bsm-10k_20151231.htm

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

(Mark One)

x

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2015

OR

o

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934

For the transition period _______________ to _______________

Commission file number 001-37362

 

Black Stone Minerals, L.P.

(Exact Name of Registrant As Specified in Its Charter)

 

 

Delaware

 

47-1846692

(State or Other Jurisdiction of

Incorporation or Organization)

 

(I.R.S. Employer

Identification No.)

 

 

 

1001 Fannin Street, Suite 2020

Houston, Texas

 

77002

(Address of Principal Executive Offices)

 

(Zip Code)

Registrant’s telephone number, including area code:  (713) 445-3200

Securities registered pursuant to Section 12(b) of the Act:

 

Title of each class

 

Name of each exchange on which registered

Common Units Representing Limited Partner Interests

 

New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  o   No  x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  o   No  x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  o

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. (Check One):

 

Large Accelerated Filer

 

¨

 

Accelerated Filer

 

¨

 

 

 

 

 

 

 

Non-Accelerated Filer

 

x

(Do not check if a smaller reporting company)

 

Smaller Reporting Company

 

¨

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  o   No  x

The aggregate market value of the common units held by non-affiliates was $1,240,495,410 on June 30, 2015, the last business day of the registrant’s most recently completed second fiscal quarter, based on a closing price of $17.22 per unit as reported by the New York Stock Exchange on such date. As of March 4, 2016, 96,965,879 common units, 95,002,347 subordinated units, and 77,216 preferred units of the registrant were outstanding.

Documents Incorporated by Reference: Certain information called for in Items 10, 11, 12, 13, and 14 of Part III are incorporated by reference from the registrant’s definitive proxy statement for the annual meeting of unitholders to be held on May 26, 2016.

 

 

 

 


 

BLACK STONE MINERALS, L.P.

TABLE OF CONTENTS

 

 

 

 

PAGE

PART I

ITEMS 1 AND 2.

BUSINESS AND PROPERTIES

 

2

ITEM 1A.

RISK FACTORS

 

26

ITEM 1B.

UNRESOLVED STAFF COMMENTS

 

44

ITEM 3.

LEGAL PROCEEDINGS

 

44

ITEM 4.

MINE SAFETY DISCLOSURES

 

44

PART II

ITEM 5.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

 

45

ITEM 6.

SELECTED FINANCIAL DATA

 

50

ITEM 7.

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

 

51

ITEM 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

64

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 

65

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

 

65

ITEM 9A.

CONTROLS AND PROCEDURES

 

65

ITEM 9B.

OTHER INFORMATION

 

66

PART III

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

 

67

ITEM 11.

EXECUTIVE COMPENSATION

 

67

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

 

67

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

 

67

ITEM 14.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

 

67

PART IV

ITEM 15.

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

 

68

 

ii


 

GLOSSARY OF TERMS

The following list includes a description of the meanings of some of the oil and gas industry terms used in this Annual Report on Form 10-K (“Annual Report”).

Basin. A large depression on the earth’s surface in which sediments accumulate.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume.

Bbl/d. Bbl per day.

Bcf. One billion cubic feet of natural gas.

Boe. Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil. This “Btu-equivalent” conversion metric is based on an approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas.

Boe/d. Boe per day.

British Thermal Unit (Btu). The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Completion. The process of treating a drilling well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

Crude oil. Liquid hydrocarbons retrieved from geological structures underground to be refined into fuel sources.

Delaware Act. Delaware Revised Uniform Limited Partnership Act.

Delay rental. Payment made to the lessor under a non-producing oil and natural gas lease at the end of each year to defer a drilling obligation and continue the lease for another year during its primary term.

Deterministic method. The method of estimating reserves or resources under which a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.

Development costs. Capital costs incurred in the acquisition, exploitation, and exploration of proved oil and natural gas reserves.

Development well. A well drilled within the proved area of an oil and natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Differential. An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.

Dry hole or dry well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Economically producible. A resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.

Electrical log. An analysis that provides information on porosity, hydraulic conductivity, and fluid content of formations drilled in fluid-filled boreholes.

iii


 

Exploitation. A drilling or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.

Exploratory well. A well drilled to find and produce natural gas or oil reserves not classified as proved to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.

Extension well. A well drilled to extend the limits of a known reservoir.

Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Formation. A layer of rock which has distinct characteristics that differs from nearby rock.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Horizontal drilling. A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

Hydraulic fracturing. A process used to stimulate production of hydrocarbons. The process involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production.

Lease bonus. Usually a one-time payment made to a mineral owner as consideration for the execution of an oil and natural gas lease.

Lease operating expense. All direct and allocated indirect costs of lifting hydrocarbons from a producing formation to the surface constituting part of the current operating expenses of a working interest. Such costs include labor, supplies, repairs, maintenance, allocated overhead charges, workover costs, insurance, and other expenses incidental to production, but exclude lease acquisition or drilling or completion costs.

MBbls. One thousand barrels of oil or other liquid hydrocarbons.

MBoe. One thousand barrels of oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of oil.

MBoe/d. MBoe per day.

Mcf. Thousand cubic feet of natural gas.

Mineral interests. Real-property interests that grant ownership of the oil and natural gas under a tract of land and the rights to explore for, drill for, and produce oil and natural gas on that land or to lease those exploration and development rights to a third party.

MMBtu. Million British Thermal Units.

MMcf. Million cubic feet of natural gas.

Net acres or net wells. The sum of the fractional working interest owned in gross acres or gross wells, respectively.

Net revenue interest. An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty, overriding royalty, and other non-cost-bearing interests.

Natural gas. A combination of light hydrocarbons that, in average pressure and temperature conditions, is found in a gaseous state. In nature, it is found in underground accumulations, and may potentially be dissolved in oil or may also be found in its gaseous state.

NGLs. Natural gas liquids.

Nonparticipating royalty interest (NPRI). A type of non-cost-bearing royalty interest, which is carved out of the mineral interest and represents the right, which is typically perpetual, to receive a fixed cost-free percentage of production or revenue from production, without an associated right to lease.

iv


 

NYMEX. New York Mercantile Exchange.

Oil. Crude oil and condensate.

Oil and natural gas properties. Tracts of land consisting of properties to be developed for oil and natural gas resource extraction.

Operator. The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.

Overriding royalty interest (ORRI). A fractional, undivided interest or right of participation in the oil or natural gas, or in the proceeds from the sale of the oil or gas, produced from a specified tract or tracts, which are limited in duration to the terms of an existing lease and which are not subject to any portion of the expense of development, operation, or maintenance.

PDP. Proved developed producing, used to characterize reserves.

Play. A set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, reservoir structure, timing, trapping mechanism, and hydrocarbon type.

Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.

Pooling. The majority of our producing acreage is pooled with third-party acreage. Pooling refers to an operator’s consolidation of multiple adjacent leased tracts, which may be covered by multiple leases with multiple lessors, in order to maximize drilling efficiency or to comply with state mandated well spacing requirements. Pooling dilutes our royalty in a given well or unit, but it also increases both the acreage footprint and the number of wells in which we have an economic interest. To estimate our total potential drilling locations in a given play, we include third-party acreage that is pooled with our acreage.

Production Costs. The production or operational costs incurred while extracting and producing, storing, and transporting oil and/or natural gas. Typical of these costs are wages for workers, facilities lease costs, equipment maintenance, logistical support, applicable taxes, and insurance.

PUD. Proved undeveloped, used to characterize reserves.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved developed producing reserves. Reserves expected to be recovered from existing completion intervals in existing wells.

Proved reserves. The estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Reliable technology. A grouping of one or more technologies (including computation methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

Reserves. Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to the market, and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated

v


 

from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations). 

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

Resource play. A set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographic, and temporal properties, such as source rock, reservoir structure, timing, trapping mechanism, and hydrocarbon type.

Royalty interest. An interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development.

Seismic data. Seismic data is used by scientists to interpret the composition, fluid content, extent, and geometry of rocks in the subsurface. Seismic data is acquired by transmitting a signal from an energy source, such as dynamite or water, into the earth. The energy so transmitted is subsequently reflected beneath the earth’s surface and a receiver is used to collect and record these reflections.

Shale. A fine grained sedimentary rock formed by consolidation of clay- and silt-sized particles into thin, relatively impermeable layers. Shale can include relatively large amounts of organic material compared with other rock types and thus has the potential to become rich hydrocarbon source rock. Its fine grain size and lack of permeability can allow shale to form a good cap rock for hydrocarbon traps.

Spacing. The distance between wells producing from the same reservoir and is often established by regulatory agencies.

Standardized measure. The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Because we are a limited partnership, we are generally not subject to federal or state income taxes and thus make no provision for federal or state income taxes in the calculation of our standardized measure. Standardized measure does not give effect to derivative transactions.

Tight formation. A formation with low permeability that produces natural gas with low flow rates for long periods of time.

Trend. A region of oil and/or natural gas production, the geographic limits of which have not been fully defined, having geological characteristics that have been ascertained through supporting geological, geophysical, or other data to contain the potential for oil and/or natural gas reserves in a particular formation or series of formations.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Working interest. An operating interest that gives the owner the right to drill, produce, and conduct operating activities on the property, and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

Workover. Operations on a producing well to restore or increase production.

WTI. West Texas Intermediate oil, which is a light, sweet crude oil, characterized by an American Petroleum Institute (“API”) gravity between 39 and 41 and a sulfur content of approximately 0.4 weight percent that is used as a benchmark for the other crude oils.

 

 

 

vi


 

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements and information in this Annual Report may constitute “forward-looking statements.”  The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could,” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature.  These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us.  While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate.  All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions.  Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections.  Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:

 

·

our ability to execute our business strategies;

 

·

the volatility of realized oil and natural gas prices;

 

·

the level of production on our properties;

 

·

regional supply and demand factors, delays, or interruptions of production;

 

·

our ability to replace our oil and natural gas reserves;

 

·

our ability to identify, complete, and integrate acquisitions;

 

·

general economic, business, or industry conditions;

 

·

competition in the oil and natural gas industry;

 

·

the ability of our operators to obtain capital or financing needed for development and exploration operations;

 

·

title defects in the properties in which we invest;

 

·

the availability or cost of rigs, equipment, raw materials, supplies, oilfield services, or personnel;

 

·

restrictions on the use of water;

 

·

the availability of transportation facilities;

 

·

the ability of our operators to comply with applicable governmental laws and regulations and to obtain permits and governmental approvals;

 

·

federal and state legislative and regulatory initiatives relating to hydraulic fracturing;

 

·

future operating results;

 

·

future cash flows and liquidity, including our ability to generate sufficient cash to pay quarterly distributions;

 

·

exploration and development drilling prospects, inventories, projects, and programs;

 

·

operating hazards faced by our operators;

 

·

the ability of our operators to keep pace with technological advancements; and

 

·

certain factors discussed elsewhere in this Annual Report.

For additional information regarding known material factors that could cause our actual results to differ from our projected results, please read Part I, Item 1A. “Risk Factors.”

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof.  We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events, or otherwise.

 

1


 

PART I

Unless the context clearly indicates otherwise, references in this Annual Report on Form 10-K to “BSMC,” “Black Stone Minerals, L.P. Predecessor,” or “our predecessor,” refer to Black Stone Minerals Company, L.P. and its subsidiaries for time periods prior to the initial public offering of Black Stone Minerals, L.P. on May 6, 2015 (the “IPO”), and references to “BSM,” “Black Stone,” “we,” “our,” “us,” “the Partnership,” or like terms refer to Black Stone Minerals, L.P. and its subsidiaries for time periods subsequent to the IPO.

 

 

ITEMS 1 AND 2. BUSINESS AND PROPERTIES

General

We are one of the largest owners of oil and natural gas mineral interests in the United States. Our principal business is actively managing our existing portfolio of mineral and royalty assets to maximize its value and expanding our asset base through acquisitions of additional mineral and royalty interests. We maximize value through marketing our mineral assets for lease, creatively structuring terms on those leases to encourage and accelerate drilling activity, and selectively participating alongside our lessees on a working-interest basis in low-risk development-drilling opportunities on our mineral acreage. Our primary business objective is to grow our reserves, production, and cash generated from operations over the long term, while increasing, to the extent practicable, the distribution to our unitholders over time.

We own mineral interests in approximately 14.6 million acres, with an average 47.8% ownership interest in that acreage. We also own nonparticipating royalty interests in 1.3 million acres and overriding royalty interests in 1.4 million acres. These non-cost-bearing interests, which we refer to collectively as our “mineral and royalty interests,” include ownership in over 45,000 producing wells. Our mineral and royalty interests are located in 41 states and in 61 onshore basins in the continental United States. Many of these interests are in active resource plays, including the Bakken/Three Forks, Eagle Ford Shale, Wolfcamp, Haynesville/Bossier, and Fayetteville Shale plays, as well as emerging plays such as the Lower Wilcox and Canyon Lime plays. The combination of the breadth of our asset base and the long-lived, non-cost-bearing nature of our mineral and royalty interests exposes us to potential additional production and reserves from new and existing plays without investing additional capital.  

We are a publicly traded Delaware limited partnership formed on September 16, 2014. On May 1, 2015, our common units began trading on the New York Stock Exchange under the symbol “BSM.”  On May 6, 2015, we completed our initial public offering of 22,500,000 common units representing limited partner interests at a price to the public of $19.00 per common unit.

BSM files or furnishes annual reports on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K, as well as any amendments to these reports with the U.S. Securities and Exchange Commission (“SEC”). Through our website, http://www.blackstoneminerals.com, we make available electronic copies of the documents we file or furnish to the SEC. Access to these electronic filings is available free of charge as soon as reasonably practicable after filing or furnishing them to the SEC.

Recent Developments

Common Unit Repurchase Program

On March 4, 2016, the board of directors of our general partner authorized the repurchase of up to $50.0 million in common units over the next six months. The repurchase program authorizes us to make repurchases on a discretionary basis as determined by management, subject to market conditions, applicable legal requirements, available liquidity, and other appropriate factors. All or a portion of any repurchases may be made under a Rule 10b5-1 plan, which would permit common units to be repurchased when we might otherwise be precluded from doing so under insider trading laws. The repurchase program does not obligate us to acquire any particular amount of common units and may be modified or suspended at any time and could be terminated prior to completion. We will periodically report the number of common units repurchased. The repurchase program will be funded from our cash on hand or available revolving credit facility. Any repurchased common units will be cancelled.

Cash Tender Offer

On November 6, 2015, we commenced a tender offer to purchase up to 100% of the 117,963 then outstanding preferred units from our preferred unitholders at the units’ par value of $1,000.00 per preferred unit, plus unpaid accrued yield. The tender offer expired on December 10, 2015. We purchased and cancelled 40,747 preferred units, representing 34.5% of our then outstanding preferred units. The tendered units were purchased for $1,019.45 per preferred unit for a total cost of approximately $41.5 million, excluding fees and expenses relating to the tender offer.

2


 

Acquisitions

We closed five separate transactions to acquire unproved oil and natural gas properties in the Permian Basin during 2015 for a total of $51.7 million. We acquired acreage in the Eagle Ford Shale play through two transactions totaling $9.7 million during 2015, and we also acquired an overriding royalty interest in the Utica Shale and Marcellus plays for $1.8 million.

Our Assets

As of December 31, 2015, our total estimated proved oil and natural gas reserves were 49,788 MBoe based on a reserve report prepared by Netherland Sewell and Associates (“NSAI”), an independent third-party petroleum engineering firm. Of the reserves as of December 31, 2015, approximately 89.6% were proved developed reserves (approximately 88.1% proved developed producing and 1.5% proved developed non-producing) and approximately 10.4% were proved undeveloped reserves. At December 31, 2015, our estimated proved reserves were 31.8% oil and 68.2% natural gas.

The locations of our oil and natural gas properties are presented on the following map. Additional information related to these properties follows this map.

 

 

Mineral and Royalty Interests

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

3


 

and development rights to another party. Mineral interests generate the substantial majority of our revenue and are also the assets that we have the most influence over. 

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

 

·

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

 

·

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

Working-Interest Participation Program

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

We collectively refer to these working interests as our “working-interest participation program.” When we participate in non-operated working-interest opportunities, we are required to pay our portion of the costs associated with drilling and operating these wells. Our 2016 drilling capital expenditure budget associated with our working-interest participation program is approximately $60.0 million. Approximately 95% of our 2016 drilling capital budget will be spent in the Haynesville/Bossier and the Bakken/Three Forks plays, with the remainder spent in various plays including the Wolfcamp and Wilcox plays. As of December 31, 2015, we owned non-operated working interests in over 10,000 gross (269 net) wells.

Working interest production represented 29.5% of our total production volumes during the year ended December 31, 2015.

Our Properties

Material Basins and Producing Regions

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

 

 

 

Acreage as of December 31, 20151

 

 

Average Daily

 

 

 

Mineral and Royalty Interests

 

 

Working Interests

 

 

Production (Boe/d)

 

USGS Petroleum Province2

 

Mineral Interests

 

 

NPRIs

 

 

ORRIs

 

 

Gross

 

 

Net

 

 

For the Year Ended

December 31, 2015

 

Louisiana-Mississippi Salt Basins

 

 

5,274,784

 

 

 

111,707

 

 

 

17,660

 

 

 

54,346

 

 

 

6,917

 

 

 

5,576

 

Western Gulf (onshore)

 

 

1,553,239

 

 

 

180,185

 

 

 

79,895

 

 

 

124,656

 

 

 

18,112

 

 

 

6,527

 

Williston Basin

 

 

1,112,646

 

 

 

62,133

 

 

 

30,765

 

 

 

54,666

 

 

 

7,740

 

 

 

4,037

 

Palo Duro Basin

 

 

1,010,414

 

 

 

22,791

 

 

 

1,120

 

 

 

 

 

 

 

 

 

23

 

Permian Basin

 

 

780,361

 

 

 

577,172

 

 

 

102,967

 

 

 

8,113

 

 

 

4,734

 

 

 

903

 

Anadarko Basin

 

 

534,332

 

 

 

10,616

 

 

 

178,394

 

 

 

31,313

 

 

 

21,294

 

 

 

2,404

 

Appalachian Basin

 

 

486,964

 

 

 

416

 

 

 

12,492

 

 

 

 

 

 

 

 

 

920

 

East Texas Basin

 

 

406,111

 

 

 

41,975

 

 

 

30,294

 

 

 

110,507

 

 

 

30,504

 

 

 

3,687

 

Arkoma Basin

 

 

331,777

 

 

 

5,170

 

 

 

35,949

 

 

 

8,950

 

 

 

2,409

 

 

 

1,849

 

Bend Arch-Fort Worth Basin

 

 

138,933

 

 

 

52,368

 

 

 

40,663

 

 

 

53,606

 

 

 

11,022

 

 

 

660

 

Southwestern Wyoming

 

 

25,450

 

 

 

560

 

 

 

70,607

 

 

 

15,336

 

 

 

2,477

 

 

 

530

 

Other

 

 

2,935,091

 

 

 

188,446

 

 

 

789,502

 

 

 

39,262

 

 

 

9,300

 

 

 

1,551

 

Total

 

 

14,590,102

 

 

 

1,253,539

 

 

 

1,390,308

 

 

 

500,755

 

 

 

114,509

 

 

 

28,667

 

 

4


 

1

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

2

The basins and regions shown in the table are consistent with U.S. Geological Survey (“USGS”) delineations of petroleum provinces of onshore and state offshore areas in the continental United States. We refer to these petroleum provinces as “basins” or “regions.”

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

 

·

Louisiana-Mississippi Salt Basins. The Louisiana-Mississippi Salt Basins region ranges from northern Louisiana and southern Arkansas through south central and southern Mississippi, southern Alabama, and the Florida Panhandle. The Haynesville/Bossier 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. 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, Tuscaloosa Marine Shale, 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 and condensate areas of the play. In addition to the Eagle Ford Shale play, 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 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 plays in which we have acreage are the Marcellus Shale and Utica plays, which cover most of western Pennsylvania, northern West Virginia, and eastern Ohio. 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.

5


 

 

·

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 significant 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.

Interests by USGS Petroleum Province

The following tables present information about our mineral-and-royalty-interest and non-operated working-interest acreage, production, and well count by basin. We may own more than one type of interest in the same tract of land. For example, where we have acquired working interests through our working-interest participation program in a given tract, our working-interest acreage in that tract will relate to the same acres as our mineral-interest acreage in that tract. Consequently, some of the acreage shown for one type of interest below may also be included in the acreage shown for another type of interest. Because of our working-interest participation program, overlap between working-interest acreage and mineral-and-royalty-interest acreage is significant, while overlap between the different types of mineral and royalty interests is not significant.

6


 

Mineral Interests

The following table sets forth information about our mineral interests:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Daily Production (Boe/d)

 

 

 

As of December 31, 2015

 

 

For the Year Ended December 31,

 

USGS Petroleum Province1

 

Acres

 

 

Average

Ownership

Interest2

 

 

Average

Ownership

Leased3

 

 

 

2015

 

 

 

2014

 

 

 

2013

 

Louisiana-Mississippi Salt Basins

 

 

5,274,784

 

 

 

54.4

%

 

 

7.2

%

 

 

3,384

 

 

 

4,061

 

 

 

5,455

 

Western Gulf (onshore)

 

 

1,553,239

 

 

 

55.2

%

 

 

39.8

%

 

 

5,021

 

 

 

4,099

 

 

 

3,443

 

Williston Basin

 

 

1,112,646

 

 

 

16.8

%

 

 

23.8

%

 

 

2,430

 

 

 

1,989

 

 

 

1,646

 

Palo Duro Basin

 

 

1,010,414

 

 

 

46.7

%

 

 

6.4

%

 

 

23

 

 

 

16

 

 

 

15

 

Permian Basin

 

 

780,361

 

 

 

16.4

%

 

 

54.9

%

 

 

585

 

 

 

566

 

 

 

499

 

Eastern Great Basin

 

 

599,463

 

 

 

96.8

%

 

 

0.1

%

 

 

 

 

 

 

 

 

 

Black Warrior Basin

 

 

592,116

 

 

 

54.7

%

 

 

2.3

%

 

 

39

 

 

 

41

 

 

 

41

 

Anadarko Basin

 

 

534,332

 

 

 

33.0

%

 

 

56.9

%

 

 

959

 

 

 

790

 

 

 

815

 

Appalachian Basin

 

 

486,964

 

 

 

39.5

%

 

 

27.6

%

 

 

80

 

 

 

89

 

 

 

67

 

East Texas Basin

 

 

406,111

 

 

 

56.1

%

 

 

29.3

%

 

 

884

 

 

 

793

 

 

 

994

 

Arkoma Basin

 

 

331,777

 

 

 

54.4

%

 

 

26.1

%

 

 

1,458

 

 

 

1,646

 

 

 

1,642

 

Western Great Basin

 

 

308,258

 

 

 

88.9

%

 

 

0.0

%

 

 

 

 

 

 

 

 

 

Piedmont

 

 

179,724

 

 

 

67.7

%

 

 

0.0

%

 

 

 

 

 

 

 

 

 

North-Central Montana

 

 

151,113

 

 

 

14.7

%

 

 

16.3

%

 

 

4

 

 

 

7

 

 

 

4

 

Bend Arch-Fort Worth Basin

 

 

138,933

 

 

 

20.8

%

 

 

32.9

%

 

 

392

 

 

 

252

 

 

 

325

 

Atlantic Coastal Plain

 

 

117,326

 

 

 

12.2

%

 

 

0.0

%

 

 

 

 

 

 

 

 

 

Cherokee Platform

 

 

106,475

 

 

 

13.8

%

 

 

29.2

%

 

 

41

 

 

 

46

 

 

 

34

 

Illinois Basin

 

 

79,221

 

 

 

53.6

%

 

 

6.1

%

 

 

2

 

 

 

1

 

 

 

1

 

Powder River Basin

 

 

66,415

 

 

 

11.1

%

 

 

15.1

%

 

 

56

 

 

 

3

 

 

 

2

 

Uinta-Piceance Basin

 

 

63,408

 

 

 

3.2

%

 

 

31.4

%

 

 

6

 

 

 

6

 

 

 

5

 

Other

 

 

697,022

 

 

 

35.1

%

 

 

12.3

%

 

 

295

 

 

 

311

 

 

 

332

 

Total

 

 

14,590,102

 

 

 

47.8

%

 

 

18.1

%

 

 

15,659

 

 

 

14,716

 

 

 

15,320

 

 

1

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

2

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

3

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

7


 

NPRIs

The following table sets forth information about our NPRIs:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Daily Production (Boe/d)

 

 

 

As of December 31, 2015

 

 

For the Year Ended December 31,

 

USGS Petroleum Province1

 

Acres

 

 

Average

Royalty

Interest2

 

 

Average

Percent

Leased3

 

 

 

2015

 

 

 

2014

 

 

 

2013

 

Permian Basin

 

 

577,172

 

 

 

3.2

%

 

 

26.5

%

 

 

31

 

 

 

11

 

 

 

3

 

Western Gulf (onshore)

 

 

180,185

 

 

 

5.2

%

 

 

36.0

%

 

 

10

 

 

 

14

 

 

 

3

 

North-Central Montana

 

 

127,307

 

 

 

3.0

%

 

 

8.2

%

 

 

 

 

 

 

 

 

 

Louisiana-Mississippi Salt Basins

 

 

111,707

 

 

 

6.8

%

 

 

24.6

%

 

 

 

 

<1

 

 

<1

 

Williston Basin

 

 

62,133

 

 

 

2.6

%

 

 

33.0

%

 

 

106

 

 

 

64

 

 

 

32

 

Bend Arch-Fort Worth Basin

 

 

52,368

 

 

 

4.3

%

 

 

7.4

%

 

 

 

 

 

3

 

 

 

2

 

East Texas Basin

 

 

41,975

 

 

 

2.8

%

 

 

79.2

%

 

 

381

 

 

 

2

 

 

 

2

 

Powder River Basin

 

 

32,424

 

 

 

6.3

%

 

 

4.2

%

 

 

 

 

 

 

 

 

 

Palo Duro Basin

 

 

22,791

 

 

 

3.8

%

 

 

1.7

%

 

 

 

 

 

 

 

 

 

Anadarko Basin

 

 

10,616

 

 

 

4.4

%

 

 

92.6

%

 

 

8

 

 

 

2

 

 

 

3

 

Cambridge Arch-Central Kansas Uplift

 

 

8,583

 

 

 

5.7

%

 

 

83.1

%

 

 

 

 

 

 

 

 

 

Montana Thrust Belt

 

 

6,474

 

 

 

3.2

%

 

 

14.7

%

 

 

 

 

 

 

 

 

 

Southwest Montana

 

 

6,307

 

 

 

5.3

%

 

 

5.1

%

 

 

 

 

 

 

 

 

 

Arkoma Basin

 

 

5,170

 

 

 

4.5

%

 

 

71.6

%

 

 

21

 

 

 

 

 

 

 

Cherokee Platform

 

 

2,634

 

 

 

4.6

%

 

 

30.4

%

 

 

 

 

 

 

 

 

 

Nemaha Uplift

 

 

2,334

 

 

 

1.6

%

 

 

41.4

%

 

 

 

 

 

 

 

 

 

Sedgwick Basin

 

 

1,530

 

 

 

3.1

%

 

 

78.4

%

 

 

 

 

 

 

 

 

 

Southwestern Wyoming

 

 

560

 

 

 

1.0

%

 

 

0.0

%

 

 

 

 

 

 

 

 

 

Denver Basin

 

 

480

 

 

 

9.1

%

 

 

0.0

%

 

 

 

 

 

 

 

 

 

Appalachian Basin

 

 

416

 

 

 

8.9

%

 

 

6.0

%

 

 

 

 

 

 

 

 

 

Other

 

 

373

 

 

 

2.0

%

 

 

12.2

%

 

 

185

 

 

 

151

 

 

 

148

 

Total

 

 

1,253,539

 

 

 

3.9

%

 

 

27.1

%

 

 

742

 

 

 

247

 

 

 

193

 

 

1

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

2

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

3

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

8


 

ORRIs

The following table sets forth information about our ORRIs:

 

 

 

 

 

 

 

 

 

 

 

Average Daily Production (Boe/d)

 

 

 

As of December 31, 2015

 

 

For the Year Ended December 31,

 

USGS Petroleum Province1

 

Acres

 

 

Average

Royalty

Interest2

 

 

 

2015

 

 

 

2014

 

 

 

2013

 

North-Central Montana

 

 

458,645

 

 

 

2.4

%

 

 

35

 

 

 

36

 

 

 

42

 

Anadarko Basin

 

 

178,394

 

 

 

2.2

%

 

 

232

 

 

 

253

 

 

 

258

 

Permian Basin

 

 

102,967

 

 

 

1.2

%

 

 

72

 

 

 

60

 

 

 

69

 

Western Gulf (onshore)

 

 

79,895

 

 

 

1.9

%

 

 

262

 

 

 

166

 

 

 

126

 

Powder River Basin

 

 

74,713

 

 

 

1.5

%

 

 

98

 

 

 

50

 

 

 

52

 

Southwestern Wyoming

 

 

70,607

 

 

 

2.1

%

 

 

529

 

 

 

530

 

 

 

631

 

Michigan Basin

 

 

56,178

 

 

 

1.0

%

 

 

21

 

 

 

21

 

 

 

24

 

Uinta-Piceance Basin

 

 

55,684

 

 

 

1.6

%

 

 

37

 

 

 

32

 

 

 

37

 

Bend Arch-Fort Worth Basin

 

 

40,663

 

 

 

4.5

%

 

 

160

 

 

 

166

 

 

 

208

 

Arkoma Basin

 

 

35,949

 

 

 

2.3

%

 

 

29

 

 

 

23

 

 

 

24

 

Williston Basin

 

 

30,765

 

 

 

2.1

%

 

 

76

 

 

 

54

 

 

 

53

 

East Texas Basin

 

 

30,294

 

 

 

3.5

%

 

 

81

 

 

 

100

 

 

 

110

 

San Juan Basin

 

 

28,187

 

 

 

1.1

%

 

 

3

 

 

 

3

 

 

 

4

 

Paradox Basin

 

 

23,374

 

 

 

0.6

%

 

 

2

 

 

 

2

 

 

 

3

 

Northern Alaska

 

 

20,039

 

 

 

1.7

%

 

 

32

 

 

 

27

 

 

 

18

 

Louisiana-Mississippi Salt Basins

 

 

17,660

 

 

 

3.2

%

 

 

1,185

 

 

 

903

 

 

 

819

 

Wind River Basin

 

 

15,841

 

 

 

1.9

%

 

 

33

 

 

 

31

 

 

 

33

 

Denver Basin

 

 

15,080

 

 

 

2.8

%

 

 

83

 

 

 

91

 

 

 

107

 

Wyoming Thrust Belt

 

 

8,149

 

 

 

1.1

%

 

 

5

 

 

 

5

 

 

 

5

 

Cambridge Arch-Central Kansas Uplift

 

 

5,762

 

 

 

3.8

%

 

 

5

 

 

 

4

 

 

 

4

 

Other

 

 

41,462

 

 

 

2.1

%

 

 

906

 

 

 

879

 

 

 

905

 

Total

 

 

1,390,308

 

 

 

2.1

%

 

 

3,886

 

 

 

3,436

 

 

 

3,532

 

 

1

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

2

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

9


 

Working Interests

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

 

 

 

 

 

 

 

 

 

 

 

Average Daily Production (Boe/d)

 

 

 

As of December 31, 2015

 

 

For the Year Ended December 31,

 

USGS Petroleum Province1

 

Gross Acres2

 

 

Net Acres2

 

 

2015

 

 

2014

 

 

2013

 

Western Gulf (onshore)

 

 

124,656

 

 

 

18,112

 

 

 

1,234

 

 

 

786

 

 

 

831

 

East Texas Basin

 

 

110,507

 

 

 

30,504

 

 

 

2,341

 

 

 

1,564

 

 

 

1,427

 

Williston Basin

 

 

54,666

 

 

 

7,740

 

 

 

1,425

 

 

 

1,386

 

 

 

844

 

Louisiana-Mississippi Salt Basins

 

 

54,346

 

 

 

6,917

 

 

 

1,007

 

 

 

2,077

 

 

 

3,105

 

Bend Arch-Fort Worth Basin

 

 

53,606