices; Written Communications.

(a) Any notice, demand, request, report or proxy materials required or permitted to be given or made to a Partner under this Agreement shall be in writing and shall be deemed given or made when delivered in person or when sent by first class United States mail or by other means of written communication to the Partner at the address described below. Any notice, payment or report to be given or made to a Partner hereunder shall be deemed conclusively to have been given or made, and the obligation to give such notice or report or to make such payment shall be deemed conclusively to have been fully satisfied, upon sending of such notice, payment or report to the Record Holder of such Partnership Interests at his address as shown on the records of the Transfer Agent or as otherwise shown on the records of the Partnership, regardless of any claim of any Person who may have an interest in such Partnership Interests by reason of any assignment or otherwise. Notwithstanding the foregoing, if (i) a Partner shall consent to receiving notices, demands, requests, reports or proxy materials via electronic mail or by the Internet or (ii) the rules of the Commission shall permit any report or proxy materials to be delivered electronically or made available via the Internet, any such notice, demand, request, report or proxy materials shall be deemed given or made when delivered or made available via such mode of delivery. An affidavit or certificate of making of any notice, payment or report in accordance with the provisions of this Section 15.1(a) executed by the General Partner, the Transfer Agent or the mailing organization shall be prima facie evidence of the giving or making of such notice, payment or report. If any notice, payment or report given or made in accordance with the provisions of this Section 15.1(a) is returned marked to indicate that such notice, payment or report was unable to be delivered, such notice, payment or report and, in the case of notices, payments or reports returned by the United States Postal Service (or other physical mail delivery mail service outside the United States of America), any subsequent notices, payments and reports shall be deemed to have been duly given or made without further mailing (until such time as such Record Holder or another Person notifies the Transfer Agent or the Partnership of a change in his address) or other delivery if they are available for the Partner at the principal office of the Partnership for a period of one year from the date of the giving or making of such notice, payment or report to the other Partners. Any notice to the Partnership shall be deemed given if received by the General Partner at the principal office of the Partnership designated pursuant to Section 15.1(a). The General Partner may rely and shall be protected in relying on any notice or other document from a Partner or other Person if believed by it to be genuine.

(b) The terms “in writing”, “written communications,” “written notice” and words of similar import shall be deemed satisfied under this Agreement by use of e-mail and other forms of electronic communication.

Section 15.2 Further Action. The parties shall execute and deliver all documents, provide all information and take or refrain from taking action as may be necessary or appropriate to achieve the purposes of this Agreement.

Section 15.3 Binding Effect. This Agreement shall be binding upon and inure to the benefit of the parties hereto and their heirs, executors, administrators, successors, legal representatives and permitted assigns.

Section 15.4 Integration. This Agreement constitutes the entire agreement among the parties hereto pertaining to the subject matter hereof and supersedes all prior agreements and understandings pertaining thereto.

Section 15.5 Creditors. None of the provisions of this Agreement shall be for the benefit of, or shall be enforceable by, any creditor of the Partnership.

Section 15.6 Waiver. No failure by any party to insist upon the strict performance of any covenant, duty, agreement or condition of this Agreement or to exercise any right or remedy consequent upon a breach thereof shall constitute waiver of any such breach of any other covenant, duty, agreement or condition.

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Section 15.7 Counterparts. This Agreement may be executed in counterparts, all of which together shall constitute an agreement binding on all the parties hereto, notwithstanding that all such parties are not signatories to the original or the same counterpart. Each party shall become bound by this Agreement immediately upon affixing its signature hereto or, in the case of a Person acquiring a Partnership Interest, pursuant to Section 10.1(a) without execution hereof.

Section 15.8 Applicable Law; Forum, Venue and Jurisdiction; Waiver of Trial by Jury; Attorney Fees.

(a) This Agreement shall be construed in accordance with and governed by the laws of the State of Delaware, without regard to the principles of conflicts of law.

(b) Each of the Partners and each Person holding any beneficial interest in the Partnership (whether through a broker, dealer, bank, trust company or clearing corporation or an agent of any of the foregoing or otherwise):

(i) irrevocably agrees that any claims, suits, actions or proceedings (A) arising out of or relating in any way to this Agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of this Agreement or the duties, obligations or liabilities among Partners or of Partners to the Partnership, or the rights or powers of, or restrictions on, the Partners or the Partnership), (B) brought in a derivative manner on behalf of the Partnership, (C) 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, (D) asserting a claim arising pursuant to any provision of the Delaware Act or (E) asserting a claim governed by the internal affairs doctrine shall be exclusively brought in the Court of Chancery of the State of Delaware (or, if such court does not have subject matter jurisdiction thereof, any other court located in the State of Delaware with subject matter jurisdiction), in each case regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims;

(ii) irrevocably submits to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or, if such court does not have subject matter jurisdiction thereof, any other court located in the State of Delaware with subject matter jurisdiction) in connection with any such claim, suit, action or proceeding;

(iii) agrees not to, and waives any right to, assert in any such claim, suit, action or proceeding that (A) it is not personally subject to the jurisdiction of the Court of Chancery of the State of Delaware or of any other court to which proceedings in the Court of Chancery of the State of Delaware may be appealed, (B) such claim, suit, action or proceeding is brought in an inconvenient forum, or (C) the venue of such claim, suit, action or proceeding is improper;

(iv) expressly waives any requirement for the posting of a bond by a party bringing such claim, suit, action or proceeding;

(v) consents to process being served in any such claim, suit, action or proceeding by mailing, certified mail, return receipt requested, a copy thereof to such party at the address in effect for notices hereunder, and agrees that such services shall constitute good and sufficient service of process and notice thereof; provided, nothing in this clause (v) shall affect or limit any right to serve process in any other manner permitted by law; and

(vi) IRREVOCABLY WAIVES THE RIGHT TO TRIAL BY JURY IN ANY SUCH CLAIM, SUIT, ACTION OR PROCEEDING.

Section 15.9 Invalidity of Provisions.

(a) If any provision or part of a provision of this Agreement is or becomes, for any reason, invalid, illegal or unenforceable in any respect (including because the enactment of such provision or part of a provision was prohibited by the agreement of limited partnership of the Organizational Limited Partner that was in effect as of the Effective Time (the “Organizational LP Partnership Agreement”)), the validity, legality and enforceability of

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the remaining provisions and part thereof contained herein shall not be affected thereby, and this Agreement shall, to the fullest extent permitted by law, be reformed and construed as if such invalid, illegal or unenforceable provision, or part of a provision, had never been contained herein, and such provision or part reformed so that it would be valid, legal and enforceable to the maximum extent possible.

(b) If this Agreement, when read together with each Supplemental Terms Annex then in effect, fails to include any provision, or part of a provision, from the Organizational LP Partnership Agreement that was required to be included herein (a “Required Provision”) by virtue of any provision of the Original LP Partnership Agreement for the transactions contemplated by the Merger and Contribution Agreement to be duly authorized and adopted without the consent of any limited partner of the Organizational Limited Partner, this Agreement shall, to the fullest extent permitted by law, be reformed and construed as if such Required Provision, or part of a Required Provision, had been included herein, and any provision or part of a provision of this Agreement that conflicts with any such Required Provision shall be reformed and construed as if such conflicting provision had never been contained herein; provided, that the terms of this Agreement shall only be modified by this Section 15.9(b) to the extent necessary to give effect to such Required Provision.

Section 15.10 Consent of Partners. Each Partner hereby expressly consents and agrees that, whenever in this Agreement it is specified that an action may be taken upon the affirmative vote or consent of less than all of the Partners, such action may be so taken upon the concurrence of less than all of the Partners and each Partner shall be bound by the results of such action.

Section 15.11 Facsimile and Email Signatures. The use of facsimile signatures and signatures delivered by email in portable document format (pdf) or other electronic format affixed in the name and on behalf of the Transfer Agent and registrar of the Partnership on Certificates representing Units is expressly permitted by this Agreement.

Section 15.12 Third Party Beneficiaries. Each Partner agrees that (a) any Indemnitee shall be entitled to assert rights and remedies hereunder as a third-party beneficiary hereto with respect to those provisions of this Agreement affording a right, benefit or privilege to such Indemnitee, and (b) any Unrestricted Person shall be entitled to assert rights and remedies hereunder as a third-party beneficiary hereto with respect to those provisions of this Agreement affording a right, benefit or privilege to such Unrestricted Person.

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IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the date first written above.

GENERAL PARTNER:
BLACK STONE MINERALS GP, L.L.C.
By:
	Name:
	Title:
LIMITED PARTNERS:
BLACK STONE MINERALS COMPANY, LP
By:	Black Stone Natural Resources, L.L.C.,
	its General Partner
By:
	Name:
	Title:
BLACK STONE MINERALS GP, L.L.C.
By:
	Name:
	Title:

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EXHIBIT A

Certificate Evidencing Common Units Representing Limited Partner Interests

in Black Stone Minerals, L.P

Exhibit A-1

ANNEX A – SERIES A PREFERRED UNITS

1. Adoption of Annex. This Annex, dated as of                     , 2015, is adopted pursuant to Section 5.5 of the First Amended and Restated Agreement of Limited Partnership of Black Stone Minerals, L.P. dated as of                     , 2015, as the same may be amended from time to time (the “Partnership Agreement”).

2. Designation of Series A Units. The General Partner hereby designates and creates a class of Preferred Units to be designated as “Series A Preferred Units” and consisting of                      Series A Preferred Units. The Series A Preferred Units shall be Limited Partner Interests and shall have the rights and preferences and shall be subject to the duties and obligations set forth in this Annex A.

3. Definitions. The following definitions shall be for all purposes, unless otherwise clearly indicated to the contrary, applied to the terms used in this Annex. Capitalized terms used but not defined in this Annex shall have the meanings given in the Partnership Agreement.

a. “Affiliate” means, with respect to any Person, (a) any Person that directly, or indirectly through one or more intermediaries, controls, is controlled by or is under common control with the Person to whom reference is made or (b) any Family Member of the Person to whom reference is made. The term “control” as used herein (including the terms “controlling,” “controlled by,” and “under common control with”) means the possession, direct or indirect, of the power (a) to vote 20% or more of the outstanding voting securities of or voting interest in a Person or (b) to direct the management policies of such Person by contract or otherwise.

b. “Annual Conversion/Redemption Deadline” has the meaning given in Paragraph 8(a).

c. “Applicable Law” or “Law” (whether the initial letter of the word or words is capitalized or in lower case type) means all applicable governmental actions, any constitutions, laws, statutes, treaties, rules, codes, ordinances, regulations, certificates, orders, official interpretations, licenses and permits of any applicable governmental authority and judgments, decrees, injunctions, writs, any voluntary restraint, policy or guideline, orders or like action of any court, arbitrator or other administrative, judicial or quasijudicial tribunal or agency of competent jurisdiction (including those pertaining to health and safety and all environmental laws).

d. “Budgeted Distributions” means, with respect to each calendar year, a schedule of the annual and quarterly budgeted distributions to the holders of Common Units in respect of such calendar year, as approved by the Board and as adjusted from time to time by the Board.

e. “Business Day” means any day other than a Saturday, Sunday or a holiday on which national banking associations in the state of Texas are required or permitted to be closed.

f. “Carter” means Thomas L. Carter, Jr.

g. “Change of Control” means (i) the transfer by the Limited Partners of beneficial ownership (as defined in Rule 13d-3 under the Exchange Act) of a majority of the outstanding Common Units (including the outstanding Series A Preferred Units on an as-converted basis), or the transfer by the Partnership of beneficial ownership of a majority of the outstanding membership interests in the Company, to any Person (including a “group” as such term is used in Section 13(d)(3) of the Exchange Act), except that if beneficial ownership would be deemed to occur merely upon the execution of voting agreements to support a merger, consolidation or other business combination transaction to be consummated in the future, then the date of such Change of Control shall instead be the date of such consummation; provided, however, that in no event shall any relationship among any Partners created solely by the ownership of Units be deemed, de facto, to create a group for purposes of this definition; (ii) the Partners of the Partnership prior to any merger, consolidation or other business combination transaction do not continue to own at least 50% of the surviving entity following such merger, consolidation or other business combination transaction to which the Partnership is a party; (iii) the Partnership does not continue to own at least 50% of the surviving entity following any merger, consolidation or other business combination transaction to which the

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Company is a party; or (iv) the Partnership sells, leases or exchanges all or substantially all of the assets of the Partnership and its controlled subsidiaries, taken as a whole, to any other Person (other than a direct or indirect controlled subsidiary of the General Partner or the Partnership).

h. “Closing Price” means for any day the last sale price on such day, regular way, or in case no such sale takes place on such day, the average of the closing bid and asked prices on such day, regular way, in either case as reported in the principal consolidated transaction reporting system with respect to securities listed or admitted for trading on the principal National Securities Exchange on which such Units of such class are listed or admitted to trading or, if such Units of such class are not listed or admitted to trading on any National Securities Exchange (other than the Nasdaq Stock Market), the last quoted price on such day or, if not so quoted, the average of the high bid and low asked prices on such day in the over-the-counter market, as reported by the Nasdaq Stock Market or such other system then in use, or, if on any such day such Limited Partner Interests of such class are not quoted by any such organization, the average of the closing bid and asked prices on such day as furnished by a professional market maker making a market in such Limited Partner Interests of such class selected by the General Partner, or if on any such day no market maker is making a market in such Limited Partner Interests of such class, the fair value of such Limited Partner Interests on such day as determined reasonably and in good faith by the General Partner.

i. “Company” means Black Stone Natural Resources, L.L.C., a Delaware limited liability company.

j. “Consolidated Net Income” shall mean with respect to the Partnership and its consolidated subsidiaries, for any period, the aggregate of the net income (or loss) of the Partnership and its consolidated subsidiaries after allowances for taxes for such period determined on a consolidated basis in accordance with GAAP; provided, that there shall be excluded from such net income (to the extent otherwise included therein) the following: (a) the net income of any Person in which the Partnership or any consolidated subsidiary has an interest (which interest does not cause the net income of such other Person to be consolidated with the net income of the Partnership and its consolidated subsidiaries in accordance with GAAP), except to the extent of the amount of dividends or distributions actually paid in such period or within the 60 day period following such period by such other Person to the Partnership or to a consolidated subsidiary, as the case may be; (b) the net income (but not loss) during such period of any consolidated subsidiary to the extent that the declaration or payment of dividends or similar distributions or transfers or loans by that consolidated subsidiary is not at the time permitted by operation of the terms of its charter or any agreement, instrument or Governmental Requirement applicable to such consolidated subsidiary or is otherwise restricted or prohibited, in each case determined in accordance with GAAP; (c) any extraordinary gains or losses during such period, including gains or losses attributable to Property sales not in the ordinary course of business, it being acknowledged and agreed that sales of oil and gas properties or interests therein are in the ordinary course of the Partnership’s business; and (d) the cumulative effect of a change in accounting principles and any gains or losses attributable to writeups or writedowns of assets; and provided, further, that if the Partnership or any consolidated subsidiary shall acquire or dispose of any Property during such period, then Consolidated Net Income shall be calculated after giving pro forma effect to such acquisition, disposition or redesignation, as if such acquisition, disposition or redesignation had occurred on the first day of such period.

k. “Conversion Date” means:

i. if a Conversion Notice for any Series A Preferred Unit is given by the holder thereof not later than 15 Business Days following receipt of the Partnership’s annual report pursuant to Section 8.3 of the Partnership Agreement containing financial statements with respect to the previous calendar year, the Conversion Date for such Series A Preferred Unit shall be deemed to be the January 1 immediately preceding the date on which such Conversion Notice is given;

ii. if a Conversion Notice for any Series A Preferred Unit is given by the holder thereof following the Liquidation Notice from the Partnership and prior to the making of any liquidating

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distributions pursuant to Paragraph 13(d), the Conversion Date for such Series A Preferred Unit shall be the day immediately preceding (but conditioned on) the making of any liquidating distributions pursuant to Paragraph 13(d);

iii. if any Series A Preferred Unit is to be converted on a Mandatory Conversion Date pursuant to Paragraph 6, the Conversion Date for such Series A Preferred Unit shall be deemed to be such Mandatory Conversion Date;

iv. if any Series A Preferred Unit is to be converted pursuant to Paragraph 8(f), the Conversion Date for such Series A Preferred Unit shall be the day immediately preceding (but conditioned on) the consummation of the Change of Control; and

v. if a Conversion Notice for any Series A Preferred Unit is provided by its holder and none of the clauses above applies, the Conversion Date for such Series A Preferred Unit shall be the first January 1 that follows the date such Conversion Notice is given; provided, however, that if prior to such date there is a Change of Control or a liquidation, the Conversion Date shall be the day immediately preceding (but conditioned on) the Change of Control or the making of any liquidating distributions pursuant to Paragraph 13(d), as applicable.

l. “Conversion Notice” has the meaning given in Paragraph 5(c).

m. “Conversion Price” has the meaning given in Paragraph 5(a).

n. “Conversion Rate” means, with respect to any Series A Preferred Unit as of the date of determination, the quotient obtained by dividing the Series A Preferred Investment Amount of such Series A Preferred Unit, as adjusted to such date of determination, by the Conversion Price of such Series A Preferred Unit then in effect.

o. “Convertible Securities” means Partnership Securities directly or indirectly convertible into or exchangeable or exercisable for Common Units.

p. “Credit Facility” means the Second Amended and Restated Credit Agreement, dated as of February 3, 2012, as amended by the First Amendment to Second Amended and Restated Credit Agreement, dated as of November 2, 2012, by and among the Partnership as borrower, Wells Fargo Banks, National Association, as administrative agent and the lenders signatory thereto, as further amended, and any successor credit agreement governing the senior indebtedness of the Partnership.

q. “Default” means the Partnership has failed for any reason (a) within 15 days after the last day of each calendar quarter to reduce to zero for all outstanding Series A Preferred Units the aggregate Unpaid Series A Preferred Yield accrued through the last day of such immediately preceding calendar quarter or (b) to redeem the Series A Preferred Units in accordance with and as and when required by Section 8 of this Annex.

r. “Derivative Instruments” means options, rights, warrants, appreciation rights, tracking, profit and phantom interests and other derivative instruments (other than equity interests in the Partnership) relating to, convertible into or exchangeable for Partnership Interests.

s. “Dispose,” “Disposing” or “Disposition” means, with respect to any asset (including Partnership Interests or any portion thereof), a sale, assignment, transfer (excluding the grant of a security interest), conveyance, gift, exchange or other disposition of such asset, whether such disposition be voluntary, involuntary or by operation of law, including the following: (a) in the case of an asset owned by a natural person, a transfer of such asset upon the death of its owner, whether by will, intestate succession or otherwise; (b) in the case of an asset owned by an Entity, (i) a change in control of such Entity (“control” being defined as a direct or indirect transfer of 50% or more of the voting securities of such Entity) or (ii) a distribution of such asset in connection with the dissolution, liquidation, winding-up or termination of such Entity (unless, in the case of dissolution, such Entity’s business is continued without the commencement of liquidation or winding-up); and (c) disposition in connection with, or in lieu of, a foreclosure of an encumbrance.

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t. “EBITDAX” means, with respect to the Partnership and its consolidated subsidiaries, for any period, (1) Consolidated Net Income for such period plus (2) the following expenses or charges to the extent deducted from Consolidated Net Income in such period: interest, taxes, depreciation, depletion, amortization, impairments and other similar noncash charges, exploration expenses, delay rentals, and dry hole expenses minus (3) all noncash income added to Consolidated Net Income, all as determined in accordance with GAAP.

u. “Entity” means any Person other than a natural person.

v. “Exchange Act” means the Securities Exchange Act of 1934, as amended, supplemented, or restated from time to time.

w. “Family Member” means (a) any ancestor or descendant (including any stepchild or adopted child) of a Limited Partner; (b) any spouse of a Limited Partner or ancestor or descendant of a Limited Partner; (c) any descendant of a grandparent of a Limited Partner; (d) any spouse of any descendant of a grandparent of a Limited Partner; (e) any trust established for the primary benefit of a Limited Partner or any of the foregoing Persons; (f) in the case of a Limited Partner which is a trust, any beneficiary of such trust; (g) an Entity which is controlled (whether by ownership of voting securities or contract or other arrangement) by the Limited Partner or any of the foregoing Persons; or (h) any organization described in Section 170(b)(1)(A), 170(c), 2055(a) or 2522(a) of the Code.

x. “GAAP” shall mean generally accepted accounting principles in the United States of America as in effect from time to time, applied on a basis consistent with the audited consolidated financial statements of the Partnership (except for changes concurred with by the Partnership’s independent public accountants).

y. “Governmental Requirement” shall mean any law, statute, code, ordinance, order, determination, rule, regulation, judgment, decree, injunction, franchise, permit, certificate, license, authorization or other directive or requirement, including environmental laws, energy regulations and occupational, safety and health standards or controls, of any governmental authority.

z. “Holder Redemption Notice” has the meaning given in Paragraph 8(a).

aa. “Holder Redemption Price” has the meaning given such term in Paragraph 8(a).

bb. “Interest Fair Market Value” means, as of any date, the amount which would be received by the holder of a Common Unit if (a) all of the Series A Preferred Units and other Convertible Securities were converted into or exchanged or exercised for Common Units, (b) the fair market value of the assets of the Partnership in excess of its liabilities as of the date of determination of Interest Fair Market Value equaled the Value as of such date, adjusted to reflect any increases in equity value resulting from the deemed conversion, exchange or exercise of Convertible Securities, and (c) an amount equal to such Value, as so adjusted, were distributed to the Partners in accordance with Paragraph 13(d).

cc. “Junior Redemption Securities” has the meaning given in Paragraph 4(b)(iii).

dd. “Key Man Event” has the meaning given in Paragraph 8(c).

ee. “Key Man Objection Notice” has the meaning given in Paragraph 8(c).

ff. “Liquidation Notice” has the meaning given in Paragraph 10.

gg. “Management” means Thomas L. Carter, Jr. and any of his controlled Affiliates.

hh. “Mandatory Conversion Date” means January 1 of each of the years 2015 through 2018.

ii. “Maximum Annual Redemption” means, for a Series A Preferred Unitholder on any Scheduled Redemption Date, the excess of (i) 25% of the sum of (A) the number of Series A Preferred Units held by such Series A Preferred Unitholder as of the date of its Holder Redemption Notice plus

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(B) the number of Series A Preferred Units which, while held by such Series A Preferred Unitholder, were previously redeemed or converted into Common Units, over (ii) the aggregate Redemption Adjustment Amounts in respect of all prior Scheduled Redemption Dates.

jj. “Minimum Conversion/Redemption Amount” means, for a Series A Preferred Unitholder on any Mandatory Conversion Date, the product of (i) the sum of (A) the number of Series A Preferred Units held by such Series A Preferred Holder on the Mandatory Conversion Date plus (B) the number of Series A Preferred Units which, while held by such Series A Preferred Unitholder, were previously redeemed or converted into Common Units, times (ii) the percentage specified below with respect to the applicable Mandatory Conversion Date:

Mandatory Conversion Date Percentage

January 1, 2015	25	%
January 1, 2016	50	%
January 1, 2017	75	%
January 1, 2018	100	%

kk. “National Securities Exchange” means an exchange registered with the Securities and Exchange Commission under Section 6(a) of the Exchange Act, and any successor to such statute, or the Nasdaq Stock Market or any successor thereto.

ll. “Partnership” means Black Stone Minerals, L.P..

mm. “Partnership Act” means the Delaware Revised Uniform Limited Partnership Act, as amended from time to time.

nn. “Partnership Agreement” has the meaning given in Paragraph 1.

oo. “Partnership Redemption Price” has the meaning given such term in Paragraph 8(e).

pp. “Partnership Securities” means Partnership Interests, Derivative Instruments, or any unsecured or secured debt obligations of the Partnership or debt obligations of the Partnership convertible into any class of Partnership Interests.

qq. “Per Unit Capital Account” means, as of any date of determination, the Capital Account stated on a per Unit basis, underlying any class of Units held by a Person.

rr. “Permitted Transferee” means, with respect to any Partner, (a) any other Partner; (b) any Family Member of such Partner; (c) in the case of a Limited Partner which is an Entity, any owner (including a partner, shareholder or member) of such Entity; or (d) any Affiliate of such Partner.

ss. “Person” means any individual, corporation, company, limited liability company, voluntary association, partnership, joint venture, trust, unincorporated organization or government or any agency, instrumentality or political subdivision thereof, or any other form of entity.

tt. “Property” means all assets, properties and rights of any type owned or acquired by the Partnership.

uu. “Pro Rata” means when used with respect to (a) Common Units or any class thereof, apportioned equally among all designated Units in accordance with their relative Percentage Interests, (b) all Partners or Record Holders, apportioned among all Partners or Record Holders in accordance with their relative Percentage Interests, (c) some but not all Partners or Record Holders, apportioned among such Partners or Record Holders in accordance with their relative Percentage Interests, and (d) Series A Preferred Units, apportioned among such Units based on the number of Outstanding Series A Preferred Units or, if used with respect to Series A Units being redeemed or converted, apportioned among such Units based on the number of such Units being redeemed or converted.

vv. “Redemption Adjustment Amount” means, for a Series A Preferred Unitholder, in respect of the Scheduled Redemption Date on December 31, 2015, 33-1/3% of the number of Series A Preferred

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Units redeemed from such Series A Preferred Unitholder pursuant to Paragraph 8(e) on the Scheduled Redemption Date on December 31, 2014, and in respect of the Scheduled Redemption Date on December 31, 2016, the sum of (i) 33-1/3% of the number of Series A Preferred Units redeemed from such Series A Preferred Unitholder pursuant to Paragraph 8(e) on the Scheduled Redemption Date on December 31, 2014, plus (ii) 50% of the number of Series A Preferred Units redeemed from such Series A Preferred Unitholder pursuant to Paragraph 8(e) on the Scheduled Redemption Date on December 31, 2015.

ww. “Redemption Date” means any Scheduled Redemption Date or other date of redemption of Series A Preferred Units pursuant to Paragraph 8(a).

xx. “Representation Breach” means one or more inaccuracies in or breaches of the Partnership’s representations and warranties in the Securities Purchase Agreement other than those in Section 3.3(a) of the Securities Purchase Agreement, which inaccuracy or breach will be determined by disregarding any knowledge qualifiers, which have resulted in or would be reasonably expected to result in a reduction in the value of the Partnership’s equity of at least $100,000,000 from what would have been the value of the Partnership’s equity had such representations and warranties been true and correct (disregarding knowledge qualifiers). For purposes of determining whether a Representation Breach has occurred by reason of a breach of the last sentence of Section 3.12(a) of the Securities Purchase Agreement, the $100 million threshold in such sentence shall be disregarded to avoid duplication with the $100,000,000 threshold above in this definition.

yy. “Required Allocations” means any allocation of an item of income, gain, loss and deduction pursuant to Paragraphs 13(a)(ii)(1), 13(a)(ii)(2), 13(a)(ii)(4), 13(a)(ii)(5), 13(a)(ii)(6), 13(a)(ii)(7) or 13(a)(ii)(9), or 13(a)(iii).

zz. “Scheduled Redemption Date” means December 31 of each of the years 2014 through 2017.

aaa. “Securities Purchase Agreement” means that certain Securities Purchase Agreement, dated as of July 10, 2009 by and among certain of the Series A Preferred Unitholders, the Partnership and the General Partner, as it may be amended or supplemented from time to time.

bbb. “Series A Liquidation Preference Amount” means, with respect to any Series A Preferred Unit outstanding at the time of the liquidation of the Partnership, an amount equal to the sum of (i) the Unpaid Series A Preferred Yield plus (ii) the Series A Preferred Investment Amount.

ccc. “Series A Majority” means Series A Preferred Unitholders (other than Management) holding of record a majority of the Series A Preferred Units then outstanding and not held by Management.

ddd. “Series A Majority Approval” means the affirmative vote at a meeting of Series A Preferred Unitholders, or the written consent, of a Series A Majority.

eee. “Series A Preferred Investment Amount” means, for any Series A Preferred Unit, the $1,000.00 of Capital Contributions made to the Partnership in respect of such Series A Preferred Unit.

fff. “Series A Preferred Unit” means an undivided fractional part of the Partnership Interests of all the Series A Preferred Unitholders and their assignees to the extent such Partnership Interests are attributable to the Units designated as “Series A Preferred Units.”

ggg. “Series A Preferred Unitholder” means a holder of a Series Preferred A Unit.

hhh. “Series A Preferred Yield” means, with respect to each Series A Preferred Unit and as of any date of determination, the interest amount that would be accrued as of such determination date on a hypothetical promissory note having the following terms, (a) an original principal amount equal to $1,000, (b) an issuance date on the Closing Date, (c) interest that accrues on a daily basis, based on a 365-day year, at a per annum rate equal to the Yield Rate applicable on each day (i.e., taking into account fluctuations in the Yield Rate when determining each daily accrual), and (d) compounding on any interest accrual that remains unpaid as of the last day of each calendar quarter that occurs on or

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before the Conversion Date of such Series A Preferred Unit (if it is converted) or the Redemption Date of such Series A Preferred Unit (if it is redeemed); provided, that for purposes of determining compounding under this clause (d), distributions made by the Partnership in respect of such Series A Preferred Unit under Paragraph 13(c)(i) within 15 days after the end of a calendar quarter shall be deemed to have been paid on the day before the last day of such calendar quarter so that compounding does not occur on such distributed amounts.

iii. “Series A Super Majority” means Series A Preferred Unitholders (other than Management) holding of record at least 70% of the Series A Preferred Units then outstanding and not held by Management.

jjj. “Series A Super Majority Approval” means the affirmative vote at a meeting of Series A Preferred Unitholders, or the written consent, of a Series A Super Majority.

kkk. “Specified Series A Investor” means a Series A Preferred Unitholder party to the Securities Purchase Agreement and any of its transferees.

lll. “Threshold Amount” means, at any time, 99% of the difference obtained by subtracting (a) the sum of (i) the reserve-based borrowing base under the Credit Facility in effect at such time, plus (ii) the Unreturned Series A Preferred Investment Amount at such time, plus (iii) the Unpaid Series A Preferred Yield at such time from (b) 70% of the present value of the cash flows from the Partnership’s proved oil and gas reserves reflected in the Partnership’s most recent third party reserve report, discounted at 10% per year.

mmm. “Trading Day” means a day on which the principal National Securities Exchange on which such Units of any class are listed or admitted to trading is open for the transaction of business or, if Units of a class are not listed or admitted to trading on any National Securities Exchange, a day on which banking institutions in New York City generally are open.

nnn. “Unpaid Series A Preferred Yield” means, with respect to each Series A Preferred Unit and as of any date of determination, an amount equal to the excess, if any, of (a) the cumulative Series A Preferred Yield from the Closing Date through such date, over (b) the cumulative amount of distributions made as of such date in respect of such Series A Preferred Unit pursuant to Paragraph 13(c)(i).

ooo. “Unreturned Series A Preferred Investment Amount” means, for any Series A Preferred Unit, as of any time, an amount equal to the excess, if any, of (a) the Series A Preferred Investment Amount of such Series A Preferred Unit, over (b) an amount equal to the excess, if any, of (i) the aggregate amount of distributions made by the Partnership with respect to such Series A Preferred Unit pursuant to Paragraph 13(d), over (ii) the Unpaid Series A Preferred Yield, if any, with respect to such Series A Preferred Unit at the time of any such distributions.

ppp. “Value” means, as of any date of determination, (i) the value of the Partnership’s equity as of December 31 of the calendar year preceding the calendar year in which such determination date falls, as determined by the Board in good faith based upon its review of a report of a third party valuation firm selected by the Board, plus (ii) any Capital Contributions made to the Partnership from and after the applicable date in clause (i) to but excluding such determination date, minus (iii) any amounts paid by the Partnership or its subsidiaries (to the extent of the Partnership’s net interest in any such subsidiary) to redeem or repurchase any Partnership Securities (other than convertible debt obligations) from and after the applicable date in clause (i) to but excluding such determination date.

qqq. “Yield Rate” means a rate of 10% per annum; provided, however, that from and after the occurrence of a Default and during the continuation of a Default, without any action by the Series A Preferred Unitholders the Yield Rate shall increase 500 basis points, or 5% per annum, on the date of Default and on each 90 day anniversary of the date of Default during which the Partnership remains in Default, to a maximum rate of 30% per annum; provided, further, however, that the Yield Rate shall be 10% per annum at and from such time as the Default is no longer continuing.

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4. Voting; Waiver.

a. Except with respect to matters requiring Series A Super Majority Approval, Series A Majority Approval or the approval of a Series A Preferred Unitholder pursuant to Paragraphs 4(b), 4(c) or 4(d) of this Annex, at each meeting of the Limited Partners (or pursuant to any action by written consent), with respect to any and all matters presented to the Limited Partners for their action or consideration, each Series A Preferred Unitholder shall be entitled to vote as a single class with the Common Units. Each Series A Preferred Unit shall have a number of votes equal to the number of Common Units into which such Series A Preferred Unit is convertible at the time of such vote or consent.

b. Notwithstanding the other provisions of the Partnership Agreement or this Annex, without first obtaining Series A Super Majority Approval, the General Partner shall not, and shall not cause the Partnership to, either directly or indirectly, by amendment, merger, consolidation or otherwise, do any of the following:

i. amend or modify any provision of the Partnership Agreement or this Annex that has the effect of amending or modifying the rights, preferences or designations of the Series A Preferred Units, except for any amendment or modification described in Paragraph 4(c) or 4(d) of this Annex, which shall be subject to the approval required in such Paragraph;

ii. create, or authorize the creation of, or issue or obligate itself to issue, any Partnership Securities having preferences or rights with priority over or on a parity with the Series A Preferred Units with respect to rights to share in distributions, including those on liquidation or, except as provided in Paragraph 4(b)(iii), redemption obligations or redemption rights;

iii. create, or authorize the creation of, or issue or obligate itself to issue, any Partnership Securities having redemption rights arising on a date prior to the last Mandatory Conversion Date contemplated herein (“Junior Redemption Securities”); provided, however, that the Partnership shall have the right to create, authorize the creation of, issue or obligate itself to issue Junior Redemption Securities in an aggregate amount that, together with prior issuances of Junior Redemption Securities, does not exceed the Threshold Amount (measured at the time of issuance (which shall be a positive number)), and provided, further, that in no event shall any such Junior Redemption Securities have redemption rights that permit or require a payment to the holders thereof of more than one-third of the aggregate issuance price of such Junior Redemption Securities (measured at the time of issuance), plus any accrued and unpaid distributions, during the 12-month periods commencing on each of July 1, 2014, July 1, 2015 and July 1, 2016;

iv. issue or obligate itself to issue any Series A Preferred Units; or

v. effect any amendment, modification or waiver that by its explicit terms would alter or change the rights of the Series A Preferred Unitholders pursuant to Paragraph 13.

c. Notwithstanding the other provisions of the Partnership Agreement or this Annex, without first obtaining a Series A Majority Approval, the General Partner shall not, and shall not cause the Partnership to, either directly or indirectly, by amendment, merger, consolidation or otherwise, effect any split, reverse split, subdivision, combination or similar action with respect to the Series A Preferred Units.

d. Notwithstanding the other provisions of the Partnership Agreement or this Annex, without first obtaining the written consent or waiver of the affected Series A Preferred Unitholder, the General Partner shall not, and shall not cause the Partnership to, either directly or indirectly, by amendment, merger, consolidation or otherwise, do any of the following:

i. effect any amendment, modification or waiver that by its explicit terms would alter or change the rights, obligations, powers or preferences of such Series A Preferred Unitholder in its capacity as a holder of Series A Preferred Units in a disproportionate and adverse manner compared to other holders of Series A Preferred Units;

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ii. effect any amendment, modification or waiver that would alter, or result in the alteration of, the limited liability of such Series A Preferred Unitholder;

iii. effect any amendment, modification or waiver that would impose any additional material obligations or duties on such Series A Preferred Unitholder; or

iv. amend, modify or waive the provisions of this Paragraph 4(d)(iv).

e. Any of the rights, powers or preferences of the Series A Preferred Unitholders set forth herein may be waived in writing by any Series A Preferred Unitholder with respect to such holder.

5. Optional Conversion.

a. Each Series A Preferred Unit may be converted, at the option of the holder thereof, at any time and from time to time, and without the payment of additional consideration by the holder thereof, into Common Units at the then effective Conversion Rate. The Series A Preferred Units shall have an initial Conversion Price of $1.1020948 (as adjusted as provided herein, the “Conversion Price”) and an initial Conversion Rate of 898.2893305 Common Units per Series A Preferred Unit, each subject to adjustment as provided herein.

b. The initial Conversion Price and the initial Conversion Rate for the Series A Preferred Units, each of which is subject to adjustment as provided herein, shall be set forth in one or more written statements signed by the General Partner and maintained at the principal office of the Partnership. The Conversion Rate and Conversion Price from time to time in effect are subject to adjustment as provided in Paragraph 7.

c. In order to exercise the conversion privilege, the holder of any Series A Preferred Units to be converted shall give written notice (the “Conversion Notice”) to the Partnership that the holder elects to convert all or a specified number of Series A Preferred Units held. A Conversion Notice may be given at any time but shall only be effective as of the Conversion Date.

d. Upon any such conversion, no adjustment to the Conversion Rate shall be made for Unpaid Series A Preferred Yield on the Series A Preferred Units surrendered for conversion or any unpaid distributions on the Common Units delivered pursuant thereto. The Series A Preferred Unitholder shall remain entitled to receive his Unpaid Series A Preferred Yield accrued through the date prior to the Conversion Date, the Partnership shall pay such amount to such holder promptly following receipt of the Conversion Notice, and any such payment shall be treated as a distribution to such Series A Preferred Unitholder for purposes of maintaining Capital Accounts. Upon each conversion, the Partnership shall make a cash payment to the converting Series A Preferred Unitholder, and the converting Series A Preferred Unitholder shall make a cash payment to the Partnership, to adjust for any distributions declared in respect of the Common Units or the Series A Preferred Units on or after the Conversion Date but prior to the receipt of the Conversion Notice, the intent being to put both the converting Series A Preferred Unitholder and the Partnership in the same position that they would have been if the Conversion Notice had been delivered on or before the Conversion Date. Any cash payment made pursuant to the preceding sentence shall be treated as (i) a distribution to the Series A Preferred Unitholder if made by the Partnership and (ii) a Capital Contribution if made by the Series A Preferred Unitholder.

e. The Partnership shall not issue fractions of Common Units upon conversion of Series A Preferred Units or scrip in lieu thereof. If any fraction of a Common Unit would, except for the provisions of this Paragraph 5(e), be issuable upon conversion of any Series A Preferred Unit, the Partnership shall in lieu thereof pay to the Person entitled thereto an amount in cash equal to the current value of such fraction, calculated to the nearest one-hundredth (1/100) of a Common Unit, to be computed on the basis of the Interest Fair Market Value of one Common Unit as determined by the General Partner; provided, however, that if the amount payable in respect of any fractional Common Unit would not exceed $10.00, the Partnership may at its option round the number of Common Units to be issued in respect of the conversion of Series A Preferred Units to the nearest whole number, with 0.50 Common

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Unit being rounded up to one Common Unit. As soon as practicable after the effectiveness of any conversion, the Partnership shall cause to be issued and delivered to the converting holder any cash in lieu of a fraction of a Common Unit otherwise issuable upon such conversion. For purposes of determining fractional units, all Common Units or fractions thereof being issued to a holder upon conversion as of a particular Conversion Date shall be aggregated so that, under no circumstances, would any particular conversion by a holder result in more than one fractional Common Unit.

f. The Series A Preferred Units shall cease to be convertible on the day of the first liquidating distribution pursuant to Paragraph 13.

g. Each Series A Preferred Unit which shall have been surrendered for conversion as herein provided shall no longer be deemed to be outstanding as of the Conversion Date and all rights with respect to such Series A Preferred Unit shall terminate, except only the rights of the holder thereof to receive Common Units in exchange therefor (and any payment in lieu of a fractional Common Unit pursuant to Paragraph 5(e)) and payment of any Unpaid Series A Preferred Yield thereon.

h. In the event of an inaccuracy in or breach of the representations and warranties in Section 3.3(a) of the Securities Purchase Agreement, determined without regard to any knowledge qualifiers, the sole and exclusive remedies therefor shall be (i) the recalculation and adjustment of the Conversion Price to what it would have been if there had been no such breach, recalculating such Conversion Price as equal to the lesser of (1) the initial Conversion Price of $1.1020948, or (2) the quotient obtained by dividing (A) the Value determined immediately before the issuance of the Series A Preferred Units pursuant to the Securities Purchase Agreement by (B) the total number of Common Units outstanding on the date of issuance of such Series A Preferred Units (assuming (x) the conversion of the then issued and outstanding Series A Preferred Units into Common Units at the then applicable Conversion Rate and (y) any issued and outstanding Common Units held by members of the Board or Officers or employees of the Partnership, the General Partner or any subsidiary of the Partnership or the General Partner are outstanding even if subject to forfeiture), (ii) the issuance by the Partnership of any additional Common Units that would have been issued by the Partnership upon conversion of Series A Preferred Units, if necessary, and (iii) the payment of any additional distributions that would have been paid by the Partnership or the Company, if necessary, in the case of each of clauses (i) through (iii) above as if the initial Conversion Price had been correctly determined.

6. Mandatory Conversion

a. Effective as of each Mandatory Conversion Date, there shall automatically be converted into Common Units at the then effective Conversion Rate a number of Series A Preferred Units held by each Series A Preferred Unitholder (after the provisions of Paragraphs 8(a) and 8(e) are applied with respect to the Scheduled Redemption Date immediately preceding such Mandatory Conversion Date) equal to the amount, if any, by which the applicable Minimum Conversion/Redemption Amount exceeds the number of Series A Preferred Units which, while held by such Series A Preferred Unitholder, were previously redeemed or converted into Common Units. If a Series A Preferred Unitholder Disposes of any Series A Preferred Units which are subject to conversion pursuant to this Paragraph 6 on or after the Mandatory Conversion Date and on or before the later of the Annual Redemption/Conversion Deadline or 10 days after the Partnership’s receipt from and such Series A Preferred Unitholder of a Holder Redemption Notice pursuant to Paragraph 8(a), such Series A Preferred Units so Disposed shall, in the hands of the transferee, be subject to conversion pursuant to this Paragraph 6.

b. Effective as of each Mandatory Conversion Date, any Series A Preferred Unit so converted shall no longer be deemed to be outstanding and all rights with respect to each Series A Preferred Unit so converted shall terminate, except only the rights of the holder thereof to receive the number of Common Units into which such Series A Preferred Unit has been converted (and any payment in lieu of a fractional Common Unit pursuant to Paragraph 5(e)) and payment of any Unpaid Series A Preferred Yield thereon, which the Partnership shall pay to the holder promptly following the implementation of mandatory conversion pursuant to Paragraph 6, and any such payment shall be treated as a distribution to such Series A Preferred Unitholder for purposes of

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maintaining Capital Accounts. Upon each conversion, the Partnership shall make a cash payment to the converting Series A Preferred Unitholder, and the converting Series A Preferred Unitholder shall make a cash payment to the Partnership, to adjust for any distributions declared in respect of the Common Units or the Series A Preferred Units on or after the Conversion Date but prior to the implementation of mandatory conversion pursuant to Paragraph 6, the intent being to put both the converting Series A Preferred Unitholder and the Partnership in the same position that they would have been if the mandatory conversion pursuant to Paragraph 6 had been implemented on the Mandatory Conversion Date. Any cash payment made pursuant to the preceding sentence shall be treated as (i) a distribution to the Series A Preferred Unitholder if made by the Partnership and (ii) a Capital Contribution if made by the Series A Preferred Unitholder.

7. Anti-Dilution Provisions

a. The Conversion Price and the Conversion Rate shall be subject to adjustment from time to time in accordance with this Paragraph 7.

b. In case the Partnership shall at any time (i) subdivide the outstanding Common Units, (ii) make a distribution on its outstanding Common Units payable in Common Units or (iii) combine its outstanding Series A Preferred Units, the Conversion Price in effect immediately prior to such subdivision or distribution shall be proportionately decreased (with appropriate adjustments to the Conversion Rate in effect immediately prior to such subdivision or distribution). In case the Partnership shall at any time (i) combine its outstanding Common Units, (ii) subdivide the outstanding Series A Preferred Units or (iii) make a distribution on its outstanding Series A Preferred Units payable in Series A Preferred Units, the Conversion Price in effect immediately prior to such combination shall be proportionately increased (with appropriate adjustments to the Conversion Rate in effect immediately prior to such combination).

c. If any capital reorganization or reclassification of the Units of the Partnership or consolidation or merger of the Partnership with another Entity shall be effected in such a way that Common Unitholders shall be entitled to receive stock, securities, cash or other property with respect to or in exchange for Common Units, then, as a condition of such reorganization, reclassification, consolidation or merger, lawful and adequate provision shall be made whereby the Series A Preferred Unitholders shall have the right to acquire and receive upon conversion of the Series A Preferred Units, such shares of stock, securities, cash or other property issuable or payable (as part of the reorganization, reclassification, consolidation, merger or sale) with respect to or in exchange for such number of outstanding Common Units as would have been received upon conversion of the Series A Preferred Units at the Conversion Rate then in effect. The Partnership will not effect any such consolidation, merger or sale unless prior to the consummation thereof the successor Entity (if other than the Partnership) resulting from such consolidation or merger or the Person purchasing such assets shall expressly assume by written instrument the obligation to deliver to each such holder such stock, securities, cash or other property as, in accordance with the foregoing provisions, such holder may be entitled to acquire and receive.

d. If any event occurs as to which, in the good faith opinion of the General Partner, the provisions of this Paragraph 7 are not strictly applicable or if strictly applicable would not fairly protect the rights of the Series A Preferred Unitholders in accordance with the essential intent and principles of such provisions, then the General Partner shall make an adjustment in the application of such provisions, in accordance with such essential intent and principles, so as to protect such rights as aforesaid.

e. Whenever the Conversion Rate and the Conversion Price shall be adjusted as provided in this Paragraph 7 hereof, the General Partner shall forthwith file at the principal office of the Partnership a statement, signed by the General Partner, showing in reasonable detail the facts requiring such adjustment and the Conversion Rate that will be effective after such adjustment. Upon written request, the General Partner shall provide the requesting Series A Preferred Unitholder with the then applicable Conversion Price and Conversion Rate for the Series A Preferred Units.

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8. Redemption

a. With respect to each Scheduled Redemption Date, each Series A Preferred Unitholder may, upon written notice (the “Holder Redemption Notice”) given to the Partnership not earlier than the November 1 preceding such Scheduled Redemption Date and not later than the later of (i) the March 31 following such Scheduled Redemption Date or (ii) 15 Business Days following the filing of the Partnership’s Annual Report on Form 10-K (such later date being the “Annual Redemption/Conversion Deadline”), require the Partnership to redeem (to the extent that such redemption shall not violate any applicable provisions of the Partnership Act or other Applicable Laws) from such Series A Preferred Unitholder effective as of each Scheduled Redemption Date, for a cash price per Series A Preferred Unit equal to the sum of the Series A Preferred Investment Amount plus the Unpaid Series A Preferred Yield accrued through the Scheduled Redemption Date (such aggregate amount, the “Holder Redemption Price”), a number of Series A Preferred Units not in excess of the Maximum Annual Redemption of such Series A Preferred Unitholder. As promptly as practicable and in any event not later than the later of the Scheduled Redemption Date or 10 days after the receipt of a Holder Redemption Notice pursuant to this Paragraph 8, the Partnership shall pay to the redeeming Series A Preferred Unitholder the Holder Redemption Price plus, in the event of a payment after the Scheduled Redemption Date, interest on the Holder Redemption Price at the Yield Rate from the Scheduled Redemption Date until the date paid to the redeeming Series A Preferred Unitholder.

b. If the Partnership has made a Representation Breach, a Specified Series A Investor may notify the General Partner (a “Representation Breach Notice”) of the Representation Breach and each Series A Preferred Unitholder shall have the right to require the Partnership to redeem its Series A Preferred Units for a cash price per Series A Preferred Unit equal to the Holder Redemption Price. If the General Partner disputes the occurrence of a Representation Breach, then an independent third party arbitrator shall determine if a Representation Breach occurred, which arbitrator shall be jointly selected by the General Partner and the Specified Series A Investors holding a majority of the Series A Preferred Units held by the Specified Series A Investors sending a Representation Breach Notice. The expense of the arbitrator shall be borne by the Partnership if the arbitrator determines that a Representation Breach occurred or by the Specified Series A Investors sending a Representation Breach Notice if the arbitrator determines that a Representation Breach did not occur. The General Partner shall provide the Series A Preferred Unitholders prompt notice following the final determination of the occurrence of a Representation Breach and for 60 days after such notice each Series A Preferred Unitholder shall have the right to send a Holder Redemption Notice to the General Partner. Upon receipt of a Holder Redemption Notice pursuant to this Paragraph 8(b), the Partnership shall redeem one-third of the number of Series A Preferred Units for which a Series A Preferred Unitholder requests redemption on December 31 of each of the calendar year in which such Holder Redemption Notice is received and the two following calendar years; provided, however, that in the event of a Change of Control or a liquidation occurring prior to redemption of such Series A Preferred Units in full pursuant to this Paragraph 8(b), the Partnership shall redeem 100% of such unredeemed Series A Preferred Units on the date of consummation of such Change of Control or the date of the first liquidating distribution pursuant to Paragraph 13(d), as applicable, at a cash price per Series A Preferred Unit equal to the Holder Redemption Price. For purposes of clarity, the Unpaid Series A Preferred Yield shall continue to accrue at the Yield Rate on each outstanding Series A Preferred Unit until redeemed.

c. If Carter is no longer chief executive officer of the General Partner or any successor general partner of the Partnership or otherwise actively involved in the investment decisions, management and operations of the Partnership (“Key Man Event”), a Series A Preferred Unitholder may notify the General Partner of its objection (“Key Man Objection Notice”), and each Series A Preferred Unitholder shall have the right to require the Partnership to redeem its Series A Preferred Units for a cash price per Series A Preferred Unit equal to the Holder Redemption Price; provided, however, that if the General Partner disputes the occurrence of a Key Man Event, then an independent third party arbitrator shall determine if a Key Man Event occurred, which arbitrator shall be jointly selected by the General Partner and the

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Series A Preferred Unitholders holding a majority of the Series A Preferred Units held by the Series A Unitholders sending a Key Man Objection Notice. The expense of the arbitrator shall be borne by the Partnership if the arbitrator determines that a Key Man Event occurred or by the Series A Preferred Unitholders sending a Key Man Objection Notice if the arbitrator determines that a Key Man Event did not occur. The General Partner shall provide the Series A Preferred Unitholders prompt notice following the final determination of the occurrence of a Key Man Event, and for 60 days after such notice, each Series A Preferred Unitholder shall have the right to send a Holder Redemption Notice to the General Partner. Upon receipt of a Holder Redemption Notice pursuant to this Paragraph 8(c), the Partnership shall redeem one-third of the number of Series A Preferred Units for which a Series A Preferred Unitholder requests redemption on December 31 of each of the calendar year in which such Holder Redemption Notice is received and the two following calendar years; provided, however, that in the event of a Change of Control or a liquidation occurring prior to redemption of such Series A Preferred Units in full pursuant to this Paragraph 8(c), the Partnership shall redeem 100% of such unredeemed Series A Preferred Units on the date of consummation of such Change of Control or the date of the first liquidating distribution pursuant to Paragraph 13(d), as applicable, at a cash price per Series A Preferred Unit equal to the Holder Redemption Price. For purposes of clarity, the Unpaid Series A Preferred Yield shall continue to accrue at the Yield Rate on each outstanding Series A Preferred Unit until redeemed.

d. If on any Redemption Date the Partnership is unable to redeem any Series A Preferred Units designated for redemption in the Holder Redemption Notice for any reason, including because such redemption would violate the Partnership Act or other Applicable Laws, then the Partnership shall redeem, pro rata among the Series A Preferred Unitholders who have given a Holder Redemption Notice (based on the number of Series A Preferred Units held by such redeeming Series A Preferred Unitholders as of such Redemption Date), as many of such Series A Preferred Units as may be redeemed, and as soon thereafter as the Partnership is able the Partnership shall redeem, pro rata among the Series A Preferred Unitholders who have given a Holder Redemption Notice (based on the number of Series A Preferred Units held by such redeeming Series A Preferred Unitholders as of such Redemption Date), such unredeemed Series A Preferred Units for which a Series A Preferred Unitholder has given a Holder Redemption Notice; provided, however, that notwithstanding the provisions of this Paragraph 8(d), the Partnership shall be deemed to be in Default if the Partnership is unable to redeem in accordance with this Agreement (without giving effect to this Paragraph 8(d)) all of the Series A Preferred Units designated for redemption in the Holder Redemption Notice.

e. In the event that a Series A Preferred Unitholder gives a Holder Redemption Notice pursuant to Paragraph 8(a) with respect to any Scheduled Redemption Date, after first complying with Paragraph 10, the Partnership shall have the option to redeem (to the extent that such redemption shall not violate the Partnership Act or other Applicable Laws) from such Series A Preferred Unitholder, for a cash price per Series A Preferred Unit equal to the greater of (i) the Holder Redemption Price or (ii) the Interest Fair Market Value of the Common Units into which such Series A Preferred Units so redeemed are convertible on such Scheduled Redemption Date (the “Partnership Redemption Price”), a number of Series A Preferred Units not in excess of the number of Series A Preferred Units designated for redemption by such Series A Preferred Unitholder in such Holder Redemption Notice; provided, however, that the Partnership shall not exercise the redemption rights pursuant to this Paragraph 8(e) while a Default by the Partnership is continuing. The Partnership shall exercise its right to redeem pursuant to this Paragraph 8(e) by notifying such redeeming Series A Preferred Unitholder of the number of additional Series A Preferred Units being redeemed on the applicable Scheduled Redemption Date, which notice need not be provided in advance of the payment of the Partnership Redemption Price therefor. The Partnership shall pay to the redeeming Series A Preferred Unitholder the Partnership Redemption Price plus, in the event of a payment after the Scheduled Redemption Date, interest on the Partnership Redemption Price at the Yield Rate from the Scheduled Redemption Date until the date paid in full to the redeeming Series A Preferred Unitholder, concurrent with the payment to the redeeming Series A Preferred Unitholder pursuant to Paragraph 8(a). In the event that the

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Partnership elects to redeem a portion but not all of the Series A Preferred Units subject to redemption under this Paragraph 8(e), then the Partnership shall to the maximum extent possible effect such redemption pro rata among the Series A Preferred Unitholders who have given a Holder Redemption Notice (based on the number of Series A Preferred Units requested for redemption by such redeeming Series A Preferred Unitholders in connection with the applicable Scheduled Redemption Date).

f. In the event of a Change of Control or anticipated Change of Control, except with respect to any Series A Preferred Unit a Series A Preferred Unitholder elects to convert pursuant to Paragraph 5(a), the Partnership shall redeem (to the extent that such redemption shall not violate the Partnership Act or other Applicable Laws) at the Holder Redemption Price (determined by treating the Redemption Date as the Scheduled Redemption Date) the Series A Preferred Units upon the consummation of the Change of Control. The Partnership shall provide at least 15 Business Days prior notice to the Series A Preferred Unitholders of (i) the redemption pursuant to this Paragraph 8(f), (ii) the proposed Change of Control, (iii) the consideration that a holder of one Common Unit would receive in connection with such Change of Control, determined on a fully-diluted basis as if all Convertible Securities were first converted, exchanged or exercised in full, and (iv) if other than cash or marketable securities, the Board’s good faith valuation of any such consideration and any support for such valuation, and (v) the Redemption Date (which will be the closing date of the consummation of the Change of Control), which redemption pursuant to this Paragraph 8(f) shall be conditioned upon and subject to the consummation of the Change of Control.

g. Unless there has been a Default, no Series A Preferred Unitholder may Dispose of or convert any Series A Preferred Units (i) with respect to which it has given a Holder Redemption Notice or (ii) which are subject to the Partnership’s option to redeem pursuant to Paragraph 8(e).

h. From and after the redemption of any Series A Preferred Units in full, all rights of the holders with respect to the Series A Preferred Units redeemed (except the right to receive the Holder Redemption Price or Partnership Redemption Price, as the case may be, plus interest if applicable) shall cease with respect to such Series A Preferred Units, and such Series A Preferred Units shall not thereafter be transferred on the books of the Partnership and shall be deemed to no longer be outstanding for any purpose whatsoever.

i. Except as provided in Paragraph 8(e), the Partnership shall have no option to redeem the Series A Preferred Units. Nothing contained herein shall prevent or restrict the purchase by the Partnership, from time to time either at public or private sale, of the whole or any part of the Series A Preferred Units at such price or prices as the General Partner may determine, subject to the provisions of the Partnership Act and other Applicable Laws; provided, however, that at least 10 days prior to such sale, each of the Series A Preferred Unitholders shall be offered the right to sell to the Partnership its pro rata portion (based on the number of Series A Preferred Units held) of the Series A Preferred Units being sold to the Partnership for the same price(s) and terms as the Series A Preferred Units are then being sold to the Partnership.

j. Upon any redemption, the Partnership shall make a cash payment to the redeeming Series A Preferred Unitholder, and the redeeming Series A Preferred Unitholder shall make a cash payment to the Partnership, to adjust for any distributions declared in respect of the Common Units or the Series A Preferred Units after the applicable Redemption Date but prior to the implementation of the redemption, the intent being to put both the redeeming Series A Preferred Unitholder and the Partnership in the same position that they would have been if the redemption had been implemented on the Redemption Date. Any cash payment made pursuant to the preceding sentence shall be treated as (i) a distribution to the Series A Preferred Unitholder if made by the Partnership and (ii) a Capital Contribution if made by the Series A Preferred Unitholder.

9. Additional Information

a. In addition to the information to be provided to Unitholders pursuant to Section 8.3 of the Partnership Agreement, (i) the General Partner agrees to provide each Unitholder with the annual reserve

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engineering report regarding not less than a majority of the Partnership producing oil and gas properties prepared by an independent reserve engineering firm selected by the General Partner and (ii) on the request of a Series A Preferred Unitholder, the General Partner shall provide such Series A Preferred Unitholder, to the extent permitted by Applicable Law, with a schedule of the Budgeted Distributions in respect of any calendar year for which such information is available. On a Series A Preferred Unitholder’s request, the General Partner agrees to discuss with such Series A Preferred Unitholder the General Partner’s possible exercise of its right to redeem additional Series A Preferred Units from such Series A Preferred Unitholder pursuant to Paragraph 8(e) if such Series A Preferred Unitholder sends a Holder Redemption Notice pursuant to Paragraph 8(a).

10. Information or Liquidation

a. The General Partner shall provide the Series A Preferred Unitholders with at least 15 Business Days’ notice of the first liquidating distribution pursuant to Paragraph 13(d) (the “Liquidation Notice”). The Liquidation Notice shall include the General Partner’s good faith estimate of the amount of distributions that a holder of one Common Unit would receive pursuant to Paragraph 13(d), estimated on a fully-diluted basis as if all Convertible Securities were converted, exchanged or exercised in full.

11. Documents Executed as Attorney-in-Fact

a. The General Partner shall provide each Series A Preferred Unitholder with a copy of any amendment, certificate, instrument or any other document for which the power of attorney provided for in Section 2.8 of the Partnership Agreement is exercised in respect of such Series A Preferred Unitholder.

12. Restricted Transferability

a. No Series A Preferred Unitholder may Dispose of its Series A Preferred Units to a Person other than a Permitted Transferee without the consent of the General Partner, such consent not to be unreasonably withheld. The General Partner shall have the right to cause the Partnership to purchase all of the Series A Preferred Units proposed to be Disposed of by such Series A Preferred Unitholder for the minimum price per Series A Preferred Unit for which such Series A Preferred Unitholder offers to sell its Series A Preferred Units. If the Partnership does not elect to purchase all of the disposing Series A Preferred Unitholder’s offered Series A Preferred Units in accordance with this Paragraph 12(a), the disposing Series A Preferred Unitholder shall then have 90 days within which to Dispose of the offered Series A Preferred Units to a Partner or Partners or a third party for a price at least equal to that described in its offer to the Partnership. The Assignee in any such Disposition shall be permitted to assume all of the rights and obligations of the selling Series A Preferred Unitholder. The General Partner must, if it desires to purchase the Series A Preferred Units being offered, exercise its rights pursuant to this Paragraph 12(a) within 15 Business Days following receipt from a Series A Preferred Unitholder of its offer to sell its Series A Preferred Units.

13. Allocations and Distributions

a. Allocations for Capital Account Purposes. Notwithstanding Section 6.1 of the Partnership Agreement, for purposes of maintaining the Capital Accounts and in determining the rights of the Partners among themselves, the Partnership’s items of income, gain, loss, deduction, amount realized and Simulated Gain (computed in accordance with Section 5.4(b)) of the Partnership Agreement for each taxable period shall be allocated among the Partners, and the Capital Accounts of the Partners shall be adjusted for Simulated Depletion and Simulated Loss, as provided herein below. Consistent with Section 5.4(d) of the Partnership Agreement, the taxable periods for which allocations shall be made pursuant to this Paragraph 13 shall include any taxable periods ending on a Redemption Date or a Conversion Date, as applicable, and any Series A Preferred Units being redeemed or converted on such date shall be treated as Outstanding as of the last day of the taxable period ending on such date for purposes of this Paragraph 13.

i. Net Income and Net Loss.

(1) Net Income. After giving effect to the special allocations set forth in Paragraph 13(a)(ii) and Capital Account adjustments pursuant to Paragraph 13(a)(iii)(2), Net Income and Net Loss

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for each taxable period and all items of income, gain, loss, deduction and, to the extent provided in Paragraph 13(a)(iii)(3), Simulated Gain taken into account in computing Net Income and Net Loss for such taxable period shall be allocated 100% to all Common Unitholders, Pro Rata.

(2) Net Loss. After giving effect to the special allocations set forth in Paragraph 13(a)(ii) and Capital Account adjustments pursuant to Paragraph 13(a)(iii)(2), Net Loss for each taxable period and all items of income, gain, loss, deduction and, to the extent provided in Paragraph 13(a)(iii)(3), Simulated Gain taken into account in computing Net Loss for such taxable period shall be allocated as follows:

(a) First, 100% to all Common Unitholders, Pro Rata, until the Adjusted Capital Account of each Common Unitholder is equal to zero; and

(b) Second, the balance, if any, 100% to all Series A Preferred Unitholders, Pro Rata, until the Adjusted Capital Account of each Series A Preferred Unitholder is equal to zero.

ii. Special Allocations. Notwithstanding any other provision of this Paragraph 13(a), the following special allocations shall be made for each taxable period in the following order:

(1) Partnership Minimum Gain Chargeback. Notwithstanding any other provision of this Paragraph 13(a), if there is a net decrease in Partnership Minimum Gain during any Partnership taxable period, each Partner shall be allocated items of Partnership income, gain and Simulated Gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(f)(6), 1.704-2(g)(2) and 1.704-2(j)(2)(i), or any successor provision. For purposes of this Paragraph 13(a)(ii), each Partner’s Adjusted Capital Account balance shall be determined, and the allocation of income, gain and Simulated Gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Paragraph 13(a)(ii) with respect to such taxable period (other than an allocation pursuant to Paragraphs 13(a)(ii)(6) and 13(a)(ii)(7)). This Paragraph 13(a)(ii)(1) is intended to comply with the Partnership Minimum Gain chargeback requirement in Treasury Regulation Section 1.704-2(f) and shall be interpreted consistently therewith.

(2) Chargeback of Partner Nonrecourse Debt Minimum Gain. Notwithstanding the other provisions of this Paragraph 13(a) (other than Paragraph 13(a)(ii)(1)), except as provided in Treasury Regulation Section 1.704-2(i)(4), if there is a net decrease in Partner Nonrecourse Debt Minimum Gain during any Partnership taxable period, any Partner with a share of Partner Nonrecourse Debt Minimum Gain at the beginning of such taxable period shall be allocated items of Partnership income, gain and Simulated Gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(i)(4) and 1.704-2(j)(2)(ii), or any successor provisions. For purposes of this Paragraph 13(a)(ii), each Partner’s Adjusted Capital Account balance shall be determined, and the allocation of income, gain and Simulated Gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Paragraph 13(a)(ii), other than Paragraph 13(a)(ii)(1) and other than an allocation pursuant to Paragraphs 13(a)(ii)(6) and 13(a)(ii)(7), with respect to such taxable period. This Paragraph 13(a)(ii)(2) is intended to comply with the chargeback of items of income and gain requirement in Treasury Regulation Section 1.704-2(i)(4) and shall be interpreted consistently therewith.

(3) Priority Allocations.

(a) Series A Preferred Unitholder Periodic Allocations. Items of gross income and gain (including Unrealized Gain and Simulated Gain) for the taxable period shall be allocated to the Series A Preferred Unitholders, Pro Rata, in the following order:

(i) first, an amount equal to the excess, if any, of (x) the cumulative Series A Preferred Yield from the Closing Date through the last day of such taxable period with

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respect to each Series A Preferred Unit that is Outstanding as of the last day of such taxable period, over (y) the cumulative gross income and gain allocated pursuant to this Paragraph 13(a)(ii)(3)(a)(i) from all prior taxable periods with respect to each Series A Preferred Unit that is Outstanding as of the last day of such taxable period;

(ii) second, an amount equal to the excess, if any, of (x) the cumulative amount of distributions made pursuant to Paragraph 13(c)(iii) from the Closing Date through the last day of such taxable period (including any distributions made with respect to such taxable period within thirty (30) days of the end of such taxable period) with respect to each Series A Preferred Unit that is Outstanding as of the last day of such taxable period, over (y) the cumulative gross income and gain allocated pursuant to this Paragraph 13(a)(ii)(3)(a)(ii) from all prior taxable periods with respect to each Series A Preferred Unit that is Outstanding as of the last day of such taxable period; and

(iii) third, an amount equal to the excess, if any, of (x) the cumulative amount of Net Loss allocated pursuant to Paragraph 13(a)(i)(2) for all prior taxable periods with respect to each Series A Preferred Unit that is Outstanding as of the last day of such taxable period, over (y) the cumulative gross income and gain allocated pursuant to this Paragraph 13(a)(ii)(3)(a)(iii) for all prior taxable periods with respect to each Series A Preferred Unit that is Outstanding as of the last day of such taxable period.

(b) Holder Redemption Allocations. If any Series A Preferred Units are redeemed pursuant to Paragraph 8 (other than Paragraph 8(e)) and the Capital Account with respect to each such Unit does not equal the Holder Redemption Price, then items of gross income, gain, loss and deduction will be allocated to the Series A Unitholders whose Units are being redeemed, Pro Rata, in a manner such that, to the extent possible, the Capital Account balance with respect to each such Series A Unit equals the Holder Redemption Price; provided that such Capital Account balance shall be determined after giving effect to (x) all Capital Contributions made with respect to such Series A Preferred Unit, including any Capital Contributions made pursuant to Paragraph 8(j), (y) all distributions made with respect to such Series A Preferred Unit, including any distributions made pursuant to Paragraph 13(c) with respect to Unpaid Series A Preferred Yield as of the Redemption Date, and (z) all allocations made pursuant to this Paragraph 13 with respect to such Series A Preferred Unit for all periods. If, after making such allocations, the Capital Account balance with respect to each such Series A Unit does not equal the Holder Redemption Price, then (i) to the extent the Holder Redemption Price exceeds such Capital Account balance, the Partnership will make a guaranteed payment to the Series A Preferred Unitholders whose Series A Preferred Units are being redeemed in an aggregate amount equal to the amount of such excess for each Series A Preferred Unit being redeemed, and the deduction with respect to the guaranteed payments will be allocated 100% to the Common Unitholders, Pro Rata, or (ii) to the extent such Capital Account balance exceeds the Holder Redemption Price, the Partnership will make a guaranteed payment to the Common Unitholders, Pro Rata, in an aggregate amount equal to the amount of such excess for each Series A Preferred Unit being redeemed, and the deduction with respect to the guaranteed payments will be allocated 100% to the Series A Preferred Unitholders, Pro Rata.

(c) Partnership Redemption Allocations. If any Series A Preferred Units are redeemed pursuant to Paragraph 8(e) and the Capital Account with respect to each such Unit does not equal the Partnership Redemption Price, then items of gross income, gain, loss and deduction will be allocated to the Series A Unitholders whose Units are being redeemed,

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Pro Rata, in a manner such that, to the extent possible, the Capital Account balance with respect to each such Series A Unit equals the Partnership Redemption Price; provided that such Capital Account balance shall be determined after giving effect to (x) all Capital Contributions made with respect to such Series A Preferred Unit, including any Capital Contributions made pursuant to Paragraph 8(j), (y) all distributions made with respect to such Series A Preferred Unit, including any distributions made pursuant to Paragraph 13(c) with respect to Unpaid Series A Preferred Yield as of the Redemption Date, and (z) all allocations made pursuant to this Paragraph 13 with respect to such Series A Preferred Unit for all periods. If, after making such allocations, the Capital Account balance with respect to each such Series A Unit does not equal the Partnership Redemption Price, then (i) to the extent the Partnership Redemption Price exceeds such Capital Account balance, the Partnership will make a guaranteed payment to the Series A Preferred Unitholders whose Series A Preferred Units are being redeemed in an aggregate amount equal to the amount of such excess for each Series A Preferred Unit being redeemed, and the deduction with respect to the guaranteed payments will be allocated 100% to the Common Unitholders, Pro Rata, or (ii) to the extent such Capital Account balance exceeds the Partnership Redemption Price, the Partnership will make a guaranteed payment to the Common Unitholders, Pro Rata, in an aggregate amount equal to the amount of such excess for each Series A Preferred Unit being redeemed, and the deduction with respect to the guaranteed payments will be allocated 100% to the Series A Preferred Unitholders, Pro Rata.

(d) Liquidation Allocations. If upon the liquidation of the Partnership, the Capital Account with respect to each Series A Preferred Unit (after giving effect to all (i) contributions and distributions and (ii) allocations pursuant to this Paragraph 13 for all periods) does not equal the Series A Liquidation Preference Amount, then items of gross income, gain, loss and deduction will be allocated to the Series A Unitholders, Pro Rata, in a manner such that, to the extent possible, the Capital Account balance with respect to each such Series A Unit equals the Series A Liquidation Preference. If, after making such allocations, the Capital Account balance with respect to each such Series A Unit does not equal the Series A Liquidation Preference Amount, then (i) to the extent the Series A Liquidation Preference Amount exceeds such Capital Account balance, the Partnership will make a guaranteed payment to the Series A Preferred Unitholders, Pro Rata, in an aggregate amount equal to the amount of such excess for each Series A Preferred Unit, and the deduction with respect to the guaranteed payments will be allocated 100% to the Common Unitholders, Pro Rata, or (ii) to the extent such Capital Account balance exceeds the Series A Liquidation Preference Amount, the Partnership will make a guaranteed payment to the Common Unitholders, Pro Rata, in an aggregate amount equal to the amount of such excess for each Series A Preferred Unit, and the deduction with respect to the guaranteed payments will be allocated 100% to the Series A Preferred Unitholders, Pro Rata.

(e) Interest Yield Payments. Any interest paid on the Holder Redemption Price at the Yield Rate pursuant to Paragraph 8(a) or on the Partnership Redemption Price at the Yield Rate pursuant to Paragraph 8(e) shall be treated as a Code Section 707(c) guaranteed payment and the items of deduction attributable to such guaranteed payment shall be allocated 100% to the Common Unitholders, Pro Rata.

(4) Qualified Income Offset. In the event any Partner unexpectedly receives any adjustments, allocations or distributions described in Treasury Regulation Sections 1.704-1(b)(2)(ii)(d)(4), 1.704-1(b)(2)(ii)(d)(5), or 1.704-1(b)(2)(ii)(d)(6), items of Partnership gross income and gain shall be specially allocated to such Partner in an amount and manner sufficient to eliminate, to the extent required by the Treasury Regulations promulgated under Section 704(b) of the

Annex A-18

Code, the deficit balance, if any, in its Adjusted Capital Account created by such adjustments, allocations or distributions as quickly as possible; provided, that an allocation pursuant to this Paragraph 13(a)(ii)(4) shall be made only if and to the extent that such Partner would have a deficit balance in its Adjusted Capital Account after all other allocations provided for in this Paragraph 13(a) have been tentatively made as if this Paragraph 13(a)(ii)(4) were not in this Agreement.

(5) Gross Income Allocations. In the event any Partner has a deficit balance in its Capital Account at the end of any taxable period in excess of the sum of (A) the amount such Partner is required to restore pursuant to the provisions of this Agreement and (B) the amount such Partner is deemed obligated to restore pursuant to Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5), such Partner shall be specially allocated items of Partnership gross income, gain and Simulated Gain in the amount of such excess as quickly as possible; provided, that an allocation pursuant to this Paragraph 13(a)(ii)(5) shall be made only if and to the extent that such Partner would have a deficit balance in its Capital Account after all other allocations provided for in this Paragraph 13(a) have been tentatively made as if Paragraph 13(a)(ii)(4) and this Paragraph 13(a)(ii)(5) were not in this Agreement.

(6) Nonrecourse Deductions. Nonrecourse Deductions for any taxable period shall be allocated to the Common Unitholders, Pro Rata. If the General Partner determines that the Partnership’s Nonrecourse Deductions should be allocated in a different ratio to satisfy the safe harbor requirements of the Treasury Regulations promulgated under Section 704(b) of the Code, the General Partner is authorized, upon notice to the other Partners, to revise the prescribed ratio to the numerically closest ratio that does satisfy such requirements.

(7) Partner Nonrecourse Deductions. Partner Nonrecourse Deductions for any taxable period shall be allocated 100% to the Partner that bears the Economic Risk of Loss with respect to the Partner Nonrecourse Debt to which such Partner Nonrecourse Deductions are attributable in accordance with Treasury Regulation Section 1.704-2(i). If more than one Partner bears the Economic Risk of Loss with respect to a Partner Nonrecourse Debt, such Partner Nonrecourse Deductions attributable thereto shall be allocated between or among such Partners in accordance with the ratios in which they share such Economic Risk of Loss. This Paragraph 13(a)(ii)(7) is intended to comply with Treasury Regulations Section 1.704-2(i)(1) and shall be interpreted consistently therewith.

(8) Nonrecourse Liabilities. For purposes of Treasury Regulation Section 1.752-3(a)(3), the Partners agree that Nonrecourse Liabilities of the Partnership in excess of the sum of (A) the amount of Partnership Minimum Gain and (B) the total amount of Nonrecourse Built-in Gain shall be allocated among the Common Unitholders, Pro Rata.

(9) Code Section 754 Adjustments. To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) of the Code (including pursuant to Treasury Regulation Section 1.734-2(b)(1)) is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts as a result of a distribution to a Partner in complete liquidation of such Partner’s interest in the Partnership, the amount of such adjustment to the Capital Accounts shall be treated as an item of gain or Simulated Gain (if the adjustment increases the basis of the asset) or loss or Simulated Loss (if the adjustment decreases such basis) taken into account pursuant to Section 5.4 of the Partnership Agreement, and such item of gain, loss, Simulated Gain or Simulated Loss shall be specially allocated to the Partners in a manner consistent with the manner in which their Capital Accounts are required to be adjusted pursuant to such Section of the Treasury Regulations.

(10) Economic Uniformity; Changes in Law. For the proper administration of the Partnership and for the preservation of uniformity of the Limited Partner Interests (or any class or classes thereof), the

Annex A-19

General Partner shall (i) adopt such conventions as it deems appropriate in determining the amount of depreciation, amortization and cost recovery deductions; (ii) make special allocations of income, gain, loss, deduction, Unrealized Gain or Unrealized Loss; and (iii) amend the provisions of this Agreement as appropriate (x) to reflect the proposal or promulgation of Treasury Regulations under Section 704(b) or Section 704(c) of the Code or (y) otherwise to preserve or achieve uniformity of the Limited Partner Interests (or any class or classes thereof). The General Partner may adopt such conventions, make such allocations and make such amendments to this Annex as provided in this Paragraph 13(a)(ii)(10) only if such conventions, allocations or amendments would not have a material adverse effect on the Partners, the holders of any class or classes of Outstanding Limited Partner Interests or the Partnership.

(11) Curative Allocation.

(a) Notwithstanding any other provision of this Paragraph 13(a), other than the Required Allocations, the Required Allocations shall be taken into account in making the Agreed Allocations so that, to the extent possible, the net amount of items of gross income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss allocated to each Partner pursuant to the Required Allocations and the Agreed Allocations, together, shall be equal to the net amount of such items that would have been allocated to each such Partner under the Agreed Allocations had the Required Allocations and the related Curative Allocation not otherwise been provided in this Paragraph 13(a) and Simulated Depletion and Simulated Loss had been included in the definition of Net Income and Net Loss. In exercising its discretion under this Paragraph 13(a)(ii)(11)(a), the General Partner may take into account future Required Allocations that, although not yet made, are likely to offset other Required Allocations previously made. Allocations pursuant to this Paragraph 13(a)(ii)(11)(a) shall only be made with respect to Required Allocations to the extent the General Partner determines that such allocations will otherwise be inconsistent with the economic agreement among the Partners.

(b) The General Partner shall, with respect to each taxable period, (1) apply the provisions of Paragraph 13(a)(ii)(11)(a) in whatever order is most likely to minimize the economic distortions that might otherwise result from the Required Allocations, and (2) divide all allocations pursuant to Paragraph 13(a)(ii)(11)(a) among the Partners in a manner that is likely to minimize such economic distortions.

(12) Allocations of GP Items. All GP Items shall, to the maximum extent possible, be allocated to the Series A Preferred Unitholders and the holders (other than the General Partner) of the Common Units in accordance with the provisions of this Paragraph 13(a).

(13) Equalization of Capital Accounts With Respect to Privately Placed Units. Unrealized Gain or Unrealized Loss deemed recognized as a result of a Revaluation Event shall first be allocated to the (A) Unitholders holding Privately Placed Units, Pro Rata, or (B) Unitholders holding Common Units (other than Privately Placed Units), Pro Rata, as applicable, to the extent necessary to cause the Capital Account in respect of each Privately Placed Unit then Outstanding to equal the Capital Account in respect of each Common Unit (other than Privately Placed Units) then Outstanding.

(14) Allocations Regarding Certain Payments Made to Employees and Other Service Providers. Consistent with the provisions of Treasury Regulation Section 1.83-6(d), if any Partner (or its successor) transfers property (including cash) to any employee or other service provider of the Partnership Group and such Partner is not entitled to be reimbursed by (or otherwise elects not to seek reimbursement from) the Partnership for the value of such property, then any items of deduction or loss resulting from or attributable to such transfer shall be allocated to the Partner (or its successor) that made such transfer and was deemed to have contributed such property to the Partnership pursuant to Section 5.8 of the Partnership Agreement.

Annex A-20

(15) Converted Series A Preferred Units; Economic Uniformity. With respect to any taxable period ending upon, or after, a Conversion Date, items of Partnership income, gain, deduction and loss shall be allocated to each Series A Preferred Unitholder holding converted Series A Preferred Units until each such Partner has been allocated an amount of Partnership income, gain, deduction and loss that increases, or decreases, as the case may be, the Capital Account maintained with respect to such converted Series A Preferred Units to an amount equal to the product of (A) the number of converted Series A Preferred Units and (B) the Per Unit Capital Account for a Common Unit. For purposes of this Paragraph 13(a)(ii)(15), the Capital Account maintained with respect to a converted Series A Preferred Unit shall give effect to (i) all Capital Contributions made with respect to such Series A Preferred Unit, including any Capital Contributions made pursuant to Paragraph 5(d) or Paragraph 6(b), (ii) all distributions made with respect to such Series A Preferred Unit, including any distributions made pursuant to Paragraph 13(c) with respect to Unpaid Series A Preferred Yield as of the Conversion Date and pursuant to Paragraph 5(d) or Paragraph 6(b) with respect to the Common Unit into which such Series A Preferred Unit was converted, and (iii) all allocations made pursuant to such converted Series A Preferred Unit for all periods. The purpose for this allocation is to establish uniformity between the Capital Accounts underlying converted Series A Preferred Units and the Capital Accounts underlying Common Units.

iii. Simulated Basis; Simulated Depletion and Simulated Loss; Simulated Gain; Amount Realized.

(1) Simulated Basis. For purposes of determining and maintaining the Partners’ Capital Accounts, (i) the initial Simulated Basis of each oil and gas property (as defined in Section 614 of the Code) of the Partnership shall be allocated among the Common Unitholders, Pro Rata and (ii) if the Carrying Value of an oil and gas property (as defined in Section 614 of the Code) is adjusted pursuant to Section 5.4(d) of the Partnership Agreement, the Simulated Basis of such property (as adjusted to reflect the adjustment to the Carrying Value of such property), shall be allocated to the Common Unitholders, Pro Rata.

(2) Simulated Depletion and Simulated Loss. For purposes of applying clause (z) of the second sentence of Section 5.4(a) of the Partnership Agreement, Simulated Depletion and Simulated Loss with respect to each oil and gas property (as defined in Section 614 of the Code) of the Partnership shall reduce each Partner’s Capital Account in proportion to the manner in which the Simulated Basis of such property is allocated among the Partners pursuant to Paragraph 13(a)(iii)(1).

(3) Simulated Gain. For purposes of applying clause (iii) of the second sentence of Section 5.4(a) of the Partnership Agreement, Simulated Gain for any taxable period will be treated as included in either Net Income or Net Loss and allocated pursuant to Paragraph 13(a)(i).

(4) Amount Realized. For purposes of Treasury Regulation Sections 1.704-1(b)(2)(iv)(k)(2) and 1.704-1(b)(4)(iii), the amount realized on the disposition of any oil and gas property (as defined in Section 614 of the Code) of the Partnership shall be allocated (i) first to the Partners in an amount equal to the remaining Simulated Basis of such property in the same proportions as the Simulated Basis of such property was allocated among the Partners pursuant to Paragraph 13(a)(iii)(1), and (ii) any remaining amount realized shall be allocated to the Partners in the same ratio as Simulated Gain from the disposition of such oil and gas property is allocated pursuant to Paragraph 13(a)(i).

b. Allocations for Tax Purposes

i. Except as otherwise provided herein, for U.S. federal income tax purposes, each item of income, gain, loss and deduction shall be allocated among the Partners in the same manner as its correlative item of “book” income, gain, loss or deduction is allocated pursuant to Paragraph 13(a).

Annex A-21

ii. The deduction for depletion with respect to each separate oil and gas property (as defined in Section 614 of the Code) shall be computed for federal income tax purposes separately by the Partners rather than by the Partnership in accordance with Section 613A(c)(7)(D) of the Code. Except as provided in Paragraph 13(b)(iii), for purposes of such computation (before taking into account any adjustments resulting from an election made by the Partnership under Section 754 of the Code), the adjusted tax basis of each oil and gas property (as defined in Section 614 of the Code) that is (i) a Contributed Property shall initially be allocated among the non-contributing Common Unitholders, Pro Rata, but not in excess of any such Partner’s share of Simulated Basis as determined pursuant to Paragraph 13(a)(iii)(1), and (ii) not a Contributed Property or an Adjusted Property shall initially be allocated to the Partners in proportion to each such Partner’s share of Simulated Basis as determined pursuant to Paragraph 13(a)(iii)(1). If there is an event described in Section 5.4(d) of the Partnership Agreement, the General Partner shall reallocate the adjusted tax basis of each oil and gas property in a manner (i) consistent with the principles of Section 704(c) of the Code and (ii) that maintains the federal income tax fungibility of the Units.

Each Partner shall separately keep records of his share of the adjusted tax basis in each oil and gas property, allocated as provided above, adjust such share of the adjusted tax basis for any cost or percentage depletion allowable with respect to such property, and use such adjusted tax basis in the computation of its cost depletion or in the computation of his gain or loss on the disposition of such property by the Partnership.

iii. In an attempt to eliminate Book-Tax Disparities attributable to a Contributed Property or Adjusted Property, items of income, gain, loss, depreciation, amortization and cost recovery deductions shall be allocated for U.S. federal income tax purposes among the Partners in the manner provided under Section 704(c) of the Code, and the Treasury Regulations promulgated under Section 704(b) and 704(c) of the Code, as determined appropriate by the General Partner (taking into account the General Partner’s discretion under Paragraph 13(a)(ii)(10)); provided that, in all events, the General Partner shall apply the “remedial allocation method” in accordance with the principles of Treasury Regulation Section 1.704-3(d). For purposes of applying the “remedial allocation method” to oil and gas properties (i) the amount by which any Partner’s Capital Account is adjusted for Simulated Depletion shall be treated as an amount of book depletion allocated to such Partner and (ii) the amount of cost depletion computed by such Partner under Section 613A(c)(7)(D) of the Code shall be treated as an amount of tax depletion allocated to such Partner.

iv. The General Partner may determine to depreciate or amortize the portion of an adjustment under Section 743(b) of the Code attributable to unrealized appreciation in any Adjusted Property (to the extent of the unamortized Book-Tax Disparity) using a predetermined rate derived from the depreciation or amortization method and useful life applied to the unamortized Book-Tax Disparity of such property, despite any inconsistency of such approach with Treasury Regulation Section 1.167(c)-l(a)(6) or any successor regulations thereto. If the General Partner determines that such reporting position cannot reasonably be taken, the General Partner may adopt depreciation and amortization conventions under which all purchasers acquiring Limited Partner Interests in the same month would receive depreciation and amortization deductions, based upon the same applicable rate as if they had purchased a direct interest in the Partnership’s property. If the General Partner chooses not to utilize such aggregate method, the General Partner may use any other depreciation and amortization conventions to preserve the uniformity of the intrinsic tax characteristics of any Units, so long as such conventions would not have a material adverse effect on the Limited Partners or Record Holders of any class or classes of Limited Partner Interests.

v. In accordance with Treasury Regulation Sections 1.1245-1(e) and 1.1250-1(f), any gain allocated to the Partners upon the sale or other taxable disposition of any Partnership asset shall, to the extent possible, after taking into account other required allocations of gain pursuant to this Paragraph 13(b), be characterized as Recapture Income in the same proportions and to the same

Annex A-22

extent as such Partners (or their predecessors in interest) have been allocated any deductions directly or indirectly giving rise to the treatment of such gains as Recapture Income.

vi. All items of income, gain, loss, deduction and credit recognized by the Partnership for U.S. federal income tax purposes and allocated to the Partners in accordance with the provisions hereof shall be determined without regard to any election under Section 754 of the Code that may be made by the Partnership; provided, however, that such allocations, once made, shall be adjusted (in the manner determined by the General Partner) to take into account those adjustments permitted or required by Sections 734 and 743 of the Code.

vii. Each item of Partnership income, gain, loss and deduction shall, for U.S. federal income tax purposes, be determined for each Quarter and prorated on a monthly basis and shall be allocated to the Partners as of the opening of the National Securities Exchange on which the Partnership’s Units are listed or admitted to trading on the first Business Day of each month; provided, however, such items for the period beginning on the Closing Date and ending on the last day of the month in which the Closing Date occurs shall be allocated to the Partners who are issued Units as a result of the transactions contemplated by the Contribution Agreement and the Underwriting Agreement; and provided, further, that each item of Partnership income, gain, loss and deduction for the period beginning on the Contribution Date and ending the date immediately before the Closing Date shall be allocated to the Partners holding Units on the date immediately before the Closing Date; and provided, further, that gain or loss on a sale or other disposition of any assets of the Partnership or any other extraordinary item of income, gain, loss or deduction, as determined by the General Partner, shall be allocated to the Partners as of the opening of the National Securities Exchange on which the Partnership’s Units are listed or admitted to trading on the first Business Day of the month in which such item is recognized for U.S. federal income tax purposes. The General Partner may revise, alter or otherwise modify such methods of allocation to the extent permitted or required by Section 706 of the Code and the regulations or rulings promulgated thereunder.

viii. Allocations that would otherwise be made to a Partner under the provisions of this Paragraph 13 shall instead be made to the beneficial owner of Partnership Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method determined by the General Partner.

ix. If, as a result of an exercise of a Noncompensatory Option, a Capital Account reallocation is required under Treasury Regulation Section 1.704-1(b)(2)(iv)(s)(3), the General Partner shall make corrective allocations pursuant to Treasury Regulation Section 1.704-1(b)(4)(x).

c. Distributions Prior to Liquidation. Notwithstanding Section 6.3(b) of the Partnership Agreement and except as otherwise provided in Paragraph 8, prior to the liquidation of the Partnership in accordance with Section 12.4 of the Partnership Agreement, in the sole discretion of the General Partner, cash or other property of the Partnership shall be distributed to the Partners in the following order and priority; provided, however, that distributions pursuant to clause i below shall be made in cash only:

i. First, 100% to the Series A Preferred Unitholders (ratably among the Series A Preferred Unitholders based on the aggregate Unpaid Series A Preferred Yield of each such Series A Preferred Unitholder’s Series A Preferred Units accrued through the last day of the immediately preceding calendar quarter), until the aggregate Unpaid Series A Preferred Yield of each such Series A Preferred Unit accrued through the last day of the immediately preceding calendar quarter has been reduced to zero; and then

ii. Second, in respect of each calendar year, 100% to the Common Unitholders, Pro Rata, until there has been distributed pursuant to this Paragraph 13(c)(ii) an aggregate amount in respect of such calendar year equal to 10% of the aggregate Interest Fair Market Value of the outstanding Common Units as of the first day of such calendar year; and then

Annex A-23

iii. Finally, 100% to the Common Unitholders and the Series A Preferred Unitholders Pro Rata (with the Percentage Interest of each Series A Preferred Unitholder being determined on an “as converted” basis).

Distributions under this Paragraph 13(c) shall be made to the Partners each calendar quarter no later than thirty (30) days following the last day of each calendar quarter. The General Partner shall be entitled to establish record dates for the payment of distributions and adopt any other procedures deemed by the General Partner to be necessary or appropriate in order to effect the provisions of this Paragraph 13(c).

Subject to the contractual obligations of the Partnership and the Partnership Act and other Applicable Laws, the Partnership shall distribute to the Unitholders an aggregate amount of cash with respect to each calendar year (for purposes of this Paragraph 13(c), any distribution in January being deemed to be a distribution with respect to the previous calendar year unless such distribution is specified by the General Partner as being deemed to be a distribution with respect to a different calendar year) at least equal to fifty percent (50%) of the Partnership’s EBITDAX for such calendar year, unless otherwise determined by the General Partner.

Promptly following the determination of the Partnership’s EBITDAX for each calendar year, the General Partner shall calculate the cash distributions, if any, to be made to the Unitholders in order to comply with this Paragraph 13(c) and shall make any such additional distribution in respect of such calendar year in order to cause the aggregate cash distributions to Unitholders in respect of such calendar year to meet the requirements of this Paragraph 13(c).

The Partnership will make distributions of (i) cash (other than GP Available Cash), if any, to the Unitholders in accordance with this Paragraph 13(c) and (ii) GP Available Cash, if any, to the Series A Preferred Unitholders and the holders (other than the General Partner) of Common Units pursuant to the provisions of this Paragraph 13(c).

d. Distributions in Liquidation. In connection with the liquidation of the Partnership pursuant to Section 12.4 of the Partnership Agreement, any cash available for distribution in connection with such liquidation shall first be used to make liquidating distributions to the Series A Preferred Unitholders pursuant to and in accordance with Section 12.4(c) of the Partnership Agreement, and any remaining cash of the Partnership shall be distributed to the Common Unitholders pursuant to and in accordance with Section 12.4(c) of the Partnership Agreement.

14. Invalidity of Provisions.

a. If any provision or part of a provision of this Annex is or becomes, for any reason, invalid, illegal or unenforceable in any respect (including because the enactment of such provision or part of a provision was prohibited by the Organizational LP Partnership Agreement), the validity, legality and enforceability of the remaining provisions and part thereof contained herein shall not be affected thereby, and this Annex shall, to the fullest extent permitted by law, be reformed and construed as if such invalid, illegal or unenforceable provision, or part of a provision, had never been contained herein, and such provision or part reformed so that it would be valid, legal and enforceable to the maximum extent possible.

b. If this Annex, when read together with the Partnership Agreement, fails to include any provision, or part of a provision, from the Organizational LP Partnership Agreement that was required to be included herein (a “required provision”) by virtue of any provision of the Original LP Partnership Agreement, this Annex shall, to the fullest extent permitted by law, be reformed and construed as if such provision, or part of a provision, had been included herein (it being understood that any required provision that relates solely to the rights or preferences of the Series A Preferred Units or Unitholders shall be included in this Annex and any other required provision shall be included in the Partnership Agreement). Any provision or part of a provision of this Annex that conflicts with any such required provision shall be reformed and construed as if such conflicting provision had never been contained herein. The terms of this Annex shall only be modified by this Paragraph 14(b) to the extent necessary to give effect to such required provision.

Annex A-24

15. Effectiveness. This Annex shall be deemed to be effective upon execution by the General Partner.

16. Termination. This Annex shall automatically terminate and be of no further force and effect at such time as no Class A Preferred Units remain outstanding.

Annex A-25

IN WITNESS WHEREOF, the undersigned has executed this Agreement as of the day and year first written above.

BLACK STONE MINERALS GP, L.L.C.
By:
	Name:
	Title:

Annex A-26

Appendix B

GLOSSARY OF TERMS

The following are definitions of certain terms used in this prospectus.

Basin. A large depression on the earth’s surface in which sediments accumulate.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume.

Bbl/d. Bbl per day.

Bcf. One billion cubic feet of natural gas.

Bcfe. One billion cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of oil, condensate, or natural gas liquids.

Boe. Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.

Boe/d. Boe per day.

British Thermal Unit (Btu). The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Completion. The process of treating a drilling well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

Crude oil. Liquid hydrocarbons retrieved from geological structures underground to be refined into fuel sources.

Delaware Act. Delaware Revised Uniform Limited Partnership Act.

Delay rental. Payment made to the lessor under a non-producing oil and natural gas lease at the end of each year to defer a drilling obligation and continue the lease for another year during its primary term.

Deterministic method. The method of estimating reserves or resources under which a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.

Development costs. Capital costs incurred in the acquisition, exploitation, and exploration of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves.

Development well. A well drilled within the proved area of an oil and natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

B-1

Differential. An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.

Dry gas. A natural gas containing insufficient quantities of hydrocarbons heavier than methane to allow their commercial extraction or to require their removal in order to render the gas suitable for fuel use.

Dry hole or dry well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Economically producible. A resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.

Electrical log. Provide information on porosity, hydraulic conductivity, and fluid content of formations drilled in fluid-filled boreholes.

Exploration. A drilling or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.

Exploratory well. A well drilled to find and produce natural gas or oil reserves not classified as proved to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.

Extension well. A well drilled to extend the limits of a known reservoir.

Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Formation. A layer of rock which has distinct characteristics that differs from nearby rock.

Fracturing. The process of creating and preserving a fracture or system of fractures in a reservoir rock typically by injecting a fluid under pressure through a wellbore and into the targeted formation.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Horizontal drilling. A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

Hydraulic fracturing. A process used to stimulate production of hydrocarbons. The process involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production.

Lease bonus. Usually a one-time payment made to a mineral owner as consideration for the execution of an oil and natural gas lease.

Lease operating expense. All direct and allocated indirect costs of lifting hydrocarbons from a producing formation to the surface constituting part of the current operating expenses of a working interest. Such costs include labor, superintendence, supplies, repairs, maintenance, allocated overhead charges, workover, insurance, and other expenses incidental to production, but exclude lease acquisition or drilling or completion expenses.

MBbls. One thousand barrels of oil or other liquid hydrocarbons.

MBoe. One thousand barrels of oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of oil.

MBoe/d. MBoe per day.

B-2

Mcf. Thousand cubic feet of natural gas.

Mcf/d. Mcf per day.

Mineral interests. Real-property interests that 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.

MMBtu. Million British Thermal Units.

MMcf. Million cubic feet of natural gas.

Net acres or net wells. The sum of the fractional working interest owned in gross acres.

Net revenue interest. An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty, overriding royalty, and other non-cost-bearing interests.

Natural gas. A combination of light hydrocarbons that, in average pressure and temperature conditions, is found in a gaseous state. In nature, it is found in underground accumulations, and may potentially be dissolved in oil or may also be found in its gaseous state.

NGLs. Natural gas liquids.

Nonparticipating royalty interest (NPRI). A type of non-cost-bearing royalty interest, which is carved out of the mineral interest and represents 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.

NYMEX. New York Mercantile Exchange.

Oil. Crude oil and condensate.

Oil and natural gas properties. Tracts of land consisting of properties to be developed for oil and natural gas resource extraction.

Operator. The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.

Overriding royalty interest (ORRI). A fractional, undivided interest or right of participation in the oil or natural gas, or in the proceeds from the sale of the oil or gas, produced from a specified tract or tracts, which are limited in duration to the terms of an existing lease and which are not subject to any portion of the expense of development, operation or maintenance.

PDP. Proved developed producing.

Play. A set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, reservoir structure, timing, trapping mechanism, and hydrocarbon type.

Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.

Pooling. The majority of our producing acreage is pooled with third-party acreage. Pooling refers to an operator’s consolidation of multiple adjacent leased tracts, which may be covered by multiple leases with

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multiple lessors, in order to maximize drilling efficiency or to comply with state mandated well spacing requirements. Pooling dilutes our royalty in a given well or unit, but it also increases both the acreage footprint and the number of wells in which we have an economic interest. To estimate our total potential drilling locations in a given play, we include third-party acreage that is pooled with our acreage.

Production Costs. The production or operational costs incurred while extracting and producing, storing, and transporting oil and/or natural gas. Typical of these costs are wages for workers, facilities lease costs, equipment maintenance, logistical support, applicable taxes, and insurance.

PUD. Proved undeveloped.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved developed producing reserves. Reserves expected to be recovered from existing completion intervals in existing wells.

Proved reserves. The estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Pugh clauses. Provides that a well on a pooled area only maintains that portion of the lease within the pooled area. When an operator is producing from pooled acreage that only includes part of a lease tract, Pugh clauses prevent operators from holding the entire leased tract with the production from the pooled unit. As to the other areas of the lease outside the pooled area, the lessor will have to pay rentals, drill wells, or obtain production as necessary to maintain that outside acreage, or else it terminates. Pugh clauses can also be used to limit the area within a lease that can be maintained by a well on the lease or to provide that a well can only maintain lease rights down to a certain depth, resulting in the release of unexplored deep rights, the latter provision sometimes called a horizontal Pugh clause.

Reliable technology. A grouping of one or more technologies (including computation methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

Reserves. Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to the market, and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

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Resource play. A set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographic, and temporal properties, such as source rock, reservoir structure, timing, trapping mechanism, and hydrocarbon type.

Royalty interest. An interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development.

Seismic data. Seismic data is used by scientists to interpret the composition, fluid content, extent, and geometry of rocks in the subsurface. Seismic data is acquired by transmitting a signal from an energy source, such as dynamite or water, into the earth. The energy so transmitted is subsequently reflected beneath the earth’s surface and a receiver is used to collect and record these reflections.

Shale. A fine grained sedimentary rock formed by consolidation of clay- and silt-sized particles into thin, relatively impermeable layers. Shale can include relatively large amounts of organic material compared with other rock types and thus has the potential to become rich hydrocarbon source rock. Its fine grain size and lack of permeability can allow shale to form a good cap rock for hydrocarbon traps.

Spacing. The distance between wells producing from the same reservoir and is often established by regulatory agencies.

Standardized measure. The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Because we are a limited partnership, we are generally not subject to federal or state income taxes and thus make no provision for federal or state income taxes in the calculation of our standardized measure. Standardized measure does not give effect to derivative transactions.

Tight formation. A formation with low permeability that produces natural gas with low flow rates for long periods of time.

Trend. A region of oil and/or natural gas production, the geographic limits of which have not been fully defined, having geological characteristics that have been ascertained through supporting geological, geophysical, or other data to contain the potential for oil and/or natural gas reserves in a particular formation or series of formations.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Working interest. An operating interest that gives the owner the right to drill, produce, and conduct operating activities on the property, and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

Workover. Operations on a producing well to restore or increase production.

WTI. West Texas Intermediate oil, which is a light, sweet crude oil, characterized by an American Petroleum Institute gravity, of API gravity, between 39 and 41 and a sulfur content of approximately 0.4 weight percent that is used as a benchmark for the other crude oils.

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Black Stone Minerals, L.P.

Common Units

Representing Limited Partner Interests

Prospectus

                    , 2015

Barclays

BofA Merrill Lynch

Citigroup

Credit Suisse

Wells Fargo Securities

J.P. Morgan

Morgan Stanley

Raymond James

Scotiabank / Howard Weil

Simmons & Company

International

Through and including                     , 2015 (25 days after the date of this prospectus), all dealers that buy, sell or trade our common units, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

PART II

INFORMATION NOT REQUIRED IN THE PROSPECTUS

ITEM 13. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION.

Set forth below are the expenses (other than the underwriting discount and structuring fee) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the SEC registration fee, the NYSE listing fee, and the FINRA filing fee, the amounts set forth below are estimates.

SEC registration fee	$	*
NYSE listing fee		*
FINRA filing fee		650
Printing expenses		*
Fees and expenses of legal counsel		*
Accounting fees and expenses		*
Transfer agent and registrar fees		*
Miscellaneous		*
Total		*

* To be provided by amendment.

ITEM 14. INDEMNIFICATION OF OFFICERS AND THE DIRECTORS OF THE BOARD OF DIRECTORS OF OUR GENERAL PARTNER.

The section of the prospectus entitled “The Partnership Agreement—Indemnification” is incorporated herein by reference and discloses that we will generally indemnify the directors, officers, and affiliates of the general partner against all losses, claims, damages, or similar events. Subject to any terms, conditions, or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other person from and against all claims and demands whatsoever.

Section 18-108 of the Delaware Limited Liability Company Act provides that a Delaware limited liability company may indemnify and hold harmless any member or manager or other person from and against any and all claims and demands whatsoever. The amended and restated limited liability company agreement of our general partner provides for the indemnification of its directors and executive officers against liabilities they incur in their capacities as such.

The underwriting agreement that we expect to enter into with the underwriters, the form of which will be filed as Exhibit 1.1 to this registration statement, will contain indemnification and contribution provisions that will indemnify and hold harmless the directors and executive officers of our general partner.

ITEM 15. RECENT SALES OF UNREGISTERED SECURITIES.

In connection with our formation in September 2014, we issued (i) the non-economic general partner interest to BSNR, which interest was transferred to New GP, our general partner, for $100.00, and (ii) all of the limited partner interests in us to BSMC for $100.00, which limited partner interest interests will be redeemed and cancelled in connection with the closing of the initial public offering of common units of the Partnership and the merger of BSMC with and into Merger Sub, with BSMC as the surviving entity. Prior to such initial public offering and merger, we issued a one percent limited partner interest in us to our general partner, which will remain outstanding immediately after our initial public offering. These issuances were exempt from registration under Section 4(a)(2) of the Securities Act. There have been no other sales of unregistered securities within the past three years. In connection with the merger, the common units (other than common units held by BSNR) and preferred units of BSMC will be exchanged for common units and preferred units of the partnership.

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ITEM 16. EXHIBITS.

See the Exhibit Index on the page immediately preceding the exhibits for a list of exhibits filed as part of this registration statement on Form S-1, which Exhibit Index is incorporated herein by reference.

ITEM 17. UNDERTAKINGS.

The undersigned Registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the Registrant pursuant to the provisions described in Item 14 above, or otherwise, the Registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the Registrant of expenses incurred or paid by a director, officer, or controlling person of the Registrant in the successful defense of any action, suit, or proceeding) is asserted by such director, officer, or controlling person in connection with the securities being registered, the Registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this Registration Statement in reliance upon Rule 430A and contained in a form of prospectus filed by the Registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this Registration Statement as of the time it was declared effective; and

(2) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at the time shall be deemed to be the initial bona fide offering thereof.

The Registrant undertakes to send to each common unitholder, at least on an annual basis, a detailed statement of any transactions with Registrant, our general partner or any of its affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to, Registrant or its affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.

The Registrant undertakes to provide to the common unitholders the financial statements required by Form 10-K for the first full fiscal year of operations of the Registrant.

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on                     , 2015.

Black Stone Minerals, L.P.
By:	Black Stone Minerals GP, L.L.C., its general partner
By:
Name:	Thomas L. Carter, Jr.
Title:	President, Chief Executive Officer, and Chairman

Each person whose signature appears below appoints Thomas L. Carter, Jr., Marc Carroll, and Steve Putman, and each of them, any of whom may act without the joinder of the other, as his or her true and lawful attorneys-in-fact and agents, with full power of substitution and re-substitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Registration Statement and any Registration Statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he might or would do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them of their or his or her substitute and substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities and the dates indicated.

Signature	Title	Date
Thomas L. Carter, Jr.	President, Chief Executive Officer, and Chairman (Principal Executive Officer)		, 2015
Marc Carroll	Senior Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)		, 2015
William G. Bardel	Director		, 2015
D. Mark DeWalch	Director		, 2015
Jerry V. Kyle, Jr.	Director		, 2015
Michael C. Linn	Director		, 2015

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Signature	Title	Date
John H. Longmaid	Director		, 2015
William N. Mathis	Director		, 2015
Richard N. Papert	Director		, 2015
Alexander D. Stuart	Director		, 2015
Allison K. Thacker	Director		, 2015

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EXHIBIT INDEX

Exhibit Number			Description
1.1	**	—	Form of Underwriting Agreement
3.1	***	—	Certificate of Limited Partnership of Black Stone Minerals, L.P.
3.2	***	—	Certificate of Amendment to Certificate of Limited Partnership of Black Stone Minerals, L.P.
3.3	***	—	Form of First Amended and Restated Limited Partnership Agreement of Black Stone Minerals, L.P. (included as Appendix A in the prospectus included in this Registration Statement)
3.4	***	—	Agreement of Limited Partnership of Black Stone Minerals, L.P. dated as of September 16, 2014
3.5	***	—	Assignment of Partnership Interest between Black Stone Natural Resources, L.L.C. and Black Stone Minerals GP, L.L.C. dated as of November 21, 2014
5.1	*	—	Opinion of Richards, Layton & Finger, P.A. as to the legality of the securities being registered
8.1	***	—	Opinion of Vinson & Elkins L.L.P. relating to tax matters
10.1	***	—	Form of Black Stone Minerals, L.P. Long-Term Incentive Plan
10.2	*	—	Third Amended and Restated Credit Agreement among Black Stone Minerals Company, L.P., as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, Bank of America, N.A. and Compass Bank, as Co-Syndicate Agents, Wells Fargo Bank, N.A. and Amegy Bank National Association, as Co-Documentation Agents, and a syndicate of lenders dated as of January 23, 2015
10.3	***	—	2009 Employment Agreement of Thomas L. Carter, Jr. dated as of April 1, 2009
10.4	***	—	First Amendment to 2009 Employment Agreement of Thomas L. Carter, Jr. dated as of June 25, 2014
10.5	***	—	2012 Executive Incentive Plan of Black Stone Minerals Company, L.P. dated as of January 1, 2012
10.6	***	—	Restricted Unit Award Agreement of Thomas L. Carter, Jr. dated as of January 1, 2012
10.7	***	—	Restricted Unit Award Agreement of Marc Carroll dated as of January 1, 2012
10.8	***	—	Restricted Unit Award Agreement of Holbrook F. Dorn dated as of January 1, 2012
10.9	**	—	Form of Restricted Unit Grant Notice and Award Agreement for Senior Management (IPO Awards)
10.10	**	—	Form of Performance Unit Grant Notice and Award Agreement for Senior Management (IPO Awards)
10.11	**	—	Form of Restricted Unit Grant Notice and Award Agreement for Senior Management (Annual Awards)
10.12	**	—	Form of Non-Employee Director Unit Grant Notice and Award Agreement
10.13	**	—	Form of Severance Agreement
16.1	*	—	Letter from UHY LLP dated January 28, 2015
21.1	***	—	List of Subsidiaries of Black Stone Minerals, L.P.
23.1	**	—	Consent of UHY LLP
23.2	**	—	Consent of Pressler Petroleum Consultants, Inc.
23.3	**	—	Consent of Netherland, Sewell & Associates, Inc.
23.4	*	—	Consent of Richards, Layton & Finger, P.A. (contained in Exhibit 5.1)
23.5	***	—	Consent of Vinson & Elkins L.L.P. (contained in Exhibit 8.1)
24.1	**	—	Powers of Attorney (included on page II-3)
99.1	***	—	Report of Pressler Petroleum Consultants, Inc.
99.2	***	—	Report of Netherland, Sewell & Associates, Inc.

* Provided herewith.

** To be filed by amendment.

*** Previously submitted.

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