Terryville Mineral & Royalty Partners LP - FORM S-1/A

Attached files

file	filename
EX-23.2 - EX-23.2 - Terryville Mineral & Royalty Partners LP	d802014dex232.htm
EX-3.2 - EX-3.2 - Terryville Mineral & Royalty Partners LP	d802014dex32.htm
EX-23.1 - EX-23.1 - Terryville Mineral & Royalty Partners LP	d802014dex231.htm

As filed with the Securities and Exchange Commission on December 8, 2014

Registration No. 333-199846

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Amendment No. 1

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

Terryville Mineral & Royalty Partners LP

(Exact Name of Registrant as Specified in its Charter)

Delaware

1311

47-2131131

(State or Other Jurisdiction of

Incorporation or Organization)

(Primary Standard Industrial

Classification Code Number)

(IRS Employer

Identification Number)

500 Dallas St., Suite 1800

Houston, Texas 77002

(713) 588-8300

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

Kyle N. Roane

Vice President, General Counsel and

Corporate Secretary

TRVL Partners GP LLC

500 Dallas St., Suite 1800

Houston, Texas 77002

(713) 588-8300

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

Copies to:

Douglas E. McWilliams

Vinson & Elkins L.L.P.

1001 Fannin, Suite 2500

Houston, TX 77002

Tel: (713) 758-2222

J. Michael Chambers

Brett E. Braden

Latham & Watkins LLP

811 Main Street, Suite 3700

Houston, Texas 77002

Tel: (713) 546-5400

Approximate date of commencement of proposed sale to the public:

As soon as practicable after this registration statement becomes effective.

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

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

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, 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 December 8, 2014

PROSPECTUS

Terryville Mineral & Royalty Partners LP

Common Units

Representing Limited Partner Interests

This is the initial public offering of our common units representing limited partner interests. We are offering common units. Prior to this offering, there has been no public market for our common units.

We have applied to list our common units on the NASDAQ Global Select Market under the symbol “TRVL.”

We anticipate that the initial public offering price will be between $ and $ per common unit.

Investing in our common units involves risks. Please read “Risk Factors” beginning on page 22.

These risks include the following:

•

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

•

On a pro forma basis, we would not have generated sufficient cash available for distribution to support the payment of the minimum quarterly distribution on all of our units for the year ended December 31, 2013 and the twelve months ended September 30, 2014.

•

Oil, natural gas and NGL prices are volatile, due to factors beyond our control, and will greatly affect our business, results of operations, liquidity and financial condition.

•

We depend on Memorial Resource Development Corp. (“Memorial Resource”) for all of the development and production on the properties underlying our royalty interests. All of our revenue is derived from royalty payments made by Memorial Resource. A reduction in the expected number of wells to be drilled on our acreage by Memorial Resource or the failure by it to adequately and efficiently develop and operate our acreage could have an adverse effect on our expected growth and our results of operations.

•

Our general partner and its affiliates will own a controlling interest in us and will have conflicts of interest with, and owe limited fiduciary duties to, us, which may permit them to favor their own interests to the detriment of our unitholders.

•

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

•

Our unitholders have limited voting rights and are not entitled to elect our general partner or its board of directors. Memorial Resource, as owner of our general partner, will have the power to appoint and remove our general partner’s directors.

•

Our unitholders will experience immediate and substantial dilution of $ per unit.

•

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

•

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

We are an emerging growth company as that term is used in the Jumpstart Our Business Startups Act of 2012, and as such, we have elected to take advantage of certain reduced public company reporting requirements for this prospectus and future filings. See “Risk Factors” and “Summary—Emerging Growth Company Status.”


	Per Common Unit	Total
Public Offering Price	$	$
Underwriting Discount(1)	$	$
Proceeds to Terryville Mineral & Royalty Partners LP (before expenses)	$	$

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

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

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

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

Barclays

Prospectus dated , 2015

[map to come]

TABLE OF CONTENTS


SUMMARY			1
Overview			1
Our Initial Assets			3
Our Relationship with Memorial Resource			5
Business Strategies			6
Competitive Strengths			7
Risk Factors			8
Management of Our Partnership and Memorial Resource			8
Conflicts of Interest and Fiduciary Duties			9
Emerging Growth Company Status			10
Formation Transactions and Structure			10
Principal Executive Offices			12
The Offering			13
Summary Historical Financial Data			18
Non-GAAP Financial Measure			19
Summary Reserve Data			20

RISK FACTORS			22
Risks Related to Our Business			22
Risks Related to Our Operator			31
Risks Inherent in an Investment in Us			41
Tax Risks to Common Unitholders			54

USE OF PROCEEDS			59

CAPITALIZATION			60

DILUTION			61

CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS			62
General			62
Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2013 and the Twelve Months Ended September 30, 2014			66
Estimated Cash Available for Distribution for the Twelve Months Ending December 31, 2015			68

PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS			71
Distributions of Available Cash			71
Operating Surplus and Capital Surplus			72
Subordination Period			76
Distributions of Available Cash from Operating Surplus During the Subordination Period			78
Distributions of Available Cash from Operating Surplus After the Subordination Period			79
General Partner Interest and Incentive Distribution Rights			79
Percentage Allocations of Available Cash from Operating Surplus			80
General Partner’s Right to Reset Incentive Distribution Levels			80
Distributions from Capital Surplus			82
Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels			83
Distributions of Cash Upon Liquidation			83

SELECTED HISTORICAL FINANCIAL DATA			86

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			87
Overview			87
Sources of Our Revenue			87
Principal Components of Our Cost Structure			88


Reserves and Pricing			88
Factors Affecting the Comparability of Our Results to the Historical Financial Results of Our Predecessor			89
Results of Operations			90
Liquidity and Capital Resources			91
Contractual Obligations			93
Internal Controls and Procedures			94
New and Revised Financial Accounting Standards			94
Critical Accounting Policies			94
Off-Balance Sheet Arrangements			96
Quantitative and Qualitative Disclosure about Market Risk			96

BUSINESS			98
Overview			98
Our Initial Assets			99
Our Relationship with Memorial Resource			102
Business Strategies			103
Competitive Strengths			104
Our Operations			105
Marketing and Major Customers			111
Our Royalty Interests			111
Seasonality			111
Competition			111
Hydraulic Fracturing			112
Regulation of the Oil and Natural Gas Industry			112
Regulation of Environmental and Occupational Health and Safety Matters			113
Employees			118
Our Offices			119
Legal Proceedings			119

MANAGEMENT			120
Management of Terryville Mineral & Royalty Partners LP			120
Executive Officers and Directors of Our General Partner			121
Director Independence			122
Committees of the Board of Directors			122
Indemnification Agreements			122
Executive Compensation			123
Long-Term Incentive Plan			124
Director Compensation			127

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT			129

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS			130
Distributions and Payments to Memorial Resource and Its Affiliates			130
Agreements and Transactions with Affiliates in Connection with this Offering			131
Other Transactions with Related Persons			132
Procedures for Review, Approval and Ratification of Transactions with Related Persons			132

CONFLICTS OF INTEREST AND FIDUCIARY DUTIES			134
Summary of Applicable Duties			134
Conflicts of Interest			134
Fiduciary Duties			141

DESCRIPTION OF OUR COMMON UNITS			144
Our Common Units			144
Transfer Agent and Registrar			144


Transfer of Common Units			144
Listing			145
THE PARTNERSHIP AGREEMENT			146
Organization and Duration			146
Purpose			146
Cash Distributions			146
Capital Contributions			146
Limited Voting Rights			147
Applicable Law; Forum, Venue and Jurisdiction			148
Reimbursement of Partnership Litigation Costs			148
Limited Liability			148
Issuance of Additional Securities			149
Amendment of the Partnership Agreement			150
Merger, Consolidation, Conversion, Sale or Other Disposition of Assets			152
Termination and Dissolution			153
Liquidation and Distribution of Proceeds			153
Withdrawal or Removal of Our General Partner			153
Transfer of General Partner Interest			155
Transfer of Subordinated Units and Incentive Distribution Rights			155
Transfer of Ownership Interests in Our General Partner			155
Change of Management Provisions			155
Limited Call Right			156
Meetings; Voting			156
Voting Rights of Incentive Distribution Rights			157
Status as Limited Partner			157
Non-Taxpaying Assignees; Redemption			157
Non-Eligible Holders; Redemption			158
Indemnification			158
Reimbursement of Expenses			159
Books and Reports			159
Right to Inspect Our Books and Records			159
Registration Rights			160

UNITS ELIGIBLE FOR FUTURE SALE			161

MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES			163
Taxation of the Partnership			163
Tax Consequences of Unit Ownership			165
Tax Treatment of Operations			169
Disposition of Units			171
Uniformity of Units			174
Tax-Exempt Organizations and Other Investors			174
Administrative Matters			175
FATCA Withholding Requirements			176
State, Local and Other Tax Considerations			177

INVESTMENT IN TERRYVILLE MINERAL & ROYALTY PARTNERS LP BY EMPLOYEE BENEFIT PLANS			178

UNDERWRITING			179
Commissions and Expenses			179
Option to Purchase Additional Common Units			179
Lock-Up Agreements			180

iii


Offering Price Determination			180
Indemnification			180
Stabilization, Short Positions and Penalty Bids			180
Directed Unit Program			181
Electronic Distribution			182
Listing on the NASDAQ			182
Discretionary Sales			182
Stamp Taxes			182
Other Relationships			182
Direct Participation Program Requirements			183
Selling Restrictions			183

LEGAL MATTERS			184

EXPERTS			184

WHERE YOU CAN FIND MORE INFORMATION			184

FORWARD-LOOKING STATEMENTS			185

INDEX TO FINANCIAL STATEMENTS			F-1

APPENDIX A: AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF TERRYVILLE MINERAL & ROYALTY PARTNERS LP			A-1

APPENDIX B: GLOSSARY OF TERMS			B-1

APPENDIX C: NETHERLAND, SEWELL & ASSOCIATES, INC. SUMMARY RESERVE REPORT			C-1

You should rely only on the information contained in this prospectus, any free writing prospectus prepared by or on behalf of us or any other information to which we have referred you in connection with this offering. We have not, and the underwriters have not, authorized any other person to provide you with information different from that contained in this prospectus. Neither the delivery of this prospectus nor sale of our common units means that information contained in this prospectus is correct after the date of this prospectus. This prospectus is not an offer to sell or solicitation of an offer to buy our common units in any circumstances under which the offer or solicitation is unlawful.

INDUSTRY AND MARKET DATA

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

COMMONLY USED DEFINED TERMS

As used in this prospectus, unless we indicate otherwise, the following terms have the following meanings:

•

“the Partnership,” “we,” “our,” “us” or like terms refer collectively to Terryville Mineral & Royalty Partners LP and its subsidiaries;

•

“our general partner” refers to TRVL Partners GP LLC, our general partner;

•

“our initial assets,” “our properties” or “our predecessor” refers to the royalty interests in horizontal producing wells and in adjacent undeveloped acreage that will be contributed to us by Memorial Resource in connection with the closing of this offering;

•

“the Funds” refers collectively to Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P., which collectively control MRD Holdco;

•

“Memorial Resource” refers collectively to Memorial Resource Development Corp. and its subsidiaries;

•

“MEMP” refers collectively to Memorial Production Partners LP and its subsidiaries;

•

“MRD Holdco” refers to MRD Holdco LLC, which owns a majority of the outstanding common stock of Memorial Resource;

•

“NGP” refers to Natural Gas Partners, a family of private equity investment funds organized to make direct equity investments in the energy industry, including the Funds;

•

“our royalty interests” refer to our 7% overriding royalty interests that have been carved out of and burden Memorial Resource’s working interests in certain natural gas, NGL and oil properties in the Terryville Complex of North Louisiana;

•

“our acreage” refers to the gross acres underlying our royalty interests; and

•

“our management,” “our employees,” or similar terms refer to the management or other personnel of our general partner or, as applicable, provided to us or our general partner by Memorial Resource under an omnibus agreement among us, our general partner and Memorial Resource.

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 carve-out 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. You should read “Risk Factors” for information about important risks that you should consider before buying our common units.

Our proved reserves as of September 30, 2014 have been prepared by Netherland, Sewell & Associates, Inc., our independent reserve engineers (“NSAI”), which are reflected in our reserve report (our “reserve report”), a summary of which is included as Appendix C of this prospectus. Our proved reserves as of December 31, 2013 have been prepared by our internal reserve engineers. Our proved reserves and production presented in this prospectus on a gas-equivalent basis are done so using a conversion of 6 Mcf “equivalent” per barrel of oil or NGL. This conversion is based on energy equivalence and not price equivalence. References in this prospectus to “our initial assets” refer to the overriding royalty interests in horizontal producing wells and in adjacent undeveloped acreage that will be contributed to us by Memorial Resource in connection with the closing of this offering. These overriding royalty interests have been carved out of and burden Memorial Resource’s working interests in certain natural gas, NGL and oil properties in the Terryville Complex in North Louisiana and will remain in effect until the associated leases expire. We include a glossary of some of the terms used in this prospectus as Appendix B.

Terryville Mineral & Royalty Partners LP

Overview

We are a Delaware limited partnership formed by Memorial Resource to own and acquire natural gas, NGL and oil properties in North America. Our primary business objective is to provide an attractive return to unitholders by maximizing distributions through organic growth and pursuing accretive growth opportunities through acquisitions of royalty interests and mineral interests from Memorial Resource and third parties. Our initial assets consist of royalty interests in natural gas, NGL and oil properties in the Terryville Complex within the Cotton Valley formation in North Louisiana, all of which are operated by Memorial Resource. Because we own royalty interests, we are not required to pay capital or operating expenses associated with our existing wells, or expenses associated with the development of any future wells subject to our royalty interests. Memorial Resource will contribute these assets to us upon the closing of this offering.

Memorial Resource is a publicly traded independent natural gas and oil company focused on the exploitation, development, and acquisition of natural gas, NGL and oil properties with a majority of its activity in the Terryville Complex of North Louisiana, where it is targeting overpressured, liquids-rich natural gas opportunities in multiple zones in the Cotton Valley formation. Memorial Resource has assembled a largely contiguous acreage position of approximately 60,041 gross acres in the Terryville Complex as of December 31, 2013, including our approximately 26,931 gross acres. We own royalty interests in 44 of Memorial Resource’s 46 existing horizontal producing wells as well as in the undeveloped acreage surrounding these 44 wells. As of September 30, 2014, Memorial Resource has advised us that it has identified 1,022 additional drilling locations across our acreage. We believe Memorial Resource intends to continue focusing its development within our acreage. We believe that the acreage held by Memorial Resource that does not underlie our royalty interests may have, or with additional development will have, production and reserves characteristics that could make them attractive for inclusion in our partnership in the future. Upon the completion of this offering, Memorial Resource

will own and control our general partner, and will own approximately % of our outstanding common units, all of our subordinated units and all of our incentive distribution rights. We believe Memorial Resource’s significant ownership interest in us will motivate it to offer additional royalty and mineral interests in oil and natural gas properties to us in the future.

The majority of Memorial Resource’s current and planned development is focused in and around a portion of what it believes to be the core of the Terryville Complex, where it currently operates six rigs and expects to increase to seven rigs in 2015, all of which are expected to operate exclusively within our acreage in 2015. Like Memorial Resource, we expect our initial focus will concentrate on the Terryville Complex within the Cotton Valley formation in North Louisiana. The Cotton Valley formation extends across East Texas, North Louisiana and Southern Arkansas. The formation has been under development since the 1930s and is characterized by thick, multi-zone natural gas and oil reservoirs with well-known geologic characteristics and long-lived, predictable production profiles. Over 21,000 vertical wells have been completed throughout the play. In 2005, operators began redeveloping the Cotton Valley using horizontal drilling and advanced hydraulic fracturing techniques. To date, operators, including Memorial Resource, have drilled an aggregate of over 600 horizontal Cotton Valley wells. Memorial Resource is currently engaged in the horizontal redevelopment of the Terryville Complex in Lincoln Parish, Louisiana utilizing horizontal drilling and completion techniques similar to those employed by others at the Nan-Su-Gail Field, Carthage Complex in East Texas and other major resource plays across the United States. As of September 30, 2014, 29 of Memorial Resource’s producing horizontal wells in the Terryville Complex were in the top 2.5% of all horizontal wells drilled in the United States in terms of peak 30-day production.

Memorial Resource entered the Terryville Complex through an acquisition from Petrohawk Energy Corporation in April 2010, with the goal of redeveloping the field with horizontal drilling and modern completion techniques. We believe the Terryville Complex, which has been producing since 1954, is one of North America’s most prolific natural gas fields, characterized by high recoveries relative to drilling and completion costs, high initial production rates with high liquids yields, long reserve life, multiple stacked producing zones, available infrastructure and a large number of service providers.

After initially drilling eight vertical pilot wells in the Terryville Complex, Memorial Resource commenced a horizontal drilling program in 2011 to further delineate and define its position. In 2013, Memorial Resource shifted its operational focus to full-scale horizontal redevelopment of the Terryville Complex, going from two rigs to four rigs by the end of that year. Additionally, in the fourth quarter of 2013, Memorial Resource moved to drilling on multi-well pads that allow it to more efficiently drill wells and control costs as it develops its stacked pay zones. Memorial Resource has continued to accelerate its development, adding two additional rigs in 2014 and intends to dedicate approximately $304 million of its $351 million drilling and completion budget in 2014 to develop multiple zones within the Terryville Complex.

The following chart provides information regarding Memorial Resource’s gross production growth associated with its Terryville Complex horizontal wells since the beginning of 2012.

Average Daily Production (MMcfe/d)

LOGO

Our Initial Assets

Our initial assets consist of overriding royalty interests in approximately 26,931 gross acres in the Terryville Complex, all of which are operated by Memorial Resource and substantially all of which are currently held by production. Our royalty interests entitle us to receive 7% of gross revenues from production on 44 of Memorial Resource’s 46 existing horizontal producing wells and all future horizontal or vertical wells completed by Memorial Resource at all depths within our acreage, regardless of the working interest that Memorial Resource owns. Memorial Resource’s two horizontal producing wells in which we will not receive a royalty interest were acquired from a third party and are not within or contiguous to our acreage. We are not required to pay any capital or operating expenses associated with any existing wells, or expenses associated with the development of any future wells on our existing acreage. For the year ended December 31, 2013 and nine months ended September 30, 2014, revenue generated from these royalty interests was $12.6 million and $22.9 million, respectively.

As of September 30, 2014, Memorial Resource had 44 gross horizontal producing wells in the Terryville Complex in which we have a royalty interest, which had average gross daily production of 232.0 MMcfe/d during the three months ended September 30, 2014, which resulted in 16.2 MMcfe/d of aggregate daily production net to our royalty interests. As of September 30, 2014, Memorial Resource has advised us that it has identified 1,022 additional drilling locations across our acreage. We believe Memorial Resource intends to continue focusing its development within our acreage. Of Memorial Resource’s drilling, recompletion and workover capital expenditure budget for 2014 of $351 million, $304 million relates to the Terryville Complex and $295 million relates to wells within our acreage. Memorial Resource currently has six rigs operating in the Terryville Complex and expects to increase to seven rigs in 2015. Memorial Resource has indicated all of these rigs are currently scheduled to operate exclusively within our acreage in 2015. Based on Memorial Resource’s expected 2015 drilling program, our drilling locations represent an inventory of over years.

The estimated proved oil and natural gas reserves associated with our initial assets, as of September 30, 2014, were 71 Bcfe based on a report prepared by NSAI. PUD reserves included in the proved reserve estimate were attributable to 104 gross horizontal well locations. As of September 30, 2014, our proved reserves were approximately 71% natural gas, 24% NGLs and 5% oil.

Memorial Resource’s well results have shown consistency in initial production, decline rates and estimated ultimate recovery. The consistency of these results gives us confidence that the full-scale redevelopment of the Terryville Complex that Memorial Resource began in 2013 will continue to be successful. The table below details certain information on estimated ultimate recoveries and production on a gross basis for Memorial Resource’s 41 existing horizontal wells currently producing from its four primary target zones in the Terryville Complex in which we have a non-cost bearing royalty interest to the extent such data is available as of the dates and for the periods presented below. The wells below highlight the consistency of Memorial Resource’s drilling results in the four primary target zones in which it plans to focus its future development activity.


			Producing Wells										Gross Wellhead Flow Rates After Processing (MMcfe/d)(3)(4)
Well Name	Lateral Length (Feet)		EUR (Bcfe)(1)(2)		EUR BCFe/ 1,000’		First Production		Days Producing		Cumulative Production (Bcfe)		0-30		0-90		91-180		181-360		D&C ($MM)(5)
Upper Red
LD Barnett 23H-2		4,015		12.3		3.1		1/30/2012		975		5.0		14.5		12.0		7.7		5.6		6.7
Colquitt 20 17H-1		4,357		11.5		2.6		7/30/2012		793		4.3		17.5		12.6		7.2		5.1		7.8
Dowling 22 15H-1		5,376		9.4		1.8		9/22/2012		739		5.7		16.3		15.6		11.1		8.2		8.8
Nobles 13H-1		4,216		9.1		2.1		11/17/2012		683		4.6		21.5		16.7		9.9		6.5		7.8
Sidney McCullin 16 21H-1		4,604		13.8		3.0		1/19/2013		620		5.0		17.4		14.2		10.8		8.4		8.1
Wright 14 11 HC-1		5,250		11.9		2.3		5/27/2013		492		5.5		19.6		18.1		16.1		8.4		8.8
BF Fallin 22 15H-1		5,122		12.3		2.4		6/17/2013		471		3.9		14.8		13.7		11.8		5.9		7.5
Dowling 20 17H-1		4,327		9.0		2.1		7/22/2013		436		2.6		15.2		11.0		5.7		4.5		10.7
Gleason 31H-1		3,692		2.4		0.7		8/12/2013		415		0.6		2.9		2.3		1.6		1.2		9.5
Burnett 26H-1		2,405		5.5		2.3		9/22/2013		374		1.2		6.9		5.6		3.5		2.4		6.9
Drewett 17 8H-1		4,010		15.6		3.9		11/13/2013		322		3.9		22.1		18.6		11.9				7.7
Wright 13 12 HC-2		6,009		24.0		4.0		12/21/2013		284		4.6		22.7		19.6		16.3				8.5
LA Minerals 15 22H-2		5,814		17.3		3.0		1/21/2014		253		3.4		17.8		16.1		13.4				8.8
Wright 13 24 HC-3		6,606		20.9		3.2		4/14/2014		170		3.4		30.3		24.6						10.8
Wright 13 24 HC-1		6,678		15.5		2.3		4/14/2014		170		2.8		25.0		20.4						11.8
TL McCrary 14 11 HC-5		5,875		30.0		5.1		4/14/2014		170		3.0		22.9		23.3						10.2
LA Minerals 19 30 HC-2		6,912		15.1		2.2		5/29/2014		125		2.3		25.1		20.4						10.8
LA Minerals 19 30 HC-1		6,519		19.6		3.0		6/1/2014		122		2.0		21.5		17.7						11.6
Werner 29H-1		3,410		4.7		1.4		8/13/2014		49		0.4		8.6								11.0
Werner 29 32 5 HC-1		6,810		9.7		1.4		8/13/2014		49		0.8		18.4								10.4
Werner 29 32 5 HC-2		8,300		16.5		2.0		8/13/2014		49		1.2		26.1								12.2
Temple 8H-1		2,403		6.3		2.6		8/24/2014		38		0.4		12.7								9.6
Temple 8 17 HC-1		6,210		2.9		0.5		8/29/2014		33		0.3		8.4								11.9
TL McCrary 14 11 HC-2		4,401		NA		NA		9/25/2014		6		0.1										7.7
TL McCrary 14 11 HC-4		4,810		NA		NA		9/25/2014		6		0.0										9.0

Lower Red
TL McCrary 14H-1		4,544		12.7		2.8		5/1/2012		883		4.5		14.4		11.7		8.3		5.4		7.7
Nobles 13H-2		4,060		5.6		1.4		11/17/2012		683		3.3		16.0		11.9		8.2		5.2		7.8
LA Methodist Orphanage 14H-1		3,637		9.5		2.6		2/15/2013		593		4.0		13.9		13.0		9.7		6.3		9.1
Dowling 21 16H-1		4,590		8.4		1.8		3/18/2013		562		3.0		13.0		10.1		6.5		4.5		6.6
Drewett 17 8H-2		3,700		4.2		1.1		11/13/2013		322		1.2		8.7		6.2		3.2				7.0
Wright 13 12 HC-1		5,409		9.4		1.7		12/21/2013		284		2.2		14.7		11.4		7.2				9.3
LA Minerals 15 22H-1		5,926		8.1		1.4		1/21/2014		253		1.9		13.8		10.9		6.4				7.8
Wright 13 24 HC-4		6,518		15.1		2.3		4/14/2014		170		2.6		25.7		19.6						13.4
LA Minerals 19 30 HC-3		5,356		2.5		0.5		5/29/2014		125		0.6		8.8		5.9						12.1
LA Minerals 19 30 HC-4		6,469		3.5		0.5		6/1/2014		122		0.9		13.6		8.5						13.8
TL McCrary 14 11 HC-1		4,010		NA		NA		9/25/2014		6		0.0										8.9
TL McCrary 14 11 HC-3		4,620		NA		NA		9/25/2014		6		0.0										8.3

Lower Deep Pink Zone
LA Methodist Orphanage 14H-2		3,550		6.1		1.7		2/15/2013		593		3.5		14.2		11.6		7.6		5.7		6.1
Wright 13 12 HC-4		5,010		5.8		1.2		12/21/2013		284		1.6		11.8		8.8		4.8				7.0
Wright 13 12 HC-3		5,706		5.4		0.9		12/21/2013		284		1.6		12.5		9.3		5.0				7.4

Upper Deep Pink Zone
Werner 29 32 5 HC-3		6,679		3.1		0.5		8/13/2014		49		0.3		7.2								10.1

Averages(6)
All Wells		5,071		10.7		2.1				319		2.4		16.1		13.6		8.4		5.6		9.2
Upper Red		5,125		12.8		2.5				314		2.7		17.7		15.7		9.8		5.6		9.4
Lower Red		4,903		7.9		1.6				334		2.0		14.3		10.9		7.1		5.4		9.3
Lower Deep Pink		4,755		5.8		1.3				387		2.2		12.8		9.9		5.8		5.7		6.8
Upper Deep Pink		6,679		3.1		0.5				49		0.3		7.2								10.1

(1)	EUR represents the estimated ultimate recovery or sum of total gross remaining proved reserves attributable to each location in our reserve report and cumulative gross production from such location. EUR is shown on a combined basis for oil/condensates, gas and NGLs after the effects of processing.

(2)	TL McCrary 14 11 wells HC-1, HC-2, HC-3 and HC-4 did not begin producing in time to be included in our reserve report as proved developed producing, which has prevented us from providing an estimate of EURs for these wells.

(3)	Production data is as of September 30, 2014 and shown gross on a combined basis after the effects of processing.

(4)	Periodic flow rates start on day 4, with days 1 through 3 used to allow clean up associated with well completion. The 30-day flow rates therefore start on day 4 and continue 30 days to day 33 and the 90-day flow rates go from day 4 to day 93.

(5)	Represents approximate historical drilling and completion costs incurred by Memorial Resource. As an owner of royalty interests, we are not required to pay any capital or operating expenses associated with any existing wells, or expenses associated with the development of any future wells.

(6)	We will also have a royalty interest in three horizontal producing wells outside of the four primary zones where Memorial Resource plans to continue to focus its development activity. These averages do not include such wells.

The following table provides information regarding drilling locations associated with our acreage by area as of September 30, 2014:


	Gross Horizontal Drilling Locations(1)(2)
Terryville Complex Zone	Proved		Management		Total		Memorial Resource Total
Upper Red		40		168		208		429
Lower Red		55		166		221		386
Lower Deep Pink		9		146		155		158
Upper Deep Pink		—		153		153		153
Other Zones		—		285		285		285

Total Terryville Complex		104		918		1,022		1,411

(1)

Please see “Business—Our Operations—Drilling Locations” for more information regarding the process and criteria through which these drilling locations were identified. The drilling locations on which Memorial Resource actually drills will depend on the availability of capital, regulatory approval, commodity prices, costs, actual drilling results and other factors. Please see “Risk Factors—Risks Related to Our Business—Identified drilling locations, which are scheduled out over many years, are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.” Proved locations are based on our reserve report. Management locations are based on management estimates of additional identified drilling locations.

(2)

We do not control the drilling locations that Memorial Resource elects to drill. Please see “Risk Factors—Risks Related to Our Business—We depend on Memorial Resource for all of the development and production on the properties underlying our royalty interests. All of our revenue is derived from royalty payments made by Memorial Resource. A reduction in the expected number of wells to be drilled on our acreage by Memorial Resource or the failure by it to adequately and efficiently develop and operate our acreage could have an adverse effect on our expected growth and our results of operations.”

Our Relationship with Memorial Resource

Upon the completion of this offering, Memorial Resource will own and control our general partner and will own approximately % of our outstanding common units, all of our subordinated units and all of our incentive distribution rights. Memorial Resource has assembled a largely contiguous acreage position of approximately 60,041 gross acres in the Terryville Complex as of December 31, 2013, including our approximately 26,931 gross acres. As of September 30, 2014, Memorial Resource had 1,411 gross (981 net) identified horizontal drilling locations located in the Terryville Complex, of which 1,022 gross identified horizontal drilling locations were attributable to our acreage. Within the Terryville Complex, on a proved reserves basis, Memorial Resource operated approximately 99% of its acreage as of December 31, 2013 and holds an average working interest of approximately 74% across its acreage. We believe that the properties held by Memorial Resource beyond our acreage may include properties that have, or with additional development will have, production and reserves characteristics that could make them attractive for inclusion in our partnership. We believe Memorial Resource’s significant ownership in us will motivate it to offer additional royalty and mineral interests in such properties to us in the future, although Memorial Resource has no obligation to do so and may elect to dispose of royalty and mineral interests in such properties without offering us the opportunities to acquire them.

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

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

Business Strategies

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

•

Capitalize on the development of the properties underlying our royalty interests to grow our distributions. As of the closing of this offering, our initial assets will consist of royalty interests in the Terryville Complex in North Louisiana. We believe the Terryville Complex offers attractive drilling economics and is characterized by high recoveries relative to low drilling and completion costs, high initial production rates with high liquids yields, long reserve life, multiple stacked producing zones, available infrastructure and a large number of service providers. We expect the production from our royalty interests will increase as Memorial Resource continues to focus its drilling and development of its acreage in the Terryville Complex. We expect to capitalize on this development, cost-free to us, and believe the resulting increase in our aggregate royalty payments will enable us to grow our distributions.

•

Seek to acquire from Memorial Resource, from time to time, royalty or mineral interests in producing oil and natural gas properties that meet our acquisition criteria. We may have additional opportunities to acquire royalty or mineral interests in producing oil and natural gas properties directly from Memorial Resource or third parties from time to time in the future. As of December 31, 2013, Memorial Resource has a leasehold position of 60,041 gross acres in the Terryville Complex, including our 26,931 gross acres. We believe Memorial Resource will be incentivized to sell properties to us, including additional overriding royalty interests both within and outside our 26,931 gross acres. Following this offering, Memorial Resource will own and control our general partner as well as % of our outstanding common units, all of our subordinated units and all of our incentive distribution rights.

•

natural gas properties that are located in Texas, Louisiana, Colorado, Wyoming, New Mexico and offshore Southern California, we have access to their significant pool of management talent and industry relationships, which we believe provide us with a competitive advantage in pursuing potential third-party acquisition opportunities. We may have additional opportunities to work jointly with Memorial Resource or MEMP to pursue certain acquisitions of royalty or mineral interests in oil and natural gas properties from third parties. For example, we and Memorial Resource may jointly pursue an acquisition where we would acquire royalty or mineral interests in properties and Memorial Resource would acquire the remaining working and revenue interests in such properties. We believe our relationship with Memorial Resource and its affiliates may give us access to third-party acquisition opportunities that we would not otherwise be in a position to pursue.

•

Reduce exposure to commodity price risk and stabilize cash flows through a disciplined commodity hedging policy. We intend to implement and maintain a portfolio of commodity derivative contracts covering approximately 65% to 85% of our estimated production from total proved developed producing reserves over a three-to-six year period at any given point in time. These commodity derivative contracts may consist of natural gas, oil and NGL financial swaps and collar contracts and natural gas basis financial swaps. We believe these commodity derivative contracts will allow us to mitigate the impact of oil and natural gas price volatility, thereby increasing the predictability of our cash flow.

Competitive Strengths

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

•

Large, concentrated position in one of North America’s leading plays. All of our acreage is located in the Terryville Complex in North Louisiana, which is one of the most prolific liquids-rich natural gas plays in North America and which is characterized by consistent and predictable geology and multiple stacked pay formations confirmed by extensive vertical well control. Memorial Resource’s total leasehold position in the Terryville Complex was approximately 60,041 gross acres as of December 31, 2013, 26,931 gross acres of which underlie our royalty interests. Substantially all of our acreage is currently held by production and is not subject to lease expirations. Through September 30, 2014, Memorial Resource’s drilling program in the Terryville Complex has produced some of the top performing and most economic gas wells in the United States over the prior two years. Through September 30, 2014, Memorial Resource brought 41 horizontal wells online within its four primary target zones with average 30-day initial production rates of 16.1 MMcfe/d and average drilling and completion costs of $9.2 million per well. We believe that we will have a strong, growing production profile driven by Memorial Resource, a growth-oriented operator.

•

Built-in organic growth potential with extensive inventory of highly economic horizontal locations in largely de-risked acreage. We expect our reserves, production and cash available for distributions to grow organically as Memorial Resource continues to drill new wells on our acreage, as it may be incentivized by the attractive well economics in the area. We believe that the risk and uncertainty associated with our acreage positions in the Terryville Complex have been largely reduced through Memorial Resource’s extensive drilling and production history in the area. Furthermore, we believe that the extensive midstream infrastructure in the region will allow Memorial Resource to accelerate its development plan without encountering significant constraints in either takeaway or processing capacity. Memorial Resource has advised us that, as of September 30, 2014, it has identified 1,022 gross horizontal drilling locations across our acreage. Memorial Resource believes area seismic data, as well as information gathered from the results of its existing 275 vertical and 46 horizontal wells throughout the field, support the existence of at least ten stacked pay zones across the Terryville

Complex. Our gross identified horizontal drilling locations represent an inventory of over years based on Memorial Resource’s expected 2015 drilling program. We expect that our focus on owning royalty interests in acreage with extensive inventories of highly economic horizontal locations will result in substantial organic growth.

•

Single controlling and incentivized operator whose drilling plan is focused across our acreage. Following the completion of this offering, Memorial Resource, which will own our general partner, % of our common units, all of our subordinated units and all of our incentive distribution rights, will continue to own a substantial working interest in and operate all of the properties underlying our royalty interests, further aligning our goal of the profitable development of our acreage. We believe our acreage is located where Memorial Resource intends to continue to focus its development. Of Memorial Resource’s drilling, recompletion and workover capital expenditure budget for 2014 of $351 million, $304 million relates to the Terryville Complex and $295 million relates to wells within our acreage. Memorial Resource currently has six rigs operating in the Terryville Complex and expects to increase to seven rigs in 2015. Memorial Resource has indicated all of these rigs are currently scheduled to operate exclusively within our acreage in 2015.

•

Experienced and proven management team. We believe our management and technical teams are one of our principal competitive strengths due to our team’s significant industry experience and long history of working together in the identification, execution and integration of acquisitions, cost efficient management of profitable, large scale drilling programs and a focus on rates of return. Additionally, Memorial Resource’s technical team has substantial expertise in advanced drilling and completion technologies and decades of expertise in operating in the North Louisiana and East Texas regions. The members of our management team collectively have an average of 16 years of experience in the oil and natural gas industry. John A. Weinzierl, our Chief Executive Officer and the Chairman of the board of directors of our general partner, has 24 years of oil and natural gas industry experience as a petroleum engineer, a strong commercial and technical background and extensive experience acquiring and managing oil and natural gas properties. We believe our management team is motivated to deliver strong distributions to our unitholders and maintain safe and reliable operations.

•

Financial flexibility to fund acquisitions. We expect to have the financial flexibility to allow us to opportunistically purchase accretive royalty or mineral interests. We believe that our partnership structure should provide us with a relatively low cost of capital, thereby enhancing our ability to compete for future acquisitions, both individually and jointly with Memorial Resource and its affiliates. We also expect that the revolving credit facility we will enter into in connection with this offering, which will be undrawn following the completion of this offering, and our ability to issue additional common units and other partnership interests will provide us with substantial financial flexibility to pursue acquisitions.

Risk Factors

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

Management of Our Partnership and Memorial Resource

We are managed and operated by the board of directors and executive officers of our general partner, TRVL Partners GP LLC, a wholly owned subsidiary of Memorial Resource. As a result of owning our general partner,

Memorial Resource will have the right to appoint all members of the board of directors of our general partner, including at least three directors meeting the independence standards established by The NASDAQ Stock Market LLC (“NASDAQ”). At least one of our independent directors will be appointed by the time our common units are first listed for trading on the NASDAQ Global Select Market. Our unitholders will not be entitled to elect our general partner or its directors or otherwise directly participate in our management or operations. In addition, neither we nor our subsidiaries nor our general partner will have any employees. Memorial Resource will provide management, operating and administrative services to us and our general partner. The executive officers and some of the directors of our general partner currently serve as executive officers and directors of Memorial Resource. Please read “Management” and “Certain Relationships and Related Party Transactions.”

The principal stockholder of Memorial Resource is MRD Holdco, which is controlled by the Funds, which are three of the private equity funds managed by NGP. As of December 1, 2014, MRD Holdco owned approximately 38% of Memorial Resource’s common stock. Pursuant to a voting agreement, MRD Holdco also has the right to direct the vote of an additional approximately 18% of Memorial Resource’s common stock owned by certain former management members of WildHorse Resources, LLC, a subsidiary of Memorial Resource (“WildHorse Resources”). The Funds also collectively indirectly own 50% of MEMP’s incentive distribution rights, and MRD Holdco owns 5,360,912 subordinated units of MEMP, representing an approximate 6.2% limited partner interest in MEMP.

Founded in 1988, NGP is a family of private equity investment funds, with cumulative committed capital of over $14.5 billion since inception, organized to make investments in the natural resources sector. NGP is part of the investment platform of NGP Energy Capital Management, a premier investment franchise in the natural resources industry, which together with its affiliates has managed over $17 billion in cumulative committed capital since inception.

Conflicts of Interest and Fiduciary Duties

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

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

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

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

Emerging Growth Company Status

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

•

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

•

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

•

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

•

reduced disclosure of executive compensation.

We will cease to be an “emerging growth company” upon the earliest of:

•

the last day of the fiscal year in which we have $1.0 billion or more in annual revenues;

•

the date on which we become a large accelerated filer;

•

the date on which we issue more than $1.0 billion of non-convertible debt over a three-year period; or

•

the last day of the fiscal year following the fifth anniversary of our initial public offering.

In addition, Section 107 of the JOBS Act provides that an “emerging growth company” can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards, but we intend to irrevocably opt out of the extended transition period.

Formation Transactions and Structure

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

•

Memorial Resource will contribute our initial assets to us in exchange for common units and subordinated units;

•

we will issue all of our incentive distribution rights to our general partner, and our general partner will maintain its non-economic general partner interest;

•

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

•

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

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

We have granted the underwriters a 30-day option to purchase up to an aggregate of additional common units. Any net proceeds received from the exercise of this option will be distributed to Memorial Resource. If the underwriters do not exercise this option in full or at all, the common units that would have been sold to the underwriters had they exercised the option in full will be issued to Memorial Resource for no additional consideration at the expiration of the option period. Accordingly, the exercise of the underwriters’ option will not affect the total number of common units outstanding.

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

LOGO

(1)	As of December 1, 2014.


Public Common Units			%
Interests of Memorial Resource:
Common Units			%
Subordinated Units			%
Non-Economic General Partner Interest	—	0	%(1)

Total		100	%

(1)	Our general partner owns a non-economic general partner interest in us and all of our incentive distribution rights. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—General Partner Interest and Incentive Distribution Rights.”

Principal Executive Offices

Our principal executive offices are located at 500 Dallas St., Suite 1800, Houston, Texas 77002, and our phone number is (713) 588-8300. Our website address is www.trvlpartners.com. We expect to make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission, which we refer to as 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, and does not constitute a part of, this prospectus.

The Offering

Common units offered to the public

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

Units outstanding after this offering

common units and subordinated units, representing % and %, respectively, limited partner interests in us. If and to the extent the underwriters exercise their option to purchase additional common units, the number of common units purchased by the underwriters pursuant to any exercise will be sold to the public. Any common units not purchased by the underwriters pursuant to their exercise of the option will be issued to Memorial Resource at the expiration of the option period for no additional consideration. Accordingly, the exercise of the underwriters’ option will not affect the total number of common units outstanding or the amount of cash available for distribution needed to pay the minimum quarterly distribution on all 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), after deducting the estimated underwriting discount and structuring fee and offering expenses payable by us, to make a distribution to Memorial Resource. Affiliates of certain of the underwriters are lenders under Memorial Resource’s revolving credit facility. Memorial Resource may, but is not required to, apply the distribution that it receives from us to repay amounts outstanding under its revolving credit facility. Accordingly, affiliates of certain of the underwriters may indirectly receive a portion of the proceeds from this offering in the form of repayment of debt by Memorial Resource.

Cash distributions

We expect to make a minimum quarterly distribution of $ per unit per quarter on all common and subordinated units ($ per unit on an annualized basis) to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. We refer to this cash as “available cash,” and it is defined in our partnership agreement included in this prospectus as Appendix A. Our ability to pay the minimum quarterly distribution is subject to various restrictions and other factors described in more detail under the caption “Cash Distribution Policy and Restrictions on Distributions.” For the first quarter that we are publicly traded, we

will pay our unitholders a prorated distribution covering the period from the completion of this offering through March 31, 2015, based on the actual length of that period.

Our partnership agreement requires us to distribute all of our available cash each quarter in the following manner during the subordinated period:

•

first, to the holders of common units, until each common unit has received the minimum quarterly distribution of $ plus any arrearages from prior quarters;

•

second, to the holders of subordinated units until each subordinated unit has received the minimum quarterly distribution of $ ; and

•

third, to all unitholders, pro rata, until each unit has received a distribution of $ .

If cash distributions to our unitholders exceed $ per common and subordinated unit in any quarter, our general partner, as the holder of all of our incentive distribution rights, or IDRs, will receive increasing percentages, up to 25%, of the cash we distribute in excess of that amount. We refer to these distributions as “incentive distributions.” Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

Our ability to pay the minimum quarterly distribution is subject to various restrictions and other factors described in more detail in “Cash Distribution Policy and Restrictions on Distributions.”

Our unaudited pro forma cash available for distribution that would have been generated during the year ended December 31, 2013 and the twelve months ended September 30, 2014, was approximately $9.8 million and $23.5 million, respectively. The amount of cash available for distribution we must generate to support the payment of the minimum quarterly distribution for four quarters on our common units and subordinated units to be outstanding immediately after this offering is approximately $ million (or an average of approximately $ million per quarter). As a result, for each of the year ended December 31, 2013 and the twelve months ended September 30, 2014, on a pro forma basis, we would not have generated sufficient cash available for distribution to support the payment of the aggregate annualized minimum quarterly distribution on all of our common units and subordinated units. Please read “Cash Distribution Policy and Restrictions on Distributions—Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2013 and the Twelve Months Ended September 30, 2014.”

We believe, based on our financial forecast and related assumptions included in “Cash Distribution Policy and Restrictions on

Distributions—Estimated Cash Available for Distribution for the Twelve Months Ending December 31, 2015,” that we will have sufficient cash available for distribution to pay the aggregate annualized minimum quarterly distribution of $ million on all of our common units and subordinated units for the twelve months ending December 31, 2015. However, we do not have a legal obligation to pay distributions at our minimum quarterly distribution rate or at any other rate except as provided in our partnership agreement, and there is no guarantee that we will make quarterly cash distributions to our unitholders. Please read “Cash Distribution Policy and Restrictions on Distributions.”

Subordinated units

Memorial Resource will initially own all of our subordinated units. The principal difference between our common units and subordinated units is that, in any quarter during the subordination period, the subordinated units are entitled to receive the minimum quarterly distribution only after the common units have received their minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Accordingly, holders of subordinated units may receive a smaller distribution than holders of common units or no distribution at all. Subordinated units will not accrue arrearages.

The subordination period will begin on the closing date of this offering and will extend until the first business day on or after March 31, 2018 that we have earned and paid from operating surplus, in the aggregate, distributions on each outstanding common unit, subordinated unit and any other partnership interests that are senior or equal in right of distribution to the subordinated units equaling or exceeding the minimum quarterly distribution payable with respect to a period of twelve consecutive quarters immediately preceding such date, provided there are no arrearages in the minimum quarterly distribution on our common units at that time.

When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis and all common units thereafter will no longer be entitled to arrearages.

Early conversion of subordinated units

The subordination period will end on the first business day after we have earned and paid at least $ (125% of the minimum quarterly distribution on an annualized basis) on each outstanding common and subordinated unit, and the related distribution on the IDRs, for any four-quarter period ending on or after March 31, 2016, provided that there are no arrearages on our common units at that time. In addition, the subordination period will end (i) with respect to 50% of the subordinated units, on the first business day after we have earned and paid from operating surplus at least $ (115% of the minimum quarterly distribution) on each outstanding common and subordinated unit, and the related distribution on the IDRs, for any full quarter

ending on or after September 30, 2016 and (ii) with respect to 100% of the subordinated units, on the first business day after we have earned and paid at least $ (125% of the minimum quarterly distribution) on each outstanding common and subordinated unit, and the related distribution on the IDRs, for any full quarter ending on or after September 30, 2016, in each case provided that there are no arrearages on our common units at that time. Please read “Risk Factors—Risks Inherent in an Investment in Us—Unlike most master limited partnerships with subordinated units, our partnership agreement allows for conversion of subordinated units into common units after paying a quarterly distribution at the highest target distribution level for only a single quarter.”

Issuance of additional units

Our partnership agreement authorizes us to issue an unlimited number of additional units without the approval of our unitholders. Please read “Units Eligible for Future Sale” and “The Partnership Agreement—Issuance of Additional Securities.”

Limited voting rights

Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business. Our unitholders will have no right to elect our general partner or its directors on an annual or other continuing basis. Our general partner may not be removed except by a vote of the unitholders holding at least 66 2/3% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon the consummation of this offering, Memorial Resource will own an aggregate of % of our common units (or % of our common units, if the underwriters exercise their option to purchase additional common units in full). This will effectively give Memorial Resource the ability to prevent the removal of our general partner. Please read “The Partnership Agreement—Limited Voting Rights.”

Limited call right

If at any time our general partner and its affiliates (including Memorial Resource) own more than 80% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a purchase price not less than the then-current market price of the common units, as calculated pursuant to the terms of our partnership agreement. Upon the consummation of this offering, Memorial Resource will own approximately % of our outstanding common units (or % of our outstanding common units if the underwriters exercise their option to purchase additional common units in full) and 100% of our subordinated units. Please read “The Partnership Agreement—Limited Call Right.”

Estimated ratio of taxable income to distributions

We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending December 31, 2017, you will be allocated, on a cumulative basis, an

amount of federal taxable income for that period that will be approximately % of the cash expected to be distributed to you with respect to that period. Because of the nature of our business and the expected variability of our quarterly distributions, however, the ratio of our taxable income to distributions may vary significantly from one year to another. Please read “Material U.S. Federal Income Tax Consequences—Tax Consequences of Unit Ownership” for the basis of this estimate.

Material federal income tax consequences

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

Directed unit program

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

Exchange listing

We have applied to list our common units on the NASDAQ Global Select Market under the symbol “TRVL.”

Summary Historical Financial Data

Terryville Mineral & Royalty Partners LP was formed in October 2014 and does not have historical financial statements. Therefore, in this prospectus we present the historical carve-out financial statements of the royalty interests that will be contributed to us upon the closing of this offering. Our “predecessor” refers to the historical carve-out financial and operating data of such royalty interests. The following table presents summary historical financial data of the royalty interests as of the dates and for the periods indicated.

The summary historical financial data of the royalty interests presented as of the dates and for the periods indicated are derived from the audited historical financial statements and unaudited historical financial statements of the royalty interests included elsewhere in this prospectus.

For a detailed discussion of the summary historical financial data contained in the following table, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The following table should also be read in conjunction with “Use of Proceeds” and the audited historical financial statements and unaudited historical financial statements of the royalty interests 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.


	Nine Months Ended September 30,						Year Ended December 31,
	2014			2013			2013			2012
	(unaudited)
	(in thousands, except per unit data)
Statement of Operations Data:
Royalty income	$	22,890		$	8,887		$	12,638		$	3,079
Costs and expenses:
Production taxes		459			151			247			10
Depletion		1,574			937			1,330			367
General and administrative		72			66			92			82

Total costs and expenses		2,105			1,154			1,669			459

Income before income taxes		20,785			7,733			10,969			2,620
Income tax expense		3,373			—			—			—

Net income	$	17,412		$	7,733		$	10,969		$	2,620

Statement of Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	19,503		$	7,681		$	11,025		$	1,774
Investing activities		(181	)		(884	)		(963	)		(463	)
Financing activities		(19,322	)		(6,797	)		(10,062	)		(1,311	)
Other Financial Data:
EBITDA(1)	$	22,359		$	8,670		$	12,299		$	2,987
Pro forma net income per common unit (basic and diluted)(2)
Pro forma net income per subordinated unit (basic and diluted)(2)
Balance Sheet Data (at period end):
Total assets	$	28,236					$	26,780		$	25,872
Total liabilities		4,158						15			14
Predecessor capital		24,078						26,765			25,858

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

(2)	For more information, please read Note 2 to our predecessor’s audited carve-out financial statements included elsewhere in this prospectus.

Non-GAAP Financial Measure

EBITDA

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

We include in this prospectus the non-GAAP financial measure EBITDA and provide our calculation of EBITDA and a reconciliation of EBITDA to net cash provided by operating activities, our most directly comparable financial measure calculated and presented in accordance with GAAP. We define EBITDA as net income (loss) plus income tax expense, interest expense and depletion.

We expect that we will be required to comply with certain EBITDA-related metrics under our new revolving credit facility.

EBITDA will be used as a supplemental financial measure by our management and by external users of our financial statements, such as investors, commercial banks and others, to assess:

•

our operating performance as compared to that of other companies and partnerships in our industry, without regard to financing methods, capital structure or historical cost basis; and

•

the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness, and make distributions on our units.

In addition, our management will use EBITDA to evaluate actual cash flow available to pay distributions to our unitholders or acquire additional oil and natural gas properties.

EBITDA should not be considered an alternative to net income, operating income, cash flow from operating activities, or any other measure of financial performance or liquidity presented in accordance with GAAP. Our EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate EBITDA in the same manner. The following table presents our calculation of EBITDA. The table below further presents a reconciliation of EBITDA to net cash flows provided by operating activities, our most directly comparable GAAP financial measure, for each of the periods indicated.


	Nine Months Ended September 30,				Year Ended December 31,
	2014		2013		2013		2012
	(unaudited)
	(in thousands)
Calculation of EBITDA:
Net income	$	17,412	$	7,733	$	10,969	$	2,620
Income tax expense		3,373		—		—		—
Depletion		1,574		937		1,330		367

EBITDA(1)	$	22,359	$	8,670	$	12,299	$	2,987

(1)	We have not historically recognized interest expense. We may recognize interest expense in future periods.


	Nine Months Ended September 30,					Year Ended December 31,
	2014			2013		2013		2012
	(unaudited)
	(in thousands)
Reconciliation of Net Cash From Operating Activities to EBITDA:
Net cash provided by operating activities	$	19,503		$	7,681	$	11,025	$	1,774
Changes in working capital		(281	)		989		1,274		1,213
Income tax expense		3,373			—		—		—
Deferred taxes		(236	)		—		—		—

EBITDA	$	22,359		$	8,670	$	12,299	$	2,987

Summary Reserve Data

The following tables present summary data with respect to the estimated historical net proved oil and natural gas reserves as of September 30, 2014.

The reserve estimates presented in the table below were prepared by NSAI. Regarding our properties, estimates comprising 100% of the total proved reserves in our reserve report were prepared by NSAI. These reserve estimates were prepared in accordance with current SEC rules regarding oil and natural gas reserve reporting. The following tables also contain certain summary information regarding production and sales of oil and natural gas with respect to such properties.

Please read “Business—Our Operations” as well as “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the summary of our reserve report included herein as Appendix C in evaluating the material presented below.


	As of September 30, 2014
Estimated Proved Reserves
Natural Gas (MMcf)		50,227
Oil/Condensate (MBbls)		626
NGLs (MBbls)		2,816
Total estimated net proved reserves (MMcfe)(1)		70,877
Proved developed producing (MMcfe)		21,022
Proved developed non-producing (MMcfe)		—
Proved undeveloped (MMcfe)		49,855
Proved developed reserves as a percentage of total proved reserves		30	%
PV-10 of proved reserves (in millions)(2)		249

(1)	Includes 650 MMcf attributable to field fuel usage volumes.

(2)

In this prospectus, we have disclosed our PV-10 based on our reserve report. PV-10 represents the period-end present value of estimated future cash inflows from our natural gas and crude oil reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future cash flows and using SEC pricing assumptions in effect at the end of the period. SEC pricing for natural gas and oil of $4.23 per Mcf and $95.56 per Bbl was based on the unweighted average of the first-day-of-the-month prices for each of the twelve months preceding September 2014. Because of this, PV-10 can be used within the industry and by creditors and securities analysts to evaluate estimated net cash flows from proved reserves on a more comparable basis. PV-10 differs from standardized measure because it does not include the effects of income taxes. However, because we are a limited partnership, we are generally not subject to federal income taxes and thus our PV-10 for proved reserves and standardized measure are equivalent. Neither PV-10 nor standardized measure represents an estimate of fair market value of our natural gas and oil properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of estimated reserves held by companies without regard to the specific tax characteristics of such entities.


	Nine Months Ended September 30, 2014		Year Ended December 31, 2013
	(unaudited)
Production and Operating Data:
Net production volumes:
Oil (MBbls)		40		25
NGLs (MBbls)		106		83
Natural gas (MMcf)		2,984		1,821

Total (MMcfe)		3,856		2,472
Average net production (MMcfe/d)		14.1		6.8
Average sales price:
Oil (per Bbl)	$	98.55	$	99.73
NGLs (per Bbl)	$	47.26	$	40.58
Natural gas (per Mcf)	$	4.69	$	3.71

Average price per Mcfe	$	5.94	$	5.11
Average unit costs per Mcfe:
Production taxes	$	0.12	$	0.10
General and administrative expenses	$	0.02	$	0.04
Depletion expense	$	0.41	$	0.54

RISK FACTORS

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

If any of the following risks were to occur, our business, financial condition, results of operations and cash available for distribution could be materially adversely affected. In that case, we might not be able to make distributions on our common units, the trading price of our common units could decline, and you could lose all or part of your investment.

Risks Related to Our Business

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

We may not have sufficient cash available for distribution each quarter to pay the minimum quarterly distribution of $ per unit or any other amount. Under the terms of our partnership agreement, the amount of cash available for distribution will be reduced by the amount of any cash reserves established by our general partner to provide for future operations, future capital expenditures, including acquisitions of additional oil and natural gas properties, future debt service requirements and future cash distributions to our unitholders. The amount of cash we have to distribute each quarter principally depends upon the amount of royalty revenues we generate, which are dependent upon the prices that Memorial Resource, as the operator for 100% of the acreage associated with our initial assets, realizes from the sale of oil and natural gas. In addition, the actual amount of cash we will have to distribute each quarter under the cash distribution policy that the board of directors of our general partner will adopt will be reduced by replacement capital expenditures, payments in respect of debt service and other contractual obligations and fixed charges and increases in reserves for future operating or capital needs that the board of directors may determine are appropriate.

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

We must generate approximately $ million of cash available for distribution to support the payment of the minimum quarterly distribution for four quarters on all of our common units and subordinated units that will be outstanding immediately following this offering. The amount of pro forma cash available for distribution generated during the year ended December 31, 2013 and the twelve months ended September 30, 2014 would not have been sufficient to support the payment of the full minimum quarterly distribution on our common units and subordinated units during each such period. Specifically, the amount of pro forma cash available for distribution generated during the year ended December 31, 2013 would have been sufficient to support a distribution of $ per common unit per quarter ($ per common unit on an annualized basis), or % of the minimum quarterly distribution, and would not have supported any distributions on our subordinated units. Similarly, the amount of pro forma cash available for distribution generated during the twelve months ended September 30, 2014 would have been sufficient to support a distribution of $ per common unit per quarter ($ per common unit on an annualized basis), or % of the minimum quarterly distribution, and would not have supported any distributions on our subordinated units. For a calculation of our ability to make cash distributions to our unitholders based on our pro forma results for the year ended December 31, 2013 and the twelve months ended September 30, 2014, please read “Cash Distribution Policy and Restrictions on Distributions.” If we are

unable to generate sufficient cash available for distribution in future periods, we may not be able to support the payment of the full minimum quarterly distribution or any amount on our common units or subordinated units, in which event the market price of our common units may decline materially.

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

The forecast of cash available for distribution set forth in “Cash Distribution Policy and Restrictions on Distributions” includes our forecast of our results of operations, EBITDA and cash available for distribution for the twelve months ending December 31, 2015. The assumptions underlying the forecast may prove inaccurate and are subject to significant risks and uncertainties that could cause actual results to differ materially from our forecasted results. If our actual results are significantly below forecasted results, or if our expenses are greater than forecasted, we may not be able to pay the forecasted annual distribution, which may cause the market price of our common units to decline materially.

We depend on Memorial Resource for all of the development and production on the properties underlying our royalty interests. All of our revenue is derived from royalty payments made by Memorial Resource. A reduction in the expected number of wells to be drilled on our acreage by Memorial Resource or the failure by it to adequately and efficiently develop and operate our acreage could have an adverse effect on our expected growth and our results of operations.

Our sole assets at the closing of this offering will be royalty interests from which we derive royalty income. The failure of Memorial Resource to adequately or efficiently perform operations or its failure to act in ways that are in our best interests could reduce production and revenues. Further, Memorial Resource is not obligated to undertake any development activities, so any development and production activities will be subject to its reasonable discretion. Memorial Resource 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 Memorial Resource elects to drill any additional wells on our acreage, depends on a number of factors that will be largely outside of our control, including:

•

the prices of oil, natural gas and NGLs, which have declined significantly over the past several months;

•

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

•

Memorial Resource’s ability to access capital;

•

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

•

Memorial Resource’s expertise, operating efficiency and financial resources;

•

approval of other participants in drilling wells;

•

Memorial Resource’s expected return on investment in wells drilled on our acreage as compared to opportunities in other areas;

•

the selection of technology;

•

the selection of counterparties for the sale of production; and

•

the rate of production of the reserves.

Memorial Resource may elect not to undertake development activities, or may undertake such activities in an unanticipated fashion, which may result in significant fluctuations in our royalty revenues and cash available for distribution to our unitholders. If reductions in production by Memorial Resource are implemented on our

properties and sustained, our revenues may also be substantially affected. Accordingly, even though we have an expectation that existing and planned development of our initial assets by Memorial Resource will lead to inclining production and revenues for at least the next several years without the need to spend significant amounts of maintenance capital expenditures, if Memorial Resource were to significantly reduce its development activities, we would likely be required to spend additional maintenance capital to maintain our production over the long term, which would reduce our cash available for distribution. Additionally, if Memorial Resource was to experience significant financial difficulty, it might not be able to pay its royalty payments or continue its operations, which could have a material adverse impact on us.

As discussed below, recently oil, natural gas and NGL prices have declined significantly. A further or extended decline in commodity prices could render many of Memorial Resource’s development and production projects uneconomic and result in a reduction of its estimated reserves, which would reduce the borrowing base under its revolving credit facility and its ability to finance planned or desired capital expenditures or acquisitions. The inability of Memorial Resource to finance its planned capital expenditures with respect to our acreage would have an adverse effect on our results of operations and cash available for distribution.

Oil, natural gas and NGL prices are volatile, due to factors beyond our control, and will greatly affect our business, results of operations, liquidity and financial condition.

Our revenues, operating results, profitability, liquidity, future growth and the value of our assets depend primarily on prevailing commodity prices. Historically, oil and natural gas prices have been volatile and fluctuate in response to changes in supply and demand, market uncertainty, and other factors that are beyond our control, including:

•

the regional, domestic and foreign supply of oil, natural gas and NGLs;

•

the level of commodity prices and expectations about future commodity prices;

•

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

•

localized supply and demand fundamentals, including the proximity and capacity of pipelines and other transportation facilities, and other factors that result in differentials to benchmark prices from time to time;

•

the cost of exploring for, developing, producing and transporting reserves;

•

the price and quantity of foreign imports;

•

political and economic conditions in oil producing countries;

•

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

•

speculative trading in crude oil and natural gas derivative contracts;

•

the level of consumer product demand;

•

weather conditions and other natural disasters;

•

risks associated with operating drilling rigs;

•

technological advances affecting exploration and production operations and overall energy consumption;

•

domestic and foreign governmental regulations and taxes;

•

the continued threat of terrorism and the impact of military and other action;

•

the price and availability of competitors’ supplies of oil and natural gas and 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, natural gas and NGL price movements with any certainty. For example, for the five years ended December 31, 2013, the NYMEX-WTI oil future price ranged from a high of $113.93 per Bbl to a low of $33.98 per Bbl, while the NYMEX-Henry Hub natural gas future price ranged from a high of $7.50 per MMBtu to a low of $1.82 per MMBtu. Recently, oil and natural gas prices have declined significantly. Through December 1, 2014, the West Texas Intermediate posted price had declined from a high of $107.95 per Bbl on June 20, 2014 to $68.98 per Bbl on December 1, 2014. In addition, the Henry Hub spot market price had declined from a high of $8.15 per MMBtu on February 10, 2014 to a low of $4.30 per MMBtu on December 1, 2014. Likewise, NGLs, which comprised 24% of our estimated proved reserves at September 30, 2014 and accounted for 15% of our production on a volume equivalent basis for the three months ended September 30, 2014, have suffered significant recent declines in realized prices. NGLs are made up of ethane, propane, isobutane, normal butane and natural gasoline, all of which have different uses and different pricing characteristics. A further or extended decline in commodity prices could materially and adversely affect our future business, financial condition, results of operations and cash available for distributions. Although we intend to have a hedging policy following the consummation of this offering, we will not have any hedges prior to the completion of this offering. Any substantial decline in commodity prices will likely have a material adverse effect on our results of operations, financial condition and cash available for distribution.

The prices that Memorial Resource receives for its oil and natural gas production often reflect a regional discount, based on the location of production, to the relevant benchmark prices, such as NYMEX or ICE, that are used for calculating hedge positions. The prices that Memorial Resource receives for its production are also affected by the specific characteristics of the production relative to production sold at benchmark prices. These discounts, if significant, could adversely affect our results of operations and financial condition.

Identified drilling locations, which are scheduled out over many years, are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

As of September 30, 2014, Memorial Resource has advised us that it has identified 1,022 gross horizontal drilling locations across our acreage. Only 104 of these gross identified drilling locations had proved undeveloped reserves attributed to them in our reserve report. These drilling locations, including those with attributed proved undeveloped reserves, represent a significant part of our growth strategy. Memorial Resource’s ability to drill and develop identified potential drilling locations will depend on a number of factors, including the availability of capital, seasonal conditions, regulatory changes and approvals, negotiation of agreements with third parties, commodity prices, costs, the generation of additional seismic or geological information, the availability of drilling rigs, drilling results, construction of infrastructure, inclement weather, and lease expirations.

Further, 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 analysis of data. We will not be able to predict in advance of drilling and testing whether any particular drilling location will yield production in sufficient quantities for operators to recover drilling or completion costs or to be economically viable. Even if sufficient amounts of oil or natural gas reserves exist, the potentially productive hydrocarbon bearing formation may be damaged or mechanical difficulties may develop 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 dry holes in our current and future drilling locations, our business may be materially harmed. We will not be able to assure you that the analogies drawn from available data from other wells, more fully explored locations or producing fields will be applicable to our drilling locations. Further, initial production rates reported by us or our operators in our areas of operations may not be indicative of future or long-term production rates.

A majority of our gross horizontal drilling locations (as of September 30, 2014) within the Terryville Complex are identified within four distinct zones, with such gross horizontal drilling locations being roughly evenly distributed amongst such four zones. To date, Memorial Resource has drilled 44 horizontal wells, 41 of which are within these four distinct zones within the Terryville Complex. Accordingly, Memorial Resource has

limited experience in drilling horizontal wells in the zones of the Terryville Complex to which it has ascribed a substantial majority of our gross identified drilling locations. Please see “Business—Our Operations—Drilling Locations” for more information on our gross identified drilling locations.

Because of these uncertainties, we do not know if the potential drilling locations identified on our acreage will ever be drilled or if oil or natural gas reserves will be able to be produced from these or any other potential drilling locations. As such, actual drilling activities with respect to our acreage may materially differ from those presently identified, which could adversely affect our business, financial condition, results of operations and cash available for distribution.

The development of our proved undeveloped may take longer and may require higher levels of capital expenditures than we anticipate and may not be economically viable.

Approximately 70% of our total proved reserves at September 30, 2014 were proved undeveloped reserves; those reserves may not be ultimately developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations by Memorial Resource. The reserve data included in our reserve report assumes that substantial capital expenditures are required to develop such undeveloped reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomic to Memorial Resource. In addition, delays in the development of reserves could cause us to have to reclassify our proved reserves as unproved reserves.

Our future success depends on acquiring additional reserves.

Our future success depends upon our ability to acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that successful exploration or development activities are conducted on our properties or we acquire properties containing proved reserves, or both. Capital expenditures will be necessary for the potential acquisition of additional oil and natural gas reserves. Neither we nor our third-party operators may have sufficient resources to acquire additional reserves or to undertake exploration, development, production or other replacement activities, such activities may not result in significant additional reserves and efforts to drill productive wells at low finding and development costs may be unsuccessful. In addition, unlike most other master limited partnerships with depleting assets, we do not expect to initially retain cash from our operations for maintenance capital expenditures. See “Cash Distribution Policy and Restrictions on Distributions—Estimated Cash Available for Distribution for the Twelve Months Ending December 31, 2015—Assumptions and Considerations—Capital Expenditures.” Furthermore, although our revenues and cash available for distribution may increase if prevailing oil and natural gas prices increase significantly, finding costs for additional reserves could also increase.

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

Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review will not necessarily reveal all existing or potential problems. In the course of our due diligence, we may not inspect every well or pipeline. We cannot necessarily observe structural and environmental problems, such as pipe corrosion, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the

property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

Our hedging strategy may not effectively mitigate the impact of commodity price volatility from our cash flows, and our hedging activities could result in cash losses and may limit potential gains.

The prices at which we enter into commodity derivative contracts covering our production in the future will be dependent upon oil and natural gas prices, and price expectations, at the time we enter into these transactions, which may be substantially higher or lower than current or future oil and natural gas prices. Accordingly, our price hedging strategy may not protect us from significant declines in oil and natural gas prices received for our future production. Many of the derivative contracts to which we will be a party will require us to make cash payments to the extent the applicable index exceeds a predetermined price, thereby limiting our ability to realize the benefit of increases in oil and natural gas prices. If our actual production and sales for any period are less than our hedged production and sales for that period (including reductions in production due to operational delays) or if we are unable to perform our drilling activities as planned, we might be forced to satisfy all or a portion of our hedging obligations without the benefit of the cash flow from our sale of the underlying physical commodity, which may materially impact our liquidity.

During the year ended December 31, 2013, Memorial Resource sold all of our oil production to a single purchaser. The loss of this purchaser, if not replaced, could reduce our revenues and have a material adverse effect on our financial condition and results of operations.

For the year ended December 31, 2013, Energy Transfer Equity, L.P. and certain of its subsidiaries accounted for all of our revenues. We depend upon a limited number of significant purchasers for the sale of our production. The loss of any of these customers, should we be unable to replace them, could adversely affect our revenues and have a material adverse effect on our financial condition and results of operations. We cannot assure you that any of our customers will continue to do business with us or that we will continue to have access to suitably liquid markets for our future production.

The inability of our significant customers to meet their obligations to us may adversely affect our financial results.

We are subject to credit risk due to concentration of our oil and natural gas receivables with Energy Transfer Equity, L.P. and certain of its subsidiaries. For the year ended December 31, 2013, Energy Transfer Equity, L.P. and certain of its subsidiaries accounted for all of our revenues. We generally do not require our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial condition and results of operations.

In the future, we may enter into hedging transactions, which could expose us to counterparty credit risk.

In the future, we may enter into hedging transactions, which could expose us to risk of financial loss if a counterparty were to fail to perform under a derivative contract. Disruptions in the financial markets or other unforeseen events could lead to sudden changes in a counterparty’s liquidity, which could impair its ability to perform under the terms of a derivative contract and, accordingly, prevent us from realizing the benefit of such a derivative contract.

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

The process of estimating natural gas and oil reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions

and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect our estimated quantities and present value of our reserves.

In order to prepare our estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary.

The process also requires economic assumptions about matters such as natural gas prices, oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

Actual future production, oil prices, natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, we may adjust our reserve estimates to reflect production history, results of exploration and development, existing commodity prices and other factors, many of which are beyond our control.

You should not assume that the present value of future net revenues from our reserves is the current market value of our estimated reserves. We generally base the estimated discounted future net cash flows from our reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate.

Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, which could adversely affect our results of operations, financial condition and cash available for distribution.

SEC rules could limit our ability to book additional PUDs in the future.

SEC rules require that, subject to limited exceptions, PUDs may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement may limit our ability to book additional PUDs as Memorial Resource pursues its drilling program. Moreover, we may be required to write down our PUDs if those wells are not drilled within the required five-year timeframe.

The PV-10 of our estimated proved reserves is not necessarily the same as the current market value of our estimated proved oil and natural gas reserves.

The present value of future net cash flows from our proved reserves shown in this report, or PV-10, may not be the current market value of our estimated natural gas and oil reserves. In accordance with rules established by the SEC and the Financial Accounting Standards Board (“FASB”), we base the estimated discounted future net cash flows from our proved reserves on the 12-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.

The properties in which we have royalty interests are concentrated in the Terryville Complex within the Cotton Valley formation in North Louisiana, making us vulnerable to risks associated with operating in one major geographic area.

The producing properties of Memorial Resource in which we have a royalty interest are geographically concentrated entirely in the Terryville Complex within the Cotton Valley formation in North Louisiana. As a

result of this concentration, our results of operations may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, availability of equipment and personnel, water shortages or other drought related conditions or interruption of the processing or transportation of oil, natural gas or NGLs.

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 Memorial Resource’s and our business, financial condition, results of operations and cash flows.

We may be unable to compete effectively with larger companies.

The oil and natural gas industry is intensely competitive with respect to acquiring additional royalty or mineral interests. Our ability to acquire additional interests in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors not only drill for and produce oil and natural gas but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis, and many of our competitors have access to capital at a lower cost than that available to us. These companies may be able to pay more for oil and natural gas properties and evaluate, bid for and purchase a greater number of properties than our financial, technical or personnel resources permit. Furthermore, we may not be able to aggregate sufficient quantities of production to compete with larger companies that are able to sell greater volumes of production to intermediaries, thereby reducing the realized prices attributable to our production. Any inability to compete effectively with larger companies could have a material adverse impact on our financial condition, results of operations and cash available for distribution.

Derivatives reform legislation and related regulations could have an adverse effect on our ability to hedge risks associated with our business.

The July 2010 Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, provides for federal oversight of the over-the-counter derivatives market and entities that participate in that market and mandates that the Commodity Futures Trading Commission, or CFTC, adopt rules or regulations implementing the Dodd-Frank Act and providing definitions of terms used in the Dodd-Frank Act. The Dodd-Frank Act establishes margin requirements and requires clearing and trade execution practices for certain market participants and may result in certain market participants needing to curtail or cease their derivatives activities. Although some of the rules necessary to implement the Dodd-Frank Act remain to be adopted, the CFTC has issued a large number of rules to implement the Dodd-Frank Act, including a rule establishing an “end-user” exception to mandatory clearing, referred to herein as the “End-User Exception,” and a rule imposing position limits, referred to herein as the Initial Position Limit Rule. The Initial Position Limit Rule was vacated and remanded to the CFTC for further proceedings by order of the United States District Court for the District of Columbia on September 28, 2012. The CFTC proposed a new version of the Initial Position Limit Rule in November 2013, referred to herein as the “Re-Proposed Position Limit Rule,” with respect to which the comment period has closed but a final rule has not been issued. The CFTC and bank regulators in September 2014 re-proposed rules which would impose margin requirements on uncleared swaps between banks, swap dealers and major swap participants, referred to herein as the “Re-Proposed SD/MSP Margin Rule.”

We qualify as a “non-financial entity” for purposes of the End-User Exception and we will likely utilize such exception in the future so that any future hedging activity is not subject to mandatory clearing or the margin requirements imposed in connection with mandatory clearing. However, we anticipate that most if not all of our

future hedge counterparties will be subject to mandatory clearing in connection with their hedging activities with parties who do not qualify for the End-User Exception and, if the Re-Proposed SD/MSP Margin Rule is adopted, will be subject to such rule and required to post margin in accordance with such rule in connection with their swaps with other banks, swap dealers and major swap participants. The Dodd-Frank Act, the rules which have been adopted and not vacated, and, to the extent that the Re-Proposed Position Limit Rule and the Re-Proposed SD/MSP Margin Rule are ultimately effected, such proposed rules could significantly increase the cost of derivative contracts (including through requirements to post collateral), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we are limited in our use of derivatives in the future as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity contracts related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition, and our results of operations.

Our revolving credit facility will have restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions to our unitholders.

We expect that our revolving credit facility will restrict, among other things, our ability to incur debt and pay distributions, and will require us to comply with customary financial covenants and specified financial ratios. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any provisions of our revolving credit facility that are not cured or waived within the specified time periods, a significant portion of our indebtedness may become immediately due and payable, and we will be prohibited from making distributions to our unitholders. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our revolving credit facility will be secured by substantially all of our assets, and if we are unable to repay our indebtedness under our revolving credit facility, the lenders could seek to foreclose on our assets. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Revolving Credit Facility” for additional detail regarding the covenants and restrictive provisions to be included in our revolving credit facility.

Our revolving credit facility will allow us to borrow in an amount up to the borrowing base, which is primarily based on the estimated value of our oil and natural gas properties and our commodity derivative contracts as determined semi-annually by our lenders in their sole discretion. Our borrowing base will be subject to redetermination on a semi-annual basis based on an engineering report with respect to our estimated natural gas, oil and NGL reserves, which will take into account the prevailing natural gas, oil and NGL prices at such time, as adjusted for the impact of our commodity derivative contracts. A future decline in commodity prices could result in a redetermination that lowers our borrowing base in the future and, in such case, we could be required to repay any indebtedness in excess of the borrowing base. If we are unable to repay any borrowings in excess of a decreased borrowing base, we would be in default and no longer able to make any distributions to our unitholders.

We may not be able to generate enough cash flow to meet our debt obligations and may be forced to take other actions to satisfy our debt obligations which may not be successful.

We expect our earnings and cash flow to vary significantly from year to year due to the cyclical nature of the exploration and production industry upon which our cash flows depend. As a result, the amount of debt that we can service in some periods may not be appropriate for us in other periods. Moreover, and subject to certain limitations, we and our subsidiaries may be able to incur substantial additional indebtedness in the future.

Additionally, our future cash flow may be insufficient to meet our debt obligations and commitments. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and from our subsidiaries and to pay our debt. Many of these factors, such as oil and natural gas prices, economic and financial conditions in our industry and the global economy or competitive initiatives of our competitors, are beyond our control.

If we do not generate enough cash flow from operations and from our subsidiaries to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:

•

refinancing or restructuring our debt;

•

selling assets;

•

reducing or delaying any capital investments; or

•

seeking to raise additional capital.

However, we cannot assure you that undertaking alternative financing plans, if necessary, would allow us to meet our debt obligations. Our inability to generate sufficient cash flow to satisfy our debt obligations or to obtain alternative financing, could materially and adversely affect our ability to make payments on our indebtedness and our business, financial condition, results of operations and cash available for distribution.

Furthermore, our ability to restructure or refinance our indebtedness will depend on the condition of the capital markets and our financial condition at such time. Pursuant to a lock-up agreement that we will enter into in connection with the completion of this offering, we will be unable to sell any of our common units in a subsequent private or public offering for the 180 days following the date of this prospectus unless we obtain the consent of Barclays Capital Inc. Please read “Underwriting—Lock-Up Agreements.” Any refinancing of our indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. The terms of existing or future debt instruments, including our revolving credit facility, may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. We expect our revolving credit facility will restrict our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations.

Risks Related to Our Operator

Memorial Resource, our current operator, is subject to the risks and uncertainties described below, and, as the owner of royalty interests, we are indirectly exposed to the same risks and uncertainties.

Memorial Resource may have difficulty managing growth in its business, which could adversely affect our financial condition, results of operations and cash available for distribution.

As a recently formed company, growth in accordance with Memorial Resource’s business plan, if achieved, could place a significant strain on Memorial Resource’s financial, technical, operational and management resources. As Memorial Resource expands its activities and increases the number of projects it is evaluating or in which it participates, there will be additional demands on its financial, technical, operational and management resources. Memorial Resource also currently depends on the services of an entity managed by certain former management members of WildHorse Resources for supervising and managing Memorial Resource’s drilling

operations in the Terryville Complex. In addition, the failure of Memorial Resource to continue to upgrade its technical, administrative, operating and financial control systems or the occurrences of unexpected expansion difficulties, including the failure to recruit and retain experienced managers, geologists, engineers and other professionals in the oil and natural gas industry, could have a material adverse effect on our business, financial condition, results of operations and cash available for distribution.

Unless Memorial Resource replaces the oil and natural gas reserves it produces, its revenues and production will decline, which would adversely affect our financial condition, results of operations and cash available for distribution.

Producing oil and natural gas reservoirs are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Memorial Resource’s future oil and natural gas reserves and production and therefore its cash flow and financial condition are highly dependent on its success in efficiently developing and exploiting its current reserves. Memorial Resource’s production decline rates may be significantly higher than currently estimated if its wells do not produce as expected. Further, Memorial Resource’s decline rate may change when it drills additional wells or makes acquisitions. Memorial Resource may not be able to develop, find or acquire additional reserves to replace its current and future production on economically acceptable terms, which would adversely affect our financial condition, results of operations and cash available for distribution.

Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that may result in a total loss of investment or otherwise adversely affect our financial condition, results of operations and cash available for distribution.

Memorial Resource’s drilling activities are subject to many risks. For example, we cannot assure you that wells drilled by Memorial Resource will be productive. Drilling for oil and natural gas often involves unprofitable efforts, not only from dry holes but also from wells that are productive but do not produce sufficient oil or natural gas to return a profit at then realized prices after deducting drilling, operating and other costs. The seismic data and other technologies used do not allow Memorial Resource to know conclusively prior to drilling a well that oil or natural gas is present or that it can be produced economically. The costs of exploration, exploitation and development activities are subject to numerous uncertainties beyond Memorial Resource’s control, and increases in those costs can adversely affect the economics of a project. Further, Memorial Resource’s drilling and producing operations may be curtailed, delayed, canceled or otherwise negatively impacted as a result of other factors, including:

•

unusual or unexpected geological formations;

•

loss of drilling fluid circulation;

•

loss of well control;

•

title problems;

•

facility or equipment malfunctions;

•

unexpected operational events;

•

shortages or delivery delays or increases in the cost of equipment and services;

•

reductions in oil, natural gas and NGL prices;

•

lack of proximity to and shortage of capacity of transportation facilities;

•

the limited availability of financing at acceptable rates;

•

delays imposed by or resulting from compliance with environmental and other governmental or regulatory requirements, which may include limitations on hydraulic fracturing or the discharge of greenhouse gases; and

•

adverse weather conditions.

Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties. In the event that planned operations, including the drilling of development wells, are delayed or cancelled, or existing wells or development wells have lower than anticipated production due to one or more of the factors above or for any other reason, our financial condition, results of operations and cash available for distribution to our unitholders may be adversely affected.

Part of Memorial Resource’s strategy involves using horizontal drilling and completion techniques, which involve risks and uncertainties in their application.

Memorial Resource’s operations involve utilizing some of the latest drilling and completion techniques as developed by Memorial Resource and its service providers. Risks that Memorial Resource faces while drilling horizontal wells include, but are not limited to, the following:

•

landing its wellbore in the desired drilling zone;

•

staying in the desired drilling zone while drilling horizontally through the formation;

•

running casing the entire length of the wellbore; and

•

being able to run tools and other equipment consistently through the horizontal wellbore.

Risks that Memorial Resource faces while completing its wells include, but are not limited to, the following:

•

the ability to fracture stimulate the planned number of stages;

•

the ability to run tools the entire length of the wellbore during completion operations; and

•

the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.

If Memorial Resource’s drilling results are less than anticipated, the return on Memorial Resource’s investment for a particular project may not be as attractive as it anticipated, and Memorial Resource could incur material write-downs of unevaluated properties, and the value of its undeveloped acreage could decline in the future.

Memorial Resource’s development and exploratory drilling efforts and its well operations may not be profitable or achieve targeted returns.

Memorial Resource owns a significant amount of unproved property, which it expects to further its development efforts. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We cannot assure you that all prospects will be economically viable or that Memorial Resource will not abandon its investments. Additionally, we cannot assure you that undeveloped acreage leased by Memorial Resource will be profitably developed, that wells drilled by Memorial Resource in prospects that it pursues will be productive or that Memorial Resource will recover all or any portion of its investment in such unproved property or wells.

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

Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres. As of December 31, 2013, our acreage included 11 gross acres scheduled to expire in 2014, 1,980 gross acres scheduled to expire in 2015, 1,810 gross acres scheduled to expire in 2016 and 1,050 gross acres scheduled to

expire in 2017. Our royalty interests would terminate if such associated leases expire. The cost to renew Memorial Resource’s leases may increase significantly, and Memorial Resource may not be able to renew such leases on commercially reasonable terms or at all. Memorial Resource is also under no obligation to offer us the opportunity to acquire royalty interests in such renewal leases. Moreover, many of Memorial Resource’s leases require lessor consent to pool, which would make it more difficult for Memorial Resource to hold its leases by production. Any reduction in Memorial Resource’s drilling program, either through a reduction in capital expenditures or the unavailability of drilling rigs, could result in the loss of acreage through lease expirations. We cannot assure you that Memorial Resource will have the liquidity to deploy these rigs when needed, or that commodity prices will warrant Memorial Resource operating such a drilling program. Any such losses of leases could materially and adversely affect the growth of our financial condition, results of operations and cash available for distribution.

Shortages of rigs, equipment and crews could delay our operations, increase Memorial Resource’s costs and delay forecasted revenue.

Higher oil and natural gas prices generally increase the demand for rigs, equipment and crews and can lead to shortages of, and increasing costs for, development equipment, services and personnel. Shortages of, or increasing costs for, experienced development crews and oil field equipment and services could restrict Memorial Resource’s ability to drill the wells and conduct the operations that it currently has planned. Any delay in the development of new wells or a significant increase in development costs could reduce Memorial Resource’s revenues and impact its development plan, which would thus affect our financial condition, results of operations and cash available for distribution.

Expenses not covered by Memorial Resource’s insurance could have a material adverse effect on our financial position, results of operations and cash available for distribution.

Memorial Resource’s operations are subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including natural disasters, 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, ruptures or discharges of toxic gases. In addition, Memorial Resource’s operations are subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. The location of any properties and other assets near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of damages resulting from these risks. The occurrence of any of these events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, suspension of operations, substantial revenue losses and repairs to resume operations.

Memorial Resource maintains insurance coverage against potential losses that it believes is customary in the industry. However, these policies may not cover all liabilities, claims, fines, penalties or costs and expenses that Memorial Resource may incur in connection with its business and operations, including those related to environmental claims. Pollution and environmental risks generally are not fully insurable. In addition, we cannot assure you that Memorial Resource will be able to maintain adequate insurance at rates it considers reasonable. Memorial Resource may elect not to obtain insurance if it believes that the cost of available insurance is excessive relative to the perceived risks presented. A loss not fully covered by insurance could have a material adverse effect on Memorial Resource’s business, and as a result, our financial position, results of operations and cash available for distribution.

Memorial Resource requires substantial capital expenditures to conduct its operations, engage in acquisition activities and replace its production, and it may be unable to obtain needed financing on satisfactory terms necessary to execute its operating strategy.

Memorial Resource requires substantial capital expenditures to conduct its exploration, development and production operations, engage in acquisition activities and replace its production. Memorial Resource has established a capital budget for 2014 of approximately $351 million, and it intends to rely on cash flow from operating activities as its primary sources of liquidity. Memorial Resource also may engage in asset and equity sale transactions to, among other things, fund capital expenditures when market conditions permit it to complete transactions on terms it finds acceptable. There can be no assurance that such sources will be sufficient to fund Memorial Resource’s exploration, development and acquisition activities. If Memorial Resource’s revenues and cash flows decrease in the future as a result of a decline in commodity prices or a reduction in production levels, however, and Memorial Resource is unable to obtain additional equity or debt financing in the capital markets or access alternative sources of funds, Memorial Resource may be required to reduce the level of its capital expenditures and may lack the capital necessary to replace its reserves or maintain our production levels.

Memorial Resource may be unable to compete effectively with larger companies.

The oil and natural gas industry is intensely competitive with respect to acquiring prospects and productive properties, marketing oil and natural gas, and securing equipment and trained personnel. Memorial Resource’s ability to acquire additional properties and to discover reserves in the future will depend on its ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of Memorial Resource’s larger competitors not only drill for and produce oil and natural gas but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis, and many of our competitors have access to capital at a lower cost than that available to Memorial Resource. These companies may be able to pay more for oil and natural gas properties and evaluate, bid for and purchase a greater number of properties than Memorial Resource’s financial, technical or personnel resources permit. In addition, there is substantial competition for investment capital in the oil and natural gas industry. These larger companies may have a greater ability to continue development activities during periods of low oil and natural gas prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Furthermore, Memorial Resource may not be able to aggregate sufficient quantities of production to compete with larger companies that are able to sell greater volumes of production to intermediaries, thereby reducing the realized prices attributable to its production. Any inability to compete effectively with larger companies could have a material adverse impact on Memorial Resource’s financial condition, results of operations and our cash available for distribution.

Memorial Resource’s business depends in part on pipelines, gathering systems and processing facilities owned by Memorial Resource or others. Any limitation in the availability of those facilities could interfere with Memorial Resource’s ability to market its oil and natural gas production.

The marketability of Memorial Resource’s oil and natural gas production depends in part on the availability, proximity and capacity of pipelines and other transportation methods, gathering systems and processing facilities owned by third parties. The amount of oil and natural gas 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 contracted capacity on such systems. Memorial Resource’s access to transportation options can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, Memorial Resource is provided with only limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or transportation or processing facility capacity could reduce Memorial Resource’s ability to market its oil and natural gas production and, as a result, harm our financial condition, results of operations and cash available for distribution.

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

Memorial Resource relies on 2-D and 3-D seismic data. Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and Memorial Resource could incur losses as a result of such expenditures. As a result, Memorial Resource’s drilling activities may not be successful or economical, which could have a material adverse impact on our financial condition, results of operations and cash available for distribution.

Memorial Resource is subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting its operations.

Memorial Resource’s natural gas and oil exploration, production, and transportation operations are subject to complex and stringent laws and regulations. To conduct its operations in compliance with these laws and regulations, Memorial Resource must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. Memorial Resource may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment and thus, Memorial Resource’s costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to its operations. Failure to comply with laws and regulations applicable to Memorial Resource’s operations, including any evolving interpretation and enforcement by governmental authorities, could have a material adverse effect on our financial condition, results of operations and cash available for distribution.

Memorial Resource’s oil and natural gas development and production operations are also subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment, worker health and safety aspects of its operations, or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations applicable to Memorial Resource’s operations including: (i) the acquisition of a permit before conducting regulated drilling activities, (ii) the restriction of types, quantities and concentration of materials that can be released into the environment, (iii) the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas, (iv) the application of specific health and safety criteria addressing worker protection and (v) the imposition of substantial liabilities for pollution resulting from its operations. Numerous governmental authorities, such as the U.S. Environmental Protection Agency, or the EPA, and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them. Such enforcement actions often involve taking difficult and costly compliance measures or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of Memorial Resource’s operations. In addition, Memorial Resource may experience delays in obtaining or be unable to obtain required permits, which may delay or interrupt its operations and limit its growth and revenues.

Certain environmental laws impose strict as well as joint and several liability for costs required to remediate and restore sites where hazardous substances, hydrocarbons, or solid wastes have been stored or released. Memorial Resource may be required to remediate contaminated properties currently or formerly operated by Memorial Resource or facilities of third parties that received waste generated by its operations regardless of whether such contamination resulted from the conduct of others or from consequences of Memorial Resource’s own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health

and safety impacts of Memorial Resource’s operations. Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, Memorial Resource’s business, prospects, and, as a result, our financial condition and results of operations could be materially adversely affected.

Please read “Business—Regulation of Environmental and Occupational Health and Safety Matters” for a further description of the laws and regulations that affect us.

Climate change legislation or regulations restricting emissions of “greenhouse gases,” or GHGs could result in increased operating costs for Memorial Resource and reduced demand for the oil and natural gas that Memorial Resource produces.

In December 2009, the EPA published its findings that emissions of GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA adopted regulations under existing provisions of the federal Clean Air Act (“CAA”) that establish Prevention of Significant Deterioration, or PSD, and Title V permit reviews for GHG emissions from certain large stationary sources. On June 23, 2014, the Supreme Court held that stationary sources could not become subject to PSD or Title V permitting solely by reason of their GHG emissions. The Court ruled, however, that the EPA may require installation of best available control technology for GHG emissions at sources otherwise subject to the PSD or Title V programs. The EPA has announced that it is currently evaluating the decision and awaiting further action by the courts, and that it will provide relevant guidance on GHG permitting requirements.

The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources on an annual basis in the United States, including certain oil and natural gas production facilities, which includes certain of Memorial Resource’s operations. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, Memorial Resource’s equipment and operations could require Memorial Resource to incur costs to reduce emissions of GHGs associated with its operations or could adversely affect demand for the oil and natural gas it produces. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on Memorial Resource’s business and, as a result, our financial condition and results of operations.

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations that require reporting of GHGs or otherwise limit emissions of GHGs from Memorial Resource’s equipment and operations could require Memorial Resource to incur costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with its operations, and such requirements also could adversely affect demand for the oil and natural gas that it produces. 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, droughts and floods and other climatic events. If any such effects

were to occur, they could have an adverse effect on our financial condition, results of operations and cash available for distribution. Please read “Business—Regulation of Environmental and Occupational Health and Safety Matters” for a further description of the laws and regulations that affect us.

The listing of a species as either “threatened” or “endangered” under the federal Endangered Species Act could result in increased costs and new operating restrictions, loss of leasehold or delays on Memorial Resource’s operations, which could adversely affect our results of operations, financial condition and cash available for distribution.

The federal Endangered Species Act and analogous state laws restrict activities that may adversely affect endangered and threatened species or their habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The designation of previously unidentified endangered or threatened species in areas where Memorial Resource operates could cause Memorial Resource to incur additional costs or become subject to operating delays, restrictions or bans. Numerous species have been listed or proposed for protected status in areas in which Memorial Resource currently, or could in the future, undertake operations. The presence of protected species in areas where Memorial Resource operates could impair Memorial Resource’s ability to timely complete or carry out those operations, lose leaseholds as Memorial Resource may not be permitted to timely commence drilling operations, cause Memorial Resource, as our operator, to incur increased costs arising from species protection measures, and, consequently, adversely affect our results of operations, financial position and cash available for distribution.

The third parties on whom Memorial Resource relies for gathering and transportation services are subject to complex federal, state and other laws that could adversely affect the cost, manner or feasibility of conducting its business.

The operations of the third parties on whom Memorial Resource relies for gathering and transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulations. If existing laws and regulations governing such third-party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that Memorial Resource pays for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom Memorial Resource relies could have a material adverse effect on Memorial Resource’s business and, as a result, our financial condition, results of operations and cash available for distribution. See “Business—Regulation of Environmental and Occupational Health and Safety Matters” and “Business—Regulation of the Oil and Natural Gas Industry” for a description of the laws and regulations that affect the third parties on whom we rely.

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

Memorial Resource engages in hydraulic fracturing, which is an essential and common practice in the oil and gas industry used to stimulate production of natural gas and/or oil from dense subsurface rock formations. Hydraulic fracturing involves using water, sand, and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow flow of hydrocarbons into the wellbore. Memorial Resource routinely applies hydraulic fracturing techniques in its drilling and completion programs. While hydraulic fracturing has historically been regulated by state oil and natural gas commissions, federal agencies have asserted regulatory authority over the process. For example, the EPA is updating chloride water quality criteria for the protection of aquatic life under the Clean Water Act, which criteria are used by states for establishing acceptable discharge limits. The EPA is expected to release draft criteria in late 2014. In October 2011, the EPA announced its plan to propose federal pre-treatment standards for wastewater generated during the hydraulic fracturing process. Hydraulic fracturing stimulation requires the use of a significant volume of water with some resulting “flowback,” as well as “produced water.” If adopted, the new pretreatment rules will require shale gas operations to pretreat wastewater

before transferring it to treatment facilities. Proposed rules are expected sometime in early 2015. In May 2014, the EPA issued an Advanced Notice of Proposed Rulemaking seeking public comment on its 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. The public comment period ended on September 18, 2014.

In August 2012, the EPA adopted rules that subject oil and natural gas production, processing, transmission, and storage operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants programs. The rules include NSPS standards for completions of hydraulically fractured gas wells and establishes specific new requirements for emissions from compressors, controllers, dehydrators, storage vessels, natural gas processing plants and certain other equipment. These standards, as well as any future laws and their implementing regulations, may require Memorial Resource to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or utilize specific equipment or technologies to control emissions. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact Memorial Resource’s business.

There are also certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater. A draft report is expected to be released for public comment and review in early 2015. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing.

Additionally, Congress from time to time has considered the adoption of legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. Certain states have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure, and well construction requirements on hydraulic-fracturing operations or otherwise seek to ban fracturing activities altogether. For example, in October 2011, the Louisiana Department of Natural Resources adopted new rules requiring the public disclosure of the composition and volume of fracturing fluids used in hydraulic fracturing operations. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. In the event state, local, or municipal legal restrictions are adopted in areas where Memorial Resource is currently conducting, or in the future plans to conduct operations, Memorial Resource may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling of wells.

If these or any other new laws or regulations that significantly restrict hydraulic fracturing are adopted at the state and local level, such laws could make it more difficult or costly for Memorial Resource, as our operator, to perform fracturing to stimulate production from dense subsurface rock formations and, in the event of local prohibitions against commercial production of natural gas, may preclude Memorial Resource’s ability to drill wells. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA or other federal agencies, Memorial Resource’s fracturing activities could become subject to additional permitting requirements and result in permitting delays as well as potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that Memorial Resource, as our operator, is ultimately able to produce from its reserves, which could have a material adverse impact on our financial condition, results of operations and cash available for distribution.

Oil and natural gas producers’ operations, especially those using hydraulic fracturing, are substantially dependent on the availability of water and wastewater disposal options. Restrictions on Memorial Resource’s ability to obtain water or dispose of water may have an adverse effect on our financial condition, results of operations and cash available for distribution.

Water is an essential component of oil and natural gas production during the drilling, and in particular, hydraulic fracturing, process. Memorial Resource’s inability to locate sufficient amounts of water, or dispose of or recycle water used in its exploration and production operations, could adversely impact Memorial Resource’s business, and as a result, our financial condition, results of operations and cash available for distribution. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on Memorial Resource’s ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of natural gas. The Federal Water Pollution Control Act (the “CWA”) imposes restrictions and strict controls regarding the discharge of produced waters and other natural gas and oil waste into navigable waters. Permits must be obtained to discharge pollutants to waters and to conduct construction activities in waters and wetlands. The CWA and similar state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of pollutants and unauthorized discharges of reportable quantities of oil and other hazardous substances. State and federal discharge regulations prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the natural gas and oil industry into coastal waters. Also, the EPA has adopted regulations requiring certain natural gas and oil exploration and production facilities to obtain permits for storm water discharges. Compliance with current and future environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase Memorial Resource’s operating costs and cause delays, interruptions or termination of its operations, the extent of which cannot be predicted.

Memorial Resource’s operations may be exposed to significant delays, costs and liabilities as a result of environmental, health and safety requirements applicable to its business activities.

Memorial Resource may incur significant delays, costs and liabilities as a result of federal, state and local environmental, health and safety requirements applicable to its exploration, development and production activities. These laws and regulations may, among other things: (i) require Memorial Resource to obtain a variety of permits or other authorizations governing its air emissions, water discharges, waste disposal or other environmental impacts associated with drilling, producing and other operations; (ii) regulate the sourcing and disposal of water used in the drilling, fracturing and completion processes; (iii) limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas; (iv) require remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; and/or (v) impose substantial liabilities for spills, pollution or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of oil or natural gas production. These laws and regulations are complex, change frequently and have tended to become increasingly stringent over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations. Under certain environmental laws that impose strict as well as joint and several liability, Memorial Resource may be required to remediate contaminated properties operated by it or facilities of third parties that received waste generated by its operations regardless of whether such contamination resulted from the conduct of others or from consequences of its own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. In addition, the risk of accidental and/or unpermitted spills or releases from our operations could expose Memorial Resource to significant liabilities, penalties and other sanctions under applicable laws. Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and

stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, financial condition, results of operations and cash available for distribution could be materially adversely affected.

Risks Inherent in an Investment in Us

Our general partner will have control over all decisions related to our operations. Upon consummation of this offering, Memorial Resource will own and control our general partner, % of our outstanding common units and all of our subordinated units. MRD Holdco, in turn, owns % of the outstanding common stock of Memorial Resource. The directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to the owners of our general partner. However, certain directors and officers of our general partner are directors and/or officers of affiliates of our general partner (including Memorial Resource, MEMP, the Funds and NGP), and certain of our general partner’s executive officers and directors will continue to have economic interests, investments and other economic incentives in the Funds and other NGP-affiliated entities. Conflicts of interest may arise in the future between our general partner and its affiliates (including Memorial Resource, MEMP, the Funds and NGP), on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders and us. Please read “Conflicts of Interest and Fiduciary Duties.” These potential conflicts include, among others, the following situations:

•

neither our partnership agreement nor any other agreement requires Memorial Resource, MEMP, the Funds or NGP to pursue a business strategy that favors us. The directors and officers of Memorial Resource, MEMP, the Funds and their respective affiliates (including NGP) have a fiduciary duty to make decisions in the best interests of their respective equity holders, which may be contrary to our interests;

•

our general partner is allowed to take into account the interests of parties other than us, such as its owner, in exercising certain rights under our partnership agreement, including with respect to conflicts of interest;

•

Memorial Resource, MEMP, the Funds and their affiliates (including NGP) are not limited in their ability to compete with us, including with respect to future acquisition opportunities, and are under no obligation to offer assets to us. Please read “Conflicts of Interest and Fiduciary Duties—Conflicts of Interest—Memorial Resource, MEMP, the Funds and other affiliates of our general partner will not be limited in their ability to compete with us, which could cause conflicts of interest and limit our ability to acquire additional assets or businesses”;

•

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

•

many of the officers and directors of our general partner who will provide services to us will devote time to affiliates of our general partner, including Memorial Resource, MEMP, the Funds, and/or NGP, and may be compensated for services rendered to such affiliates;

•

our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limits our general partner’s liabilities and restricts the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty;

•

our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership interests, other investments, including investment capital

expenditures in other partnerships with which our general partner is or may become affiliated, and the creation, reduction or increase of cash reserves, each of which can affect the amount of cash that is distributed to unitholders;

•

our general partner determines the amount of our estimated maintenance capital expenditures, which reduces operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner, the amount of adjusted operating surplus in any given period and the ability of the subordinated units to convert into common units;

•

we and our general partner will enter into an omnibus agreement with Memorial Resource in connection with this offering, pursuant to which, among other things, Memorial Resource will perform management, administrative and operating services for us and our general partner;

•

our general partner is entitled to determine which costs, including allocated overhead, incurred by it and its affiliates, including Memorial Resource, are reimbursable by us, which will include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf, and expenses allocated to our general partner by its affiliates;

•

our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period;

•

our partnership agreement permits us to classify up to $ million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or to our general partner in respect of the incentive distribution rights;

•

our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations;

•

our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;

•

our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, is entitled to be indemnified by us;

•

our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of our common units;

•

our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including Memorial Resource, MEMP, the Funds and NGP; and

•

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

Please read “Certain Relationships and Related Party Transactions” and “Conflicts of Interest and Fiduciary Duties.”

Unlike most master limited partnerships with subordinated units, our partnership agreement allows for conversion of subordinated units into common units after paying a quarterly distribution at the highest target distribution level for only a single quarter.

Most master limited partnerships that have subordinated units in their capital structures allow for early conversion of subordinated units into common units only after a significant increase in quarterly distributions (typically at the highest target distribution level) measured over a four-quarter period. Unlike most master limited

partnerships with subordinated units, our partnership agreement allows for conversion of subordinated units into common units after payment of quarterly distributions at the highest target distribution level for any single quarter ending on or after September 30, 2016. This early conversion provision could allow our sponsor to convert its subordinated units into common units solely as a result of a short-term increase in commodity prices or production volumes, rather than as a result of a more sustainable increase in operations measured over a longer period of time, as is the case with most other master limited partnerships with subordinated units.

Memorial Resource, MEMP, the Funds and other affiliates of our general partner will not be limited in their ability to compete with us, which could cause conflicts of interest and limit our ability to acquire additional assets or businesses.

Our partnership agreement provides that Memorial Resource and the Funds and their respective affiliates (including MEMP and NGP and its affiliates’ portfolio investments) are not restricted from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, Memorial Resource, MEMP and the Funds and their respective affiliates may acquire, develop or dispose of additional oil and natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets.

NGP and the Funds are established participants in the oil and natural gas industry, and have resources greater than ours, which factors may make it more difficult for us to compete with them with respect to commercial activities as well as for potential acquisitions. As a result, competition from these affiliates could adversely impact our results of operations and cash available for distribution to our unitholders. Please read “Conflicts of Interest and Fiduciary Duties.”

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

Neither we nor our general partner have any employees and we will rely solely on Memorial Resource to operate our assets. Upon consummation of this offering, we and our general partner will enter into an omnibus agreement with Memorial Resource, pursuant to which, among other things, Memorial Resource will agree to perform management, administrative and operating services for us and our general partner.

Memorial Resource will provide substantially similar activities with respect to its and MEMP’s assets and operations. Because Memorial Resource will be providing services to us that are substantially similar to those performed for itself and MEMP, Memorial Resource may not have sufficient human, technical and other resources to provide those services at a level that Memorial Resource would be able to provide to us if it were solely focused on our business and operations. Memorial Resource may make internal decisions on how to allocate its available resources and expertise that may not always be in our best interest compared to Memorial Resource’s interests. There is no requirement that Memorial Resource favor us over itself or MEMP in providing its services. If the employees of Memorial Resource and their affiliates do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our unitholders may be reduced.

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.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain

our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes Oxley Act of 2002. 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 units.

Many of the directors and all of the officers who have responsibility for our management have significant duties with, and spend significant time serving, entities that may compete with us in seeking acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities.

Most of our officers hold similar positions with Memorial Resource and the general partner of MEMP, which we refer to as MEMP GP, and many of our directors, who are responsible for managing the direction of our operations and acquisition activities, hold positions of responsibility with other entities (including NGP-affiliated entities) that are in the business of identifying and acquiring oil and natural gas properties. For example, the Funds and their affiliates (including NGP) are in the business of investing in oil and natural gas companies with independent management teams that also seek to acquire oil and natural gas properties, and Memorial Resource and MEMP are both in the business of acquiring and developing oil and natural gas properties. Mr. Weinzierl, our Chief Executive Officer and the Chairman of the board of directors of our general partner, is the Chief Executive Officer and Chairman of MEMP GP, the Chief Executive Officer and a director of Memorial Resource, and was a managing director and operating partner of NGP and continues to hold ownership interests in the Funds and certain of their affiliates. Our officers will continue to devote significant time to the business of Memorial Resource and MEMP and face conflicts in allocating their time on our behalf and on behalf of MEMP GP and Memorial Resource. Our officers have also historically received a significant portion of their overall compensation in MEMP restricted unit awards under the long term incentive plan of MEMP GP and expect to receive a significant portion in Memorial Resource restricted stock awards under Memorial Resource’s long-term incentive plan. We cannot assure you that any conflicts that may arise between us and our unitholders, on the one hand, and Memorial Resource, MEMP, or the Funds, on the other hand, will be resolved in our favor. The existing positions held by these directors and officers may give rise to fiduciary or other duties that are in conflict with the duties they owe to us. These officers and directors may become aware of business opportunities that may be appropriate for presentation to us as well as to the other entities with which they are or may become affiliated. Due to these existing and potential future affiliations, they may present potential business opportunities to other entities prior to presenting them to us, which could cause additional conflicts of interest. They may also decide that certain opportunities are more appropriate for other entities with which they are affiliated, and as a result, they may elect not to present those opportunities to us. These conflicts may not be resolved in our favor. For additional discussion of our management’s business affiliations and the potential conflicts of interest of which our unitholders should be aware, see “Certain Relationships and Related Party Transactions.”

Cost reimbursements due to Memorial Resource and our general partner for services provided to us or on our behalf will be substantial and will reduce our cash available for distribution to our unitholders.

Our partnership agreement requires us to reimburse our general partner and its affiliates for all actual direct and indirect expenses they incur or actual payments they make on our behalf and all other expenses allocable to us or otherwise incurred by our general partner or its affiliates in connection with operating our business, including overhead allocated to our general partner by its affiliates, including Memorial Resource. These expenses include salary, bonus, incentive compensation (including equity compensation) and other amounts paid to persons who perform services for us or on our behalf, and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine the expenses that are allocable to us.

Prior to making distributions on our common units, we will reimburse our general partner and its affiliates for all such expenses. None of these reimbursements are capped. The reimbursements to Memorial Resource and our general partner will reduce the amount of cash otherwise available for distribution to our unitholders.

At the closing of this offering, we will enter into agreements with Memorial Resource and our general partner pursuant to which, among other things, we will make payments to Memorial Resource. These payments will be substantial and will reduce the amount of cash available for distribution to unitholders. These include an omnibus agreement pursuant to which, among other things, Memorial Resource will provide management, administrative and operating services for us and our general partner.

Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

Our general partner has the right (but not the obligation), at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (25%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election. Following any reset election by our general partner, the minimum quarterly distribution will be reset to an amount equal to the cash contribution per common unit for the fiscal quarter immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units. The number of common units to be issued to our general partner will be equal to that number of common units which would have entitled their holder to a quarterly cash distribution in the prior quarter equal to the distributions to our general partner on the incentive distribution rights in the prior quarter. We anticipate that our general partner would exercise this reset right (if at all) to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that our common unitholders would have otherwise received had we not issued new common units to our general partner in connection with resetting the target distribution levels. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—General Partner’s Right to Reset Incentive Distribution Levels.”

Common units held by persons who are non-taxpaying assignees will be subject to the possibility of redemption.

If our general partner determines that our not being treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes, coupled with the tax status (or lack of proof thereof) of one or more of our limited partners, has, or is reasonably likely to have, a material adverse effect on our ability to operate our assets or generate revenues from our assets, then our general partner may adopt such amendments to our partnership agreement as it determines are necessary or advisable to obtain proof of the U.S. federal income tax status of our limited partners (and their owners, to the extent relevant) and permit us to redeem the units held by any person whose tax status has or is reasonably likely to have a material adverse effect on our ability to operate our assets or generate revenues from our assets or who fails to comply with the procedures instituted by our general partner to obtain proof of the U.S. federal income tax status. Please read “The Partnership Agreement—Non-Taxpaying Assignees; Redemption.”

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

In order to comply with U.S. laws with respect to the ownership of interests in oil and natural gas leases on federal lands, we will adopt certain requirements regarding those investors who may own our common units. As used herein, an Eligible Holder means a person or entity qualified to hold an interest in oil and natural gas leases on federal lands. As of the date hereof, Eligible Holder means: (1) a citizen of the United States; (2) a corporation organized under the laws of the United States or of any state thereof; or (3) an association of United States citizens, such as a partnership or limited liability company, organized under the laws of the United States or of any state thereof, but only if this association does not have any direct or indirect foreign ownership, other than foreign ownership of stock in a parent corporation organized under the laws of the United States or of any state thereof. For the avoidance of doubt, onshore mineral leases or any direct or indirect interest therein may be acquired and held by aliens only through stock ownership, holding or control in a corporation organized under the laws of the United States or of any state thereof and only for so long as the alien is not from a country that the United States federal government regards as denying similar privileges to citizens or corporations of the United States. Common unitholders who are not persons or entities who meet the requirements to be an Eligible Holder will not be entitled to receive distributions or allocations of income and loss on their units and they run the risk of having their units redeemed by us at the lower of their purchase price cost or the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will not elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner will be appointed by Memorial Resource. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Our general partner will have control over all decisions related to our operations. Since, upon consummation of this offering, Memorial Resource will own our general partner, approximately % of our outstanding common units and all of our subordinated units, the other unitholders will not have an ability to influence any operating decisions and will not be able to prevent us from entering into any transactions. Our partnership agreement generally may not be amended during the subordination period without the approval of our public common unitholders. However, our partnership agreement can be amended with the consent of our general partner and the approval of the holders of a majority of our outstanding common units (including common units held by Memorial Resource and its affiliates) after the subordination period has ended. Assuming we do not issue any additional common units and Memorial Resource does not transfer its common units, Memorial Resource will have the ability to amend our partnership agreement, including our policy to distribute all of our cash available for distribution to our unitholders, without the approval of any other unitholder once the subordination period ends. Furthermore, the goals and objectives of Memorial Resource and its affiliates that hold our common units relating to us may not be consistent with those of a majority of the other unitholders. Please read “—Our general partner and its affiliates will own a controlling interest in us and will have conflicts of interest with, and owe limited fiduciary duties to, us, which may permit them to favor their own interests to the detriment of our unitholders.”

Our general partner will be required to deduct estimated maintenance capital expenditures from our operating surplus, which may result in less cash available for distribution to unitholders from operating surplus than if actual maintenance capital expenditures were deducted.

Maintenance capital expenditures are those capital expenditures required to maintain our long-term production or asset base, including expenditures to replace our oil and natural gas reserves, whether through the development, exploitation and production of an existing leasehold or the acquisition of a new oil or natural gas property. Our partnership agreement requires our general partner to deduct estimated, rather than actual, maintenance capital expenditures from operating surplus in determining cash available for distribution from operating surplus. The amount of estimated maintenance capital expenditures deducted from operating surplus will be subject to review and change by our conflicts committee at least once a year. Our partnership agreement does not cap the amount of maintenance capital expenditures that our general partner may estimate. In years when our estimated maintenance capital expenditures are higher than actual maintenance capital expenditures, the amount of cash available for distribution to unitholders from operating surplus will be lower than if actual maintenance capital expenditures had been deducted from operating surplus. On the other hand, if our general partner underestimates the appropriate level of estimated maintenance capital expenditures, we will have more cash available for distribution from operating surplus in the short term but will have less cash available for distribution from operating surplus in future periods when we have to increase our estimated maintenance capital expenditures to account for the previous underestimation.

Due to our expectation that existing and planned development of our initial assets by Memorial Resource will lead to inclining production and revenues for at least the next several years, we have estimated that the amount of maintenance capital expenditures currently necessary to maintain our production or asset base over the long term is negligible. However, the board of directors of our general partner may in the future determine that capital expenditures are required to be made to maintain our production or asset base over the long term, in which case, we may be required to deduct such estimated amounts from our operating surplus, which would reduce the amount of cash available for distribution.

Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit its liability under contractual arrangements between us and third parties so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s duties, even if we could have obtained more favorable terms without the limitation on liability.

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

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

•

how to allocate business opportunities among us and its affiliates;

•

whether to exercise its call right;

•

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

•

whether to exercise its registration rights;

•

whether to elect to reset target distribution levels; and

•

whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.

By purchasing a common unit, a unitholder is treated as having consented to the provisions in the partnership agreement, including the provisions discussed above. Please read “Conflicts of Interest and Fiduciary Duties—Fiduciary Duties.”

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

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

•

whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is generally required to make such determination, or take or decline to take such other action, in “good faith,” meaning it must act in a manner that it believes is not adverse to the interest of the partnership and will not be subject to any higher standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

•

our general partner and its officers and directors will not be liable for monetary damages or otherwise to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that such losses or liabilities were the result of conduct in which our general partner or its officers or directors engaged in bad faith, meaning that they believed that the decision was adverse to the interest of the partnership or, with respect to any criminal conduct, with knowledge that such conduct was unlawful; and

•

our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is:

(1) approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval; or

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

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

Our partnership agreement provides that the conflicts committee of the board of directors of our general partner may be comprised of one or more independent directors. If the board of directors of our general partner establishes a conflicts committee with only one independent director, your interests may not be as well served as if the conflicts committee was comprised of at least two independent directors. A single-member conflicts committee would not have the benefit of discussion with, and input from, other independent directors.

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

Our partnership agreement is governed by Delaware law. Our partnership agreement includes exclusive forum, venue and jurisdiction provisions designating Delaware courts as the exclusive venue for most claims, suits, actions and proceedings involving us or our officers, directors and employees. Please read “The Partnership Agreement—Applicable Law; Forum, Venue and Jurisdiction.” 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. In addition, if any unitholder brings any of the aforementioned claims, suits, actions or proceedings and such person does not obtain a judgment on the merits that substantially achieves, in substance and amount, the full remedy sought, then such person shall be obligated to reimburse us and our affiliates for all fees, costs and expenses of every kind and description, including but not limited to all reasonable attorneys’ fees and other litigation expenses, that the parties may incur in connection with such claim, suit, action or proceeding. These provisions may increase the costs of bringing lawsuits and have the effect of discouraging lawsuits against us and our general partner’s directors and officers. The enforceability of these provisions in other companies’ certificates of incorporation or similar governing documents has been challenged in legal proceedings, and it is possible that in connection with any action a court could find these provisions contained in our partnership agreement to be inapplicable or unenforceable in such action. If a court were to find these provisions inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition and results of operations and our ability to make cash distributions to our unitholders. By purchasing a common unit, a limited partner is irrevocably consenting to these provisions and potential reimbursement obligations regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of Delaware courts. For additional information about the potential obligation to reimburse us for all fees, costs and expenses incurred in connection with claims, suits, actions or proceedings initiated by a unitholder that are not successful, please read “The Partnership Agreement—Reimbursement of Partnership Litigation Costs.”

Even if our unitholders are dissatisfied, they cannot remove our general partner without Memorial Resource’s consent.

The public unitholders will be unable initially to remove our general partner without Memorial Resource’s consent because Memorial Resource will own sufficient units upon completion of this offering to be able to prevent our general partner’s removal. The vote of the holders of at least 66²/₃% of all outstanding units voting together as a single class is required to remove our general partner. Upon consummation of this offering, Memorial Resource will own our general partner, approximately % of our outstanding common units (approximately % if the underwriters exercise their option to purchase additional common units in full) and all of our subordinated units.

Control of our general partner and its incentive distribution rights may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of Memorial Resource from transferring all or a portion of its ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own choices and thereby influence the decisions made by the board of directors and officers in a manner that may not be aligned with the interests of our unitholders.

In addition, our general partner may transfer its incentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers its incentive distribution rights to a third party but retains its general partner interest, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its incentive distribution rights.

We may not make cash distributions during periods when we record net income.

The amount of cash we have available for distribution to our unitholders depends primarily on our cash flow, including cash from reserves established by our general partner, working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions to our unitholders during periods when we record net losses and may not make cash distributions to our unitholders during periods when we record net income.

We may issue an unlimited number of additional units, including units that are senior to the common units, without unitholder approval, which would dilute unitholders’ ownership interests.

Our partnership agreement does not limit the number of additional common units that we may issue at any time without the approval of our unitholders. In addition, we may issue an unlimited number of units that are senior to the common units in right of distribution, liquidation and voting. The issuance by us of additional common units or other equity interests of equal or senior rank will have the following effects:

•

our unitholders’ proportionate ownership interest in us will decrease;

•

the amount of cash available for distribution on each unit may decrease;

•

because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

•

the ratio of taxable income to distributions may increase;

•

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

•

the market price of our common units may decline.

Our partnership agreement restricts the limited voting rights of unitholders, other than our general partner and its affiliates, owning 20% or more of our common units, which may limit the ability of significant unitholders to influence the manner or direction of management.

Our partnership agreement restricts unitholders’ limited voting rights by providing that any common units held by a person, entity or group that owns 20% or more of any class of common units then outstanding (other than our general partner, its affiliates, their transferees and persons who acquired such common units with the prior approval of the board of directors of our general partner) cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting unitholders’ ability to influence the manner or direction of management.

Once our common units are publicly traded, Memorial Resource may sell common units in the public markets, which sales could have an adverse impact on the trading price of the common units.

After the sale of the common units offered hereby, Memorial Resource will own approximately % of our outstanding common units and all of our subordinated units, which convert into common units at the end of the subordination period. Once our common units are publicly traded, the sale of these units, including common units issued upon the conversion of the subordinated units, in the public markets could have an adverse impact on the price of the common units or on any trading market that may develop.

Our general partner has a call right that may require unitholders to sell their common units at an undesirable time or price.

If at any time our general partner and its affiliates (including Memorial Resource) own more than 80% of the common units, our general partner has the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is the greater of (i) the highest cash price paid by either of our general partner or any of its affiliates for any common units purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those common units; and (ii) the average daily closing prices of our common units over the 20 days preceding the date three days before the date the notice is mailed. As a result, our unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Our unitholders also may incur a tax liability upon a sale of their common units. Upon consummation of this offering, Memorial Resource will own approximately % of our outstanding common units and all of our subordinated units. For additional information about this call right, please read “The Partnership Agreement—Limited Call Right.”

If we distribute cash from capital surplus, which is analogous to a return of capital, our minimum quarterly distribution will be reduced proportionately, and the distribution thresholds after which the incentive distribution rights entitle our general partner to an increased percentage of distributions will be proportionately decreased.

Our cash distributions will be characterized as coming from either operating surplus or capital surplus. Operating surplus is defined in our partnership agreement, and generally means amounts we receive from operating sources, such as sale of our oil and natural gas production, less operating expenditures, such as production costs and taxes, and less estimated average maintenance capital expenditures, which are generally amounts we estimate we will need to spend in the future to maintain our production levels over the long term. Capital surplus is defined in our partnership agreement, and generally would result from cash received from non-operating sources such as sales of properties and issuances of debt and equity interests. Cash representing capital surplus, therefore, is analogous to a return of capital. Distributions of capital surplus are made to our unitholders and will result in a decrease in our minimum quarterly distribution. For a more detailed description of operating surplus, capital surplus and the effect of distributions from capital surplus, please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

Our partnership agreement allows us to add to operating surplus $ million. As a result, a portion of this amount, which is analogous to a return of capital, may be distributed to the general partner and its affiliates, as holders of incentive distribution rights, rather than to holders of common units as a return of capital.

Our unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in other states. 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 may do business. A unitholder could be liable for our obligations as if it was a general partner 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

•

a unitholder’s right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

Please read “The Partnership Agreement—Limited Liability” for a discussion of the implications of the limitations of liability on a unitholder.

Our unitholders may have liability to repay distributions.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make distributions to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to us are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that for a period of three years from the date of an 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. A purchaser of common units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to us that are known to such purchaser of common units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from our partnership agreement.

Our unitholders may have limited liquidity for their common units, a trading market may not develop for the common units and our unitholders may be unable to resell their common units at the initial public offering price.

Prior to this offering, there has been no public market for the common units. After this offering, there will be 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. Our unitholders may not be able to resell their common units at or above the initial public offering price. Additionally, a lack of liquidity would likely 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. All of the common units that are issued to affiliates of our general partner, or % of our outstanding common units, will be subject to resale restrictions under a 180-day lock-up agreement with the underwriters. Each of the lock-up agreements with the underwriters may be waived by Barclays Capital Inc. in its sole discretion. Sales by affiliates of our general partner of a substantial number of our common units in the public markets following this offering, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. In addition, we have agreed to provide registration rights to our general partner and its affiliates. Under our partnership agreement, our general partner and its affiliates have registration rights relating to the offer and sale of any units that they hold, subject to certain limitations.

If our common unit price declines after the initial public offering, our unitholders could lose a significant part of their investment.

The initial public offering price for the common units will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units could be subject to wide fluctuations in response to a number of factors, most of which we cannot control, including:

•

changes in commodity prices;

•

changes in securities analysts’ recommendations and their estimates of our financial performance;

•

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

•

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

•

changes in market valuations of similar companies;

•

departures of key personnel;

•

commencement of or involvement in litigation;

•

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

•

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

•

future issuances and sales of our common units; and

•

changes in general conditions in the U.S. economy, financial markets or the oil and natural gas industry.

In recent years, the securities market has experienced extreme price and volume fluctuations. This volatility has had a significant effect on the market price of securities issued by many companies for reasons unrelated to the operating performance of these companies. Future market fluctuations may result in a lower price of our common units.

Our unitholders will experience immediate and substantial dilution of $ per unit.

The assumed initial offering price of $ per common unit (the midpoint of the price range set forth on the cover of this prospectus) exceeds our pro forma net tangible book value after this offering of $ per common unit. Based on the assumed initial offering price of $ per common unit, our unitholders will incur immediate and substantial dilution of $ per common unit. This dilution will occur primarily because the assets contributed by affiliates of our general partner are recorded, in accordance with GAAP at their historical cost, and not their fair value. The impact of such dilution would be magnified upon any conversion of the incentive distribution rights into common units. Please read “Dilution.”

We have the right to borrow to make distributions. Repayment of these borrowings will decrease cash available for future distributions.

Our partnership agreement allows us to borrow to make distributions. We may make short-term borrowings under our revolving credit facility to make distributions. The primary purpose of these borrowings would be to mitigate the effects of short-term fluctuation in our working capital that would otherwise cause volatility in our quarter-to-quarter distributions.

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow our reserves and production.

Our partnership agreement provides that we will distribute all of our available cash each quarter. As a result, we may be dependent on the issuance of additional common units and other partnership securities and borrowings to finance our growth. A number of factors will affect our ability to issue securities and borrow money to finance growth, as well as the costs of such financings, including:

•

general economic and market conditions, including interest rates, prevailing at the time we desire to issue securities or borrow funds;

•

conditions in the oil and natural gas industry;

•

the market price of, and demand for, our common units;

•

our results of operations and financial condition; and

•

prices for oil, NGLs and natural gas.

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

We have no history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accounting and other expenses that we did not incur prior to this offering. In addition, the Sarbanes-Oxley Act of 2002 and the Dodd-Frank Act of 2010, as well as rules implemented by the SEC and NASDAQ, require, or will require, publicly traded entities to adopt various corporate governance practices that will further increase our costs. Before we are able to make distributions to our unitholders, we must first pay our expenses, including the costs of being a publicly traded partnership and other operating expenses. As a result, the amount of cash we have available for distribution to our unitholders will be affected by our expenses, including the costs associated with being a publicly traded partnership.

Following this offering, we will become subject to the public reporting requirements of the Exchange Act. We expect these requirements will increase certain of our legal and financial compliance costs and make compliance activities more time-consuming and costly. For example, as a result of becoming a publicly traded partnership, we are required to have at least three independent directors and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal control over financial reporting. We estimate that we will incur approximately $2.5 million of incremental costs per year associated with being a publicly traded partnership; however, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than we currently estimate.

For as long as we are an emerging growth company, we will not be required to comply with certain disclosure requirements, including those relating to accounting standards and disclosure about our executive compensation and internal control auditing requirements that apply to other public companies.

We are classified as an “emerging growth company” under Section 2(a)(19) of the Securities Act. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things, (1) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act of 2002, (2) comply with any new requirements adopted by the PCAOB requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer, (3) comply with any new audit rules adopted by the PCAOB after April 5, 2012 unless the SEC determines otherwise or (4) provide certain disclosure regarding executive compensation required of larger public companies.

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

We have applied to list our common units on NASDAQ. Because we will be a publicly traded limited partnership, NASDAQ does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of NASDAQ corporate governance requirements. Please read “Management—Management of Terryville Mineral & Royalty Partners LP.”

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.

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

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

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. In addition, changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution to you. Therefore, treatment of us as a corporation or the assessment of a material amount of entity-level taxation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

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

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

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

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions

we take. A court may not agree with some or all of our counsel’s conclusions or positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. Moreover, the costs of any contest between us and the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

USE OF PROCEEDS

We intend to use the estimated net proceeds of approximately $ million from this offering (based on an assumed initial offering price of $ per common unit, the mid-point of the price range set forth on the cover page of this prospectus), after deducting the estimated underwriting discount and structuring fee and offering expenses payable by us, to make a distribution to Memorial Resource. Affiliates of certain of the underwriters are lenders under Memorial Resource’s revolving credit facility. Memorial Resource may, but is not required to, apply the distribution that it receives from us to repay amounts outstanding under its revolving credit facility. Accordingly, affiliates of certain of the underwriters may indirectly receive a portion of the proceeds from this offering in the form of repayment of debt by Memorial Resource.

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

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


	As of September 30, 2014
	Actual		Pro Forma
	(in thousands)
Cash and cash equivalents	$	—	$

Long-term debt(1)	$	—	$
Predecessor capital/Partners’ capital:
Predecessor capital	$	24,078	$	—
Common units held by purchasers in this offering		—
Common units held by Memorial Resource		—
Subordinated units held by Memorial Resource		—

Total predecessor capital/partners’ capital	$	24,078	$

Total capitalization	$	24,078	$

(1)	We expect to enter into a revolving credit facility in connection with the closing of this offering. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Revolving Credit Facility.”

DILUTION

Purchasers of common units offered by this prospectus will suffer immediate and substantial dilution in net tangible book value per unit. Dilution in net tangible book value per unit represents the difference between the amount per unit paid by purchasers of our common units in this offering and the pro forma net tangible book value per unit immediately after this offering. After giving effect to the sale of common units in this offering at an initial public offering price of $ per common unit, and after deduction of the estimated underwriting discount and structuring fee and estimated offering expenses payable by us, our pro forma net tangible book value as of September 30, 2014 would have been approximately $ million, or $ per unit. This represents an immediate decrease in net tangible book value of $ per unit to our existing unitholders and an immediate pro forma dilution of $ per unit to purchasers of common units in this offering. The following table illustrates this dilution on a per unit basis:


Assumed initial public offering price per common unit		$
Pro forma net tangible book value per common unit before the offering(1)	$
Decrease 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 common units to be issued to Memorial Resource for its contribution of assets and liabilities to us.

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

The following table sets forth the number of units that we will issue and the total consideration contributed to us by Memorial Resource 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
Memorial Resource(1)				%	$				%
New investors				%		(2)			%

Total			100	%	$			100	%

(1)	Reflects the value of the assets to be contributed to us by Memorial Resource recorded at historical cost.

(2)	Reflects the net proceeds of this offering after deducting the underwriting discount and structuring fee and estimated offering expenses payable by us.

CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

You should read the following discussion of our cash distribution policy in conjunction with the specific assumptions included in this section. Please read “—Estimated Cash Available for Distribution for the Twelve Months Ending December 31, 2015—Assumptions and Considerations” below. In addition, you should read “Forward-Looking Statements” and “Risk Factors” for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.

For additional information regarding our historical results of operations, you should refer to our predecessor’s audited historical financial statements as of and for the years ended December 31, 2012 and 2013 and unaudited historical financial statements as of and for the nine months ended September 30, 2014 included elsewhere in this prospectus.

General

Rationale for Our Cash Distribution Policy

Our partnership agreement requires us to distribute all of our available cash on a quarterly basis. Our available cash is our cash on hand at the end of a quarter after the payment of our expenses and the establishment of reserves for future capital expenditures, operational needs and certain future distributions, including cash from borrowings. We intend to fund any acquisitions and growth capital expenditures with additional borrowings or issuances of additional units. We may also borrow to make distributions to unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long term, but short-term factors have caused available cash from operations to be insufficient to pay the distribution at the current level. Our cash distribution policy reflects a basic judgment that our unitholders will be better served by us distributing our available cash, after expenses and reserves, rather than retaining it. Also, because we are not subject to an entity-level federal income tax, we will have more cash to distribute to our unitholders than would be the case if we were subject to federal income tax.

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

There is no guarantee that unitholders will receive quarterly distributions from us. We do not have a legal obligation to pay the minimum quarterly distribution or distributions at any other rate except as provided in our partnership agreement. Our distribution policy is subject to certain restrictions and may be changed at any time, including:

•

Our cash distribution policy may be subject to restrictions on distributions under our new revolving credit facility or other debt agreements that we may enter into in the future. Specifically, we anticipate that the agreement related to our new revolving credit facility will contain financial tests and covenants that we must satisfy. These financial ratios and covenants are described under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Revolving Credit Facility.” Should we be unable to satisfy these restrictions, or if a default occurs under our new revolving credit facility, we would be prohibited from making cash distributions to our unitholders notwithstanding our stated cash distribution policy.

•

Our general partner will have the authority to establish reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment of or increase in those reserves could result in a reduction in cash distributions to our unitholders from levels we currently anticipate under our stated distribution policy. Any determination to establish or increase reserves made by our general partner will be binding on the unitholders. Due to our expectation that existing and planned development of our initial assets by Memorial Resource will lead to inclining production and revenues for at least the next several years, we have estimated that the amount of maintenance capital expenditures currently necessary to maintain our production or asset base over the long term is negligible. However, the board of directors of our general partner may in the future determine that capital expenditures are

required to be made to maintain our production or asset base over the long term, in which case, we may be required to deduct such estimated amounts from our operating surplus, which would reduce the amount of cash available for distribution. Over a longer period of time, if our general partner does not set aside sufficient cash reserves or make sufficient cash expenditures to maintain our production or asset base, we will be unable to pay the minimum quarterly distribution from cash generated from operations and would therefore expect to reduce our distributions. If our production or asset base decrease and we do not reduce our distributions, a portion of the distributions may be considered a return of part of our unitholders’ investment in us as opposed to a return on our unitholders’ investment.

•

Prior to making any distribution on our common units, we will reimburse our general partner and its affiliates for all direct and indirect expenses they incur on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us, and Memorial Resource will be entitled to such reimbursement under the omnibus agreement. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of cash available to pay cash distributions to our unitholders.

•

Although our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions requiring us to make cash distributions contained therein, may be amended. Our partnership agreement may not be amended during the subordination period without the approval of our public common unitholders, other than in certain limited circumstances where no unitholder approval is required. However, our partnership agreement can be amended with the consent of our general partner and the approval of the holders of a majority of our outstanding common units (including common units that are held by Memorial Resource and its affiliates) after the subordination period has ended. Upon consummation of this offering, Memorial Resource will own our general partner and will control the voting of an aggregate of approximately % of our outstanding common units and all of our subordinated units. Assuming we do not issue any additional common units and Memorial Resource does not transfer its common units, Memorial Resource will have the ability to amend our partnership agreement without the approval of any other unitholder once the subordination period ends.

•

Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement, our new revolving credit facility and any other agreements we may enter into in the future.

•

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 a number of factors, including reductions in commodity prices, reductions in our oil and natural gas production, increases in our general and administrative expenses, principal and interest payments on our outstanding debt, tax expenses, working capital requirements and anticipated cash needs. For a discussion of additional factors that may affect our ability to pay distributions, please read “Risk Factors.”

•

If and to the extent our cash available for distribution materially declines, we may reduce our quarterly distribution in order to service or repay our debt or fund growth capital expenditures.

•

All available cash distributed by us on any date from any source will be treated as distributed from operating surplus until the sum of all available cash distributed since the closing of this offering equals the cumulative operating surplus from the closing of this offering through the end of the quarter immediately preceding that distribution. We anticipate that distributions from operating surplus will generally not represent a return of capital. However, operating surplus, as defined in our partnership agreement, includes certain components that represent non-operating sources of cash, including a cash basket equal to

$ million and working capital borrowings. Consequently, it is possible that distributions from operating surplus may represent a return of capital. For example, the $ million cash basket would allow us to distribute as operating surplus cash proceeds we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings, which would represent a return of capital. Distributions representing a return of capital could result in a corresponding decrease in our asset base. Additionally, any cash distributed by us in excess of operating surplus will be deemed to be capital surplus under our partnership agreement. Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is similar to a return of capital. Distributions from capital surplus could result in a corresponding decrease in our asset base. We do not anticipate that we will make any distributions from capital surplus. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Operating Surplus and Capital Surplus” and “Provisions of Our Partnership Agreement Relating to Cash Distributions—Distributions from Capital Surplus—Effect of a Distribution from Capital Surplus.

•

Our ability to make distributions to our unitholders depends on the performance of our operating subsidiaries and its ability to distribute cash to us. The ability of our operating 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.

Our Minimum Quarterly Distribution

Upon completion of this offering, the board of directors of our general partner will establish a minimum quarterly distribution of $ per unit per whole quarter, or $ per unit per year on an annualized basis, to be paid no later than 60 days after the end of each fiscal quarter beginning with the quarter ending March 31, 2015. This equates to an aggregate cash distribution of approximately $ million per quarter or $ million per year, in each case based on the number of common units and subordinated units outstanding immediately after completion of this offering, but excluding any common units that may be issued under the long-term incentive plan that our general partner is expected to adopt prior to the closing of this offering. Our ability to make cash distributions at the minimum quarterly distribution will be subject to the factors described above under the caption “—General—Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.”

Because our general partner’s interest entitles it to control us without a right to any percentage of our distributions, our general partner will not receive ongoing distributions in respect of its general partner interest.

The table below sets forth the number of outstanding common and subordinated units upon the closing of this offering and the aggregate distribution amounts payable on such units during the year following the closing of this offering at our minimum quarterly distribution of $ per unit per quarter, or $ per unit on an annualized basis.


		Distributions
	Number of Units	One Quarter	Four Quarters
Common units held by purchasers in this offering(1)(2)		$	$
Common units held by Memorial Resource and its affiliates(1)(2)		$	$
Subordinated units		$	$

Total		$	$

(1)	Does not include any common units that may be issued under the long-term incentive plan that our general partner is expected to adopt prior to the closing of this offering.

(2)	Assumes no exercise of the underwriters’ option to purchase additional common units. If and to the extent the underwriters exercise their option to purchase additional common units, the number of common units

purchased by the underwriters pursuant to any exercise will be sold to the public. Any common units not purchased by the underwriters pursuant to their exercise of the option will be issued to Memorial Resource at the expiration of the option period for no additional consideration. Accordingly, the exercise of the underwriters’ option will not affect the total number of common units outstanding or the aggregate distribution payable on such units during the year following the closing of this offering.

If the minimum quarterly distribution on our common units is not paid with respect to any quarter, the common unitholders will not be entitled to receive such payments in the future except that, during the subordination period, to the extent we distribute cash in any future quarter in excess of the amount necessary to make cash distributions at the minimum quarterly distribution to holders of our common units, we will use this excess cash to pay any of these arrearages related to prior quarters before any cash distribution is made to holders of subordinated units. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordination Period.”

We do not have a legal obligation to pay the minimum quarterly distribution or distributions at any other rate except as provided in our partnership agreement. Our distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly. Under our partnership agreement, available cash is defined to generally mean, for each fiscal quarter, cash generated from our business in excess of expenses and the amount of reserves our general partner determines is necessary or appropriate to provide for the prudent conduct of our business (including payments to our general partner for reimbursement of expenses it incurs on our behalf), to comply with applicable law, any of our debt instruments or other agreements or to provide for future distributions to our unitholders for any one or more of the next four quarters. Please read “Provisions of our Partnership Agreement Relating to Cash Distributions—Distributions of Available Cash—Definition of Available Cash.”

Our cash distribution policy, as expressed in our partnership agreement, may not be modified or repealed without amending our partnership agreement. The actual amount of our cash distributions for any quarter is subject to fluctuation based on the amount of cash we generate from our business and the amount of reserves our general partner establishes in accordance with our partnership agreement as described above. Our partnership agreement, including provisions contained therein requiring us to make cash distributions, may be amended by a vote of the holders of a majority of our common units. Upon consummation of this offering, Memorial Resource will own our general partner, approximately % of our outstanding common units (assuming no exercise of the underwriters’ option to purchase additional common units) and all of our subordinated units. Assuming we do not issue any additional common units and Memorial Resource does not transfer a controlling portion of its equity interests in our general partner or its common units, Memorial Resource will have the ability to amend our partnership agreement without the approval of any other unitholders once the subordination period ends.

We expect to pay our distributions on or about the last day of each February, May, August and November to holders of record on or about the 15th day of each such month. If the distribution date does not fall on a business day, we will make the distribution on the business day immediately preceding the indicated distribution date. For our initial quarterly distribution, we will adjust the quarterly distribution for the period from the closing of this offering through March 31, 2015 based on the actual length of the period. We expect to pay this initial quarterly cash distribution on or before May 31, 2015.

In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our minimum quarterly distribution of $ per unit each quarter for the four quarters ending December 31, 2015. In those sections, we present two tables, consisting of:

•

“Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2013 and Twelve Months Ended September 30, 2014,” in which we present the amount of cash we would have had available for distribution to our unitholders and our general partner for the year ended December 31, 2013 and the twelve months ended September 30, 2014, based on the historical carve-

out financial statements of our predecessor. Our calculation of unaudited pro forma cash available for distribution in this table should only be viewed as a general indication of the amount of cash available for distribution that we might have generated had the transactions contemplated in this prospectus occurred in an earlier period.

•

“Estimated Cash Available for Distribution for the Twelve Months Ending December 31, 2015,” in which we demonstrate our ability to generate sufficient cash available for distribution to pay the full minimum quarterly distribution on all the outstanding units for the twelve months ending December 31, 2015.

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

If we had completed this offering and the related transactions on January 1, 2013, we estimate that we would have generated $9.8 million and $23.5 million of cash available for distribution for the year ended December 31, 2013 and the twelve months ended September 30, 2014, respectively.

Our unaudited pro forma cash available for distribution for each of the year ended December 31, 2013 and the twelve months ended September 30, 2014 includes $0.1 million and $0.1 million, respectively, of general and administrative expenses as well as an incremental $2.5 million of general and administrative expenses we expect to incur as a result of becoming a publicly traded partnership. Incremental general and administrative expenses related to being a publicly traded partnership include: expenses associated with annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the NASDAQ; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees; director and officer liability insurance expenses; and director compensation. These expenses are not reflected in the historical carve-out financial statements of our predecessor included elsewhere in this prospectus.

We based the pro forma adjustments upon currently available information and specific estimates and assumptions. The pro forma amounts below do not purport to present our results of operations had this offering and related formation transactions been completed as of the date indicated. In addition, cash available for distribution is primarily a cash accounting concept, while the historical carve-out financial statements of our predecessor included elsewhere in this prospectus have been prepared on an accrual basis. As a result, you should view the amount of pro forma cash available for distribution only as a general indication of the amount of cash available for distributions that we might have generated had we completed this offering on the date indicated. Our unaudited pro forma cash available for distribution should be read together with “Selected Historical Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the audited historical financial statements and the notes to those statements included elsewhere in this prospectus.

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

The following table illustrates the amount of cash available for distribution that we estimate that we would have generated for the year ended December 31, 2013 and the twelve months ended September 30, 2014. All of the amounts for the year ended December 31, 2013 and the twelve months ended September 30, 2014 in the table below are estimates.

Terryville Mineral & Royalty Partners LP

Unaudited Pro Forma Cash Available for Distribution


	Year Ended December 31, 2013 (In thousands, except per unit data)		Twelve-Month Period Ended September 30, 2014 (In thousands, except per unit data)
Average sale prices:
Oil (per Bbl)	$	99.73	$	98.16
NGLs (per Bbl)	$	40.58	$	45.92
Natural gas (per Mcf)	$	3.71	$	4.55
Royalty income	$	12,638	$	26,641
Cost and expenses:
Production taxes		247		555
Depletion		1,330		1,967
General and administrative expenses		92		98

Total costs and expenses		1,669		2,620

Income before income taxes		10,969		24,021
Income tax expense(1)		—		—

Net income		10,969		24,021
Adjustments to reconcile net income to EBITDA:
Add:
Depletion		1,330		1,967
Interest expense(2)		—		—

EBITDA(3)		12,299		25,988
Less:
Cash interest expense(2)		—		—
Incremental public partnership general and administrative expenses(4)		2,500		2,500
Maintenance capital expenditures		—		—

Estimated cash available for distribution(5)	$	9,799	$	23,488

Estimated cash distribution:
Distribution per unit (based on a minimum quarterly distribution of $ per unit)	$		$
Estimated aggregate distributions to:
Common units held by the public
Common units held by Memorial Resource

Subordinated units held by Memorial Resource
Total Distributions
Excess Cash (Shortfall)	$		$

Percent of minimum quarterly distributions payable to common unitholders

Percent of minimum quarterly distributions payable to subordinated unitholders

(1)

Prior to the completion of Memorial Resource’s initial public offering on June 18, 2014, its predecessor was a pass-through entity not subject to federal tax. As a limited partnership, we will not be subject to federal income tax following the completion of this offering. Accordingly, we made a pro forma adjustment to exclude income tax that was recognized by our predecessor.

(2)	We will not have any indebtedness outstanding following the completion of this offering and consequently did not recognize any pro forma interest expense during the periods presented.

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

(4)

We expect to incur $2.5 million of estimated incremental annual general and administrative expenses associated with being a publicly traded partnership. Please read “—Estimated Cash Available for Distribution for the Twelve Months Ending December 31, 2015—Assumptions and Considerations—Expenditures—General and Administrative Expenses.”

(5)

As an owner of overriding royalty interests, we are not responsible for capital costs of developing our acreage, and consequently we did not make any capital expenditures during the periods presented. Please read “—Estimated Cash Available for Distribution for the Twelve Months Ending December 31, 2015—Assumptions and Considerations—Capital Expenditures” for a discussion of our anticipated capital expenditures following the completion of this offering.

Estimated Cash Available for Distribution for the Twelve Months Ending December 31, 2015

We forecast that our estimated cash available for distribution during the year ending December 31, 2015 will be approximately $ million. The forecasted estimated cash available for distribution would exceed by $ million the amount needed to pay the minimum quarterly distribution of $ per unit on all of our common and subordinated units for the year ending December 31, 2015. In “—Assumptions and Considerations” below, we discuss the major assumptions underlying this estimate. The cash available for distribution discussed in the forecast should not be viewed as management’s projection of the actual cash available for distribution that we will generate during the twelve months ending December 31, 2015.

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

Management has prepared the prospective financial information set forth in the table below to present our expectations regarding our ability to generate $ million of cash available for distribution for the twelve months 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.

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

We do not undertake any obligation to release publicly the results of any future revisions we may make to the financial forecast or to update this financial forecast to reflect events or circumstances after the date of this prospectus. In light of the above, the statement that we believe that we will have sufficient cash available for distribution to allow us to make the full minimum quarterly distribution on all of our outstanding common units for the twelve months 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.

The following table shows how we calculate estimated cash available for distribution for the twelve months ending December 31, 2015. The assumptions that we believe are relevant to particular line items in the table below are explained in the corresponding footnotes and in “—Assumptions and Considerations.”

The following table illustrates the amount of cash that we estimate that we will generate for the twelve months ending December 31, 2015 that would be available for distribution to our unitholders. All of the amounts for the twelve months ending December 31, 2015 in the table below are estimates.

Three
Months
Ending
March 31,
2015

Three
Months
Ending
June 30,
2015

Three
Months
Ending
September 30,
2015

Three
Months
Ending
December 31,
2015

Twelve
Months
Ending
December 31,
2015

Royalty income

Forecasted realized prices:

Natural gas price per Mcf

Oil price per Bbl

Natural gas liquids price per Bbl

Expenditures:

Production taxes

Depletion

Interest expense

Income Taxes

General and administrative expenses

Net income

Adjustments to reconcile net income to EBITDA:

Add:

Depletion

Interest expense

Income Taxes

EBITDA(1)

Less:

Cash interest expense

Maintenance capital expenditures(2)

Estimated cash available for distribution

Three
Months
Ending
March 31,
2015

Three
Months
Ending
June 30,
2015

Three
Months
Ending
September 30,
2015

Three
Months
Ending
December 31,
2015

Twelve
Months
Ending
December 31,
2015

Estimated cash distributions:

Distribution per unit (based on a minimum quarterly distribution of $ per unit)

Estimated aggregate distributions to:

Common units held by the public

Common units held by Memorial Resource

Subordinated units held by

Memorial Resource

Total distributions

Excess cash available for distribution

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

(2)

As an owner of overriding royalty interests, we are not responsible for capital costs of developing our acreage, and consequently we did not make any capital expenditures during the periods presented. Please read “—Assumptions and Considerations—Capital Expenditures” for a discussion of our anticipated capital expenditures following the completion of this offering.

Assumptions and Considerations

PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS

Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.

Distributions of Available Cash

General

Our partnership agreement requires that, within 60 days after the end of each quarter, beginning with the quarter ending March 31, 2015, we distribute all of our available cash to unitholders of record on the applicable record date. We will adjust the minimum quarterly distribution payable in respect of the quarter ending March 31, 2015 for the period from the closing of the offering through March 31, 2015.

Definition of Available Cash

Available cash, for any quarter, consists of all cash and cash equivalents on hand at the end of that quarter:

•

less, the amount of cash reserves established by our general partner at the date of determination of available cash for the quarter to:

•

provide for the proper conduct of our business, which could include, but is not limited to, amounts reserved for maintenance capital expenditures (if any), working capital and operating expenses;

•

comply with applicable law, any of our debt instruments or other agreements; or

•

provide funds for distributions to our unitholders (including our general partner) for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for future distributions on our common and subordinated units unless it determines that the establishment of reserves will not prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for such quarter);

•

plus, if our general partner so determines, all or a portion of cash on hand on the date of determination of available cash for the quarter resulting from borrowing (including working capital borrowings) made after the end of the quarter.

The purpose and effect of the last bullet point above is to allow our general partner, if it so decides, to use cash from borrowing (including working capital borrowings) made after the end of the quarter but on or before the date of determination of available cash for that quarter to pay distributions to unitholders.

Working capital borrowings are borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to partners and with the intent of the borrower to repay such borrowings within twelve months from sources other than additional working capital borrowings.

Due to our expectation that existing and planned development of our initial assets by Memorial Resource will lead to inclining production and revenues for at least the next several years, we have estimated that the amount of maintenance capital expenditures currently necessary to maintain our production or asset base over the long term is negligible. However, our general partner may in the future determine that capital expenditures are required to be made to maintain our production or asset base over the long term, in which case we may be required to establish cash reserves to fund such maintenance capital expenditures, which would reduce our available cash.

Intent to Distribute the Minimum Quarterly Distribution

We intend to distribute to the holders of common units and subordinated units on a quarterly basis at least the minimum quarterly distribution of $ per unit, or $ per unit on an annualized basis, to the extent we have sufficient cash from our operations after the establishment of cash reserves and payment of fees and expenses, including payments (or reserving for payment) of fees and expenses to our general partner and its affiliates. However, there is no guarantee that we will pay the minimum quarterly distribution on the units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.

General Partner Interest and Incentive Distribution Rights

Our general partner owns a non-economic general partner interest in us, which does not entitle it to receive cash distributions. However, our general partner owns the incentive distribution rights and may in the future own common units or other equity interests in us and will be entitled to receive distributions on any such interests.

Our general partner also holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 25%, of the cash we distribute from operating surplus (as defined below) in excess of $ per unit per quarter. The maximum distribution of 25% does not include any distributions that our general partner may receive on common units or subordinated units that it owns.

Operating Surplus and Capital Surplus

General

All cash distributed to unitholders will be characterized as either “operating surplus” or “capital surplus.” Our partnership agreement requires that we distribute available cash from operating surplus differently than available cash from capital surplus.

Operating Surplus

Our partnership agreement requires that we distribute available cash from operating surplus differently than available cash from capital surplus. Operating surplus for any period consists of:

•

$ million (as described below); plus

•

all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions, which include the following:

•

borrowings (including sales of debt securities) that are not working capital borrowings;

•

sales of equity interests; and

•

sales or other dispositions of assets outside the ordinary course of business;

provided that cash receipts from the termination of a commodity hedge or interest rate hedge prior to its specified termination date shall be included in operating surplus in equal quarterly installments over the remaining scheduled life of such commodity hedge or interest rate hedge; plus

•

working capital borrowings made after the end of the period but on or before the date of determination of operating surplus for the period; plus

•

cash distributions paid (including incremental incentive distributions) on equity issued to finance all or a portion of the construction, replacement, acquisition, development or improvement of a capital improvement or replacement of a capital asset (such as reserves) in respect of the period beginning on

the date that we enter into a binding obligation to commence the construction, replacement, acquisition, development or improvement of a capital improvement, construction, replacement, acquisition, development or improvement of a capital asset and ending on the earlier to occur of the 60^th day following the date the capital improvement or capital asset is acquired, begins producing in paying quantities or is placed into service, as applicable, and the date that it is abandoned or disposed of; plus

•

cash distributions paid (including incremental incentive distributions) on equity issued to pay the construction period interest on debt incurred (including periodic net payments under related interest rate swap arrangements), or to pay construction period distributions on equity issued, to finance the capital improvements or capital assets referred to above; less

•

all of our operating expenditures (as described below) after the closing of this offering and the completion of the formation transactions; less

•

the amount of cash reserves established by our general partner to provide funds for future operating expenditures; less

•

all working capital borrowings not repaid within twelve months after having been incurred, or repaid within such twelve month period with the proceeds of additional working capital borrowings; less

•

any cash loss realized on disposition of an investment capital expenditure.

As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders and is not limited to cash generated by our operations. For example, it includes a basket of $ million that will enable us, if we choose, to distribute as operating surplus $ million cash we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. In addition, the effect of including (as described above) certain cash distributions on equity interests in operating surplus will be to increase operating surplus by the amount of any such cash distributions. As a result, we may also distribute as operating surplus up to the amount of any such cash that we receive from non-operating sources.

The proceeds of working capital borrowings increase operating surplus and repayments of working capital borrowings are generally operating expenditures (as described below) and thus reduce operating surplus when repayments are made. However, if a working capital borrowing is not repaid during the twelve-month period following the borrowing, it will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowing is in fact repaid, it will be excluded from operating expenditures because operating surplus will have been previously reduced by the deemed repayment.

We define operating expenditures in our partnership agreement, and it generally means all of our cash expenditures, including, but not limited to, taxes, reimbursement for expenses of our general partner and its affiliates, payments made in the ordinary course of business under interest rate and commodity hedge contracts, (provided that (i) with respect to amounts paid in connection with the initial purchase of an interest rate hedge contract or a commodity hedge contract, such amounts will be amortized over the life of the applicable interest rate hedge contract or commodity hedge contract and (ii) payments made in connection with the termination of any interest rate hedge contract or commodity hedge contract prior to the expiration of its stipulated settlement or termination date will be included in operating expenditures in equal quarterly installments over the remaining scheduled life of such interest rate hedge contract or commodity hedge contract), officer compensation, repayment of working capital borrowings, debt service payments (except as otherwise provided in our partnership agreement) and estimated maintenance capital expenditures (as discussed in further detail below), provided that operating expenditures will not include:

•

repayment of working capital borrowings previously deducted from operating surplus pursuant to the provision described in the penultimate bullet point of the description of operating surplus above when such repayment actually occurs;

•

payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness, other than working capital borrowings;

•

growth capital expenditures;

•

actual maintenance capital expenditures (as discussed in further detail below);

•

investment capital expenditures;

•

payment of transaction expenses relating to interim capital transactions;

•

distributions to our partners; or

•

repurchases of equity interests except to fund obligations under employee benefit plans.

Capital Surplus

Capital surplus is defined in our partnership agreement as any distribution of available cash in excess of our cumulative operating surplus. Accordingly, capital surplus would generally be generated by:

•

borrowings (including sales of debt securities) other than working capital borrowings;

•

sales of our equity interests; and

•

sales or other dispositions of assets outside the ordinary course of business.

Characterization of Cash Distributions

Our partnership agreement requires that we treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since the closing of this offering equals the operating surplus from the closing of this offering through the end of the quarter immediately preceding that distribution. Our partnership agreement requires that we treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. As reflected above, operating surplus includes $ million, which does not reflect actual cash on hand that is available for distribution to our unitholders. Rather, it is a provision that will enable us, if we choose, to distribute as operating surplus up to this amount of cash we receive in the future from non-operating sources such as asset sales, issuances of securities, and borrowings, that would otherwise be distributed as capital surplus. We do not anticipate that we will make any distributions from capital surplus.

Capital Expenditures

Estimated maintenance capital expenditures reduce operating surplus, but growth capital expenditures, actual maintenance capital expenditures and investment capital expenditures do not. Maintenance capital expenditures are those capital expenditures required to maintain our production or asset base over the long term. We expect that a primary component of maintenance capital expenditures will be capital expenditures associated with the replacement of oil and natural gas reserves through the acquisition of a new royalty or mineral interest in an oil and natural gas property. Maintenance capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued (including incremental distributions on incentive distribution rights) to finance all or any portion of the construction, replacement, acquisition or improvement of a capital asset that is paid in respect of the period from such financing until the earlier to occur of the date that any such construction replacement, acquisition or improvement of a capital asset begins producing in paying quantities or is placed into service, as applicable, and the date that it is abandoned or disposed of. Capital expenditures made solely for investment purposes will not be considered maintenance capital expenditures.

Because our maintenance capital expenditures can be irregular, the amount of our actual maintenance capital expenditures may differ substantially from period to period, which could cause similar fluctuations in the

amounts of operating surplus and adjusted operating surplus if we subtracted actual maintenance capital expenditures from operating surplus. To address this issue, our partnership agreement will require that an estimate of the average quarterly maintenance capital expenditures necessary to maintain our production or asset base over the long term be subtracted from operating surplus each quarter as opposed to the actual amounts spent. The amount of estimated maintenance capital expenditures deducted from operating surplus is subject to review and change by our general partner’s board of directors at least once a year, provided that any change is approved by the conflicts committee of our general partner’s board of directors. The estimate will be made at least annually and whenever an event occurs that is likely to result in a material adjustment to the amount of our maintenance capital expenditures, such as a major acquisition. For purposes of calculating operating surplus, any adjustment to this estimate will be prospective only. For a discussion of the amounts we have allocated toward estimated maintenance capital expenditures, please read “Cash Distribution Policy and Restrictions on Distributions.”

The use of estimated maintenance capital expenditures in calculating operating surplus will have the following effects:

•

it will reduce the risk that maintenance capital expenditures in any one quarter will be large enough to render operating surplus less than the minimum quarterly distribution to be paid on all the units for the quarter;

•

will increase our ability to distribute as operating surplus cash we receive from non-operating sources;

•

in quarters where estimated maintenance capital expenditures exceed actual maintenance capital expenditures, it will be more difficult for us to raise our distribution above the minimum quarterly distribution, because the amount of estimated maintenance capital expenditures will reduce the amount of cash available for distribution from operating surplus to our unitholders, even in quarters where there are no corresponding actual capital expenditures; conversely, the use of estimated maintenance capital expenditures in calculating operating surplus will have the opposite effect for quarters in which actual maintenance capital expenditures exceed our estimated maintenance capital expenditures; and

•

it will reduce the likelihood that a large maintenance capital expenditure during a particular quarter will prevent our general partner’s affiliates from being able to convert some or all of their subordinated units to common units since the effect of an estimate is to spread the expected expense over several periods, thereby mitigating the effect of the actual payment of the expenditure on any single period.

Growth capital expenditures are those capital expenditures that we expect will increase our production or asset base over the long term. Examples of growth capital expenditures include the acquisition of a new royalty or mineral interest with attributable reserves or production, to the extent such expenditures are incurred to increase our production or asset base over the long term. Growth capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued (including incremental distributions on incentive distribution rights) to finance all or any portion of such capital improvement during the period from such financing until the earlier to occur of the date any such capital improvement begins producing in paying quantities or is placed into service, as applicable, or the date that it is abandoned or disposed of. Capital expenditures made solely for investment purposes will not be considered growth capital expenditures.

Investment capital expenditures are those capital expenditures that are neither maintenance capital expenditures nor growth capital expenditures. Investment capital expenditures largely will consist of capital expenditures made for investment purposes. Examples of investment capital expenditures include traditional capital expenditures for investment purposes, such as purchases of securities, as well as other capital expenditures that might be made in lieu of such traditional investment capital expenditures, such as the acquisition of a capital asset for investment purposes or development of our undeveloped properties in excess of the maintenance of our production or asset base, but which are not expected to expand our production or asset base for more than the short term.

As described above, neither investment capital expenditures nor growth capital expenditures will be included in operating expenditures, and thus will not reduce operating surplus. Because growth capital expenditures include interest payments (and related fees) on debt incurred to finance all or a portion of the construction, replacement or improvement of a capital asset (such as equipment or reserves) during the period from such financing until the earlier to occur of the date any such capital asset begins producing in paying quantities or is placed into service, as applicable, and the date that it is abandoned or disposed of, such interest payments also do not reduce operating surplus. Losses on disposition of an investment capital expenditure will reduce operating surplus when realized and cash receipts from an investment capital expenditure will be treated as a cash receipt for purposes of calculating operating surplus only to the extent the cash receipt is a return on principal.

Capital expenditures that are made in part for maintenance capital purposes and in part for investment capital or growth capital purposes will be allocated as maintenance capital expenditures, investment capital expenditures or growth capital expenditure by our general partner’s board of directors, based upon its good faith determination, subject to approval by the conflicts committee of our general partner’s board of directors.

Subordination Period

General

Our partnership agreement provides that, during the subordination period (which we describe below), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $ per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions from operating surplus until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash from operating surplus to be distributed on the common units.

Expiration of the Subordination Period

Except as described below under “—Early Conversion of Subordinated Units,” the subordination period will extend until the first business day after the distribution to unitholders in respect of any quarter ending on or after March 31, 2018 that each of the following tests are met:

•

distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and any other partnership interests that are senior or equal in right of distribution to the subordinated units equaled or exceeded, in the aggregate, the sum of the minimum quarterly distributions payable with respect to a period of twelve consecutive quarters immediately preceding such date;

•

the “adjusted operating surplus” (as defined below) generated during the period of twelve consecutive quarters immediately preceding that date equaled or exceeded, in the aggregate, the sum of the minimum quarterly distributions on all of the outstanding common units, subordinated units and any other partnership interests that are senior or equal in right of distribution to the subordinated units that were outstanding during these periods payable with respect to such period on a fully diluted weighted average basis; and

•

there are no arrearages in payment of the minimum quarterly distribution on the common units.

Early Conversion of Subordinated Units

The subordination period will automatically terminate, and all of the subordinated units will convert into an equal number of common units, on the first business day after the distribution to unitholders in respect of any quarter ending on or after March 31, 2016, if the following tests are met:

•

distributions of available cash from operating surplus on each of the outstanding common units and subordinated units and any other partnership interests that are senior or equal in right of distribution to the subordinated units equaled or exceeded $ (125% of the minimum quarterly distribution) per quarter for the four quarter period immediately preceding that date;

•

the “adjusted operating surplus” generated during the four-quarter period immediately preceding that date equaled or exceeded the sum of a distribution of $ (125% of the annualized minimum quarterly distribution) on all of the outstanding common units and subordinated units and any other partnership interests that are senior or equal in right of distribution to the subordinated units, in each case that were outstanding during such four quarter period on a fully diluted weighted average basis, and the corresponding distributions on the incentive distribution rights; and

•

there are no arrearages in payment of the minimum quarterly distribution on the common units.

In addition, and notwithstanding the foregoing, the subordination period will also automatically terminate,

•

with respect to 50% of the subordinated units, on the first business day following the distribution of available cash in respect of any quarter, beginning with the quarter ending September 30, 2016, that each of the following tests are met:

•

distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded $ per unit (115% of the minimum quarterly distribution), for the quarter immediately preceding that date;

•

the “adjusted operating surplus” (as defined below) generated during the quarter immediately preceding that date equaled or exceeded the sum of (i) $ per unit (115% of the minimum quarterly distribution) on all of the outstanding common units and subordinated units during that period on a fully diluted, weighted average basis and (ii) the corresponding distributions on the IDRs; and

•

there are no arrearages in payment of the minimum quarterly distribution on the common units.

•

with respect to 100% of the subordinated units, on the first business day following the distribution of available cash in respect of any quarter, beginning with the quarter ending September 30, 2016, that each of the following tests are met:

•

distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded $ per unit (125% of the minimum quarterly distribution), for the quarter immediately preceding that date;

•

the “adjusted operating surplus” (as defined below) generated during the quarter immediately preceding that date equaled or exceeded the sum of (i) $ per unit (125% of the minimum quarterly distribution) on all of the outstanding common units and subordinated units during that period on a fully diluted, weighted average basis and (ii) the corresponding distributions on the IDRs; and

•

there are no arrearages in payment of the minimum quarterly distribution on the common units.

Please read “Risk Factors—Risks Inherent in an Investment in Us—Unlike most master limited partnerships with subordinated units, our partnership agreement allows for conversion of subordinated units into common units after paying a quarterly distribution at the highest target distribution level for only a single quarter.”

Effect of the Expiration of the Subordination Period

When the subordination period ends, each outstanding subordinated unit will convert into one common unit and will then participate pro rata with the other common units in distributions of available cash. Common units will then no longer be entitled to arrearages.

Effect of the Expiration of the Subordination Period Following Removal of our General Partner

If the unitholders remove our general partner other than for cause and units held by our general partner and its affiliates are not voted in favor of such removal:

•

the subordination period will end and each subordinated unit will immediately convert into one common unit; and

•

any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished.

Adjusted Operating Surplus

Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods. Adjusted operating surplus for any period consists of:

•

operating surplus generated with respect to that period (excluding the amount described in the first bullet point under “—Operating Surplus and Capital Surplus—Operating Surplus”); less

•

any net increase in working capital borrowings with respect to that period; less

•

any net decrease in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus

•

any net decrease in working capital borrowings with respect to that period; plus

•

any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium; plus

•

any net decrease made in subsequent periods in cash reserves for operating expenditures initially established with respect to such period to the extent such decrease results in a reduction of adjusted operating surplus in subsequent periods pursuant to the third bullet point above.

Distributions of Available Cash from Operating Surplus During the Subordination Period

Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

•

first, to the common unitholders, pro rata, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;

•

second, to the common unitholders, pro rata, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;

•

third, to the subordinated unitholders, pro rata, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

•

thereafter, in the manner described in “—General Partner Interest and Incentive Distribution Rights” below.

Distributions of Available Cash from Operating Surplus After the Subordination Period

Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:

•

first, to all unitholders, pro rata, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and

•

thereafter, in the manner described in “—General Partner Interest and Incentive Distribution Rights” below.

General Partner Interest and Incentive Distribution Rights

Incentive distribution rights represent the right to receive an increasing percentage (15% and 25%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in the partnership agreement. The following discussion assumes that there are no arrearages on common units and that our general partner continues to own the incentive distribution rights.

If for any quarter:

•

we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

•

we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then, our partnership agreement requires that we distribute any additional available cash from operating surplus for that quarter among the unitholders and the general partner in the following manner:

•

first, to all unitholders, pro rata, until each unitholder receives a total of $ per unit for that quarter (the “first target distribution”);

•

second, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives a total of $ per unit for that quarter (the “second target distribution”); and

•

thereafter, 75.0% to all unitholders, pro rata, and 25% to our general partner.

Percentage Allocations of Available Cash from Operating Surplus

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution per Unit.” The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below assume there are no arrearages on common units and our general partner has not transferred its incentive distribution rights.


					Marginal Percentage Interest in Distributions
	Total Quarterly Distribution per Unit				Unitholders			IDR Holders
Minimum Quarterly Distribution			$			100	%		—
First Target Distribution		above	$	up to $		100	%		—
Second Target Distribution		above	$	up to $		85.0	%		15.0	%
Thereafter		above	$			75.0	%		25.0	%

General Partner’s Right to Reset Incentive Distribution Levels

Our general partner, as the holder of all of our incentive distribution rights, has the right under our partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial cash target distribution levels and to reset, at higher levels, the minimum quarterly distribution amount and cash target distribution levels upon which the incentive distribution payments to our general partner would be set. Our general partner’s right to reset the minimum quarterly distribution amount and the target distribution levels upon which the incentive distributions payable to our general partner are based may be exercised, without approval of our unitholders or the conflicts committee of our general partner, at any time when there are no subordinated units outstanding and we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distribution for each of the prior four consecutive fiscal quarters. The reset minimum quarterly distribution amount and target distribution levels will be higher than the minimum quarterly distribution amount and the target distribution levels prior to the reset such that our general partner will not receive any incentive distributions under the reset target distribution levels until cash distributions per unit following this event increase as described below. We anticipate that our general partner would exercise this reset right (if at all) to facilitate acquisitions or internal growth projects that would otherwise not be sufficiently accretive to cash distributions per common unit, taking into account the existing levels of incentive distribution payments being made to our general partner.

In connection with the resetting of the minimum quarterly distribution amount and the target distribution levels and the corresponding relinquishment by our general partner of incentive distribution payments based on the target cash distributions prior to the reset, our general partner will be entitled to receive a number of newly issued common units based on a predetermined formula described below that takes into account the “cash parity” value of the cash distributions related to the incentive distribution rights received by our general partner for the quarter prior to the reset event as compared to the cash distributions per common unit during such quarter.

The number of common units to be issued in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels then in effect would be equal to the quotient determined by dividing (x) the amount of cash distributions received by our general partner in respect of its incentive distribution rights during the fiscal quarter ended immediately prior to the date of such reset election by (y) the amount of cash distributed per common unit during such quarter.

Following any reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equal to the cash distribution amount per unit for the fiscal quarter immediately preceding the reset election (which amount we refer to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to be correspondingly higher such that we would distribute all of our available cash from operating surplus for each quarter thereafter as follows:

•

first, to all unitholders, pro rata, until each unitholder receives an amount equal to 115% of the reset minimum quarterly distribution for that quarter;

•

second, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives an amount per unit equal to 125% of the reset minimum quarterly distribution for the quarter; and

•

thereafter, 75.0% to all unitholders, pro rata, and 25.0% to our general partner.

The following table illustrates the percentage allocation of available cash from operating surplus between the unitholders and our general partner at various cash distribution levels (i) pursuant to the cash distribution provisions of our partnership agreement in effect at the closing of this offering, as well as (ii) following a hypothetical reset of the minimum quarterly distribution and target distribution levels based on the assumption that the quarterly cash distribution amount per common unit during the fiscal quarter immediately preceding the reset election was $ .


			Marginal Percentage Interest in Distributions
	Quarterly Distribution per Unit Prior to Reset		Unitholders			IDR Holders			Quarterly Distribution per Unit Following Hypothetical Reset
Minimum quarterly distribution		$		100	%		—			$
First target distribution		up to $		100	%		—			up to $	(1)
Second target distribution	above $	up to $		85.0	%		15.0	%	above $	(1) up to $	(2)
Thereafter		above $		75.0	%		25.0	%		above $	(2)

(1)	This amount is 115.0% of the hypothetical reset minimum quarterly distribution.

(2)	This amount is 125.0% of the hypothetical reset minimum quarterly distribution.

The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and our general partner, including in respect of incentive distribution rights based on the amount distributed for the quarter immediately prior to the reset. The table assumes that immediately prior to the reset there would be common units outstanding, and the distribution to each common unit would be $ for the quarter prior to the reset.

Cash Distributions to General
Partner Prior to Reset

Quarterly Distributions
per Unit Prior to Reset

Cash
Distributions
to Common
Unitholders
Prior to
Reset

Common
Units

Incentive
Distribution
Rights

Total

Total
Distributions

Minimum quarterly distribution

—

First target distribution

up to $

—

Second target distribution

above $

up to $

—

Thereafter

above $

—

The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and our general partner, including in respect of incentive distribution rights, with respect to the quarter in which the reset occurs. The table reflects that as a result of the reset there would be common units outstanding and the distribution to each common unit would be $ . The number of common units to be issued to our general partner upon the reset was calculated by dividing (i) the amount received by our general partner in respect of its incentive distribution rights for the quarter prior to the reset as shown in the table above, or $ , by (ii) the available cash distributed on each common unit for the quarter prior to the reset as shown in the table above, or $ .

Cash Distributions to General
Partner After Reset

Unit Quarterly
Distributions per Prior
to Reset

Cash
Distributions
to Common
Unitholders
Prior to
Reset

Common
Units

Incentive
Distribution
Rights

Total

Total
Distributions

Minimum quarterly distribution

—

First target distribution

up to $

—

Second target distribution

above $

up to $

—

Thereafter

above $

—

$—

Our general partner will be entitled to cause the minimum quarterly distribution amount and the target distribution levels to be reset on more than one occasion, provided that a reset election may not be made except at a time when it has received incentive distributions for the prior four consecutive fiscal quarters based on the highest level of incentive distributions that they are entitled to receive under our partnership agreement.

Distributions from Capital Surplus

How Distributions from Capital Surplus Will Be Made

We will make distributions of available cash from capital surplus, if any, in the following manner:

•

First, to all unitholders, pro rata, until the minimum quarterly distribution is reduced to zero, as described below;

•

Second, to the common unitholders, pro rata, until we distribute for each common unit, an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and

•

Thereafter, we will make all distributions of available cash from capital surplus as if they were from operating surplus.

Effect of a Distribution from Capital Surplus

Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the distribution of capital surplus to the fair market value of the common units prior to the announcement of the distribution. Because distributions of capital surplus will reduce the minimum quarterly distribution after any of these distributions are made, it may be easier for our general partner to receive incentive distributions and for the subordinated units to convert into common units.

Once we reduce the minimum quarterly distribution and target distribution levels to zero, all future distributions will be made such that 75.0% is paid to the holders of units, pro rata, and 25.0% is paid to our general partner. The percentage interest shown for our general partner assumes our general partner has not transferred the incentive distribution rights.

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, our partnership agreement specifies that the following items will be proportionately adjusted:

•

the minimum quarterly distribution;

•

target distribution levels;

•

the initial unit price, as described below under “—Distributions of Cash Upon Liquidation”; and

•

the number of common units into which a subordinated unit is convertible.

For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the initial unit price would each be reduced to 50% of its initial level, and each subordinated unit would be convertible into two common units. Our partnership agreement provides that we do not make any adjustment by reason of the issuance of additional units for cash or property.

In addition, if legislation is enacted or if existing law is modified or interpreted by a governmental taxing authority, so that we become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels may be reduced by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter and the denominator of which is the sum of available cash for that quarter plus our general partner’s estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in subsequent quarters. In addition, if as a result of a change in law or interpretation thereof, we or any of our subsidiaries is treated as an association taxable as a corporation or is otherwise subject to additional taxation as an entity for U.S. federal, state, local or non-U.S. income or withholding tax purposes, our general partner may, in its sole discretion, reduce the minimum quarterly distribution and the target distribution levels by multiplying each by a fraction, the numerator of which is available cash for that quarter (after deducting our general partner’s estimate of our aggregate liability for the quarter for such income and withholding taxes payable by reason of such change in laws or interpretation) and the denominator of which is the sum of available cash for that quarter plus our general partner’s estimate of our aggregate liability for the quarter for such income and withholding taxes payable by reason of such change in laws or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in subsequent quarters.

Distributions of Cash Upon Liquidation

General

If we dissolve in accordance with the partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and the general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of units to a repayment of the initial value contributed by unitholders for their units in this offering, which we refer

to as the “initial unit price” for each unit. The allocations of gain and loss upon liquidation are also intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the holders of common units to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of our general partner.

Manner of Adjustments for Gain

The manner of the adjustment for gain is set forth in the partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to the partners in the following manner:

•

first, to our general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;

•

second, to the common unitholders, pro rata, until the capital account for each common unit is equal to the sum of: (1) the initial unit price; (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and (3) any unpaid arrearages in payment of the minimum quarterly distribution;

•

third, to the subordinated unitholders, pro rata, until the capital account for each subordinated unit is equal to the sum of: (1) the initial unit price; and (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;

•

fourth, to all unitholders, pro rata, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed % to the unitholders, pro rata, for each quarter of our existence;

•

fifth, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85.0% to the unitholders, pro rata, and 15.0% to our general partner for each quarter of our existence; and

•

thereafter, 75.0% to all unitholders, pro rata, and 25.0% to our general partner.

The percentage interests set forth above for our general partner assume our general partner has not transferred the incentive distribution rights.

If the liquidation occurs after the end of the subordination period, the distinction between common and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the third bullet point above will no longer be applicable.

Manner of Adjustments for Losses

If our liquidation occurs before the end of the subordination period, we will generally allocate any loss to our general partner and the unitholders in the following manner:

•

first, to holders of subordinated units in proportion to the positive balances in their capital accounts, until the capital accounts of the subordinated unitholders have been reduced to zero;

•

second, to the holders of common units in proportion to the positive balances in their capital accounts, until the capital accounts of the common unitholders have been reduced to zero; and

•

thereafter, 100.0% to our general partner.

If the liquidation occurs after the end of the subordination period, the distinction between common and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.

Adjustments to Capital Accounts

Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to the unitholders and the general partner in the same manner as we allocate gain or loss upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, our partnership agreement requires that we allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in the general partner’s capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made.

SELECTED HISTORICAL FINANCIAL DATA

Terryville Mineral & Royalty Partners LP was formed in October 2014 and does not have historical financial statements. Therefore, in this prospectus we present the historical carve-out financial statements of the royalty interests that will be contributed to us upon the closing of this offering. Our “predecessor” refers to the historical carve-out financial and operating data of such royalty interests. The following table presents selected historical financial data of the royalty interests as of the dates and for the periods indicated.

The selected historical financial data of the royalty interests presented as of the dates and for the periods indicated are derived from the audited historical carve-out financial statements and unaudited historical carve-out financial statements of the royalty interests included elsewhere in this prospectus.

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


	Nine Months Ended September 30,						Year Ended December 31,
	2014			2013			2013			2012
	(unaudited)
	(in thousands, except per unit data)
Statement of Operations Data:
Royalty income	$	22,890		$	8,887		$	12,638		$	3,079
Costs and expenses:
Production taxes		459			151			247			10
Depletion		1,574			937			1,330			367
General and administrative		72			66			92			82

Total costs and expenses		2,105			1,154			1,669			459

Income before income taxes		20,785			7,733			10,969			2,620
Income tax expense		3,373			—			—			—

Net income	$	17,412		$	7,733		$	10,969		$	2,620

Statement of Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	19,503		$	7,681		$	11,025		$	1,774
Investing activities		(181	)		(884	)		(963	)		(463	)
Financing activities		(19,322	)		(6,797	)		(10,062	)		(1,311	)
Other Financial Data:
EBITDA(1)	$	22,359		$	8,670		$	12,299		$	2,987
Pro forma net income per common unit (basic and diluted)(2)
Pro forma net income per subordinated unit (basic and diluted)(2)
Balance Sheet Data (at period end):
Total assets	$	28,236					$	26,780		$	25,872
Total liabilities		4,158						15			14
Predecessor capital		24,078						26,765			25,858

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

(2)	For more information, please read Note 2 to our predecessor’s audited carve-out financial statements included elsewhere in this prospectus.

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

You should read the following discussion of our historical performance, financial condition and future prospects in conjunction with our predecessor’s audited historical carve-out financial statements as of and for the years ended December 31, 2013 and 2012 and the unaudited historical financial statements as of and for the nine months ended September 30, 2014 included elsewhere in this prospectus. The information provided below supplements, but does not form part of our predecessor’s financial statements. This discussion contains forward-looking statements that are based on the views and beliefs of our management, as well as assumptions and estimates made by our management. Actual results could differ materially from such forward-looking statements as a result of various risk factors, including those that may not be in the control of management. For further information on items that could impact our future operating performance or financial condition, see the section entitled “Risk Factors” elsewhere in this prospectus.

Overview

Terryville Mineral & Royalty Partners LP is a Delaware limited partnership formed by Memorial Resource to own and acquire oil natural gas, NGL and oil properties in North America.

Our initial assets consist of overriding royalty interests in approximately 26,931 gross acres in the Terryville Complex, all of which are operated by Memorial Resource and substantially all of which are currently held by production. Our royalty interests entitle us to receive 7% of gross revenues from production on 44 of Memorial Resource’s 46 existing horizontal producing wells and all future horizontal or vertical wells completed by Memorial Resource at all depths within our acreage regardless of the working interest that Memorial Resource owns. We are not required to pay any capital or operating expenses associated with any existing wells, or expenses associated with the development of any future wells. For the year ended December 31, 2013 and nine months ended September 30, 2014, revenue generated from these royalty interests was $12.6 million and $22.9 million, respectively.

Sources of Our Revenue

Our revenues are derived from royalty payments we receive from Memorial Resource based on the sale of oil and natural gas production, as well as the sale of natural gas liquids that are extracted from natural gas during processing. Our royalty payments are not burdened with any post production costs such as gas gathering and processing costs. For the year ended December 31, 2013, our revenues were derived 20% from oil sales, 27% from natural gas liquid sales and 53% from natural gas sales. For the nine months ended September 30, 2014, our revenues were derived 17% from oil sales, 22% from natural gas liquid sales and 61% from natural gas sales. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. Oil, natural gas liquids and natural gas prices have historically been volatile. During 2013, West Texas Intermediate posted prices ranged from $86.65 to $110.62 per Bbl and the Henry Hub spot market price of natural gas ranged from $3.08 to $4.52 per MMBtu. During the nine months ended September 30, 2014, West Texas Intermediate posted prices ranged from $91.17 to $107.95 per Bbl and the Henry Hub spot market price of natural gas ranged from $3.77 to $8.15 per MMBtu.

Recently, oil and natural gas prices have declined significantly. Through December 1, 2014, the West Texas Intermediate posted price had declined from a high of $107.95 per Bbl on June 20, 2014 to $68.98 per Bbl on December 1, 2014. In addition, the Henry Hub spot market price had declined from a high of $8.15 per MMBtu on February 10, 2014 to a low of $4.30 per MMBtu on December 1, 2014. Likewise, NGL prices have suffered significant declines in realized prices recently. NGLs are made up of ethane, propane, isobutane, normal butane and natural gasoline, all of which have different uses and different pricing characteristics.

Natural gas, NGL and oil prices are inherently volatile and are influenced by many factors outside their control. We expect to adopt a hedging policy designed to reduce the impact to our cash flows from commodity price volatility. Under this policy, we intend to enter into commodity derivative contracts covering approximately 65% to 85% of our estimated production from total proved developed producing reserves over a three-to-six year period at any given point of time. We may, however, from time to time hedge more or less than this approximate range. Additionally, we intend to individually identify these non-speculative hedges as “designated hedges” for U.S. federal income tax purposes as we enter into them. These commodity derivative contracts may consist of natural gas, oil and NGL financial swaps and collar contracts and natural gas basis financial swaps.

Principal Components of Our Cost Structure

Production Taxes

Production taxes are paid on produced natural gas, NGLs and oil based on a percentage of market prices and at fixed per unit rates established by federal, state or local taxing authorities. We take full advantage of all credits and exemptions in the various taxing jurisdictions where we operate. For example, Louisiana allows the suspension of severance taxes on qualifying horizontal wells for two years from the date of first production or until payout of qualified costs, whichever comes first.

General and Administrative

At the closing of this offering, we and our general partner will enter into an omnibus agreement with Memorial Resource pursuant to which, among other things, it will perform all operational, management and administrative services on our general partner’s and our behalf. Our partnership agreement provides that our general partner will determine the expenses that are allocated to us, including expenses incurred by our general partner and its affiliates on our behalf. Memorial Resource currently intends to allocate its expected general and administrative costs on a quarterly basis based on estimated time spent on each entity. For a detailed description of the omnibus agreement, please read “Certain Relationships and Related Party Transactions—Agreements and Transactions with Affiliates in Connection with this Offering—Omnibus Agreement.” Under our partnership agreement and the omnibus agreement, we will reimburse Memorial Resource for all direct and indirect costs incurred on our behalf, including the $2.5 million of incremental annual expenses we expect to incur as a result of becoming a publicly traded partnership. General and administrative expenses related to being a publicly traded partnership include expenses associated with annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on NASDAQ; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees; director and officer liability insurance costs and director compensation.

Our predecessor’s carve-out financial statements included elsewhere in this prospectus include allocations of costs for salaries, benefits and other general and administrative expenses incurred by Memorial Resource. These costs were allocated based on estimated full-time equivalent labor hours that would have been devoted to running our predecessor’s business. In management’s estimation, the allocation methodology used is reasonable; however, amounts allocated may not be indicative of the cost of future operations or the amount of future allocations.

Depletion

Oil and natural gas producing activities are accounted for in accordance with the successful efforts method of accounting. Depletion of capitalized costs is provided using the units-of-production method based on proved oil and gas reserves related to the associated field.

Reserves and Pricing

The following tables present summary data with respect to the estimated historical net proved oil and natural gas reserves as of September 30, 2014.

Please read “Business—Our Operations” and the summaries of our reserve report included herein as Appendix C in evaluating the material presented below.


	As of September 30, 2014
Estimated Proved Reserves
Natural Gas (MMcf)		50,227
Oil/Condensate (MBbls)		626
NGLs (MBbls)		2,816
Total estimated net proved reserves (MMcfe)(1)		70,877
Proved developed producing (MMcfe)		21,022
Proved developed non-producing (MMcfe)		0
Proved undeveloped (MMcfe)		49,855
Proved developed reserves as a percentage of total proved reserves		30	%
PV-10 of proved reserves (in millions)(2)		249

(1)	Includes 650 MMcf attributable to field fuel usage volumes.

(2)

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

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

•

We have not historically had any outstanding indebtedness and consequently incurred no interest expense. In connection with the closing of this offering, we expect to enter into a revolving credit facility to be used for general partnership purposes and thus may incur interest expense in future periods.

•

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

•

In connection with the closing of this offering, we and our general partner will enter into an omnibus agreement with Memorial Resource pursuant to which Memorial Resource will perform management,

administrative and operating services for us and our general partner, and we will reimburse our general partner for amounts paid to Memorial Resource pursuant to such agreement. Please read “Certain Relationships and Related Party Transactions—Agreements and Transactions with Affiliates in Connection with this Offering.”

Results of Operations

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


	Nine Months Ended September 30,				Year Ended December 31,
	2014		2013		2013		2012
	(unaudited)
	(in thousands)
Operating Results:
Royalty income	$	22,890	$	8,887	$	12,638	$	3,079
Costs and expenses:
Production taxes		459		151		247		10
Depletion		1,574		937		1,330		367
General and administrative		72		66		92		82

Total costs and expenses		2,105		1,154		1,669		459

Net income before income taxes		20,785		7,733		10,969		2,620
Income tax expense		3,373		—		—		—

Net income	$	17,412	$	7,733	$	10,969	$	2,620

Production Data:
Oil (MBbls)		40		18		25		6
NGLs (MBbls)		106		56		83		25
Natural Gas (MMcf)		2,984		1,302		1,821		501

Total (MMcfe)		3,856		1,746		2,472		684
Average net production (MMcfe/d)		14.1		6.4		6.8		1.9
Average Sales Price:
Oil (per Bbl)	$	98.55	$	101.25	$	99.73	$	93.72
NGLs (per Bbl)	$	47.26	$	40.52	$	40.58	$	41.43
Natural gas (per Mcf)	$	4.69	$	3.69	$	3.71	$	3.01

Total (Mcfe)	$	5.94	$	5.09	$	5.11	$	4.50

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

Royalty Income

Our royalty income for the nine months ended September 30, 2014 was $22.9 million, an increase of $14.0 million, or 158%, from $8.9 million for the nine months ended September 30, 2013. Our revenues are a function of oil, natural gas liquids and natural gas production volumes sold and average prices received for those volumes. Production increased 2.1 Bcfe (approximately 121%), primarily from increased drilling activities by Memorial Resource. The average realized sales price increased $0.85 per Mcfe primarily due to higher natural gas prices. The favorable volume and pricing variance contributed to an approximate $10.7 million and $3.3 million increase in revenues, respectively.

Depletion

The $0.6 million increase in depletion expense was primarily due to increased production volumes related to increased drilling activities by Memorial Resource. Increased production volumes increased depletion expense

by $1.1 million, while a 24% decrease in the depletion rate between periods decreased depletion expense by $0.5 million. On a per Mcfe basis, depletion expense decreased by $0.13 per Mcfe from the nine months ended September 30, 2013 to the same period in 2014. An increase in proved reserve volumes more than offset the impact of increases to the depletable cost base.

Income Tax

Income tax expense has been presented for the nine months ended September 30, 2014, as Memorial Resource became subject to federal income tax on June 18, 2014. Prior to Memorial Resource’s initial public offering on June 18, 2014, its predecessor was a pass-through entity not subject to federal tax. Accordingly, income tax expense was based on estimated income from June 18, 2014 to September 30, 2014 on a separate return basis at a statutory rate of 40%.

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

Royalty Income

Our royalty income for the year ended December 31, 2013 was $12.6 million, an increase of $9.6 million, or 310%, from $3.1 million for the year ended December 31, 2012. Production increased 1.8 Bcfe (approximately 261%), primarily from increased drilling activities by Memorial Resource. The average realized sales price increased $0.61 per Mcfe primarily due to higher natural gas and crude oil prices. The favorable volume and pricing variance contributed to an approximate $8.1 million and $1.5 million increase in revenues, respectively.

Depletion

The $1.0 million increase in depletion expense was primarily due to increased production volumes related to increased drilling activities by Memorial Resource. Increased production volumes increased depletion expense by $1.0 million. On a per Mcfe basis, depletion expense remained flat between 2012 and 2013.

Liquidity and Capital Resources

Overview

Following the completion of this offering, we expect our primary sources of liquidity will be cash flows from operations, borrowings under our revolving credit facility and equity and debt financings and our primary uses of cash will be for paying distributions to our unitholders and any growth capital expenditures such as the acquisition of additional royalty or mineral interests in oil and gas properties. Because we own royalty interests, we will not be required to pay any capital or operating expenses associated with any existing wells, or expenses associated with the of the development of any future wells related to our initial assets.

Our partnership agreement requires that we distribute all of our available cash (as defined in the partnership agreement) to our unitholders. In making cash distributions, our general partner will attempt to avoid large variations in the amount we distribute from quarter to quarter. In order to facilitate this, our partnership agreement will permit our general partner to establish cash reserves to be used to pay distributions for any one or more of the next four quarters. In addition, our partnership agreement allows us to borrow funds to make distributions.

We may borrow to make distributions to our unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long-term, but short-term factors have caused available cash from operations to be insufficient to sustain our level of distributions. In addition, we plan to hedge a significant portion of our production. We generally will be required to settle our commodity hedge derivatives within five days of the end of the month. As is typical in the oil and natural gas industry, we do not generally receive the proceeds from the sale of our hedged production until 45 to 60 days following the end of the month. As a result,

when commodity prices increase above the fixed price in the derivative contracts, we will be required to pay the derivative counterparty the difference between the fixed price in the derivative contract and the market price before we receive the proceeds from the sale of the hedged production. If this occurs, we may make working capital borrowings to fund our distributions.

Cash Flows

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


	Nine Months Ended September 30,				Year Ended December 31,
	2014		2013		2013		2012
	(in thousands)
Cash Flow Data:
Cash flows provided by operating activities	$	19,503	$	7,681	$	11,025	$	1,774
Cash flows used in investing activities		181		884		963		463
Cash flows used in financing activities		19,322		6,797		10,062		1,311

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

Operating Activities

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

Production increased 2.1 Bcfe (approximately 121%) and average realized sales price increased $0.85 per Mcfe as previously discussed under “—Results of Operations.” Net cash provided by operating activities included a $1.3 million period-to-period increase in cash flow attributable to the timing of cash receipts and disbursements related to operating activities during the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013.

Investing Activities

On March 18, 2013, a purchase and sale agreement was executed by a subsidiary of Memorial Resource for the purchase of certain oil and gas properties and leases in Louisiana from a third party. The amount allocable to our predecessor’s financial statements was $0.7 million. This transaction closed on April 30, 2013. Additions to oil and natural gas interests related to leasing was approximately $0.2 million for both the nine months ended September 30, 2014 and 2013.

Financing Activities

Distributions, as presented on the cash flow statement under financing activities, are equal to net cash provided by operating activities less cash used in investing activities since the Partnership’s predecessor operated within the Memorial Resource cash management program. Distributions for the nine months ended September 30, 2014 were $19.3 million, an increase of $12.5 million from $6.8 million for the nine months ended September 30, 2013.

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

Operating Activities

Production increased 1.8 Bcfe (approximately 261%) and average realized sales price increased $0.61 per Mcfe as previously discussed under “—Results of Operations.”

Investing Activities

On May 1, 2012, two subsidiaries of Memorial Resource jointly acquired operating and non-operating interests in certain oil and natural gas properties located in East Texas and North Louisiana from an undisclosed third party seller. The amount allocable to our predecessor’s financial statements was less than $0.1 million.

Additions to oil and natural gas interests related to leasing were $0.2 million for the year ended December 31, 2013 compared to $0.4 million for the year ended December 31, 2012.

Financing Activities

Distributions for the year ended December 31, 2013 were $10.0 million, an increase of $8.7 million from $1.3 million for the year ended December 31, 2012.

Revolving Credit Facility

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

Commodity Derivative Contracts

Our cash flow from operations is subject to many variables, the most significant of which is the volatility of oil and natural gas prices. Oil and natural gas prices are determined primarily by prevailing market conditions, which are dependent on regional and worldwide economic activity, weather and other factors beyond our control. Our future cash flow from operations will depend on the prices of oil and natural gas and our ability to maintain and increase production through acquisitions and exploitation and development projects.

We expect to adopt a hedging policy designed to reduce the impact to our cash flows from commodity price volatility. Under this policy, we intend to enter into commodity derivative contracts covering approximately 65% to 85% of our estimated production from total proved developed producing reserves over a three-to-six year period at any given point of time. We may, however, from time to time hedge more or less than this approximate range. Additionally, we intend to individually identify these non-speculative hedges as “designated hedges” for U.S. federal income tax purposes as we enter into them. These commodity derivative contracts limit our exposure to declines in prices, but also limit the benefits if prices increase. We do not specifically designate derivative contracts as cash flow hedges; therefore, the mark-to-market adjustment reflecting the change in the unrealized gains or losses on these contracts is recorded in current period earnings. When prices for oil and natural gas are volatile, a significant portion of the effect of our hedging activities consists of non-cash income or expenses due to changes in the fair value of our derivative contracts. Realized gains or losses only arise from payments made or received on monthly settlements or if a derivative contract is terminated prior to its expiration.

Contractual Obligations

Our predecessor did not have any contractual obligations and other commitments as of December 31, 2013.

Internal Controls and Procedures

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

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

New and Revised Financial Accounting Standards

We qualify as an “emerging growth company” pursuant to the provisions of the JOBS Act, enacted on April 5, 2012. Section 102 of the JOBS Act provides that an “emerging growth company” can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. However, we are choosing to “opt out” of such extended transition period, and as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for non-emerging growth companies. Our election to “opt-out” of the extended transition period is irrevocable.

Critical Accounting Policies

Natural Gas and Oil Interests

Oil and natural gas producing activities are accounted for in accordance with the successful efforts method of accounting. Under this method, costs of acquiring properties, including royalty interests, are capitalized. Depletion of capitalized costs is provided using the units-of-production method based on proved oil and gas reserves related to the associated field. On the sale or retirement of a complete or partial unit of a proved property, the cost and related accumulated depletion are removed from the property accounts, and any gain or loss is recognized.

Proved Natural Gas and Oil Reserves

The estimates of proved oil and natural gas reserves utilized in the preparation of the carve-out financial statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board (“FASB”). These rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. We intend to use NSAI to prepare a reserve report as of December 31 of each year for a vast majority of our proved reserves and to prepare internal estimates of our proved reserves as of June 30 of each year.

Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas interests, or any combination of the above may be increased or reduced. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates.

A decline in proved reserves may result from lower market prices, which may make it uneconomical for Memorial Resource to drill for and produce higher cost fields. In addition, a decline in proved reserve estimates may impact the outcome of our assessment of oil and gas producing properties for impairment.

Impairments

Proved oil and natural gas interests are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such interests, such as a downward revision of the reserve estimates, less than expected production or lower commodity prices. The estimated undiscounted future cash flows expected in connection with the mineral interests are compared to the carrying value of the mineral interests to determine if the carrying amount is recoverable. If the carrying value of the mineral interests exceeds its estimated undiscounted future cash flows, the carrying amount of the mineral interest is reduced to its estimated fair value using Level 3 inputs. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and natural gas interests.

Royalty Interests and Revenue Recognition

Overriding royalty interests represent the right to receive revenues (oil and natural gas sales), less production taxes. Revenue is recorded when title passes to the purchaser. Overriding royalty interests have no rights or obligations to explore, develop or operate the property and do not incur any of the costs of exploration, development, and operation of the property. Our royalty interests are not burdened by post-production costs.

Royalty Income Receivable

Royalty income receivable consist of receivables from oil and natural gas sales delivered to purchasers. Those purchasers remit payment for production to the operator of the properties and the operator, in turn, remits payment to us. Substantially all of our royalty interests in oil and natural gas properties are operated by Memorial Resource. Most payments are received within two months after the production date. Royalty income receivable are stated at amounts due from operators, net of an allowance for doubtful accounts when we believe collection is doubtful.

Derivative Instruments

Commodity derivative financial instruments (e.g., swaps, floors, collars, and put options) are used to reduce the impact of natural gas and oil price fluctuations. Interest rate swaps are used to manage exposure to interest rate volatility, primarily as a result of variable rate borrowings under credit facilities. Every derivative instrument is recorded in the balance sheet as either an asset or liability measured at its fair value. Changes in the derivative’s fair value are recognized currently in earnings as we have not elected hedge accounting for any of our derivative positions. Although our predecessor did not have any derivative instruments, we intend to enter into commodity derivative contracts covering approximately 65% to 85% of our estimated production from total proved developed producing reserves over a three-to-six year period at any given point of time.

Allocation of General and Administrative Cost

The accompanying carve-out financial statements include allocations of costs for salaries, benefits and other general and administrative expenses incurred by Memorial Resource. These costs have been allocated to the carve-out financials based on estimated full-time equivalent labor hours that would have been devoted to running our predecessor’s business. In management’s estimation, the allocation methodology used is reasonable and results in an allocation of the cost of doing business borne by Memorial Resource on behalf of us; however, amounts allocated may not be indicative of the cost of future operations or the amount of future allocations.

Income Tax

We will be organized as a pass-through entity for federal income tax purposes. As a result, our partners will be responsible for federal income taxes on their share of our taxable income.

Unaudited Pro Forma Earnings Per Unit (“EPU”)

Pro forma net income (loss) per basic unit is determined by dividing the pro forma net income (loss) available to common unit holders by the number of common units expected to be outstanding immediately following the offering.

Off-Balance Sheet Arrangements

We currently have no off-balance sheet arrangements.

Quantitative and Qualitative Disclosure about Market Risk

Commodity Price Risk

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

Concentrations of Credit Risk

Cash balances and royalty income receivable are financial instruments potentially subject to credit risk. Cash and cash equivalents are maintained in bank deposit accounts which, at times, may exceed the federally insured limits. Management periodically reviews and assesses the financial condition of the banks to mitigate the risk of loss.

concentration in the oil and natural gas industry is mitigated by the creditworthiness of the underlying purchasers and Memorial Resource. We do not require collateral and do not believe the loss of any single purchaser would materially impact our operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers. Additionally, an allowance for doubtful accounts is recorded after all reasonable efforts have been exhausted to collect or settle the amount owed. Any amounts outstanding longer than the contractual terms are considered past due.

The following individual purchasers each accounted for 10% or more of total reported revenues for the period indicated:


	Year Ending December 31,
Major customers:	2013			2012
Energy Transfer Equity, L.P. and subsidiaries		100	%		80	%
Sunoco, Inc.(1)		n/a			20	%

(1)	Sunoco, Inc. became a subsidiary of Energy Transfer Equity, L.P. in October 2012.

BUSINESS

Overview

completion costs, high initial production rates with high liquids yields, long reserve life, multiple stacked producing zones, available infrastructure and a large number of service providers.

The following chart provides information regarding Memorial Resource’s gross production growth associated with its Terryville Complex horizontal wells since the beginning of 2012.

Average Daily Production (MMcfe/d)

LOGO

Our Initial Assets

100


Well Name			Producing Wells																												Gross Wellhead Flow Rates After Processing								D&C ($MM)(5)
	Lateral Length (Feet)		EUR(1)(2)											EUR Bcfe/ 1,000’		First Production		Days Producing		Cumulative Production											(MMcfe/d)(3)(4)
	Lateral Length (Feet)		(Bcfe)		%Gas			%NGL			%Oil			EUR Bcfe/ 1,000’		First Production		Days Producing		(Bcfe)		%Gas			%NGL			%Oil			0-30		0-90		91-180		181-360
Upper Red Zone
LD Barnett 23H-2		4,015		12.3		69	%		27	%		4	%		3.1		1/30/2012		975		5.0		71	%		24	%		5	%		14.5		12.0		7.7		5.6		6.7
Colquitt 20 17H-1		4,357		11.5		79	%		18	%		2	%		2.6		7/30/2012		793		4.3		81	%		17	%		2	%		17.5		12.6		7.2		5.1		7.8
Dowling 22 15H-1		5,376		9.4		78	%		20	%		2	%		1.8		9/22/2012		739		5.7		80	%		18	%		3	%		16.3		15.6		11.1		8.2		8.8
Nobles 13H-1		4,216		9.1		67	%		24	%		10	%		2.1		11/17/2012		683		4.6		65	%		22	%		13	%		21.5		16.7		9.9		6.5		7.8
Sidney McCullin 16 21H-1		4,604		13.8		75	%		21	%		3	%		3.0		1/19/2013		620		5.0		81	%		16	%		3	%		17.4		14.2		10.8		8.4		8.1
Wright 14 11 HC-1		5,250		11.9		66	%		27	%		7	%		2.3		5/27/2013		492		5.5		64	%		28	%		8	%		19.6		18.1		16.1		8.4		8.8
BF Fallin 22 15H-1		5,122		12.3		72	%		24	%		4	%		2.4		6/17/2013		471		3.9		74	%		22	%		4	%		14.8		13.7		11.8		5.9		7.5
Dowling 20 17H-1		4,327		9.0		73	%		25	%		3	%		2.1		7/22/2013		436		2.6		77	%		20	%		3	%		15.2		11.0		5.7		4.5		10.7
Gleason 31H-1		3,692		2.4		91	%		9	%		0	%		0.7		8/12/2013		415		0.6		90	%		10	%		0	%		2.9		2.3		1.6		1.2		9.5
Burnett 26H-1		2,405		5.5		71	%		25	%		4	%		2.3		9/22/2013		374		1.2		71	%		24	%		5	%		6.9		5.6		3.5		2.4		6.9
Drewett 17 8H-1		4,010		15.6		66	%		25	%		10	%		3.9		11/13/2013		322		3.9		61	%		26	%		13	%		22.1		18.6		11.9				7.7
Wright 13 12 HC-2		6,009		24.0		69	%		22	%		10	%		4.0		12/21/2013		284		4.6		76	%		11	%		13	%		22.7		19.6		16.3				8.5
LA Minerals 15 22H-2		5,814		17.3		73	%		25	%		3	%		3.0		1/21/2014		253		3.4		76	%		22	%		3	%		17.8		16.1		13.4				8.8
Wright 13 24 HC-3		6,606		20.9		74	%		23	%		3	%		3.2		4/14/2014		170		3.4		85	%		11	%		4	%		30.3		24.6						10.8
Wright 13 24 HC-1		6,678		15.5		71	%		20	%		8	%		2.3		4/14/2014		170		2.8		77	%		12	%		11	%		25.0		20.4						11.8
TL McCrary 14 11 HC-5		5,875		30.0		71	%		24	%		6	%		5.1		4/14/2014		170		3.0		81	%		11	%		8	%		22.9		23.3						10.2
LA Minerals 19 30 HC-2		6,912		15.1		75	%		24	%		2	%		2.2		5/29/2014		125		2.3		85	%		13	%		2	%		25.1		20.4						10.8
LA Minerals 19 30 HC-1		6,519		19.6		75	%		23	%		1	%		3.0		6/1/2014		122		2.0		85	%		13	%		2	%		21.5		17.7						11.6
Werner 29H-1		3,410		4.7		75	%		23	%		2	%		1.4		8/13/2014		49		0.4		84	%		13	%		2	%		8.6								11.0
Werner 29 32 5 HC-1		6,810		9.7		74	%		23	%		3	%		1.4		8/13/2014		49		0.8		84	%		13	%		3	%		18.4								10.4
Werner 29 32 5 HC-2		8,300		16.5		75	%		23	%		2	%		2.0		8/13/2014		49		1.2		84	%		13	%		3	%		26.1								12.2
Temple 8H-1		2,403		6.3		77	%		23	%		0	%		2.6		8/24/2014		38		0.4		93	%		7	%		0	%		12.7								9.6
Temple 8 17 HC-1		6,210		2.9		76	%		23	%		1	%		0.5		8/29/2014		33		0.3		92	%		7	%		1	%		8.4								11.9
TL McCrary 14 11 HC-2		4,401		NA													9/25/2014		6		0.1																			7.7
TL McCrary 14 11 HC-4		4,810		NA													9/25/2014		6		0.0																			9.0

Lower Red Zone
TL McCrary 14H-1		4,544		12.7		70	%		27	%		4	%		2.8		5/1/2012		883		4.5		73	%		23	%		4	%		14.4		11.7		8.3		5.4		7.7
Nobles 13H-2		4,060		5.6		66	%		23	%		11	%		1.4		11/17/2012		683		3.3		68	%		22	%		10	%		16.0		11.9		8.2		5.2		7.8
LA Methodist Orphanage 14H-1		3,637		9.5		69	%		24	%		7	%		2.6		2/15/2013		593		4.0		69	%		23	%		8	%		13.9		13.0		9.7		6.3		9.1
Dowling 21 16H-1		4,590		8.4		78	%		21	%		1	%		1.8		3/18/2013		562		3.0		84	%		15	%		2	%		13.0		10.1		6.5		4.5		6.6
Drewett 17 8H-2		3,700		4.2		66	%		25	%		9	%		1.1		11/13/2013		322		1.2		63	%		27	%		11	%		8.7		6.2		3.2				7.0
Wright 13 12 HC-1		5,409		9.4		70	%		21	%		9	%		1.7		12/21/2013		284		2.2		76	%		11	%		13	%		14.7		11.4		7.2				9.3
LA Minerals 15 22H-1		5,926		8.1		71	%		24	%		5	%		1.4		1/21/2014		253		1.9		73	%		21	%		5	%		13.8		10.9		6.4				7.8
Wright 13 24 HC-4		6,518		15.1		74	%		23	%		3	%		2.3		4/14/2014		170		2.6		85	%		11	%		4	%		25.7		19.6						13.4
LA Minerals 19 30 HC-3		5,356		2.5		76	%		21	%		3	%		0.5		5/29/2014		125		0.6		84	%		13	%		3	%		8.8		5.9						12.1
LA Minerals 19 30 HC-4		6,469		3.5		77	%		21	%		2	%		0.5		6/1/2014		122		0.9		85	%		13	%		2	%		13.6		8.5						13.8
TL McCrary 14 11 HC-1		4,010		NA													9/25/2014		6		0.0																			8.9
TL McCrary 14 11 HC-3		4,620		NA													9/25/2014		6		0.0																			8.3

Lower Deep Pink Zone
LA Methodist Orphanage 14H-2		3,550		6.1		68	%		23	%		9	%		1.7		2/15/2013		593		3.5		67	%		22	%		11	%		14.2		11.6		7.6		5.7		6.1
Wright 13 12 HC-4		5,010		5.8		69	%		21	%		10	%		1.2		12/21/2013		284		1.6		75	%		11	%		13	%		11.8		8.8		4.8				7.0
Wright 13 12 HC-3		5,706		5.4		71	%		20	%		8	%		0.9		12/21/2013		284		1.6		77	%		12	%		11	%		12.5		9.3		5.0				7.4

Upper Deep Pink Zone
Werner 29 32 5 HC-3		6,679		3.1		73	%		22	%		4	%		0.5		8/13/2014		49		0.3		81	%		13	%		6	%		7.2								10.1

Averages(6)
All Wells		5,071		10.7		73	%		23	%		5	%		2.1				319		2.4		78	%		17	%		6	%		16.1		13.6		8.4		5.6		9.2
Upper Red		5,125		12.8		73	%		23	%		4	%		2.5				314		2.7		79	%		16	%		5	%		17.7		15.7		9.8		5.6		9.4
Lower Red		4,903		7.9		72	%		23	%		5	%		1.6				334		2.0		76	%		18	%		6	%		14.3		10.9		7.1		5.4		9.3
Lower Deep Pink		4,755		5.8		69	%		21	%		9	%		1.3				387		2.2		73	%		15	%		12	%		12.8		9.9		5.8		5.7		6.8
Upper Deep Pink		6,679		3.1		73	%		22	%		4	%		0.5				49		0.3		81	%		13	%		6	%		7.2								10.1

(1)	EUR represents the estimated ultimate recovery or sum of total gross remaining proved reserves attributable to each location in our reserve report and cumulative gross production from such location. EUR is shown on a combined basis for oil/condensates, gas and NGLs after the effects of processing.

(2)	TL McCrary 14 11 wells HC-1, HC-2, HC-3 and HC-4 did not begin producing in time to be included in our reserve report as proved developed producing, which has prevented us from providing an estimate of EURs for these wells.

101

(3)	Production data is as of September 30, 2014 and shown gross on a combined basis after the effects of processing.

(4)	Periodic flow rates start on day 4, with days 1 through 3 used to allow clean up associated with well completion. The 30-day flow rates therefore start on day 4 and continue 30 days to day 33 and the 90-day flow rates go from day 4 to day 93.

(5)	Represents approximate historical drilling and completion costs incurred by Memorial Resource. As an owner of royalty interests, we are not required to pay any capital or operating expenses associated with any existing wells, or expenses associated with the development of any future wells.

(6)	We will also have a royalty interest in three horizontal producing wells outside of the four primary zones where Memorial Resource plans to continue to focus its development activity. These averages do not include such wells.

The following table provides information regarding drilling locations associated with our acreage by area as of September 30, 2014:


	Gross Horizontal Drilling Locations(1)(2)
Terryville Complex Zone	Proved		Management		Total		Memorial Resource Total
Upper Red		40		168		208		429
Lower Red		55		166		221		386
Lower Deep Pink		9		146		155		158
Upper Deep Pink		—		153		153		153
Other Zones		—		285		285		285

Total Terryville Complex		104		918		1,022		1,411

(1)

(2)

Our Relationship with Memorial Resource

102

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

Business Strategies

•

Seek to acquire from Memorial Resource, from time to time, royalty or mineral interests in producing oil and natural gas properties that meet our acquisition criteria. We may have additional opportunities to acquire royalty or mineral interests in producing oil and natural gas properties directly from Memorial Resource or third parties from time to time in the future. As of December 31, 2013, Memorial Resource has a leasehold position of 60,041 gross acres in the Terryville Complex, including our 26,931 gross acres. We believe Memorial Resource will be incentivized to sell properties to us, including additional overriding royalty interests both within and outside our 26,931 gross acres. Following this offering, Memorial Resource will own and control our general partner as well as % of our outstanding common units, all of our subordinated units and all of our incentive distribution rights.

•

Pursue third-party acquisitions and leverage our relationship with Memorial Resource and its affiliates to participate in acquisitions of royalty or mineral interests and to increase the size and scope of our potential acquisition targets. We intend to make opportunistic acquisitions of royalty or mineral interests that have substantial resource and organic growth potential. Memorial Resource was formed in part to acquire and develop oil and natural gas properties, some of which will likely meet our acquisition criteria. In addition, Memorial Resource’s executives have long histories of evaluating, pursuing and consummating oil and natural gas property acquisitions in North America. Through our relationships with Memorial Resource and its affiliates, including MEMP, a publicly traded limited partnership engaged in the acquisition, exploitation, development and production of producing oil and natural gas properties that are located in Texas, Louisiana, Colorado, Wyoming, New Mexico and offshore Southern California, we have access to their significant pool of management talent and industry relationships, which we believe provide us with a competitive advantage in pursuing potential third-party acquisition opportunities. We may have additional opportunities to work jointly with Memorial Resource or MEMP to pursue certain acquisitions of royalty or mineral interests in oil and natural gas properties from third parties. For example, we and Memorial Resource may jointly pursue

103

an acquisition where we would acquire royalty or mineral interests in properties and Memorial Resource would acquire the remaining working and revenue interests in such properties. We believe our relationship with Memorial Resource and its affiliates may give us access to third-party acquisition opportunities that we would not otherwise be in a position to pursue.

•

Reduce exposure to commodity price risk and stabilize cash flows through a disciplined commodity hedging policy. We intend to implement and maintain a portfolio of commodity derivative contracts covering approximately 65% to 85% of our estimated production from total proved developed producing reserves over a three-to-six year period at any given point in time. These commodity derivative contracts may consist of natural gas, oil and NGL financial swaps and collar contracts and natural gas basis financial swaps. We believe these commodity derivative contracts will allow us to mitigate the impact of oil and natural gas price volatility, thereby increasing the predictability of our cash flow.

Competitive Strengths

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

•

Large, concentrated position in one of North America’s leading plays. All of our acreage is located in the Terryville Complex in North Louisiana, which is one of the most prolific liquids-rich natural gas plays in North America and which is characterized by consistent and predictable geology and multiple stacked pay formations confirmed by extensive vertical well control. Memorial Resource’s total leasehold position in the Terryville Complex was approximately 60,041 gross acres as of December 31, 2013, 26,931 gross acres of which underlie our royalty interests. Substantially all of our acreage is currently held by production and is not subject to lease expirations. Through September 30, 2014, Memorial Resource’s drilling program in the Terryville Complex has produced some of the top performing and most economic gas wells in the United States over the prior two years. Through September 30, 2014, Memorial Resource brought 41 horizontal wells online within its four primary target zones with average 30-day initial production rates of 16.1 MMcfe/d and average drilling and completion costs of $9.2 million per well. We believe that we will have a strong, growing production profile driven by Memorial Resource, a growth-oriented operator.

•

Single controlling and incentivized operator whose drilling plan is focused across our acreage. Following the completion of this offering, Memorial Resource, which will own our general partner, % of our common units, all of our subordinated units and all of our incentive distribution rights, will continue to own a substantial working interest in and operate all of the properties underlying our

104

royalty interests, further aligning our goal of the profitable development of our acreage. We believe our acreage is located where Memorial Resource intends to continue to focus its development. Of Memorial Resource’s drilling, recompletion and workover capital expenditure budget for 2014 of $351 million, $304 million relates to the Terryville Complex and $295 million relates to wells within our acreage. Memorial Resource currently has six rigs operating in the Terryville Complex and expects to increase to seven rigs in 2015. Memorial Resource has indicated all of these rigs are currently scheduled to operate exclusively within our acreage in 2015.

•

Financial flexibility to fund acquisitions. We expect to have the financial flexibility to allow us to opportunistically purchase accretive royalty or mineral interests. We believe that our partnership structure should provide us with a relatively low cost of capital, thereby enhancing our ability to compete for future acquisitions, both individually and jointly with Memorial Resource and its affiliates. We also expect that the revolving credit facility we will enter into in connection with this offering, which will be undrawn following the completion of this offering, and our ability to issue additional common units and other partnership interests will provide us with substantial financial flexibility to pursue acquisitions.

Our Operations

Preparation of Reserve Estimates

Oil and natural gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil and natural gas that are ultimately recovered. For a discussion of risks associated with reserve estimates, please read “Risk Factors—Risks Related to Our Business—Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.”

Evaluation and Review of Estimated Reserves. Our historical proved reserve estimates as of September 30, 2014 were prepared by NSAI, our independent petroleum engineers. The technical persons responsible for preparing our proved reserve estimates meet the requirements with regard to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. NSAI does not own an interest in any of our properties, nor is it employed by us on a contingent basis. A copy of NSAI’s summary reserve report regarding our proved reserves as of September 30, 2014 is included as Appendix C to this prospectus.

Our historical proved reserve estimates as of December 31, 2013 were prepared by our internal staff. We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate our

105

estimated reserves. Our technical team meets regularly with NSAI reserve engineers to review properties and discuss the assumptions and methods used in the reserve estimation process. We provide historical information to NSAI for our properties, such as ownership interest, oil and natural gas production, well test data, commodity prices and operating and development costs.

Internal Engineers. John D. Williams is our technical person primarily responsible for liaison with and oversight of our third-party reserve engineers, NSAI, which prepared the reserve report for our properties as of September 30, 2014. Mr. Williams has been practicing petroleum engineering at Memorial Resource since March 2012. Mr. Williams is a Registered Professional Engineer in the State of Texas with over 17 years of experience in the estimation and evaluation of reserves. From April 2005 to March 2012, he held various positions at Southwestern Energy Company, most recently as Reservoir Engineering Manager. From August 1998 to April 2005, he served in various capacities at Ryder Scott Company, which culminated in his serving as Vice President. Mr. Williams is a graduate of the University of Texas at Austin with a Bachelor of Science Degree in Petroleum Engineering and with a Master of Science Degree in Petroleum Engineering.

NSAI is an independent oil and natural gas consulting firm. No director, officer, or key employee of NSAI has any financial ownership in us, Memorial Resource, the Funds, or any of their respective affiliates. NSAI’s compensation for the required investigations and preparation of its report is not contingent upon the results obtained and reported. NSAI has not performed other work for us, Memorial Resource, the Funds, or any of their respective affiliates that would affect its objectivity. The estimates of proved reserves at September 30, 2014 presented in the NSAI reports were overseen by Mr. Philip S. (Scott) Frost and Mr. William J. Knights.

Scott Frost has been practicing consulting petroleum engineering at NSAI since 1984. Mr. Frost is a Licensed Professional Engineer in the State of Texas (License No. 88738) and has over 30 years of practical experience in petroleum engineering, with over 30 years of experience in the estimation and evaluation of reserves. He graduated from Vanderbilt University in 1979 with a B.E. in mechanical engineering and from Tulane University in 1984 with an M.B.A.

William Knights has been practicing consulting petroleum geology at NSAI since 1991. Mr. Knights is a Licensed Professional Geoscientist in the State of Texas (License No. 1532) and has over 30 years of practical experience in petroleum geosciences, with over 30 years of experience in the estimation and evaluation of reserves. He graduated from Texas Christian University in 1981 with a B.S. in geology and in 1984 with a M.S. in geology.

Both technical principals meet or exceed 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; both are proficient in applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

Estimation of Proved Reserves. Under SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” All of our proved reserves as of September 30, 2014 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and natural gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and natural gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into four broad categories or

106

methods: (1) production performance-based methods; (2) material balance-based methods; (3) volumetric-based methods; and (4) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy. Non-producing reserve estimates, for developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves for our properties, due to the mature nature of the properties targeted for development and an abundance of subsurface control data.

To estimate economically recoverable reserves and related future net cash flows, NSAI considered many factors and assumptions, including the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates.

Under SEC rules, reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. 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. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves have been demonstrated to yield results with consistency and repeatability, and include production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, available seismic data and historical well cost and operating expense data.

Estimated Reserves

The table below identifies our reserves as of September 30, 2014 per our reserve report and as of December 31, 2013 per our management’s estimates:


	As of September 30, 2014			As of December 31, 2013
Estimated Proved Reserves
Natural Gas (MMcf)		50,227			39,850
Oil/Condensate (MBbls)		626			636
NGLs (MBbls)		2,816			2,259
Total estimated net proved reserves (MMcfe)(1)		70,877			57,219
Proved developed producing (MMcfe)		21,022			13,096
Proved developed non-producing (MMcfe)		0			0
Proved undeveloped (MMcfe)		49,855			44,123
Proved developed reserves as a percentage of total proved reserves		30	%		23	%
PV-10 of proved reserves (in millions)(2)		249			206

(1)	Includes 650 MMcf attributable to field fuel usage volumes.

(2)

107

on a more comparable basis. PV-10 differs from standardized measure because it does not include the effects of income taxes. However, because we are a limited partnership, we are generally not subject to federal income taxes and thus our PV-10 for proved reserves and standardized measure are equivalent. Neither PV-10 nor standardized measure represents an estimate of fair market value of our natural gas and oil properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of estimated reserves held by companies without regard to the specific tax characteristics of such entities.

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

Additional information regarding our reserves can be found in the reserve report as of September 30, 2014, which is included as Appendix C to this prospectus.

Proved Undeveloped Reserves

As of September 30, 2014, we had 50 Bcfe of proved undeveloped reserves, comprised of 0.5 MMBbls of oil, 35 Bcf of natural gas and 2 MMBbls of NGLs. None of our PUDs as of September 30, 2014 are scheduled to be developed on a date more than five years from the date the reserves were initially booked as PUDs. PUDs will be converted from undeveloped to developed as the applicable wells begin production.

Changes in PUDs that occurred during 2013:

•

Reclassifications of 4.9 Bcfe into proved developed reserves for implementation of drilling projects;

•

Additions of 12.1 Bcfe reflected as extensions and discoveries due to proving up additional drilling locations; and

•

Downward revisions of 3.5 Bcfe due to evaluation reassessments and drilling results.

Changes in PUDs that occurred during the nine months ended September 30, 2014:

•

Reclassifications of 2.7 Bcfe into proved developed reserves for implementation of drilling projects;

•

Additions of 2.2 Bcfe reflected as extensions and discoveries due to proving up additional drilling locations; and

•

Upward revisions of 6.2 Bcfe due to evaluation reassessments and drilling results.

As an owner of royalty interests, we will not bear the burden of funding the development costs of drilling our PUD reserves within a five-year timeframe. All of our PUD locations are scheduled to be drilled by Memorial Resource prior to the end of December 31, 2018. Based on Memorial Resource’s current expectations of its cash flows, Memorial Resource believes that it can fund the drilling of its current PUD inventory and its expansions in the next five years primarily from its cash flow from operations.

108

Production, Revenues and Price History

The following table sets forth information regarding our predecessor’s production, revenue and realized prices for each of the periods indicated:


	Nine Months Ended September 30, 2014		Year Ended December 31,
	Nine Months Ended September 30, 2014		2013		2012
	(unaudited)
Production and Operating Data:
Net production volumes:
Oil (MBbls)		40		25		6
NGLs (MBbls)		106		83		25
Natural gas (MMcf)		2,984		1,821		501

Total (MMcfe)		3,856		2,472		684
Average net production (MMcfe/d)		14.1		6.8		1.9
Average sales price:
Oil (per Bbl)	$	98.55	$	99.73	$	93.72
NGLs (per Bbl)	$	47.26	$	40.58	$	41.43
Natural gas (per Mcf)	$	4.69	$	3.71	$	3.01

Average price per Mcfe	$	5.94	$	5.11	$	4.50

Productive Wells

On a pro forma basis giving effect to the creation of our royalty interest, as of September 30, 2014, our predecessor owned royalty interests in 44 gross productive wells in which we have a royalty interest, all of which are natural gas wells. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities.

Acreage

The following table sets forth certain information regarding the developed and undeveloped acreage in which we owned a royalty interest as of December 31, 2013 on a pro forma basis giving effect to the creation of our royalty interest.

Basin

Developed
Acreage

Undeveloped
Acreage

Total Acreage

Terryville Complex

22,080

4,851

26,931

Undeveloped Acreage Expirations

The following table sets forth the gross undeveloped acreage in which we own a royalty interest as of December 31, 2013 on a pro forma basis giving effect to the creation of our royalty interest that will expire over the next four years unless production is established within the spacing units covering the acreage or the lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates. There are no reserves attributable to our expiring acreage.


Basin	2014		2015		2016		2017
Terryville Complex		11		1,980		1,810		1,050

109

Drilling Activity

The following table summarizes information with respect to the number of gross wells completed by Memorial Resource within our acreage during the periods indicated. Each of these wells was drilled in the Terryville Complex in northern Louisiana. At September 30, 2014, eight gross wells were in various stages of completion.


	Nine Months Ended September 30,		Years ended December 31,
	2014		2013		2012		2011
Development wells:
Productive		10		9		—		—
Dry		—		—		—		—
Total development wells		10		9		—		—
Exploratory wells:
Productive		11		6		6		2
Dry		—		—		—		—
Total exploratory wells		11		6		6		2

Total wells drilled		21		15		6		2

Drilling Locations

As of September 30, 2014, Memorial Resource had identified 1,022 gross horizontal drilling locations on our existing acreage, 798 of which were attributable to acreage that is currently held by production and approximately 10% of which were attributable to proved undeveloped reserves. As of December 31, 2013, Memorial Resource had 1,582 gross horizontal locations, 1,171 of which were attributable to acreage that is currently held by production and approximately 9% of which were attributable to proved undeveloped reserves. In making these assessments, Memorial Resource included properties in which its holds operated and non-operated interests, as well as redevelopment opportunities. Once Memorial Resource has identified acreage that is prospective for the targeted formations, well placement is determined primarily by the regulatory spacing rules prescribed by the governing body in each of our operating areas.

Our gross horizontal drilling locations as of September 30, 2014 include 104 locations in the proved category. The additional 918 gross horizontal drilling locations are locations that have been identified by Memorial Resource’s management team. Memorial Resource identified those additional locations by using existing geologic and engineering data from vertical production, seismic data and engineering data accrued over our multi-year historical drilling activities in the surrounding area. The 1,022 gross horizontal drilling locations, are based on assumed well spacing of 137 acres Memorial Resource is currently drilling multiple 137-acre spaced horizontal wells (and has drilled horizontal wells using that spacing that are currently producing) in the same geographic area where it has identified all of its management locations. Memorial Resource has received all necessary state and local approvals to drill at 35 of those locations. Memorial Resource has not encountered any, and is aware of no, regulatory constraints or field rules preventing it from obtaining new permits on all of its acreage using assumed spacing, and Memorial Resource believes that the remaining 987 locations will also receive all necessary approvals upon application. Memorial Resource believes that area seismic data, as well as information gathered from the results of its existing 44 horizontal and over 275 vertical wells throughout the field, support the existence of at least ten stacked pay zones across the Terryville Complex.

In evaluating and determining those locations, Memorial Resource also considered the availability of local infrastructure, drilling support assets and easement restrictions and state and local regulations. The locations on which Memorial Resource actually drills wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results and other factors, and may differ from the locations currently identified.

110

Marketing and Major Customers

Memorial Resource markets the majority of its production from properties it operates for both our account and the account of the other working interest owners in our properties. Memorial Resource sells substantially all of our production to a variety of purchasers under contracts ranging from one month to several years, all at market prices. Memorial Resource normally sells production to a relatively small number of customers, as is customary in the exploration, development and production business. During the year ended December 31, 2013, Energy Transfer Equity, L.P. and subsidiaries accounted for all of our revenues. If Memorial Resource were to lose any one of our customers, the loss could temporarily delay production and sale of a portion of our oil and natural gas in the related producing region. If Memorial Resource was to lose any single customer, we believe Memorial Resource could identify a substitute customer to purchase the impacted production volumes.

Our Royalty Interests

Overriding royalty interests 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. Overriding royalty interests remain in effect until the associated leases expire. Our initial assets are comprised entirely of overriding royalty interests carved out of Memorial Resource’s current working 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. We do not currently own any mineral interests but may pursue the acquisition of such interests in the future.

The typical oil and natural gas lease agreement covering Memorial Resource’s properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on Memorial Resource’s properties generally range from 12.5% to 25%, resulting in a net revenue interest to Memorial Resource generally ranging from 87.5% to 75%. The overriding royalty interests comprising our initial assets are carved out of Memorial Resource’s net revenue interest.

Seasonality

Demand for oil and natural gas generally decreases during the spring and fall months and increases during the summer and winter months. However, seasonal anomalies such as mild winters or mild summers sometimes lessen this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations. These seasonal anomalies can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay Memorial Resource’s operations.

Competition

The oil and natural gas industry is intensely competitive, and we compete with other companies in our industry that have greater resources than we do. Many of these companies not only explore for and produce oil and natural gas, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive natural gas properties and exploratory locations or define, evaluate, bid for and purchase a greater number of properties and locations than our financial or human resources permit, and may be able to expend greater resources to attract and maintain industry personnel. In addition, these companies may have a greater ability to continue exploration activities during periods of low natural gas market prices. Our larger competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional royalty interests or mineral interests

111

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.

Hydraulic Fracturing

Memorial Resource uses hydraulic fracturing as a means to maximize the productivity of almost every well that it drills and completes. Hydraulic fracturing is a necessary part of the completion process because our properties are dependent upon our ability to effectively fracture the producing formations in order to produce at economic rates. Hydraulic fracturing involves using water, sand, and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow flow of hydrocarbons into the wellbore. All of our proved non-producing and proved undeveloped reserves associated with future drilling, recompletion, and refracture stimulation projects, or approximately 70% of our total estimated proved reserves as of September 30, 2014 require hydraulic fracturing.

Memorial Resource has and continues to follow applicable industry standard practices and legal requirements for groundwater protection, its operations are subject to supervision by state and federal regulators. Protective measures include setting surface casing at a depth sufficient to protect fresh water zones as determined by regulatory agencies, and cementing the well to create a permanent isolating barrier between the casing pipe and surrounding geological formations. For recompletions of existing wells, the production casing is pressure tested prior to perforating the new completion interval.

Injection rates and pressures are monitored instantaneously and in real time at the surface during our hydraulic fracturing operations. Pressure is monitored on both the injection string and the immediate annulus to the injection string.

Certain state regulations require disclosure of the components in the solutions used in hydraulic fracturing operations. Approximately 99% of the hydraulic fracturing fluids Memorial Resource uses are made up of water and sand. The remainder of the constituents in the fracturing fluid are managed and used in accordance with applicable requirements.

Hydraulic fracture stimulation requires the use of a significant volume of water. Upon flowback of the water, we dispose of it in a way that minimizes the impact to nearby surface water by disposing into approved disposal or injection wells. Memorial Resource currently does not discharge water to the surface.

For information regarding existing and proposed governmental regulations regarding hydraulic fracturing and related environmental matters, please read “—Regulation of Environmental and Occupational Health and Safety Matters—Hydraulic Fracturing.”

Regulation of the Oil and Natural Gas Industry

Our and Memorial Resource’s operations are substantially affected by federal, state and local laws and regulations. In particular, natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own producing oil and natural gas properties have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Memorial Resource’s operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of crude natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

112

Compliance with existing requirements is not expected to have a material adverse effect on our financial position, cash flows or results of operations. However, current regulatory requirements may change. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the natural gas industry are regularly considered by Congress, the states, FERC, and the courts. We cannot predict when or whether any such proposals may become effective.

Regulation of Production of Oil and Natural Gas

The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. All of the states in which we and Memorial Resource own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. We own interests in properties located onshore in different U.S. states. These states regulate drilling and operating activities by requiring, among other things, permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. The laws of these states also govern a number of environmental and conservation matters, including the handling and disposing or discharge of waste materials, the size of drilling and spacing units or proration units and the density of wells that may be drilled, unitization and pooling of oil and natural gas properties and establishment of maximum rates of production from oil and natural gas wells. Some states have the power to prorate production to the market demand for oil and natural gas. The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Regulation of Environmental and Occupational Health and Safety Matters

Memorial Resource’s operations are subject to numerous stringent federal, state and local statutes and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety. Numerous governmental agencies, such as the U.S. Environmental Protection Agency (“EPA”), issue regulations, which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for failure to comply. 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, production and transporting through pipelines, govern the sourcing and disposal of water used in the drilling, completion and production process, limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas, require some form of remedial action to prevent or mitigate 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 or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of production. The strict and joint and several liability nature of such laws and regulations could impose liability upon us regardless of fault. Public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. Changes in environmental laws and regulations occur frequently, and to the extent laws are enacted or other governmental

113

action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business and prospects could be materially adversely affected.

Hazardous Substance and Waste Handling

Memorial Resource’s operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, solid and hazardous wastes and petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste and may impose strict and, in some cases, joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. The Comprehensive Environmental Response, Compensation, and Liability Act, as amended, referred to as CERCLA or the Superfund law, and comparable state laws, impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons deemed “responsible parties.” These persons include current owners or operators of the site where a release of hazardous substances occurred, prior owners or operators that owned or operated the site at the time of the release or disposal of hazardous substances, and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these persons may be subject to strict and joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover the costs they incur from the responsible classes of persons. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Despite the “petroleum exclusion” of Section 101(14) of CERCLA, which currently encompasses natural gas, we may nonetheless handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment. In addition, we may have liability for releases of hazardous substances at our properties by prior owners or operators or other third parties.

The Oil Pollution Act of 1990 (the “OPA”) is the primary federal law imposing oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of certain onshore facilities near or crossing waterways must maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. Under the OPA, strict, joint and several liability may be imposed on “responsible parties” for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters and natural resource damages, resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” includes the owner or operator of an onshore facility. The OPA establishes a liability limit for onshore facilities of $350 million. These liability limits may not apply if: a spill is caused by a party’s gross negligence or willful misconduct; the spill resulted from violation of a federal safety, construction or operating regulation; or a party fails to report a spill or to cooperate fully in a clean-up. We are also subject to analogous state statutes that impose liabilities with respect to oil spills.

Exploration and production activities on our acreage also generate solid wastes, including hazardous wastes, which are subject to the requirements of the Resource Conservation and Recovery Act (“RCRA”), as amended, and comparable state statutes. Although RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. Certain petroleum production wastes are excluded from RCRA’s hazardous waste regulations. It is possible, however, that these wastes, which could include wastes currently generated during our operations, could be designated as “hazardous wastes” in the future and, therefore, be subject to more rigorous and costly disposal requirements. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and gas exploration and production wastes as “hazardous wastes.” Any such changes in the laws and regulations could have a material adverse effect on our maintenance capital expenditures and operating expenses.

114

Water and Other Waste Discharges and Spills

The Federal Water Pollution Control Act, as amended, also known as the Clean Water Act, the Safe Drinking Water Act (“SDWA”), the OPA and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other natural gas wastes, into federal and 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 discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. The underground injection of fluids is subject to permitting and other requirements under state laws and regulation. Obtaining permits has the potential to delay the development of oil and natural gas projects. These same regulatory programs also limit the total volume of water that can be discharged, hence limiting the rate of development, and require us to incur compliance costs. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages. Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and the underground injection of fluids and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of significant quantities of oil.

Hydraulic Fracturing

Memorial Resource, our current operator, regularly uses hydraulic fracturing extensively in its drilling and completion programs. Hydraulic fracturing is an essential and common practice in the oil and gas industry used to stimulate production of natural gas and/or oil from low permeability subsurface rock formations. Hydraulic fracturing involves using water, sand, and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow flow of hydrocarbons into the wellbore. While hydraulic fracturing has historically been regulated by state oil and natural gas commissions, federal agencies have asserted federal regulatory authority over the process. For example, the EPA is updating chloride water quality criteria for the protection of aquatic life under the Clean Water Act, which criteria are used by states for establishing acceptable discharge limits. The EPA is expected to release draft criteria in late 2014. In October 2011, the EPA announced its plan to propose federal pre-treatment standards for wastewater generated during the hydraulic fracturing process. Hydraulic fracturing stimulation requires the use of a significant volume of water with some resulting “flowback,” as well as “produced water.” If adopted, the new pretreatment rules will require shale gas operations to pretreat wastewater before transferring it to treatment facilities. Proposed rules are expected sometime in early 2015. In May 2014, the EPA issued an Advanced Notice of Proposed Rulemaking seeking public comment on its 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. The public comment period ended on September 18, 2014.

In August 2012, the EPA adopted rules that subject oil and natural gas production, processing, transmission, and storage operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants programs. The rules include NSPS standards for completions of hydraulically fractured gas wells and establishes specific new requirements for emissions from compressors, controllers, dehydrators, storage vessels, natural gas processing plants and certain other equipment. These standards, as well as any future laws and their implementing regulations, may require obtaining pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or utilize specific equipment or technologies to control emissions. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.

115

Additionally, Congress from time to time has considered the adoption of legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. Certain states have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure, and well construction requirements on hydraulic-fracturing operations or otherwise seek to ban fracturing activities altogether. For example, in October 2011, the Louisiana Department of Natural Resources adopted new rules requiring the public disclosure of the composition and volume of fracturing fluids used in hydraulic fracturing operations. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. In the event state, local, or municipal legal restrictions are adopted in areas where Memorial Resource is currently conducting, or in the future plans to conduct operations, it may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling of wells.

If these or any other new laws or regulations that significantly restrict hydraulic fracturing are adopted at the state and local level, such laws could make it more difficult or costly for Memorial Resource, as our operator, to perform fracturing to stimulate production from dense subsurface rock formations and, in the event of local prohibitions against commercial production of natural gas, may preclude the ability to drill wells. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA or other federal agencies, fracturing activities could become subject to additional permitting requirements and result in permitting delays as well as potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas ultimately able to be produced from our reserves.

Air Emissions

The federal Clean Air Act, as amended, and comparable state laws restrict the emission of air pollutants from many sources, including compressor stations, through the issuance of permits and the imposition of other requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain permits has the potential to delay the development of oil and natural gas projects. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in August 2012, the EPA published final rules under the Clean Air Act that subject oil and natural gas production, processing, transmission and storage operations to regulation under the NSPS and NESHAPS programs. With regards to production activities, these final rules require, among other things, the reduction of volatile organic compound emissions from three subcategories of fractured and refractured gas wells for which well completion operations are conducted: wildcat (exploratory) and delineation gas wells; low reservoir pressure non-wildcat and non-delineation gas wells; and all “other” fractured and refractured gas wells. All three subcategories of wells must route flow back emissions to a gathering line or be captured and combusted using a combustion device such as a flare after October 15, 2012. However, the “other” wells must use reduced emission completions, also known as “green completions,” with or without combustion devices, after January 1, 2015. These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, effective October 15, 2012, and from pneumatic controllers and storage vessels, effective October 15, 2013. The

116

EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. The EPA issued revised rules in 2013 responding to these requests. For example, on April 12, 2013, the EPA published a proposed amendment extending compliance dates for certain storage vessels, and on September 23, 2013, the EPA issued a press release announcing that it had finalized the proposed amendment.

Operations on our acreage may incur certain capital expenditures in the next few years for air pollution control equipment in connection with maintaining or obtaining operating permits addressing other air emission related issues, which may have a material adverse effect on our operations. Obtaining permits also has the potential to delay the development of oil and natural gas projects.

Regulation of “Greenhouse Gas” Emissions

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, establish Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit reviews for certain large stationary sources that are potential major sources of GHG emissions. On June 23, 2014, the Supreme Court held that stationary sources could not become subject to PSD or Title V permitting solely by reason of their GHG emissions. The Court ruled, however, that the EPA may require installation of best available control technology for GHG emissions at sources otherwise subject to the PSD or Title V programs. The EPA has announced that it is currently evaluating the decision and awaiting further action by the courts, and that it will provide relevant guidance on GHG permitting requirements.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. If Congress were to undertake comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for refined products. In any event, the Obama administration has announced its Climate Action Plan, which, among other things, directs federal agencies to develop a strategy for the reduction of methane emissions, including emissions from the oil and gas industry. As part of the Climate Action Plan, the Obama Administration also announced that it intends to adopt additional regulations to reduce emissions of GHGs and to encourage greater use of low carbon technologies in the coming years. For example, in September 2013, the EPA re-issued proposed NSPS for GHG emissions from Electric Utility Generating Units. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our exploration and production operations.

Restrictions on GHG emissions that may be imposed in various states could adversely affect the oil and natural gas industry. Any GHG regulation could increase our costs of compliance by potentially delaying the receipt of permits and other regulatory approvals; requiring us to monitor emissions, install additional equipment or modify facilities to reduce GHG and other emissions; purchase emission credits; and utilize electric driven compression at facilities to obtain regulatory permits and approvals in a timely manner. While we and Memorial Resource are subject to certain federal GHG monitoring and reporting requirements, our operations are not adversely impacted by existing federal, state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissions would impact our business.

117

Occupational Safety and Health Act

We and Memorial Resource are also subject to the requirements of the OSHA and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens.

National Environmental Policy Act

Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Departments of Interior and Agriculture, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency prepares an environmental assessment to evaluate the potential direct, indirect and cumulative impacts of a proposed project. If impacts are considered significant, the agency will prepare a more detailed environmental impact study that is made available for public review and comment. All of Memorial Resource’s current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This environmental impact assessment process has the potential to delay the development of oil and natural gas projects. Authorizations under NEPA also are subject to protest, appeal or litigation, which can delay or halt projects.

Endangered Species Act

The Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We conduct operations on federal oil and natural gas leases in areas where certain species that are listed as threatened or endangered and where other species, such as the sage grouse, potentially could be listed as threatened or endangered under the ESA exist. The U.S. Fish and Wildlife Service may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit land access for oil and natural gas development. If we were to have a portion of our leases designated as critical or suitable habitat, it could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas, which could adversely impact the value of our leases.

Summary

In summary, we have not experienced any material adverse effect from compliance with environmental requirements, but there is no assurance that this will continue. We did not have any material capital or other non-recurring expenditures in connection with complying with environmental laws or environmental remediation matters in 2012 or 2013.

Employees

We are managed and operated by the board of directors and executive officers of our general partner. However, neither we, our subsidiary nor our general partner have any employees. All of the employees that will conduct our business, including our executive officers, will be employed by Memorial Resource.

As of September 30, 2014, Memorial Resource had 460 full-time employees. Our future success will depend partially on Memorial Resource’s ability to attract, retain and motivate qualified personnel. Memorial Resource is not a party to any collective bargaining agreements and has not experienced any strikes or work stoppages. Memorial Resource considers its relations with its employees to be satisfactory. Please read “Management” and “Certain Relationships and Related Party Transactions.”

118

Our Offices

Our executive offices are located at 500 Dallas St., Suite 1800, Houston, Texas 77002, and the phone number at this address is (713) 588-8300.

Legal Proceedings

From time to time, we are subject to various legal proceedings arising in the ordinary course of business, including proceedings for which we have insurance coverage. As of the date hereof, neither we nor Memorial Resource are party to any material legal proceedings.

119

MANAGEMENT

Management of Terryville Mineral & Royalty Partners LP

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

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

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

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

Our partnership agreement requires us to reimburse our general partner and its affiliates, including Memorial Resource, for all expenses they incur and payments they make on our behalf in connection with operating our business. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us. Please read “Certain Relationships and Related Party Transactions—Agreements and Transactions with Affiliates in Connection with this Offering.”

120

Executive Officers and Directors of Our General Partner

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


Name	Age (as of September 30, 2014)	Position With Our General Partner
John A. Weinzierl	46	Chief Executive Officer and Chairman
Andrew J. Cozby	47	Vice President and Chief Financial Officer
Kyle N. Roane	35	Vice President, General Counsel and Corporate Secretary
Dennis G. Venghaus	33	Chief Accounting Officer

John A. Weinzierl has served as our general partner’s Chief Executive Officer and Chairman of the board of directors since its formation in October 2014, Chief Executive Officer and a director of Memorial Resource since its formation in January 2014, Chief Executive Officer of MRD LLC and the Chief Executive Officer and Chairman of MEMP GP since January 2014. Previously, Mr. Weinzierl served as President and Chief Executive Officer of MRD LLC and President, Chief Executive Officer and Chairman of MEMP GP since April 2011. Prior to the completion of MEMP’s initial public offering in December 2011, Mr. Weinzierl was a managing director and operating partner of NGP from December 2010. From July 1999 to December 2010, Mr. Weinzierl worked in various positions at NGP, where he became a managing director in December 2004. Mr. Weinzierl was appointed a venture partner of NGP from February 2012 to February 2013. From October 2006 until November 2011, Mr. Weinzierl was a director of Eagle Rock Energy G&P, LLC, the indirect general partner of Eagle Rock Energy Partners, L.P., a (i) natural gas gathering, processing and transportation company and (ii) developer of oil and natural gas properties, where he also served on the compensation committee. Mr. Weinzierl is a registered professional engineer in Texas.

The board believes Mr. Weinzierl’s degree and experience in petroleum engineering and his M.B.A. education, as well as his investment and business expertise honed at NGP, bring valuable strategic, managerial and analytical skills to the board and us.

Andrew J. Cozby has served as our general partner’s Vice President and Chief Financial Officer since its formation in October 2014, Senior Vice President and Chief Financial Officer of Memorial Resource since November 2014, Vice President and Chief Financial Officer of Memorial Resource from April 2014 to November 2014, Vice President and Chief Financial Officer of MEMP GP from February 2012 to July 2014 and the Vice President, Finance of MRD LLC from April 2011 to June 2014. From February 2011 to April 2011, Mr. Cozby served as Senior Vice President and Chief Financial Officer of Energy Maintenance Services (EMS Global). Prior to that, he was Chief Financial Officer of Greystone Oil & Gas LLP and Greystone Drilling LP from May 2006 to December 2010. From 2000 to May 2006, Mr. Cozby was Director of Finance for Enterprise Products Partners LP and held various corporate finance positions with its affiliates GulfTerra Energy Partners, LP and El Paso Energy Partners, LP. Prior to that, Mr. Cozby held positions with J.P. Morgan from 1998 to 2000.

Kyle N. Roane has served as our general partner’s Vice President, General Counsel and Corporate Secretary since its formation in October 2014, Senior Vice President, General Counsel and Corporate Secretary of Memorial Resource since November 2014, Vice President, General Counsel and Corporate Secretary of Memorial Resource from its formation in January 2014 to November 2014, Senior Vice President, General Counsel and Corporate Secretary of MEMP GP since November 2014, Vice President, General Counsel and Corporate Secretary of MEMP GP from January 2014 to November 2014 and Vice President, General Counsel and Corporate Secretary of MRD LLC since January 2014. Previously, Mr. Roane served as the General Counsel and Corporate Secretary of MRD LLC and MEMP GP since February 2012. From 2005 to February 2012, Mr. Roane practiced corporate and securities law at Akin Gump Strauss Hauer & Feld L.L.P.

121

Dennis G. Venghaus has served as our general partner’s Chief Accounting Officer since its formation in October 2014, Chief Accounting Officer of Memorial Resource since its formation in January 2014 and the Controller of MRD LLC and MEMP GP since January 2012. Prior to joining MRD LLC and MEMP GP, Mr. Venghaus was with Opportune LLP from June 2010 to January 2012 as a Manager in the Complex Financial Reporting group. From September 2004 through June 2010, he held various positions in the audit practice at PricewaterhouseCoopers LLP in Houston, TX, primarily serving energy clients. Mr. Venghaus is a Certified Public Accountant.

Director Independence

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

Committees of the Board of Directors

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

Audit Committee

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

Conflicts Committee

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

Indemnification Agreements

We and our general partner will enter into indemnification agreements with each of the current directors and executive officers of our general partner effective upon the closing of this offering. These agreements will

122

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

Executive Compensation

We are a new subsidiary of Memorial Resource, formed in October 2014 and will not own any assets or have operations until the closing of this offering. Accordingly, our general partner will not have accrued any obligations with respect to compensation for its executive officers for any periods prior to the closing of this offering. As a result, we have no historical compensation information to present.

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

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

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

123

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

Long-Term Incentive Plan

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

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

Administration

The LTIP will be administered by the board of directors of our general partner or an alternative committee appointed by the board of directors of our general partner, which we refer to together as the “committee” for purposes of this summary. The committee will administer the LTIP pursuant to its terms and all applicable state, federal, or other rules or laws. The committee will have the power to determine to whom and when awards will be granted, determine the amount of awards (measured in cash or in shares of our common units), proscribe and interpret the terms and provisions of each award agreement (the terms of which may vary), accelerate the vesting provisions associated with an award, delegate duties under the LTIP and execute all other responsibilities permitted or required under the LTIP. In the event that the committee is not comprised of “nonemployee directors” within the meaning of Rule 16b-3 under the Exchange Act, the full board of directors or a subcommittee of two or more nonemployee directors will administer all awards granted to individuals that are subject to Section 16 of the Exchange Act.

124

Securities to be Offered

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

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

Awards

Unit Options

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

Unit Appreciation Rights

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

Restricted Units

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

125

Unit Awards

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

Phantom Units

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

Distribution Equivalent Rights

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

Cash Awards

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

Performance Awards

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

Other Unit-Based Awards

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

Substitute Awards

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

126

Miscellaneous

Tax Withholding

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

Anti-Dilution Adjustments

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

Change in Control

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

Termination of Employment or Service

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

Director Compensation

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

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

Effective as of the closing of this offering, each non-employee director will receive a compensation package that will consist of an annual cash retainer of $ plus an additional annual payment of $ for the chairperson of the audit committee. In addition, our directors will be reimbursed for out-of-pocket expenses in

127

connection with attending meetings of the board of directors or its committees. Each non-employee director may receive grants of equity-based awards under the long-term incentive plan we intend to adopt prior to the completion of this offering from time to time for so long as he or she serves as a director.

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

128

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

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

•

our general partner;

•

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

•

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

•

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

Beneficial ownership is determined under the rules of the SEC and generally includes voting or investment power with respect to securities. Unless otherwise noted, the address for each beneficial owner listed below is 500 Dallas St., Suite 1800, Houston, Texas 77002.

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


Name of Beneficial Owner	Common Units Beneficially Owned	Percentage of Common Units Beneficially Owned
Memorial Resource(1)			%
John A. Weinzierl
Andrew J. Cozby
Kyle N. Roane
Dennis G. Venghaus
All directors and executive officers as a group (4 persons)

(1)

Memorial Resource is a publicly traded company. The directors of Memorial Resource are Tony R. Weber, John A. Weinzierl, Scott A. Gieselman, Kenneth A. Hersh, Robert A. Innamorati, Carol L. O’Neill and Pat Wood, III. The units owned by Memorial Resource, as reflected in the table, are common units. The table assumes the underwriters do not exercise their option to purchase additional common units and such units are therefore issued to Memorial Resource upon the option’s expiration. If such option is exercised in full, Memorial Resource will beneficially own common units, or % of total common units outstanding.

The following table sets forth, as of September 30, 2014, the number of shares of common stock of Memorial Resource beneficially owned by each of the directors, director nominees and executive officers of our general partner and all directors and executive officers of our general partner as a group.


Name of Beneficial Owner	Amount and Nature of Beneficial Ownership		Percentage of Class(1)
John A. Weinzierl		294,211		*
Andrew J. Cozby		103,368		*
Kyle N. Roane		99,474		*
Dennis G. Venghaus		44,474		*

All directors and executive officers as a group (4 persons)		541,527		*

*	Less than 1%

(1)	Based on 193,559,211 shares of Memorial Resource common stock outstanding as of September 30, 2014.

129

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

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

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

Distributions and Payments to Memorial Resource and Its Affiliates

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

Formation Stage

The consideration received by our general partner and Memorial Resource for the contribution of our initial assets

•

common unit;

•

subordinated units;

•

all of our incentive distribution rights; and

•

$ million of the net proceeds of this offering.

Operational Stage

Payments to our general partner and its affiliates

We will reimburse our general partner and its affiliates for all expenses incurred on our behalf.

Cash distributions to Memorial Resource and its affiliates

We will generally make cash distributions to our unitholders, including Memorial Resource as the holder of approximately % of our limited partner interests, pro rata. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner will be entitled to increasing percentages of the distributions, up to a maximum of 25% of the distributions above the highest target distribution level.

Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, Memorial Resource would receive an annual distribution of approximately $ million on its common units and subordinated units.

Withdrawal or removal of our general partner

If our general partner withdraws or is removed, its non-economic general partner interest will either be sold to the new general partner

130

for cash or converted into common units, in each case for an amount equal to the fair market value of the interest. Please read “The Partnership Agreement—Withdrawal or Removal of Our General Partner.”

Liquidation Stage

Liquidation

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

Agreements and Transactions with Affiliates in Connection with this Offering

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

Contribution and Conveyance Agreement

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

Registration Rights Agreement

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

Omnibus Agreement

Upon the closing of this offering, we and our general partner will enter into an omnibus agreement with Memorial Resource that will address the following matters:

•

our obligation to reimburse Memorial Resource for all expenses incurred by Memorial Resource (or payments made on our behalf) in conjunction with its provision of general and administrative services to us, including, but not limited to, our public company expenses and an allocated portion of the salary and benefits of the executive officers of our general partner and other employees of Memorial Resource who perform services for us or on our behalf; and

•

our obligation to reimburse Memorial Resource for insurance coverage expenses it incurs with respect to our business and operations and with respect to director and officer liability coverage for the officers and directors of our general partner.

The omnibus agreement provides that we must indemnify Memorial Resource for any liabilities incurred by Memorial Resource attributable to the operating and administrative services provided to us under the agreement, other than liabilities resulting from Memorial Resource’s bad faith or willful misconduct. In addition, Memorial Resource must indemnify us for any liability we incur as a result of Memorial Resource’s bad faith or willful misconduct in providing operating and administrative services under the omnibus agreement. Memorial Resource

131

may terminate the omnibus agreement in the event that it ceases to be our affiliate and may also terminate the omnibus agreement if we fail to pay amounts due under that agreement in accordance with its terms. The omnibus agreement may only be assigned by either party with the other party’s consent.

Other Transactions with Related Persons

WHR Management Company Management Services Agreement

Upon the closing of its initial public offering on June 18, 2014, Memorial Resource entered into a services agreement with WildHorse Resources and WildHorse Resources Management Company, LLC (“WHR Management Company”), pursuant to which WHR Management Company provides operating and administrative services to Memorial Resource for twelve months relating to the Terryville Complex, including our acreage. In exchange for such services, Memorial Resource pays a monthly management fee to WHR Management Company of approximately $1.0 million excluding third party COPAS income credits.

WHR Management Company may only terminate the services agreement by providing 90-days prior written notice to Memorial Resource after the six-month anniversary of the date of the agreement. Memorial Resource may terminate the services agreement at any time by providing written notice to WHR Management Company. The services agreement may only be assigned by either party with the other party’s consent. WHR Management Company is a subsidiary of WildHorse Resources II, LLC, an affiliate of Memorial Resource. NGP and certain former management members of WildHorse Resources own WildHorse Resources II, LLC.

PennTex North Louisiana, LLC Gas Processing Agreement

On March 17, 2014, WildHorse Resources entered into a gas processing agreement with PennTex North Louisiana, LLC (“PennTex”). PennTex is a joint venture among certain affiliates of NGP in which MRD Midstream LLC, a subsidiary of MRD Holdco, owns a minority interest. Once PennTex’s processing plant becomes operational, it will process natural gas produced from wells located on certain leases owned by WildHorse Resources in the state of Louisiana, which include the leases underlying our royalty interests. The agreement has a 15-year primary term, subject to one-year extensions at either party’s election. WildHorse Resources will pay PennTex a monthly fee, subject to an annual inflationary escalation, based on volumes of natural gas delivered and processed. Once the plant is declared operational, WildHorse Resources will be obligated to pay a minimum processing fee equal to approximately $18.3 million on an annual basis, subject to certain adjustments and conditions. The gas processing agreement requires that the processing plant be operational no later than November 1, 2015.

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

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

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

132

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

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

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

133

CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

Summary of Applicable Duties

The Delaware Act provides that, to the extent that, at law or in equity, a partner or other person has duties (including fiduciary duties) 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, the partner’s or other person’s duties may be expanded or restricted or eliminated by provisions in the partnership agreement, provided that the Delaware Act provides that the partnership agreement may not eliminate the implied contractual covenant of good faith and fair dealing. Our partnership agreement contains provisions that eliminate and replace the fiduciary standards to which our general partner and its executive officers and directors would otherwise be held by state fiduciary duty law. Our partnership agreement also specifically defines the remedies available to unitholders for actions taken that, without these defined liability standards, might constitute breaches of fiduciary duty under applicable Delaware law.

When our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith,” meaning it must act in a manner that it believes is not 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 its executive officers and directors will not be subject to any higher standard.

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

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

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

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including Memorial Resource, MEMP, the Funds, and NGP) on the one hand, and us and our limited partners, on the other hand.

Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or our limited partners, on the other hand, the resolution, course of action or transaction in respect of such conflict of interest shall be conclusively deemed approved by us and all our limited partners and shall not constitute a breach

134

of our partnership agreement, of any agreement contemplated thereby or of any duty, if the resolution, course of action or transaction in respect of such conflict of interest is:

•

approved by the conflicts committee of our general partner; or

•

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

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

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

Our partnership agreement provides that Memorial Resource, MEMP and the Funds and their respective affiliates (including NGP and its affiliates’ portfolio investments) are not restricted from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, Memorial Resource, MEMP and the Funds and their respective affiliates may acquire, develop or dispose of additional oil and natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets.

Because Memorial Resource controls our general partner and also is permitted to compete with us, Memorial Resource could choose to acquire properties and pursue opportunities that would have been suitable for our partnership. In such a case, Memorial Resource would have the benefit of any such opportunity instead of us.

NGP and its affiliates (including the Funds) are established participants in the oil and natural gas industry, and have resources greater than ours, which factors may make it more difficult for us to compete with them with respect to commercial activities as well as for potential acquisitions. As a result, competition from these affiliates could adversely impact our results of operations and cash available for distribution to our unitholders.

135

Neither our partnership agreement nor any other agreement requires Memorial Resource, MEMP, the Funds or NGP to pursue a business strategy that favors us. The directors and officers of Memorial Resource, MEMP, the Funds and their respective affiliates (including NGP) have a fiduciary duty to make decisions in the best interests of their respective equity holders, which may be contrary to our interests.

Because the officers and certain of the directors of our general partner are also officers and/or directors of Memorial Resource, MEMP, the Funds and their respective affiliates, such officers and directors have fiduciary duties to Memorial Resource, MEMP, the Funds and their respective affiliates that may cause them to pursue business strategies that disproportionately benefit Memorial Resource, MEMP, the Funds and their respective affiliates or which otherwise are not in our best interests.

Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, shall not apply to our general partner or any of its affiliates, including its officers, directors, Memorial Resource, MEMP, the Funds or any of their affiliates. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. Therefore, Memorial Resource, MEMP, the Funds and their affiliates may compete with us for investment opportunities.

Our general partner is allowed to take into account the interests of parties other than us, such as Memorial Resource, in resolving conflicts of interest.

Our partnership agreement contains provisions that replace the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its call right, its voting rights with respect to any units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation or amendment of the partnership agreement.

Many of the directors and all of the officers who have responsibility for our management have significant duties with, and will spend significant time serving, entities that compete with us in seeking acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities.

Most of our officers hold similar positions with Memorial Resource and MEMP GP, and many of our directors, who are responsible for managing the direction of our operations and acquisition activities, hold positions of responsibility with other entities (including NGP-affiliated entities) that are in the business of identifying and acquiring oil and natural gas properties. For example, the Funds and their affiliates (including NGP) are in the business of investing in oil and natural gas companies with independent management teams that also seek to acquire oil and natural gas properties, and Memorial Resource and MEMP are in the business of acquiring and developing oil and natural gas properties. Mr. Weinzierl, our Chief Executive Officer and the Chairman of the board of directors of our general partner, is the Chief Executive Officer and Chairman of MEMP GP, the Chief Executive Officer and a director of Memorial Resource, and was a managing director and operating partner of NGP and continues to hold ownership interests in the Funds and certain of their affiliates. Our officers will continue to devote significant time to the business of Memorial Resource and MEMP and face conflicts in allocating their time on our behalf and on behalf of Memorial Resource and MEMP GP. Our officers have also historically received a significant portion of their overall compensation in MEMP restricted unit awards under the long term incentive plan of MEMP GP and expect to receive a significant portion in Memorial Resource restricted stock awards under Memorial Resource’s long-term incentive plan. We cannot assure you

136

that any conflicts that may arise between us and our unitholders, on the one hand, and Memorial Resource, MEMP, or the Funds, on the other hand, will be resolved in our favor. The existing positions held by these directors and officers may give rise to fiduciary or other duties that are in conflict with the duties they owe to us. These officers and directors may become aware of business opportunities that may be appropriate for presentation to us as well as to the other entities with which they are or may become affiliated. Due to these existing and potential future affiliations, they may present potential business opportunities to other entities prior to presenting them to us, which could cause additional conflicts of interest. They may also decide that certain opportunities are more appropriate for other entities with which they are affiliated, and as a result, they may elect not to present those opportunities to us. These conflicts may not be resolved in our favor. For additional discussion of our management’s business affiliations and the potential conflicts of interest of which our unitholders should be aware, see “Certain Relationships and Related Party Transactions.”

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

Neither we nor our general partner have any employees and we will rely solely on Memorial Resource to operate our assets. Upon consummation of this offering, our general partner will enter into an omnibus agreement with Memorial Resource, pursuant to which, among other things, Memorial Resource will agree to perform management, administrative and operating services for us and our general partner.

Memorial Resource will provide substantially similar services with respect to its and MEMP’s own assets and operations. Because Memorial Resource will be providing services to us that are substantially similar to those provided to itself or MEMP, Memorial Resource may not have sufficient human, technical and other resources to provide those services at a level that Memorial Resource would be able to provide to us if it were solely focused on our business and operations. Memorial Resource may make internal decisions on how to allocate its available resources and expertise that may not always be in our best interest compared to Memorial Resource’s and MEMP’s interests. There is no requirement that Memorial Resource favor us over itself or MEMP in providing its services. If the employees of Memorial Resource and their affiliates do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our unitholders may be reduced.

Our partnership agreement restricts the remedies available to unitholders for actions that might otherwise constitute breaches of fiduciary duty.

In addition to the provisions described above, our partnership agreement contains provisions that restrict the remedies available to our limited partners for actions that might otherwise constitute breaches of fiduciary duty. For example, our partnership agreement provides that:

•

our general partner and its executive officers and directors will not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it acted in good faith, meaning it believed that the decision was not adverse to the interest of the partnership, and, with respect to criminal conduct, did not act with the knowledge that its conduct was unlawful;

•

our general partner and its officers and directors will not be liable for monetary damages or otherwise to us or our limited partners for any losses sustained or liabilities incurred as a result of the general partner’s, officer’s or director’s determinations, acts or omissions in their capacities as general partner, officers or directors, unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that such losses or liabilities were the result of the conduct of our general partner or such officer or director engaged in by it in bad faith or, with respect to any criminal conduct, with the knowledge that its conduct was unlawful; and

137

•

in resolving conflicts of interest, it will be presumed that in making its decision our general partner, the board of directors of our general partner or the conflicts committee of the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption and proving that such decision was not in good faith.

Unlike many other master limited partnerships, which require at least two independent members of the conflicts committee, our partnership agreement provides that a conflicts committee may be comprised of one or more directors. If we establish a conflicts committee with only one director, your interests may not be as well served as if we had a conflicts committee comprised of at least two independent directors. A single member conflicts committee would not have the benefit of discussion with and input from other independent directors.

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

Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval or with respect to which our general partner has sought conflicts committee approval, on such terms as it determines to be necessary or appropriate to conduct our business, including, but not limited to, the following:

•

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 into our securities, and the incurring of any other obligations;

•

the purchase, sale or other acquisition or disposition of our securities, or the issuance of additional options, rights, warrants and unit appreciation rights relating to our securities;

•

the mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets;

•

the negotiation, execution and performance of any contracts, conveyances or other instruments;

•

the distribution of our cash;

•

the selection and dismissal of employees and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;

•

the maintenance of insurance for our benefit and the benefit of our partners;

•

the formation of, or acquisition of an interest in, the contribution of property to, and the making of loans to, any limited or general partnerships, joint ventures, corporations, limited liability companies or other entities;

•

the control of any matters affecting our rights and obligations, 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;

•

the indemnification of any person against liabilities and contingencies to the extent permitted by law;

•

the making of tax, regulatory and other filings or rendering of periodic or other reports to governmental or other agencies having jurisdiction over our business or assets; and

•

the entering into of agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.

Our partnership agreement provides that our general partner must not act in “bad faith” when making decisions on our behalf, and our partnership agreement further provides that in order for a determination by our general partner to be made not in “bad faith,” our general partner must not believe that the determination is adverse to our interests. Please read “The Partnership Agreement—Limited Voting Rights” for information regarding matters that require unitholder approval.

138

Our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional partnership interests and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders.

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

•

the manner in which our business is operated;

•

the amount, nature and timing of asset purchases and sales;

•

the amount, nature and timing of our capital expenditures and the amount of our estimated maintenance capital expenditures;

•

the amount of borrowings;

•

the issuance of additional units; and

•

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

In addition, our general partner may use an amount, initially equal to $ million, which would not otherwise constitute available cash from operating surplus, in order to permit the payment of cash distributions on its units and incentive distribution rights. All of these actions may affect the amount of cash distributed to our unitholders and our general partner and may facilitate the conversion of subordinated units into common units. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to our unitholders, including borrowings that have the purpose or effect of enabling our general partner or its affiliates to receive distributions on any subordinated units held by them or the incentive distribution rights or enabling the expiration of the subordination period.

For example, if we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and subordinated units, our partnership agreement permits us to borrow funds, which would enable us to make this distribution on all outstanding units.

Our general partner determines which costs incurred by it are reimbursable by us.

We will reimburse our general partner and its affiliates for costs incurred in managing and operating our business, including costs incurred in rendering staff and support services to us. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us.

Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.

Our partnership agreement allows our general partner to determine any amounts to pay itself or its affiliates for any services rendered to us. Our general partner may also enter into additional contractual arrangements with Memorial Resource, the Funds or their respective affiliates on our behalf. Similarly, agreements, contracts or arrangements between us and our general partner, Memorial Resource, the Funds or their respective affiliates will not be required to be negotiated on an arms-length basis, although, in some circumstances, our general partner may determine that the conflicts committee of our general partner may make a determination on our behalf with respect to one or more of these types of situations.

Our general partner will determine the terms of any of these transactions entered into after the sale of the common units offered in this offering.

139

Our general partner and its affiliates will have no obligation to permit us to use any facilities or assets of our general partner or its affiliates, except as may be provided in contracts entered into specifically dealing with that use. There is no obligation of our general partner or its affiliates to enter into any contracts of this kind.

Our general partner may exercise its right to call and purchase common units if it and its affiliates own more than 80% of the common units.

Our general partner may exercise its right to call and purchase common units as provided in the partnership agreement or assign this right to one of its affiliates or to us. As a result, a common unitholder may have his common units purchased from him at an undesirable time or price. Please read “The Partnership Agreement—Limited Call Right.”

Common unitholders will have no right to enforce obligations of our general partner and its affiliates under agreements with us.

Any agreements between us, on the one hand, and our general partner, Memorial Resource, the Funds and their respective affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner, Memorial Resource, the Funds and their respective affiliates in our favor.

Our general partner and Memorial Resource may be able to amend our partnership agreement without the approval of any other unitholder after the subordination period.

Our general partner has the discretion to propose amendments to our partnership agreement, certain of which may be made by our general partner without unitholder approval. Our partnership agreement generally may not be otherwise amended during the subordination period without the approval of a majority of our public common unitholders. However, after the subordination period has ended, our partnership agreement can be amended with the consent of our general partner and the approval of the holders of a majority of our outstanding common units (including common units held by Memorial Resource and its affiliates). Upon the consummation of this offering, Memorial Resource will own our general partner and will control the voting of an aggregate of approximately % of our outstanding common units and all of our subordinated units. Assuming that Memorial Resource retains a sufficient number of its common units and that we do not issue additional common units, our general partner and Memorial Resource will have the ability to amend our partnership agreement without the approval of any other unitholder after the subordination period. Please read “The Partnership Agreement—Amendment of the Partnership Agreement.”

Contracts between us, on the one hand, and our general partner and its affiliates, on the other, will not be the result of arm’s-length negotiations.

Our partnership agreement allows our general partner to determine any amounts to pay itself, Memorial Resource, the Funds and their respective affiliates for any services rendered to us. Our general partner may also enter into additional contractual arrangements with Memorial Resource, the Funds and their respective affiliates on our behalf. Neither the partnership agreement nor any of the other agreements, contracts and arrangements between us, on the one hand, and our general partner, Memorial Resource, the Funds and their respective affiliates, on the other, are or will be the result of arm’s-length negotiations.

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

The attorneys, independent accountants and others who have performed services for us regarding this offering have been retained by our general partner. The attorneys, independent accountants and others who perform services for us are selected by our general partner, or the conflicts committee of our general partner’s

140

board of directors, and may also perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.

Our general partner has the right (but not the obligation), at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (25%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election. Following any reset election by our general partner, the minimum quarterly distribution will be reset to an amount equal to the cash distribution per common unit for the fiscal quarter immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

We anticipate that our general partner would exercise this reset right (if at all) to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when our general partner expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, our general partner may be experiencing, or may expect to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued our common units, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for the general partner to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then current business environment. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued new common units to our general partner in connection with resetting the target distribution levels related to our general partner’s incentive distribution rights. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—General Partner’s Right to Reset Incentive Distribution Levels.”

Fiduciary Duties

Our general partner is accountable to us and our unitholders as a fiduciary. Fiduciary duties owed to unitholders by our general partner are prescribed by law and the partnership agreement. The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements expand, restrict or eliminate the fiduciary duties otherwise owed by a general partner to limited partners and the partnership.

Our partnership agreement contains various provisions that eliminate and replace the fiduciary duties that might otherwise be owed by our general partner and its directors and executive officers with contractual standards governing the duties of our general partner and contracted methods of resolving conflicts of interest. We have adopted these provisions to allow our general partner or its affiliates to engage in transactions with us that otherwise might be prohibited by state law fiduciary standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because the board of directors of our general partner has a duty to manage our partnership in good faith and a duty to manage our general partner in a manner beneficial to its owner. Without these modifications, our general partner’s ability to make decisions involving conflicts of interest would be restricted. Replacing the fiduciary duty standards in this manner benefits our general partner by enabling it to take into consideration all

141

parties involved in the proposed action. Replacing the fiduciary duty standards also strengthens the ability of our general partner to attract and retain experienced and capable directors. Replacing the fiduciary duty standards represents a detriment to our public unitholders because it restricts the remedies available to our public unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permits our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interests.

The following is a summary of the fiduciary duties imposed on general partners of a limited partnership by the Delaware Act in the absence of partnership agreement provisions to the contrary, the contractual duties of our general partner contained in our partnership agreement that replace the fiduciary duties that would otherwise be imposed by Delaware laws on our general partner and the rights and remedies of our unitholders with respect to these contractual duties:

State-law fiduciary duty standards

Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and 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 for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally require that any action taken or transaction engaged in be entirely fair to the partnership.

Rights and remedies of unitholders

The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third-party 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. 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

Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues as to compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith,” meaning that it believes its actions or omissions were not adverse to the interest of the partnership, and will not be subject to any other standard under applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These contractual standards replace the obligations to which our general partner would otherwise be held under applicable Delaware law.

If our general partner does not obtain approval from the conflicts committee of the board of directors of our general partner or our common unitholders, excluding any such units owned by our general

142

partner or its affiliates, and the board of directors of our general partner approves the resolution or course of action taken with respect to the conflict of interest, then it will be presumed that, in making its decision, its 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 such proceeding will have the burden of overcoming such presumption and proving that such decision was not in good faith. These standards replace the obligations to which our general partner would otherwise be held.

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 our partnership agreement unenforceable against that person.

Under our partnership agreement, we must indemnify our general partner and its officers, directors, managers and certain other specified persons, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud or willful misconduct. We must also provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent these provisions purport to include indemnification for liabilities arising under the Securities Act, in the opinion of the SEC, such indemnification is contrary to public policy and, therefore, unenforceable. Please read “The Partnership Agreement—Indemnification.”

143

DESCRIPTION OF OUR COMMON UNITS

Our Common Units

The common units and subordinated units represent separate classes of limited partner interests in us. Unitholders are entitled to participate in partnership distributions and exercise the rights and privileges provided to limited partners under our partnership agreement. For a description of the relative rights and privileges of unitholders to partnership distributions, please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.” For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please read “The Partnership Agreement.”

Transfer Agent and Registrar

Wells Fargo Shareowner Services 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 such 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, waivers and approvals 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.

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.

144

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 NASDAQ Global Select Market under the symbol “TRVL.”

145

THE PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement as to be amended and restated prior to the closing of this offering is included in this prospectus as Appendix A. We will provide 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 distributions of available cash, please read “Cash Distribution Policy and Restrictions on Distributions” and “Provisions of Our Partnership Agreement Relating to Cash Distributions”;

•

with regard to the duties of, and standards of care applicable to our general partner and its executive officers and directors, please read “Conflicts of Interest and 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, taxable loss and other matters, please read “Material U.S. Federal Income Tax Consequences.”

Organization and Duration

Our partnership was organized in October 2014 and will have a perpetual existence unless terminated pursuant to the terms of our partnership agreement.

Purpose

Our purpose under 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. However, our general partner may not cause us to engage in any business activity that it determines would cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than the ownership and acquisition of natural gas, NGL and oil properties and the ownership and acquisition of related assets, our general partner has no current plans to do so and may decline to do so free of any duty or obligation whatsoever to us or our limited partners, including any duty to act in the best interests of us or our limited partners. 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.

Cash Distributions

Our partnership agreement specifies the manner in which we will make cash distributions to holders of our common units and other partnership securities as well as our general partner in respect of its incentive distribution rights. For a description of these cash distribution provisions, please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

Capital Contributions

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

146

Limited Voting Rights

The following is a summary of the unitholder vote required for each of the matters specified below.

Various matters require the approval of a “unit majority,” which means:

•

during the subordination period, the approval of a majority of the outstanding common units, excluding those common units whose vote is controlled by our general partner and its affiliates, and a majority of the outstanding subordinated units, each voting as a separate class; and

•

after the subordination period, the approval of a majority of the outstanding common units.

By virtue of the exclusion of those common units held by our general partner and its affiliates from the required vote, and by their ownership of all of the subordinated units, during the subordination period, our general partner and its affiliates do not have the ability to ensure passage of, but do have the ability to ensure defeat of, any amendment that requires a unit majority.

In voting their common units and subordinated units, our general partner and its affiliates 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 incentive distribution rights may be entitled to vote in certain circumstances.

Issuance of additional units

No approval right. Please read “—Issuance of Additional Securities.”

Amendment of the partnership agreement

Certain amendments may be made by our general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. 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 “—Termination and Dissolution.”

Continuation of our business upon dissolution

Unit majority. Please read “—Termination and Dissolution.”

Withdrawal of our general partner

Prior to December 31, 2024, under most circumstances, the approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of our general partner in a manner that would cause a dissolution of our partnership. Please read “—Withdrawal or Removal of Our General Partner.”

Removal of our general partner

Not less than 66²/₃% of the outstanding units, including units held by our general partner and its affiliates. In addition, any vote to remove our general partner during the subordination period must provide for the election of a successor general partner by the holders of a majority of the common units and a majority of the subordinated units, voting as separate classes. Please read “—Withdrawal or Removal of Our General Partner.”

147

Transfer of our general partner interest

No approval right. Please read “—Transfer of General Partner Interest.”

Transfer of incentive distribution rights

No approval rights. Please read “—Transfer of Subordinated Units and Incentive Distribution Rights.”

Transfer of ownership interests in our general partner

No approval required. Please read “—Transfer of Ownership Interests in Our General Partner.”

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 fiduciary 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 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. 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.

Reimbursement of Partnership Litigation Costs

Our partnership agreement provides that if a limited partner or any person holding a beneficial interest in us files a claim, suit, action or proceeding against us and does not obtain a judgment on the merits that substantially achieves, in substance and amount, the full remedy sought in any such claim, suit, action or proceeding, then such partner or person will be obligated to reimburse us and our affiliates for all fees, costs and expenses of every kind and description, including but not limited to all reasonable attorneys’ fees and other litigation expenses, that the parties may incur in connection with such claim, suit, action or proceeding. By purchasing a common unit, a limited partner is irrevocably consenting to these reimbursement obligations as set forth in the partnership agreement.

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 our partnership agreement, his

148

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. If it were determined, however, that the right or exercise of the right, by our limited partners as a group:

•

to remove or replace our general partner;

•

to approve some amendments to the partnership agreement; or

•

to take other action under the partnership agreement

constituted “participation in the control” of our business for the purposes of the Delaware Act, then our limited partners could be held personally liable for our obligations under Delaware law, to the same extent as our general partner. This liability would extend to persons who transact business with us and reasonably believe 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.

Under the Delaware Act, 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. Moreover, under the Delaware Act, a limited partnership may also not make a distribution to a partner upon the winding up of the limited partnership before liabilities of the limited partnership to creditors have been satisfied by payment or the making of reasonable provision for payment thereof. 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. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from the partnership agreement.

We currently conduct business in Louisiana, and we may have operating subsidiaries that conduct business in other states in the future. Maintenance of our limited liability as a member of each of our operating subsidiaries may require compliance with legal requirements in the jurisdictions in which our operating subsidiaries conduct business, including qualifying our operating subsidiaries to do business there.

Limitations on the liability of limited partners for the obligations of a limited partner 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 state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by our 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 our 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 our limited partners.

Issuance of Additional Securities

Our partnership agreement authorizes us to issue an unlimited number of additional partnership securities for the consideration and on the terms and conditions determined by our general partner without the approval of our unitholders.

149

It is possible that we will fund acquisitions through the issuance of additional common units or other partnership securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional common units or other partnership securities may dilute the value of the interests of the then-existing holders of common units in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership securities that, as determined by our general partner, may have special limited voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity securities, which may effectively rank senior to our common units.

Our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units or other partnership securities whenever, and on the same terms that, we issue those securities to persons other than our general partner and its affiliates, to the extent necessary to maintain the aggregate percentage interest in us of our general partner and its affiliates, including such interest represented by common units, that existed immediately prior to each issuance. The holders of common units will not have preemptive rights to acquire additional common units or other partnership securities.

Amendment of the Partnership Agreement

General

Amendments to our partnership agreement may be proposed only by or with the consent of our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any duty or obligation whatsoever to us or our limited partners, including any duty to act in the best interests of us or our limited partners. To adopt a proposed amendment, other than the amendments discussed below under “—No Unitholder Approval,” our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or call a meeting of our limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

Prohibited Amendments

No amendment may be made that would:

•

enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or

•

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.

The provision of our partnership agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding units voting together as a single class (including units owned by our general partner and its affiliates). Upon completion of this offering, Memorial Resource will own approximately % of our outstanding common units and all of our subordinated units, representing an aggregate % limited partner interest in us.

No Unitholder Approval

Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner or assignee to reflect:

•

a change in our name, the location of our principal place of business, our registered agent or our registered office;

150

•

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 for us to qualify or to 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;

•

a change in our fiscal year or taxable year and related changes;

•

an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or the directors, officers, agents or trustees of our general partner from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed;

•

an amendment that our general partner determines to be necessary or appropriate for the creation, authorization or issuance of additional partnership securities or rights to acquire partnership securities;

•

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 or appropriate for the formation by us of, or our investment in, any corporation, partnership or other entity, as otherwise permitted by our partnership agreement;

•

any amendment necessary to require our limited partners to provide a statement, certification or other evidence to us regarding whether such limited partner is subject to United States federal income taxation on the income generated by us and to provide for the ability of our general partner to redeem the units of any limited partner who fails to provide such statement, certification or other evidence;

•

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 if our general partner determines that those amendments:

•

do not adversely affect our limited partners (or any particular class of limited partners) 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 or appropriate to facilitate the trading of our limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which our limited partner interests are or will be listed for trading;

•

are necessary or appropriate 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 the partnership agreement or are otherwise contemplated by our partnership agreement.

151

Opinion of Counsel and Unitholder Approval

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 not result in a loss of limited liability to our limited partners or result in our being treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes. No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units 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.

In addition to the above restrictions, any 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 amendment that reduces 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 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.

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 our limited partners, including any duty to act in the best interest of us or our limited partners.

In addition, the partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us to, among other things, 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, or sale, exchange or other disposition of our subsidiaries. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without that approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without the approval of a unit majority. Finally, our general partner may consummate any merger, consolidation or conversion 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 will not result in a material amendment to our 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 securities to be issued do not exceed 20% of our outstanding partnership securities 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 some or 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, our general partner has received an opinion of counsel regarding limited liability and tax matters, and the governing instruments of the new entity provide our limited partners and our general partner with the same rights and obligations as contained in our partnership agreement. The 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.

152

Termination and Dissolution

We will continue as a limited partnership until terminated under our partnership agreement. We will dissolve upon:

•

the election of our general partner to dissolve us, if approved by the holders of 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 us in accordance with our partnership agreement or withdrawal or removal following 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 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

•

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 we are continued as a new limited partnership, 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 described in “Provisions of Our Partnership Agreement Relating to Cash Distributions—Distributions of Cash Upon Liquidation.” 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.

Withdrawal or Removal of Our General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to December 31, 2024 without obtaining the approval of the holders of at least a majority of our outstanding common units, excluding common units held by our general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after December 31, 2024, our general partner may withdraw as our general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw as our general partner without unitholder approval upon 90 days’ notice to our limited partners if at least 50% of the outstanding common units are held or controlled by one person and its affiliates other than our general partner and its affiliates. In addition, our partnership agreement permits our general partner in some instances to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders.

Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a majority of our outstanding units may select a successor to the withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up

153

and liquidated, unless within a specified period of time after that withdrawal, the holders of a majority of our outstanding common units, excluding the common units held by the withdrawing general partner and its affiliates, agree in writing to continue our business and to appoint a successor general partner. Please read “—Termination and Dissolution.”

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66²/₃% of our outstanding units, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of our outstanding common units, voting as a class, and the outstanding subordinated units, voting as a class. The ownership of more than 33¹/₃% of our outstanding units by our general partner and its affiliates would give them the practical ability to prevent our general partner’s removal. At the closing of this offering, Memorial Resource will own approximately % of our outstanding common units and 100% of our subordinated units representing an aggregate % limited partner interest in us.

Our partnership agreement also provides that if our general partner is removed as our general partner without cause and no units held by our general partner and its affiliates are voted in favor of that removal:

•

the subordination period will end and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;

•

any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

•

our general partner will have the right to convert its incentive distribution rights into common units or to receive cash in exchange for its incentive distribution rights based on the fair market value of the incentive distribution rights at the time.

In the event of removal of our general partner under circumstances where cause exists or withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the departing general partner’s general partner interest and incentive distribution rights for a cash payment equal to the fair market value of that interest. Under all other circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the departing general partner’s general partner interest and incentive distribution rights for its fair market value.

In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. If the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partner interest and incentive distribution rights will automatically convert into common units equal to the fair market value of that interest as determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an investment banking firm or other independent expert selected in the manner described in the preceding paragraph will determine the fair market value.

In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.

154

Transfer of General Partner Interest

At any time, our general partner may transfer all or any of its general partner interest to another person without the approval of our common unitholders. As a condition of this transfer, the transferee must, among other things, assume the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement and furnish an opinion of counsel regarding limited liability and tax matters.

Transfer of Subordinated Units and Incentive Distribution Rights

At any time, our general partner may sell or transfer its subordinated units or incentive distribution rights to an affiliate or third party without the approval of the unitholders. By transfer of subordinated units or incentive distribution rights in accordance with our partnership agreement, each transferee of subordinated units or incentive distribution rights will be admitted as a limited partner with respect to the subordinated units or incentive distribution rights transferred when such transfer and admission is 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 becomes bound by the terms and conditions of our partnership agreement; and

•

gives the consents, waivers and approvals contained in our partnership agreement, such as the approval of all transactions and agreements we are entering into in connection with our formation and this offering.

Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.

We may, at our discretion, treat the nominee holder of subordinated units or incentive distribution rights 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.

Subordinated units and incentive distribution rights are securities and any transfers are subject 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 for the transferred subordinated units or incentive distribution rights.

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

Transfer of Ownership Interests in Our General Partner

At any time, the owner of our general partner may sell or transfer all or part of its membership interest in our general partner to an affiliate or a third party without the approval of our unitholders.

Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove our general partner or otherwise change the management of our general partner. If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses limited voting rights on all of its units. This loss of limited voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the prior approval of the board of directors of our general partner.

155

Limited Call Right

If at any time our general partner and its affiliates own more than 80% of our then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the limited partner interests of the class held by unaffiliated persons as of a record date to be selected by our general partner, on at least 10 but not more than 60 days’ notice. The purchase price in the event of this purchase is the greater of:

•

the highest price paid by our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and

•

the average of the daily closing prices of the partnership securities of such class over the 20 trading days preceding the date that is three days before the date the notice is mailed.

As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at an undesirable time or at a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Units.”

Meetings; Voting

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, record holders of units 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.

Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting, if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting where all limited partners were present and voted. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. 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 has been called, represented in person or by proxy, will constitute a quorum 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. Our general partner may postpone any meeting of unitholders one or more times for any reason by giving notice to the unitholders entitled to vote at such meeting. Our general partner may also adjourn any meeting of unitholders one or more times for any reason, including the absence of a quorum, without a vote of the unitholders.

Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special limited voting rights could be issued. Please read “—Issuance of Additional Securities.” However, if at any time any person or group, other than our general partner and its affiliates or a direct or subsequently approved transferee of our general partner or its affiliates and purchasers specifically approved by our general partner, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose limited 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, calculating required votes, determining the presence of a quorum or for other similar purposes. Common 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. Except as our partnership agreement otherwise provides, subordinated units will vote together with common units, as a single class.

156

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

Voting Rights of Incentive Distribution Rights

If a majority of the incentive distribution rights are held by our general partner and its affiliates, the holders of the incentive distribution rights will have no right to vote in respect of such rights on any matter, unless otherwise required by law, and the holders of the incentive distribution rights shall be deemed to have approved any matter approved by our general partner.

If less than a majority of the incentive distribution rights are held by our general partner and its affiliates, the incentive distribution rights will be entitled to vote on all matters submitted to a vote of unitholders, other than amendments and other matters that our general partner determines do not adversely affect the holders of the incentive distribution rights in any material respect. On any matter in which the holders of incentive distribution rights are entitled to vote, such holders will vote together with the subordinated units, prior to the end of the subordination period, or together with the common units, thereafter, in either case as a single class, and such incentive distribution rights shall be treated in all respects as subordinated units or common units, as applicable, when sending notices of a meeting of our 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 our partnership agreement. The relative voting power of the holders of the incentive distribution rights and the subordinated units or common units, depending on which class the holders of incentive distribution rights are voting with, will be set in the same proportion as cumulative cash distributions, if any, in respect of the incentive distribution rights for the four consecutive quarters prior to the record date for the vote bears to the cumulative cash distributions in respect of such class of units for such four quarters.

Status as Limited Partner

By transfer of any 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 is reflected in our books and records. Except as described above under “—Limited Liability,” the common units will be fully paid, and unitholders will not be required to make additional contributions.

Non-Taxpaying Assignees; Redemption

If our general partner, with the advice of counsel, determines that our not being treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes, coupled with the tax status (or lack of proof thereof) of one or more of our limited partners, has, or is reasonably likely to have, a material adverse effect on our ability to operate our assets or generate revenues from our assets, then our general partner may adopt such amendments to our partnership agreement as it determines necessary or advisable to:

•

obtain proof of the U.S. federal income tax status of limited partners (and their owners, to the extent relevant); and

•

permit us to redeem the units at their current market price held by any person whose tax status has or is reasonably likely to have a material adverse effect on our ability to operate our assets or generate revenues from our assets or who fails to comply with the procedures instituted by our general partner to obtain proof of the U.S. federal income tax status.

A non-taxpaying assignee does not have the right to direct the voting of his units and may not receive distributions in-kind upon our liquidation.

157

Non-Eligible Holders; Redemption

To comply with certain U.S. laws relating to the ownership of interests in oil and gas leases on federal lands, common unit transferees may be required to fill out a properly completed transfer application certifying, and our general partner, acting on our behalf, may at any time require each common unitholder to re-certify that the common unitholder is an Eligible Holder. As used herein, an Eligible Holder means a person or entity qualified to hold an interest in oil and gas leases on federal lands. As of the date hereof, Eligible Holder means: (1) a citizen of the United States; (2) a corporation organized under the laws of the United States or of any state thereof; or (3) an association of United States citizens, such as a partnership or limited liability company, organized under the laws of the United States or of any state thereof, but only if such association does not have any direct or indirect foreign ownership, other than foreign ownership of stock in a parent corporation organized under the laws of the United States or of any state thereof. For the avoidance of doubt, onshore mineral leases, or any direct or indirect interest therein may be acquired and held by aliens only through stock ownership, holding, or control in a corporation organized under the laws of the United States or of any state thereof and only for so long as the alien is not from a country that the United States federal government regards as denying similar privileges to citizens or corporations of the United States. This certification can be changed in any manner our general partner determines is necessary or appropriate to implement its original purpose.

If a common unit transferee or common unitholder, as the case may be:

•

fails to furnish a transfer application containing the required certification;

•

fails to furnish a re-certification containing the required certification within 30 days after request; or

•

provides a false certification;

then, as the case may be, such transfer will, to the fullest extent permitted by law, be void or we will have the right to redeem the units held by the common unitholder. Further, the common units held by the common unitholder may not be entitled to any allocations of income or loss, distributions, or voting rights.

The purchase price will be paid in cash or delivery of a promissory note, as determined by our general partner. Any such promissory note will bear interest at the rate of 8% annually and be payable in three equal annual installments of principal and accrued interest, commencing one year after the redemption date.

Indemnification

Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:

•

our general partner;

•

any departing general partner;

•

any person who is or was an affiliate of a general partner or any departing general partner;

•

any person who is or was a director, officer, member, partner, fiduciary or trustee of any entity set forth in the preceding three bullet points;

•

any person who is or was serving as a director, officer, member, partner, fiduciary or trustee of another person at the request of 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 it otherwise agrees, our general partner 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 covering 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.

158

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. These expenses include salary, bonus, incentive compensation, and other amounts paid to persons who perform services for us or on our behalf, and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine the expenses that are allocable to us.

Immediately prior to the closing of this offering, our general partner will enter into an omnibus agreement pursuant to which, among other things, Memorial Resource will agree to provide the administrative, management, and acquisition advisory services that we believe are necessary to allow our general partner to manage, operate and grow our business, as well as the operating services that we believe are necessary to develop and operate our properties.

Books and Reports

Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For financial reporting and tax purposes, our fiscal year end is December 31.

We will furnish or make available to record holders of common units, within 90 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent registered public accounting firm. Except for our fourth quarter, we will also furnish or make available summary financial information within 60 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 which we maintain.

We will furnish each record holder of a unit with information reasonably required for 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 the cooperation of our unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies us with information.

Right to Inspect Our Books and Records

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at his own expense, obtain:

•

a current list of the name and last known address of each partner;

•

a copy of our tax returns;

•

information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each partner became a partner;

•

copies of our partnership agreement, our certificate of limited partnership, related amendments and powers of attorney under which they have been executed;

•

information regarding the status of our business and financial condition; and

•

any other information regarding our affairs as is just and reasonable.

159

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 believes is not in our best interests or that we are required by law or by agreements with third parties to keep confidential.

Registration Rights

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units or other partnership securities proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. In addition, our general partner and its affiliates have the right to include such securities in a registration by us or any other unitholder, subject to customary exceptions. These registration rights continue for two years following any withdrawal or removal of our general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts. In connection with any registration of this kind, we will indemnify the unitholders participating in the registration and their officers, directors and controlling persons from and against specified liabilities, including under the Securities Act or any applicable state securities laws. Please read “Units Eligible for Future Sale.”

160

UNITS ELIGIBLE FOR FUTURE SALE

Upon the completion of this offering, Memorial Resource will hold common units. The sale of these common units could have an adverse impact on the price of the common units or on any trading market that may develop.

Our common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act, except that units purchased through the directed unit program will be subject to the lock-up restrictions described below and 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. 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 Securities.”

Under our partnership agreement and the registration rights agreement that we expect to enter into, our general partner and its affiliates will have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any units that they hold. Subject to the terms and conditions of the partnership agreement and the registration rights agreement, these registration rights allow our general partner and its affiliates or their assignees holding any units to require registration of any of these units and to include any of these units in a registration by us of other units, including units offered by us or by any unitholder. Our general partner and its affiliates will continue to have these registration rights for two years following its withdrawal or removal as our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors, and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discount. Except as described below, our general partner and its affiliates may sell their units in private transactions at any time, subject to compliance with applicable laws.

161

from issuing and selling any additional common units in a subsequent private or public offering during the lock-up period without the consent of Barclays Capital Inc. Please read “Underwriting—Lock-Up Agreements” 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.

162

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 Terryville Mineral & Royalty Partners LP 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 our cash available for distribution. 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 such income directly, even if we make no cash distributions to the unitholder.

163

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 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 crude 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 3% 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 partnership and limited liability company subsidiary will be disregarded as separate from us 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 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 the cash available for distribution 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.

164

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 such 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 owns those units from the date of closing of this offering through the record date for distributions for the period ending December 31, 2017, 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. 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 flow, 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 such 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 amortization for federal income tax purposes during such 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;

165

•

legislation is enacted that limits or repeals certain U.S. federal income tax preferences currently available to oil and 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

166

not 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. 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 such 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.

167

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 the facts and circumstances, including (i) the partner’s relative contributions to us, (ii) the interests of all the partners in profits and losses, (iii) the interest of all the partners in cash flow and (iv) the rights of all 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 “short seller” to cover a short sale of units) may be treated as having disposed of those units. If so, such 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.

168

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 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 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.

169

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 producer is a person not directly or indirectly involved in the retail sale of oil, 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 crude oil, or the gas equivalent, does not exceed 1,000 barrels. This depletable amount may be allocated between oil and gas production, with 6,000 cubic feet of domestic gas production regarded as equivalent to one barrel of crude 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 such 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 such 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 thousand cubic feet, or Mcf, of 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 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

170

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 such administrative expenses will not be significant in relation to the partnership’s income.

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, but are not limited to, (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 and commissions 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

171

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 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 such 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

172

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.

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 such 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 such 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.

173

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.”

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 such 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 will 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 IPO, we will only have income from our royalty interests and thus should not have any effectively connected income. We may have effectively connected income in the future if we engage in an active trade or business. Furthermore, is it probable that we will be deemed to conduct such 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 their share of our income, gain, loss or deduction and pay federal income tax on their 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 IPO income from our royalty interests will not 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. Accordingly, non-U.S. holders may be entitled to a refund of all or a portion of this amount and may seek to obtain such refund by filing a U.S. income tax return. Alternatively, a non-U.S. holder may obtain credit for these withholding taxes against any U.S. federal income tax liability if the non-U.S. unitholder obtains a taxpayer identification number from the IRS and submits that number to our transfer agent on a Form W-8BEN, W-8BEN-E or applicable substitute form.

174

In addition, because a non-U.S. unitholder classified as a corporation may be treated as engaged in a United States 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.

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 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 such unitholder held the units or the 5-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

175

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 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.

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

(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 Sections 1471 through 1474 of the Code (“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 or other disposition of any property of a type which can produce interest or dividends from sources within the United States (“Gross Proceeds”) (if such sale or other disposition occurs after December 31, 2016) paid to a “foreign financial institution” or a “non-financial foreign entity” (each as defined in the Code) unless (a) in the case of a foreign financial institution, such institution enters into an agreement with the U.S. government to withhold on

176

certain payments, perform diligence with respect to its account holders and perform reporting with respect to its U.S. account holders (which includes certain equity and debt holders of such institution, as well as certain account holders that are foreign entities with U.S. owners); (b) in the case of a non-financial foreign entity, such entity certifies that it does not have any “substantial United States owners” (as defined in the Code) or provides the withholding agent with a certification identifying its direct and indirect substantial United States owners; or (c) the foreign financial institution or non-financial foreign entity otherwise qualifies for an exemption from these rules and provides appropriate documentation. Foreign financial institutions located in jurisdictions that have an intergovernmental agreement with the United States may be subject to different rules. For purposes of the FATCA rules, a “foreign financial institution” is defined broadly to include various types of investment entities, including foreign hedge funds or private equity funds, foreign-broker-dealers, clearing organizations and investment companies.

Accordingly, to the extent we have FDAP Income or Gross Proceeds that are not treated as effectively connected income (please read “—Tax-Exempt Organizations and Other Investors”), unitholders that are foreign financial institutions or non-financial foreign entities or are persons (including “United States persons,” as defined in the Code) that hold their units through such foreign entities, may be subject to FATCA withholding on distributions received from us or on their distributive shares of FDAP Income or Gross Proceeds.

If a prospective unitholder is a foreign financial institution or non-financial foreign entity or will hold its units through one of these entities, the prospective unitholder is strongly encouraged to consult its tax advisor regarding the implications of FATCA withholding on an investment in our units.

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 Louisiana, which imposes an income tax on corporations and other entities but does not impose a personal income tax. 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.

177

INVESTMENT IN TERRYVILLE MINERAL & ROYALTY PARTNERS LP BY EMPLOYEE BENEFIT PLANS

An investment in us 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, restrictions imposed by Section 4975 of the Internal Revenue Code, and/or provisions under any 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, Keogh plans, 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. 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 plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA and any other applicable Similar Laws; and

•

whether the investment will result in recognition of unrelated business taxable income by the 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 us is authorized by the appropriate governing instrument and is a proper investment for the plan.

Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit employee benefit plans 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 plan.

In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that 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 some circumstances. Under these regulations, an entity’s assets 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 widely held by 100 or more investors independent of the issuer and each other, freely transferable and registered under some provisions of the federal securities laws;

(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 less than 25% of the value of each class of equity interest is held by the employee benefit plans referred to above.

Plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA, the Internal Revenue Code and any other applicable Similar Laws in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.

178

UNDERWRITING

Barclays Capital Inc. is acting as the representative of the underwriters and the sole book-running manager of this offering. Under the terms of an underwriting agreement, which will be filed as an exhibit to the registration statement, 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.

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 and Memorial Resource 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 discount 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 Barclays Capital Inc. an aggregate structuring fee equal to % of the gross proceeds of this offering for evaluation, analysis and structuring of our partnership.

Barclays Capital Inc. has 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 such offering price less a selling concession not in excess of $ per common unit. After the offering, the representative may change the offering price and other selling terms.

The expenses of the offering that are payable by us are estimated to be approximately $ million (excluding underwriting discount and structuring fee).

Option to Purchase Additional Common Units

We have granted the underwriters an option exercisable for 30 days after the date of this prospectus to purchase, from time to time, in whole or in part, up to an aggregate of common units from us at the public offering price less underwriting discounts. This option may be exercised to the extent 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 percentage underwriting commitment in the offering as indicated in the table at the beginning of this section.

179

Lock-Up Agreements

We, our general partner, Memorial Resource, the directors and executive officers of our general partner and all participants in the directed unit program have agreed that, for a period of 180 days after the date of this prospectus, we and they will not directly or indirectly, without the prior written consent of Barclays Capital Inc., (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 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, or sell or grant options, rights or warrants with respect to any common units or securities convertible into or exchangeable for common units, (2) enter into any swap or other derivatives transaction that transfers to another, in whole or in part, any of the economic benefits or risks of ownership of common units, whether any such transaction described in clause (1) or (2) above is to be settled by delivery of common units or other securities, in cash or otherwise, (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, or (4) publicly disclose the intention to do any of the foregoing. As such, we will be unable to sell any of our common units in a subsequent private or public offering for the 180 days following the date of this prospectus unless we obtain the consent of Barclays Capital Inc.

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. 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 was negotiated between the representative and us. In determining the initial public offering price of our common units, the representative considered:

•

the history and prospects for the industry in which we compete;

•

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; and

•

the recent market prices of, and the demand for, publicly traded common units of generally comparable companies.

Indemnification

We and certain of our affiliates have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, and to contribute to payments that the underwriters may be required to make for these liabilities.

Stabilization, Short Positions and Penalty Bids

The representative may engage in stabilizing transactions, short sales and 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.

180

•

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 representative to reclaim a selling concession from a syndicate member when the common units originally sold by the syndicate member is 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 NASDAQ or otherwise and, if commenced, may be discontinued at any time.

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 representative 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 10% 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 its affiliates 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. Each person buying common units through the directed unit program has agreed that, for a period of 180 days from the date of this prospectus, he or she will not, without the prior written consent of Barclays Capital Inc., dispose of or hedge any common units purchased in the program. Barclays Capital Inc., in its sole discretion, may release any of the securities subject to these lock-up agreements at any time without notice. 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.

181

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 such allocation for online distributions will be made by the representatives on the same basis as other allocations.

Other than this 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 underwriters or selling group member is not part of this 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.

Listing on the NASDAQ

We have applied to list our common units on the NASDAQ Global Select Market under the symbol “TRVL.”

Discretionary Sales

The underwriters have informed us that they do not expect to sell more than 5% of the common units in the aggregate to accounts over which they exercise discretionary authority.

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.

Other Relationships

The underwriters and certain of their affiliates are full service financial institutions engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, investment research, principal investment, hedging, financing and brokerage activities. The underwriters and certain of their affiliates have, from time to time, performed, and may in the future perform, various commercial and investment banking and financial advisory services for the issuer and its affiliates, for which they received or may in the future receive customary fees and expenses. Affiliates of certain of the underwriters have served as underwriters and initial purchasers for equity and debt securities offerings of Memorial Resource and its affiliates. In addition, affiliates of certain of the underwriters are lenders under Memorial Resource’s revolving credit facility. Memorial Resource may, but is not required to, apply the distribution that it receives from us to repay amounts outstanding under its revolving credit facility. Accordingly, affiliates of certain of the underwriters may indirectly receive a portion of the proceeds from this offering in the form of repayment of debt by Memorial Resource.

In the ordinary course of their various business activities, the underwriters and certain of their affiliates may make or hold a broad array of investments 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, and such investment and securities activities may involve securities and/or instruments of the issuer or its affiliates. If the underwriters or their affiliates have a lending relationship with us, the underwriters or their affiliates may hedge their credit exposure to us consistent with their customary risk management policies.

182

Typically, the underwriters and their affiliates would hedge such exposure by entering into transactions which consist of either the purchase of credit default swaps or the creation of short positions in our securities or the securities of our affiliates, including potentially the common units offered hereby. Any such credit default swaps or short positions could adversely affect future trading prices of the common units offered hereby. The underwriters and certain of their affiliates may also communicate independent investment recommendations, market color or trading ideas and/or publish or express independent research views in respect of such securities or instruments and may at any time hold, or recommend to clients that they acquire, long and/or short positions in such securities and instruments.

Direct Participation Program Requirements

Because FINRA views the common units offered hereby as interests in a direct participation program, the offering is being made in compliance with FINRA Rule 2310. 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

This prospectus does not constitute an offer to sell to, or a solicitation of an offer to buy from, anyone in any country or jurisdiction (i) in which such an offer or solicitation is not authorized, (ii) in which any person making such offer or solicitation is not qualified to do so or (iii) in which any such offer or solicitation would otherwise be unlawful. No action has been taken that would, or is intended to, permit a public offer of the common units or possession or distribution of this prospectus or any other offering or publicity material relating to the common units in any country or jurisdiction (other than the United States) where any such action for that purpose is required. Accordingly, each underwriter has undertaken that it will not, directly or indirectly, offer or sell any common units or have in its possession, distribute or publish any prospectus, form of application, advertisement or other document or information in any country or jurisdiction except under circumstances that will, to the best of its knowledge and belief, result in compliance with any applicable laws and regulations and all offers and sales of common units by it will be made on the same terms.

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.

183

LEGAL MATTERS

The validity of our common units and certain other legal matters will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. Certain legal matters in connection with this offering will be passed upon for the underwriters by Latham & Watkins LLP, Houston, Texas.

EXPERTS

The carve-out balance sheets of our predecessor as of December 31, 2013 and 2012, and the related carve-out statements of operations, carve-out statements of equity, and carve-out statements of cash flows for the years then ended included in this prospectus and elsewhere in the registration statement, have been so included in reliance upon the report of KPMG LLP, independent registered public accountants, upon the authority of said firm as experts in accounting and auditing.

The balance sheet of Terryville Mineral & Royalty Partners LP dated as of October 31, 2014, included in this prospectus and elsewhere in the registration statement, has been so included in reliance upon the report of KPMG LLP, independent registered public accountants, upon the authority of said firm as experts in accounting and auditing.

Information included in this prospectus regarding our estimated quantities of oil and 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., an independent 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.

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. The registration statement, including any exhibits and schedules, 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.

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.

184

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 ability of Memorial Resource to develop and operate our acreage;

•

the volatility of realized oil, natural gas and NGL 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 and complete acquisitions of properties or businesses;

•

general economic, business or industry conditions;

•

competition in the oil and natural gas industry;

•

the ability of Memorial Resource to obtain capital or financing needed for development, exploration and production operations;

•

uncertainties with respect to identified drilling locations and estimates of reserves;

•

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 Memorial Resource 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 Memorial Resource; and

•

certain factors discussed elsewhere in this prospectus.

All forward-looking statements are expressly qualified in their entirety by the foregoing cautionary statements.

185

INDEX TO FINANCIAL STATEMENTS


	Page
TERRYVILLE MINERAL & ROYALTY PARTNERS LP PREDECESSOR CARVE-OUT
Historical Balance Sheet
Report of Independent Registered Public Accounting Firm		F-2
Balance Sheet as of October 31, 2014		F-3
Note to Balance Sheet		F-4
Audited Financial Statements
Report of Independent Registered Public Accounting Firm		F-5
Carve-out Balance Sheets as of September 30, 2014 and December 31, 2013 and 2012		F-6
Carve-out Statements of Operations for the Periods ended September 30, 2014 and 2013 and December 31, 2013 and 2012		F-7
Carve-out Statements of Cash Flows for the Periods ended September 30, 2014 and 2013 and December 31, 2013 and 2012		F-8
Carve-out Statements of Equity for the Periods ended September 30, 2014 and December 31, 2013 and 2012		F-9
Notes to Carve-out Financial Statements		F-10

F-1

Report of Independent Registered Public Accounting Firm

To the Board of Directors

TRVL Partners GP LLC:

We have audited the accompanying balance sheet of Terryville Mineral & Royalty Partners LP as of October 31, 2014. This financial statement is the responsibility of the Terryville Minerals & Royalty Partners LP’s management. Our responsibility is to express an opinion on this financial statement 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 Company 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 Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit of a balance sheet includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement 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 Terryville Mineral & Royalty Partners LP as of October 31, 2014 in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Dallas, TX

November 4, 2014

F-2

TERRYVILLE MINERAL & ROYALTY PARTNERS LP

BALANCE SHEET


	October 31, 2014
	(in thousands)
ASSETS
Cash and cash equivalents	$	—

Total assets	$	—

PARTNERS’ CAPITAL
Limited partners’ capital	$	1
Less receivable from Memorial Resource		(1	)

Total partners’ capital	$	—

See Accompanying Note to Financial Statement.

F-3

TERRYVILLE MINERAL & ROYALTY PARTNERS LP

NOTE TO BALANCE SHEET

Note 1. Organization and Basis of Presentation

Terryville Mineral & Royalty Partners LP (the “Partnership”) is a Delaware limited partnership formed on October 10, 2014 by Memorial Resource Development Corp. (“Memorial Resource”) to own and acquire natural gas, NGL and oil properties in North America. Our primary business objective is to provide an attractive return to unitholders by maximizing distributions through organic growth and pursuing accretive growth opportunities through acquisitions of royalty interests and mineral interests from Memorial Resource and third parties. Our initial assets will consist of 7% overriding royalty interests in approximately 26,931 gross acres in the Terryville Complex, all of which are operated by Memorial Resource. These royalty interests entitle us to receive 7% of the gross revenues from existing horizontal wells and all future horizontal or vertical wells completed by Memorial Resource within this acreage. Because we will own royalty interests, we will not be required to pay capital or operating expenses associated with our existing wells, or expenses associated with the development of any future wells subject to our royalty interests.

In connection with its formation, the Partnership issued (a) a non-economic general partner interest to TRVL Partners GP LLC, its general partner and (b) a 100% limited partner interest to Memorial Resource, its organizational limited partner. The Partnership is planning to pursue an initial public offering of its common units representing limited partner interests (the “Offering”). At or prior the closing of the Offering:

•

Memorial Resource will contribute our initial assets to us in exchange for common units and subordinated units; and

•

we will issue incentive distribution rights to our general partner, and our general partner will maintain its non-economic general partner interest.

This balance sheet has been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Memorial Resource, as the initial limited partner has committed to contribute $1,000 in the aggregate to the Partnership as of October 31, 2014. This contribution receivable is reflected as a reduction to equity. Separate Statements of Income, Changes in Unit holder Equity and of Cash Flows have not been presented because the Partnership has had no business transactions or activities to date.

F-4

Report of Independent Registered Public Accounting Firm

To the Board of Directors

TRVL Partners GP LLC:

We have audited the accompanying carve-out balance sheets of Terryville Mineral & Royalty Partners LP Predecessor (as described in note 1 to the financial statements) as of December 31, 2013 and 2012, and the related carve-out statements of operations, carve-out statements of equity, and carve-out statements cash flows for the years then ended. These financial statements are the responsibility of the Terryville Mineral & Royalty Partners LP’s management. Our responsibility is to express an opinion on these 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 audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Predecessor 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 Predecessor’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the carve-out financial statements referred to above present fairly, in all material respects, the financial position of Terryville Mineral & Royalty Partners LP Predecessor as of December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the years then ended in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Dallas, TX

November 4, 2014

F-5

TERRYVILLE MINERAL & ROYALTY PARTNERS LP (PREDECESSOR)

CARVE-OUT BALANCE SHEETS


				Pro Forma
	September 30,			September 30,			December 31,			December 31,
	2014			2014			2013			2012
	(Unaudited)			(Unaudited)
	(in thousands, except per unit data)
ASSETS
Current assets:
Cash and cash equivalents (Note 2)	$	—		$	—		$	—		$	—
Royalty income receivable from affiliate (Note 2)		5,351			5,351			2,502			1,227

Total current assets		5,351			5,351			2,502			1,227
Oil and natural gas interests, successful efforts method		26,156			26,156			25,975			25,012
Accumulated depletion and impairment		(3,271	)		(3,271	)		(1,697	)		(367	)

Oil and natural gas interests, net		22,885			22,885			24,278			24,645

Total assets	$	28,236		$	28,236		$	26,780		$	25,872

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable – affiliate	$	8		$	8		$	15		$	14
Taxes payable		3,137			3,137			—			—
Distribution payable (Note 2)		—						—			—

Total current liabilities		3,145						15			14
Deferred tax liability		1,013			1,013			—			—

Total liabilities		4,158						15			14
Commitments and contingencies (Note 4)
Equity:
Predecessor capital		24,078						26,765			25,858

Total liabilities and partners’ capital	$	28,236		$	28,236		$	26,780		$	25,872

See Accompanying Notes to Carve-Out Financial Statements.

F-6

TERRYVILLE MINERAL & ROYALTY PARTNERS LP (PREDECESSOR)

CARVE-OUT STATEMENTS OF OPERATIONS


	For the Nine Months Ended September 30,				For the Twelve Months Ended December 31,
	2014		2013		2013		2012
	(Unaudited)		(Unaudited)
	(in thousands, except per unit data)
Revenues:
Royalty income	$	22,890	$	8,887	$	12,638	$	3,079
Costs and expenses:
Production taxes		459		151		247		10
Depletion		1,574		937		1,330		367
General and administrative		72		66		92		82

Total costs and expenses		2,105		1,154		1,669		459

Income before income taxes		20,785		7,733		10,969		2,620
Income tax expense		3,373		—		—		—

Net income		17,412		7,733		10,969		2,620
Net income attributable to predecessor		17,412		7,733		10,969		2,620

Net income attributable to partners	$	—	$	—	$	—	$	—

Pro Forma earnings per unit: (Note 2)
Basic and diluted	$		$		$		$
Weighted average common and common equivalent units outstanding:
Basic and diluted

See Accompanying Notes to Carve-Out Financial Statements.

F-7

TERRYVILLE MINERAL & ROYALTY PARTNERS LP (PREDECESSOR)

CARVE-OUT STATEMENTS OF CASH FLOWS


	For the Nine Months Ended September 30,						For the Twelve Months Ended December 31,
	2014			2013			2013			2012
	(Unaudited)			(Unaudited)
	(in thousands)
Cash flows from operating activities:
Net income	$	17,412		$	7,733		$	10,969		$	2,620
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion		1,574			937			1,330			367
Deferred taxes		236			—			—			—
Changes in operating assets and liabilities:
Accounts receivable		(2,849	)		(981	)		(1,275	)		(1,227	)
Payables		3,130			(8	)		1			14

Net cash provided by operating activities		19,503			7,681			11,025			1,774
Cash flows from investing activities:
Additions of overriding royalty interests		(181	)		(165	)		(244	)		(423	)
Acquisitions of overriding royalty interests (Note 3)		—			(719	)		(719	)		(40	)

Net cash used in investing activities		(181	)		(884	)		(963	)		(463	)
Cash flows from financing activities:
Distributions		(19,322	)		(6,797	)		(10,062	)		(1,311	)

Net cash used in financing activities		(19,322	)		(6,797	)		(10,062	)		(1,311	)
Net change in cash and cash equivalents		—			—			—			—
Cash and cash equivalents, beginning of period		—			—			—			—

Cash and cash equivalents, end of period	$	—		$	—		$	—		$	—

See Accompanying Notes to Carve-Out Financial Statements.

F-8

TERRYVILLE MINERAL & ROYALTY PARTNERS LP (PREDECESSOR)

CARVE-OUT STATEMENTS OF EQUITY


	(in thousands)
PREDECESSOR’S CAPITAL:
Balance January 1, 2012	$	24,549
Net income		2,620
Distributions		(1,311	)

Balance December 31, 2012		25,858
Net income		10,969
Distributions		(10,062	)

Balance December 31, 2013		26,765
Net income		17,412
Distributions		(19,322	)
Tax related effects in connection with parent restructuring transactions		(777	)

Balance September 30, 2014	$	24,078

See Accompanying Notes to Carve-Out Financial Statements.

F-9

TERRYVILLE MINERAL & ROYALTY PARTNERS LP (PREDECESSOR)

NOTES TO CARVE-OUT FINANCIAL STATEMENTS

Note 1. Background, Organization and Basis of Presentation

Overview

•

Memorial Resource will contribute our initial assets to us in exchange for common units and subordinated units; and

•

we will issue incentive distribution rights to our general partner, and our general partner will maintain its non-economic general partner interest.

Basis of Presentation

The accompanying carve-out financial statements were derived from the historical accounting records of Memorial Resource and reflect the historical financial position, results of operations and cash flows for the periods described herein. The accompanying carve-out financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”), including Regulation S-X, Article 3, “General instructions as to financial statements” and Staff Accounting Bulletin (“SAB”) Topic 1-B, “Allocations of Expenses and Related Disclosure in Financial Statements of Subsidiaries, Divisions or Lesser Business Components of Another Entity”. Certain expenses incurred by Memorial Resource are only indirectly attributable to our predecessor. As a result, certain assumptions and estimates were made in order to allocate a reasonable share of such expenses to our predecessor, so that the amounts included in the accompanying financial statements attributable to our predecessor reflect substantially all of the costs of doing business. Such allocations may or may not reflect future costs associated with operation of the Partnership.

Upon completion of our initial public offering, we intend to distribute approximately $ million in cash to Memorial Resource. The pro forma balance sheet as of September 30, 2014 reflects the pro forma distribution accrual related to this estimated cash distribution.

Note 2. Summary of Significant Accounting Policies

Use of Estimates

The preparation of the accompanying carve-out 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 carve-out financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

F-10

TERRYVILLE MINERAL & ROYALTY PARTNERS LP (PREDECESSOR)

NOTES TO CARVE-OUT FINANCIAL STATEMENTS

Significant estimates include, but are not limited to, oil and natural gas reserves, depletion of proved oil and natural gas interests; future cash flows from oil and natural gas interests and impairment of long-lived assets.

Cash and Cash Equivalents

Distributions as presented on the cash flow statement under financing activities, is equal to net cash provided by operating activities less cash used in investing activities since the Partnership’s predecessor operated within the Memorial Resource cash management program for all periods presented.

Concentrations of Credit Risk

Our royalty income receivable is derived from oil and natural gas sales delivered to purchasers. Memorial Resource, as operator, markets and collects proceeds of production on our behalf and remits payments to us. We receive payments on a monthly basis typically within 60 to 90 days following the end of the calendar month in which production is sold. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that both the purchaser and Memorial Resource may be similarly affected by changes in economic, industry or other conditions. Management believes that any credit risk imposed by a concentration in the oil and natural gas industry is mitigated by the creditworthiness of the underlying purchasers and Memorial Resource. We do not require collateral and do not believe the loss of any single purchaser would materially impact our operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers. Additionally, an allowance for doubtful accounts is recorded after all reasonable efforts have been exhausted to collect or settle the amount owed. Any amounts outstanding longer than the contractual terms are considered past due. Management determined that an allowance for uncollectible accounts was unnecessary at September 30, 2014 and December 31, 2013 and 2012, respectively.

The following individual purchasers each accounted for 10% or more of total reported revenues for the period indicated:


	Year Ending December 31,
Major customers:	2013			2012
Energy Transfer Equity, L.P. and subsidiaries		100	%		80	%
Sunoco, Inc.(1)		n/a			20	%

(1)	Sunoco, Inc. became a subsidiary of Energy Transfer Equity, L.P. in October 2012.

Oil and Natural Gas Interests

Oil and natural gas producing activities are accounted for in accordance with the successful efforts method of accounting. Under this method, costs of acquiring properties, including overriding royalty interests, are capitalized. Depletion of capitalized costs is provided using the units-of-production method based on proved oil and gas reserves related to the associated field. On the sale or retirement of a complete or partial unit of a proved property, the cost and related accumulated depletion are removed from the property accounts, and any gain or loss is recognized.

F-11

TERRYVILLE MINERAL & ROYALTY PARTNERS LP (PREDECESSOR)

NOTES TO CARVE-OUT FINANCIAL STATEMENTS

Since our predecessor only owns overriding royalty interests, it did not capitalize the costs of drilling successful exploration wells and development costs since it did not bear the burden of funding these types of expenditures. Our predecessor also did not expense exploration costs such as geological, geophysical, and seismic costs since it did not bear the burden of funding these expenditures.

The historical cost of our oil and gas interests was apportioned between the carved-out overriding royalty interests and Memorial Resource’s retained working interests in proportion to their relative fair values at the date of the acquisition.

Impairments

Proved oil and natural gas interests are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such interests, such as a downward revision of the reserve estimates, less than expected production or lower commodity prices. The estimated undiscounted future cash flows expected in connection with the overriding royalty interests are compared to the carrying value of the overriding royalty interests to determine if the carrying amount is recoverable. If the carrying value of the overriding royalty interests exceeds its estimated undiscounted future cash flows, the carrying amount of the overriding royalty interest is reduced to its estimated fair value using Level 3 inputs. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and natural gas interests. No impairment on proved oil and natural gas interests was recorded for the periods presented herein.

Oil and Gas Reserves

Royalty Interests and Revenue Recognition

Royalty interests represents the right to receive revenues (oil and natural gas sales), less production taxes. Revenue is recorded when title passes to the purchaser. Royalty interests have no rights or obligations to explore, develop or operate the property and do not incur any of the costs of exploration, development, and operation of the property. In addition, the overriding royalty interests included in our predecessor are not burdened by post-production costs.

Royalty Income Receivable

As discussed above, royalty income receivable consist of receivables from oil and natural gas sales delivered to purchasers. Those purchasers remit payment for production to the operator of the properties (e.g.,

F-12

TERRYVILLE MINERAL & ROYALTY PARTNERS LP (PREDECESSOR)

NOTES TO CARVE-OUT FINANCIAL STATEMENTS

Memorial Resource) and the operator, in turn, remits payment to us. All of our royalty interests in oil and natural gas properties are operated by Memorial Resource. Most payments are received within two months after the production date. Royalty income receivable are stated at amounts due from operators, net of an allowance for doubtful accounts when we believe collection is doubtful.

Allocation of General and Administrative Cost

The accompanying carve-out financial statements include allocations of costs for salaries, benefits and other general and administrative expenses incurred by a 100% owned subsidiary of Memorial Resource. These costs have been allocated to the carve-out financials based on estimated full-time equivalent labor hours that would have been devoted to running our predecessor’s business. In management’s estimation, the allocation methodology used is reasonable and results in an allocation of the cost of doing business borne by Memorial Resource’s subsidiary on behalf of us; however, amounts allocated may not be indicative of the cost of future operations or the amount of future allocations.

Income Tax

In the accompanying financial statements, current income tax expense has been presented for the nine months ending September 30, 2014, as Memorial Resource became subject to federal income tax on June 18, 2014. Prior to Memorial Resource’s initial public offering on June 18, 2014, its predecessor was a pass through entity not subject to federal or state taxes. Accordingly, the tax provision was based on estimated income from June 18, 2014 to September 30, 2014 on a separate return basis at a statutory rate of 40%. A deferred tax liability has been recorded in equity related to Memorial Resource’s initial public offering and restructuring transactions as it represented a transaction among shareholders.

Unaudited Pro Forma Earnings Per Unit

Pro forma earnings per unit (“EPU”) for all periods is presented. Pro forma net income per basic unit is determined by dividing the pro forma net income available to common unit holders by the number of common units expected to be outstanding immediately following the Offering.

The following sets forth the calculation of pro forma EPU for the periods indicated (in thousands, except per unit data):


	For the Period Ended September 30,				For the Year Ended December 31,
	2014		2013		2013		2012
Numerator:
Pro forma net income available to common unitholders	$	17,412	$	7,733	$	10,969	$	2,620

Denominator:
Common units outstanding immediately following the Offering

Basic and dilutive EPU	$		$		$		$

New Accounting Pronouncements

Revenue from Contracts with Customers. In May 2014, the FASB issued a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition guidance,

F-13

TERRYVILLE MINERAL & ROYALTY PARTNERS LP (PREDECESSOR)

NOTES TO CARVE-OUT FINANCIAL STATEMENTS

including industry-specific guidance. The core principle of this standard is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, the standard provides a five-step analysis of transactions to determine when and how revenue is recognized. Other major provisions include the capitalization and amortization of certain contract costs, ensuring the time value of money is considered in the transaction price, and allowing estimates of variable consideration to be recognized before contingencies are resolved in certain circumstances. This guidance also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from an entity’s contracts with customers. The new standard is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. Early application is prohibited. The standard permits the use of either the retrospective or cumulative effect transition method. This guidance will be applicable to the Partnership beginning on January 1, 2017. Management is currently assessing the impact that adopting this new accounting guidance will have on the financial statements and footnote disclosures.

Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Partnership’s financial position, results of operations and cash flows.

Note 3. Acquisitions & Additions

2013 Acquisitions

On March 18, 2013, a purchase and sale agreement was executed by Memorial Resource’s subsidiary for the purchase of certain oil and gas properties and leases in Louisiana from a third party. The amount allocable to the carve-out financial statements was $0.7 million. This transaction closed on April 30, 2013.

2012 Acquisitions

On May 1, 2012, two of Memorial Resource’s subsidiaries jointly acquired operating and non-operating interests in certain oil and natural gas properties located in East Texas and North Louisiana from an undisclosed third party seller. The amount allocable to the carve-out financial statements was less than $0.1 million, which was recorded as part of oil and gas interests on the accompanying balance sheet.

Lease Additions

As presented on the accompanying statements of cash flow, additions to overriding royalty interests related to leasing were approximately $0.2 million for both the nine months ended September 30, 2014 and 2013, respectively. Additions to overriding royalty interests related to leasing were approximately $0.2 million and $0.4 million for the years ended December 31, 2013 and 2012, respectively.

Note 4. Commitments and Contingencies

We could be subject to various possible loss contingencies which arise primarily from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry. Such contingencies include differing interpretations as to the prices at which natural gas and crude oil sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Management believes it has complied with the various laws and regulations, administrative rulings and interpretations.

F-14

TERRYVILLE MINERAL & ROYALTY PARTNERS LP (PREDECESSOR)

NOTES TO CARVE-OUT FINANCIAL STATEMENTS

Note 5. Subsequent Events

In preparing the carve-out financial statements, management evaluated all subsequent events and transactions for potential recognition or disclosure through December 8, 2014, the date the carve-out financial statements were available for issuance.

Memorial Resource acquired additional undeveloped acreage in three separate transactions in the Terryville Complex a portion of which will be allocated to our predecessor.

Note 6. Supplemental Oil and Gas Information (Unaudited)

Capitalized Costs

The total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depletion is as follows at the dates indicated (in thousands):


	Years Ended December 31,
	2013			2012
Evaluated oil and natural gas interests	$	24,899		$	24,869
Unevaluated oil and natural gas interests		1,076			143
Accumulated depletion		(1,697	)		(367	)

Total	$	24,278		$	24,645

Costs Incurred

Costs incurred related to our oil and natural gas interests were as follows for the periods indicated (in thousands):


	Years Ended December 31,
	2013		2012
Acquisition costs - proved	$	30	$	340
Acquisition costs - unproved		933		123

Since our assets consist only of overriding royalty interests, we did not incur any exploratory or development costs.

Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves

As required by the FASB and SEC, the standardized measure of discounted future net cash flows presented below is computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates and a discount factor of 10 percent to proved reserves. We do not believe the standardized measure provides a reliable estimate of the expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions including first-day-of-the-month average prices, which represent discrete points in time, and therefore, may cause significant variability in cash flows from year to year as prices change.

Oil and Natural Gas Reserves

Users of this information should be aware that the process of estimating quantities of “proved” reserves, which include “proved developed” and “proved undeveloped” oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic

F-15

TERRYVILLE MINERAL & ROYALTY PARTNERS LP (PREDECESSOR)

NOTES TO CARVE-OUT FINANCIAL STATEMENTS

data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

Proved reserves are those quantities of oil and natural gas that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

We internally prepared reserves estimates for all of our estimated proved reserves (by volume) at December 31, 2013 and 2012. All proved reserves are located in the United States and all prices are held constant in accordance with SEC rules.

The weighted-average benchmark product prices used for valuing the reserves are based upon the average of the first-day-of-the-month price for each month within the period January through December of each year presented:


	2013		2012
Oil ($/Bbl):
Spot(1)	$	93.42	$	91.21

NGL ($/Bbl):
Spot(1)	$	93.42	$	91.21

Natural Gas ($/MMbtu):
Spot(2)	$	3.67	$	2.76

(1)

The unweighted average West Texas Intermediate spot price was adjusted by lease for quality, transportation fees, and a regional price differential. The realized price we received for oil was $99.73 and $93.72 for the years ended December 31, 2013 and 2012, respectively. The realized price we received for NGLs was $40.58 and $41.43 for the years ended December 31, 2013 and 2012, respectively. NGL prices have largely tracked crude oil prices historically. A NGL barrel is made up of multiple products that receive different prices based on market fundamentals.

(2)	The unweighted average Henry Hub spot price was adjusted by lease for energy content and regional price differentials. The realized price we received was $3.71 and $3.01 for the years ended December 31, 2013 and 2012, respectively.

F-16

TERRYVILLE MINERAL & ROYALTY PARTNERS LP (PREDECESSOR)

NOTES TO CARVE-OUT FINANCIAL STATEMENTS

The following tables set forth estimates of the net reserves as of December 31, 2013 and 2012, respectively:


	Year Ended December 31, 2013
	Oil (MBbls)			Gas (MMcf)			NGLs (MBbls)			Equivalent (MMcfe)
Proved developed and undeveloped reserves:
Beginning of year		526			30,904			1,811			44,925
Extensions and discoveries		168			10,139			589			14,681
Production		(25	)		(1,821	)		(83	)		(2,472	)
Revision of previous estimates		(33	)		628			(58	)		85

End of year(1)		636			39,850			2,259			57,219

Proved developed reserves:
Beginning of year		36			2,989			189			4,338
End of year		117			9,243			525			13,096
Proved undeveloped reserves:
Beginning of year		490			27,915			1,622			40,587
End of year		519			30,607			1,734			44,123


	Year Ended December 31, 2012
	Oil (MBbls)			Gas (MMcf)			NGLs (MBbls)			Equivalent (MMcfe)
Proved developed and undeveloped reserves:
Beginning of year		3			61			5			107
Extensions and discoveries		529			31,344			1,831			45,502
Production		(6	)		(501	)		(25	)		(684	)
Revision of previous estimates		—			—			—			—

End of year(1)		526			30,904			1,811			44,925

Proved developed reserves:
Beginning of year		3			61			5			107
End of year		36			2,989			189			4,338
Proved undeveloped reserves:
Beginning of year		—			—			—			—
End of year		490			27,915			1,622			40,587

F-17

TERRYVILLE MINERAL & ROYALTY PARTNERS LP (PREDECESSOR)

NOTES TO CARVE-OUT FINANCIAL STATEMENTS

Noteworthy amounts included in the categories of proved reserve changes for the years ended December 31, 2013 and 2012 in the above tables include:

•

14.7 Bcfe of the increase in reserves for the year ended December 31, 2013, through the category extensions and discoveries, was due to the Memorial Resource’s full-scale horizontal redevelopment drilling program in the Terryville Complex.

•

Proved developed reserves increased by 8.8 Bcfe during the year ended December 31, 2013 as Memorial Resource brought 15 wells online as part its ongoing horizontal expansion in the Terryville Complex.

•

45.5 Bcfe of the increase in reserves for the year ended December 31, 2012, through the category extensions and discoveries, was due to the Memorial Resource’s horizontal redevelopment drilling program that began in 2011 to further delineate and define Memorial Resource’s position in the Terryville Complex.

•

Proved developed reserves increased by 4.2 Bcfe during the year ended December 31, 2012 as Memorial Resource brought 6 wells online as part its ongoing horizontal expansion in the Terryville Complex.

A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are reservoir simulation, decline curve analysis, volumetric, material balance, advance production type curve matching, petro-physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields.

The standardized measure of discounted future net cash flows is as follows:


	Years Ended December 31,
	2013			2012
	(in thousands)
Future cash inflows	$	305,037		$	225,367
Future production costs		(12,362	)		(11,825	)

Future net cash flows for estimated timing of cash flows		292,675			213,542
10% annual discount for estimated timing of cash flows		(86,712	)		(73,032	)

Standardized measure of discounted future net cash flows	$	205,963		$	140,510

F-18

TERRYVILLE MINERAL & ROYALTY PARTNERS LP (PREDECESSOR)

NOTES TO CARVE-OUT FINANCIAL STATEMENTS

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves

The following is a summary of the changes in the standardized measure of discounted future net cash flows for the proved oil and natural gas reserves during each of the years in the two year period ended December 31, 2013:


	Years Ended December 31,
	2013			2012
	(in thousands)
Beginning of year	$	140,510		$	404
Sale of oil and natural gas produced, net of production costs		(12,393	)		(3,069	)
Extensions and discoveries		51,442			143,135
Changes in prices and costs		7,986			—
Revisions of previous quantities		286			—
Accretion of discount		14,051			40
Change in production rates and other		4,081			—

End of year	$	205,963		$	140,510

The $51.4 million and $143.1 million increase in standardized measure of discounted future net cash flows through the category extensions and discoveries for the year ended December 31, 2013 and 2012, respectively, was due to the Memorial Resource’s horizontal redevelopment drilling program that began in 2011 to further delineate and define Memorial Resource’s position in the Terryville Complex.

F-19

Appendix A

AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF TERRYVILLE MINERAL & ROYALTY PARTNERS LP

[To be filed by amendment]

A-1

Appendix B

GLOSSARY OF TERMS

The following are definitions of certain terms used in this prospectus.

Analogous Reservoir: Analogous reservoirs, as used in resource assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, analogous reservoir refers to a reservoir that shares all of the following characteristics with the reservoir of interest: (i) the same geological formation (but not necessarily in pressure communication with the reservoir of interest); (ii) the same environment of deposition; (iii) similar geologic structure; and (iv) the same drive mechanism.

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, used in reference to oil or other liquid hydrocarbons.

Bcf: One billion cubic feet of natural gas.

Bcfe: One billion cubic feet of natural gas equivalent.

Btu: One British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.

Developed Acreage: The number of acres which are allocated or assignable to producing wells or wells capable of production.

Development Well: A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

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.

Economically Producible: The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. For this determination, the value of the products that generate revenue are determined at the terminal point of oil and natural gas producing activities.

Estimated Ultimate Recovery (EUR): Estimated ultimate recovery is the sum of proved reserves remaining as of a given date and cumulative production as of that date.

Exploitation: A development 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 oil and natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.

B-1

Field: An area consisting of a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

Gross Acres or Gross Wells: The total acres or wells, as the case may be, in which we have working interest.

ICE: Inter-Continental Exchange.

Mcf: One thousand cubic feet of natural gas.

MMBtu: One million British thermal units.

MMcf: One million cubic feet of natural gas.

MMcfe: One million cubic feet of natural gas equivalent.

MMcfe/d: One million cubic feet of natural gas equivalent per day.

Net Production: Production that is owned by us less royalties and production due others.

Net Revenue Interest: A working interest owner’s gross working interest in production less the royalty, overriding royalty, production payment and net profits interests.

NGLs: The combination of ethane, propane, butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

NYMEX: New York Mercantile Exchange.

Oil: Oil and condensate.

Operator: The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.

Overriding royalty interest: A fractional, undivided interest or right of participation in the oil or 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.

Play: A geographic area with hydrocarbon potential.

Productive Well: A well that produces commercial quantities of hydrocarbons, exclusive of its capacity to produce at a reasonable rate of return.

Proved Developed Reserves: Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.

B-2

Proved Reserves: Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, as seen in a well penetration, unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir, or an analogous reservoir or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price used is the average price during the twelve-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

PUDs: Proved Undeveloped Reserves.

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.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir (as defined in Rule 4-10(a)(2) of Regulation S-X), or by other evidence using reliable technology establishing reasonable certainty.

Realized Price: The cash market price less all expected quality, transportation and demand adjustments.

Recompletion: The completion for production of an existing wellbore in another formation from that which the well has been previously completed.

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.

B-3

Reserve Life: A measure of the productive life of an oil and natural gas property or a group of properties, expressed in years. Reserve life is calculated by dividing proved reserve volumes at year-end by production volumes. In our calculation of reserve life, production volumes are adjusted, if necessary, to reflect property acquisitions and dispositions.

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 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 oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

Resources: Resources are quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered unrecoverable. Resources include both discovered and undiscovered accumulations.

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.

Spacing: The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 40-acre spacing) and is often established by regulatory agencies.

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.

Wellbore: The hole drilled by the bit that is equipped for oil or natural gas production on a completed well. Also called well or borehole.

Working Interest: An interest in an oil and natural gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.

WTI: West Texas Intermediate.

B-4

Appendix C

LOGO

December 5, 2014

Mr. John A. Weinzierl

Memorial Resource Development Corp.

500 Dallas Street, Suite 1800

Houston, Texas 77002

Dear Mr. Weinzierl:

In accordance with your request, we have estimated the proved reserves and future revenue, as of September 30, 2014, to the Memorial Resource Development Corp. (MRD) Terryville Mineral & Royalty Partners LP (TMR) overriding royalty interest in certain oil and gas properties located in Terryville Complex, Louisiana. MRD owns its interest in these properties through its wholly-owned subsidiary WildHorse Resources, LLC. MRD plans to carve out a 7 percent overriding royalty interest from its interest in certain properties in these fields and convey such interest to TMR; such interest is referred to herein as the “MRD TMR overriding royalty interest”. We completed our evaluation on October 29, 2014. It is our understanding that the proved reserves estimated in this report constitute approximately 6 percent of all proved reserves owned by MRD. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for MRD’s and TMR’s use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

We estimate the net reserves and future net revenue to the MRD TMR overriding royalty interest in these properties, as of September 30, 2014, to be:


	Net Reserves						Future Net Revenue (M$)
Category	Oil (MBBL)		NGL (MBBL)		Gas⁽¹⁾ (MMCF)		Total		Present Worth at 10%
Proved Developed Producing		146.6		858.2		14,993.5		109,884.8		66,790.5
Proved Undeveloped		479.2		1,957.7		35,233.1		272,363.6		182,077.5

Total Proved		625.8		2,815.9		50,226.6		382,248.4		248,868.0

(1)	Estimates of gas reserves include field fuel usage volumes.

The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

The estimates shown in this report are for proved developed producing and proved undeveloped reserves. Our study indicates that there are no proved developed non-producing reserves for these properties at this time. As requested, probable and possible reserves that exist for these properties have not been included. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which

LOGO

C-1

LOGO

undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.

Gross revenue is the MRD TMR overriding royalty interest share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for the MRD TMR overriding royalty interest share of production taxes and ad valorem taxes but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period October 2013 through September 2014. For oil and NGL volumes, the average West Texas Intermediate posted price of $95.56 per barrel is adjusted by gas gatherer for quality, transportation fees, and regional price differentials. For gas volumes, the average Henry Hub spot price of $4.236 per MMBTU is adjusted by gas gatherer for energy content, transportation fees, and regional price differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $102.85 per barrel of oil, $42.30 per barrel of NGL, and $4.293 per MCF of gas.

Because the MRD TMR overriding royalty interest includes no working interest in these properties, no operating costs or capital costs would be incurred by the interest owner. However, estimated operating costs and capital costs have been used to confirm economic producibility and determine economic limits for the properties. Operating costs used in this report are based on operating expense records of MRD. Capital costs were provided by MRD and are based on authorizations for expenditure and actual costs from recent activity. Operating costs and capital costs are not escalated for inflation. The interest owner would not incur any costs due to abandonment, nor would it realize any salvage value for the lease and well equipment.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. Since the MRD TMR overriding royalty interest does not include a working interest in these properties, the interest owner would not incur any costs due to possible environmental liability.

We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the MRD TMR overriding royalty interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on the interest owner receiving its overriding royalty interest share of estimated future gross production after field usage and shrinkage.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the


		C-2

LOGO

estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred by the working interest owners in recovering such reserves may vary from assumptions made while preparing this report.

For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. A substantial portion of these reserves are for undeveloped locations and producing wells that lack sufficient production history upon which performance-related estimates of reserves can be based; such reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogy to properties with similar geologic and reservoir characteristics. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

The data used in our estimates were obtained from MRD, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical persons responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.


		Sincerely, NETHERLAND, SEWELL & ASSOCIATES, INC. Texas Registered Engineering Firm F-2699

			/s/ C.H. (Scott) Rees III
		By:
			C.H. (Scott) Rees III, P.E. Chairman and Chief Executive Officer

	/s/ Philip S. (Scott) Frost		/s/ William J. Knights
By:		By:
	Philip S. (Scott) Frost, P.E. 88738 Senior Vice President		William J. Knights, P.G. 1532 Vice President

Date Signed: December 5, 2014		Date Signed: December 5, 2014

PSF:JLO

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.


		C-3

LOGO

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC’s Compliance and Disclosure Interpretations.

(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers’ fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i)

Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

(ii)

Same environment of deposition;

(iii)

Similar geological structure; and

(iv)

Same drive mechanism.

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate. Condensate is 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.

(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i)

Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii)

Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.


		C-4		Definitions - Page 1 of 10

LOGO

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

Supplemental definitions from the 2007 Petroleum Resources Management System:

Developed Producing Reserves—Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing Reserves—Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(i)

Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.

(ii)

Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

(iii)

Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.

(iv)

Provide improved recovery systems.

(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.


		C-5		Definitions - Page 2 of 10

LOGO

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(i)

Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or “G&G” costs.

(ii)

Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

(iii)

Dry hole contributions and bottom hole contributions.

(iv)

Costs of drilling and equipping exploratory wells.

(v)

Costs of drilling exploratory-type stratigraphic test wells.

(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14)	Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms “structural feature” and “stratigraphic condition” are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(16)	Oil and gas producing activities.

(i)

Oil and gas producing activities include:

(A)

The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations;

(B)

The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

(C)

The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

(1)

Lifting the oil and gas to the surface; and

(2)

Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and


		C-6		Definitions - Page 3 of 10

LOGO

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(D)

Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a “terminal point”, which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

(ii)

Oil and gas producing activities do not include:

(A)

Transporting, refining, or marketing oil and gas;

(B)

Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;

(C)

Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

(D)

Production of geothermal steam.

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i)

When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii)

Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii)

Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv)

The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.


		C-7		Definitions - Page 4 of 10

LOGO

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(v)

Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi)

Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i)

When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii)

Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii)

Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv)

See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20)	Production costs.

(i)

Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

(A)

Costs of labor to operate the wells and related equipment and facilities.

(B)

Repairs and maintenance.


		C-8		Definitions - Page 5 of 10

LOGO

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(C)

Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

(D)

Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

(E)

Severance taxes.

(ii)

Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i)

The area of the reservoir considered as proved includes:

(A)

The area identified by drilling and limited by fluid contacts, if any, and

(B)

Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii)

In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii)

Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv)

Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A)

Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and


		C-9		Definitions - Page 6 of 10

LOGO

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(B)

The project has been approved for development by all necessary parties and entities, including governmental entities.

(v)

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(23) Proved properties. Properties with proved reserves.

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) 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.

(26) Reserves. Reserves are estimated remaining quantities of oil and 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 gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): 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).


		C-10		Definitions - Page 7 of 10

LOGO

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:

932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity’s interests in both of the following shall be disclosed as of the end of the year:

Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)

Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).

The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.

932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:

Future cash inflows. These shall be computed by applying prices used in estimating the entity’s proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.

Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.

Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity’s proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity’s proved oil and gas reserves.

Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.

Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.

Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.

(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.


		C-11		Definitions - Page 8 of 10

LOGO

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category 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.

(i)

Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii)

Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

From the SEC’s Compliance and Disclosure Interpretations (October 26, 2009):

Although several types of projects—such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations—by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.

Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:

•

The company’s level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);

•

The company’s historical record at completing development of comparable long-term projects;

•

The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;

•

The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and

•

The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).


		C-12		Definitions - Page 9 of 10

LOGO

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(iii)

Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties. Properties with no proved reserves.


		C-13		Definitions - Page 10 of 10

Terryville Mineral & Royalty Partners LP

Common Units

Representing Limited Partner Interests

Prospectus

, 2015

Barclays

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 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 FINRA filing fee and the NASDAQ listing fee, the amounts set forth below are estimates.


SEC registration fee	$	17,430
FINRA filing fee		23,000
Printing expenses		*
Fees and expenses of legal counsel		*
Accounting fees and expenses		*
Transfer agent and registrar fees		*
NASDAQ listing fee		*
Miscellaneous		*

Total		*

*	To be filed by amendment.

ITEM 14.

INDEMNIFICATION OF OFFICERS AND THE DIRECTORS OF THE BOARD OF DIRECTORS OF OUR GENERAL PARTNER.

The section of this 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 to the fullest extent permitted by law 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 limited liability company agreement of TRVL Partners GP LLC, our general partner, provides for the indemnification of its directors and officers against liabilities they incur in their capacities as such. We and our general partner will also enter into indemnification agreements with each of the current directors and executive officers of our general partner effective upon the closing of this offering. These agreements will require us to indemnify these individuals to the fullest extent permitted by law against expenses incurred as a result of any proceeding in which they are involved by reason of their service to us and, if requested, to advance expenses incurred as a result of any such proceeding. We also intend to enter into indemnification agreements with future directors and executive officers of our general partner.

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 officers of our general partner.

ITEM 15.

RECENT SALES OF UNREGISTERED SECURITIES.

In connection with our formation in October 2014, we issued (i) the non-economic general partner interest in us to TRVL Partners GP LLC and (ii) the 100.0% limited partner interest in us to Memorial Resource for $1000.00. 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.

II-1

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.

II-2

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, December 8, 2014.


Terryville Mineral & Royalty Partners LP

By:		TRVL Partners GP LLC, its general partner

By:		/s/ John A. Weinzierl
Name:		John A. Weinzierl
Title:		Chief Executive Officer

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

/s/ John A. Weinzierl John A. Weinzierl	Chief Executive Officer and Director (Principal Executive Officer)	December 8, 2014

/s/ Andrew J. Cozby Andrew J. Cozby	Chief Financial Officer (Principal Financial Officer)	December 8, 2014

/s/ Dennis G. Venghaus Dennis G. Venghaus	Chief Accounting Officer (Principal Accounting Officer)	December 8, 2014

II-3

EXHIBIT INDEX


Exhibit Number			Description

	1.1	**	Form of Underwriting Agreement

	3.1	***	Certificate of Limited Partnership of Terryville Mineral & Royalty Partners LP

	3.2	*	Limited Partnership Agreement of Terryville Mineral & Royalty Partners LP

	3.3	**	Form of First Amended and Restated Limited Partnership Agreement of Terryville Mineral & Royalty Partners LP (included as Appendix A in the prospectus included in this Registration Statement)

	4.1	**	Form of Registration Rights Agreement

	5.1	**	Opinion of Vinson & Elkins L.L.P. 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 Contribution and Conveyance Agreement

	10.2	**	Form of Long-Term Incentive Plan

	10.3	**	Form of Omnibus Agreement

	10.4	**	Form of Indemnification Agreement

	10.5	**	Form of Revolving Credit Agreement

	21.1	**	List of Subsidiaries of Terryville Mineral & Royalty Partners LP

	23.1	*	Consent of KPMG LLP

	23.2	*	Consent of Netherland, Sewell & Associates, Inc.

	23.3	**	Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1)

	23.4	**	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 Netherland, Sewell & Associates, Inc. (included as Appendix C in the prospectus included in this Registration Statement)

*	Filed herewith.

**	To be filed by amendment.

***	Previously filed.

II-4

Terryville Mineral & Royalty Partners LP - FORM S-1/A - December 8, 2014

Attached files