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

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

USGS Petroleum Province(2)

Louisiana-Mississippi Salt Basins

Western Gulf (onshore)

Williston Basin

Palo Duro Basin

Permian Basin

Anadarko Basin

Appalachian Basin

East Texas Basin

Arkoma Basin

Bend Arch-Fort Worth Basin

Southwestern Wyoming

Other

Total

We may own more than one type of interest in the same tract of land. For example, where we have acquired working interests through our working-interest participation program in a given tract, our working-interest

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

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

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

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

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

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

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

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

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

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

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

Resource Play(2)

Bakken Shale

Three Forks

Haynesville Shale

Marcellus Shale

Canyon Lime

Bossier Shale

Tuscaloosa Marine Shale

Granite Wash

Fayetteville Shale

Barnett Shale

Eagle Ford Shale

Wolfcamp-Midland

Wolfcamp-Delaware

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

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

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

geologic support for future production and reserve growth;

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

targeted positions in high-growth resource and conventional plays.

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

Maintain a conservative capital structure and prudently manage the business for the long term. We are committed to maintaining a conservative capital structure that will afford us the financial flexibility to execute our business strategies on an ongoing basis. We believe that internally generated cash from operations, $563.7 million of undrawn borrowing capacity under our credit facility, and access to the public capital markets will provide us with sufficient liquidity and financial flexibility to grow our production, reserves, and cash generated from operations through the continued development of our existing assets and accretive acquisitions of mineral and royalty interests.

Significant diversified portfolio of mineral and royalty interests in mature producing basins and exposure to prospective exploration opportunities. We have a large-scale, diversified asset base with exposure to active, high-quality conventional and unconventional plays. With our mineral and royalty interests spanning over 16.7 million total acres across the continental United States, we have established a strong position with significant growth opportunities and exposure to potentially large new discoveries in the future. In some cases, we have built our positions in anticipation of development in a play, as we did in the Eagle Ford Shale. In other cases, we acquired diversified mineral packages in rich geologic basins with multiple prospective horizons from which subsequent resource plays, including the Bakken/Three Forks and the Haynesville/Bossier plays, have developed. Because our asset base is large and diversified, we are able to make significant focused acquisitions in active areas within well-established resource plays, while maintaining overall diversity. Furthermore, the geographic breadth of our assets

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

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

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

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

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

Financial flexibility to fund expansion. Upon the completion of this offering and the application of the net proceeds as set forth under “Use of Proceeds,” we expect to have approximately $6.3 million of cash on hand and $563.7 million of undrawn borrowing capacity under our credit facility. The credit facility, combined with internally generated cash from operations and access to the public capital markets, will provide us with the financial capacity and flexibility to grow our business.

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

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

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

an exemption from compliance with any other new auditing standards adopted by the PCAOB after April 5, 2012, unless the Securities and Exchange Commission (“SEC”) determines otherwise; and

reduced disclosure of executive compensation.

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

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

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

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

in connection with the merger, (i) the common units of the partnership held by BSMC will be redeemed in exchange for a return of its original capital contribution, (ii) the common units of BSMC (other than common units of BSMC held by BSNR) will be exchanged for an aggregate of 72,633,333 common units of the partnership and 95,133,333 subordinated units of the partnership at a conversion ratio of 12.9465 : 1 for 0.4329 common units and 0.5671 subordinated units, and the preferred units of BSMC will be exchanged for an aggregate of 117,980 preferred units of the partnership at a conversion ratio of one to one, (iii) the common units of BSMC held by BSNR will remain outstanding as limited partner interests in BSMC, and New GP will retain its non-economic general partner interest in the partnership and its units in the partnership, (iv) the partnership’s 100% equity interest in Merger Sub will be converted into a 99% limited partner interest in BSMC, and (v) BSNR will retain its non-economic general partner interest in BSMC;

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

the partnership will issue and sell 22,500,000 common units to the public in this offering and use the net proceeds from this offering in the manner described under “Use of Proceeds.”

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Cyber attacks could significantly affect us.

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

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

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

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

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

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

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

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

Unitholders may have liability to repay distributions.

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

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

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

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

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

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

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

If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.

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

Our partnership agreement includes exclusive forum, venue, and jurisdiction provisions. By purchasing a common unit, a limited partner is irrevocably consenting to these provisions regarding claims, suits, actions, or proceedings, and submitting to the exclusive jurisdiction of Delaware courts.

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

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

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

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

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

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

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

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

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

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

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

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

Common units offered to the public

Units outstanding after this offering

Use of proceeds

Cash distributions

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

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

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

If the distributions to our common and subordinated unitholders exceed the applicable minimum quarterly distribution per unit, then such excess amounts will be distributed pro rata on the common and subordinated units as if they were a single class. The preferred units have a right to further participate (on an as-converted basis) in quarterly distributions in excess of the quarterly preferred distribution

amount under certain circumstances that we do not expect to occur. Even if those additional distributions do occur, considering that the outstanding preferred units are convertible into only a relatively small number of our total outstanding common and subordinated units, we believe these additional distributions payable under those circumstances would not materially adversely affect the per unit distribution rate we would otherwise pay on our common and subordinated units.

We believe, based on our financial forecast and related assumptions included in “Cash Distribution Policy and Restrictions on Distributions,” that we will generate sufficient cash from operations to pay, for the twelve months ending March 31, 2016, the required distribution on the preferred units and the applicable minimum

quarterly distribution of $0.2625 per unit ($1.05 per unit on an annualized basis) on all the common and subordinated units outstanding.

Subordinated units

Conversion of subordinated units

In addition, at any time on or after March 31, 2019, provided there are no arrearages in the payment of the minimum quarterly distribution on the common units, our general partner may decide in its sole discretion to convert each subordinated unit into a number of common units at a ratio that will be less than one to one. If our general partner makes

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

Preferred units

Incentive distribution rights

Issuance of additional units

Our partnership agreement authorizes us to issue an unlimited number of additional units, including units that are senior to the common units and the subordinated units, without the approval of our unitholders. However, our partnership agreement does not authorize us to issue securities having preferences or rights with priority over or on a parity with the preferred units with respect to rights to share in distributions, redemption obligations, or redemption rights unless we receive the

approval of our preferred unitholders. Please read “Units Eligible for Future Sale,” “The Partnership Agreement—Issuance of Additional Partnership Interests,” and “Description of Our Preferred Units.”

Voting rights

Limited call right

Eligible Holders and redemption

Estimated ratio of taxable income to distributions

We estimate that if you (i) are subject to the passive activity loss limitation and (ii) own the common units you purchase in this offering through the record date for distributions for the period ending December 31, 2018, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be approximately 30% of the aggregate applicable minimum quarterly

distribution with respect to that period. Alternatively, if you are not subject to the passive loss limitation, your ratio of taxable income for such period to cash distributions will likely be lower. Thereafter, the ratio of allocable taxable income to cash distributions to you could substantially increase. Please read “Material U.S. Federal Income Tax Consequences—Tax Consequences of Unit Ownership” for the basis of this estimate.

Material federal income tax consequences

Directed unit program

Exchange listing

(unaudited)

(in thousands)

Statement of Operations Data:

Revenue:

Oil and condensate sales

Natural gas and natural gas liquids sales

Gain (loss) on commodity derivative instruments

Lease bonus and other income

Total revenue

Operating (income) expense:

Lease operating expense and other

Production and ad valorem taxes

Depreciation, depletion, and amortization

Impairment of oil and natural gas properties

General and administrative

Accretion of asset retirement obligations

(Gain) loss on disposal of assets

Total operating expense

Income from operations

Other income (expense):

Interest and investment income

Interest expense(1)

Other income

Total other expense

Net income

Statement of Cash Flow Data:

Net cash provided by (used in):

Operating activities

Investing activities

Financing activities

Other Financial Data:

EBITDA(2)

Adjusted EBITDA(2)

Capital expenditures(3)

Balance Sheet Data (at year end):

Cash and cash equivalents

Total assets

Credit facilities

Total liabilities

Total mezzanine equity

Total equity

(unaudited)

(in thousands)

Reconciliation of EBITDA and Adjusted EBITDA to net income:

Net income

Add:

Depreciation, depletion, and amortization

Interest expense(1)

EBITDA

Add: