Document
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
  
(Mark One)
ý
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended September 30, 2018
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE 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)
(713) 445-3200
(Registrant’s telephone number, including area code)
 
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 ý  No ☐  
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 ý No ☐ 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one): 
 
Large accelerated filer
ý
 
 
Accelerated filer
 
 
Non-accelerated filer
(Do not check if a smaller reporting company)
 
Smaller reporting company
 
 
 
 
 
 
Emerging growth company
 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐  No ý
As of October 31, 2018, there were 108,465,215 common units, 96,328,836 subordinated units, and 14,711,219 Series B cumulative convertible preferred units of the registrant outstanding.
 



TABLE OF CONTENTS
 
 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 





ii


PART I – FINANCIAL INFORMATION


Item 1. Financial Statements 


BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In thousands)
 
 
September 30, 2018
 
December 31, 2017
ASSETS
 
 

 
 

CURRENT ASSETS
 
 

 
 

Cash and cash equivalents
 
$
4,441

 
$
5,642

Accounts receivable
 
111,482

 
80,695

Commodity derivative assets
 

 
94

Prepaid expenses and other current assets
 
1,205

 
1,212

TOTAL CURRENT ASSETS
 
117,128

 
87,643

PROPERTY AND EQUIPMENT
 
 

 
 

Oil and natural gas properties, at cost, using the successful efforts method of accounting, includes unproved properties of $1,097,373 and $988,720 at September 30, 2018 and December 31, 2017, respectively
 
3,461,109

 
3,247,613

Accumulated depreciation, depletion, amortization, and impairment
 
(1,830,906
)
 
(1,766,842
)
Oil and natural gas properties, net
 
1,630,203

 
1,480,771

Other property and equipment, net of accumulated depreciation of $14,565 and $14,433 at September 30, 2018 and December 31, 2017, respectively
 
431

 
559

NET PROPERTY AND EQUIPMENT
 
1,630,634

 
1,481,330

DEFERRED CHARGES AND OTHER LONG-TERM ASSETS
 
6,497

 
7,478

TOTAL ASSETS
 
$
1,754,259

 
$
1,576,451

LIABILITIES, MEZZANINE EQUITY, AND EQUITY
 
 

 
 

CURRENT LIABILITIES
 
 

 
 

Accounts payable
 
$
14,595

 
$
2,464

Accrued liabilities
 
58,868

 
52,631

Commodity derivative liabilities
 
40,801

 
4,222

Other current liabilities
 
459

 
417

TOTAL CURRENT LIABILITIES
 
114,723

 
59,734

LONG–TERM LIABILITIES
 
 

 
 

Credit facility
 
402,000

 
388,000

Accrued incentive compensation
 
1,496

 
3,648

Commodity derivative liabilities
 
11,966

 
1,263

Asset retirement obligations
 
14,669

 
14,092

Other long-term liabilities
 
92,096

 
19,171

TOTAL LIABILITIES
 
636,950

 
485,908

COMMITMENTS AND CONTINGENCIES (Note 8)
 


 


MEZZANINE EQUITY
 
 

 
 

Partners' equity – Series A redeemable convertible preferred units, zero and 26 units outstanding at September 30, 2018 and December 31, 2017, respectively
 

 
27,028

Partners' equity – Series B cumulative convertible preferred units, 14,711 and 14,711 units outstanding at September 30, 2018 and December 31, 2017, respectively
 
298,361

 
295,394

EQUITY
 
 

 
 

Partners' equity – general partner interest
 

 

Partners' equity – common units, 108,330 and 103,456 units outstanding at September 30, 2018 and December 31, 2017, respectively
 
657,603

 
603,116

Partners' equity – subordinated units, 96,329 and 95,388 units outstanding at September 30, 2018 and December 31, 2017, respectively
 
160,638

 
164,138

Noncontrolling interests
 
707

 
867

TOTAL EQUITY
 
818,948

 
768,121

TOTAL LIABILITIES, MEZZANINE EQUITY, AND EQUITY
 
$
1,754,259

 
$
1,576,451


The accompanying notes are an integral part of these unaudited consolidated financial statements.

1



BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(In thousands, except per unit amounts)

 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 
2018
 
2017
 
2018
 
2017
REVENUE

 


 

 
 

 
 

Oil and condensate sales

$
82,712


$
41,361

 
$
232,920

 
$
119,097

Natural gas and natural gas liquids sales

63,080


45,047

 
170,179

 
142,651

Lease bonus and other income

12,440


12,044

 
28,616

 
37,082

Revenue from contracts with customers

158,232


98,452

 
431,715

 
298,830

Gain (loss) on commodity derivative instruments

(18,514
)

(9,341
)
 
(68,194
)
 
35,387

TOTAL REVENUE

139,718


89,111

 
363,521

 
334,217

OPERATING (INCOME) EXPENSE

 


 

 
 

 
 

Lease operating expense

4,229


4,569

 
12,767

 
12,906

Production costs and ad valorem taxes

17,641


11,549

 
46,939

 
35,314

Exploration expense

34


8

 
6,782

 
616

Depreciation, depletion, and amortization

29,273


29,204

 
88,135

 
84,483

General and administrative

22,083


17,305

 
60,416

 
51,998

Accretion of asset retirement obligations

278


260

 
820

 
760

(Gain) loss on sale of assets, net




 
(2
)
 
(931
)
TOTAL OPERATING EXPENSE

73,538


62,895

 
215,857

 
185,146

INCOME (LOSS) FROM OPERATIONS

66,180


26,216

 
147,664

 
149,071

OTHER INCOME (EXPENSE)

 


 

 
 

 
 

Interest and investment income

53


(9
)
 
123

 
30

Interest expense

(5,518
)

(4,172
)
 
(15,319
)
 
(11,660
)
Other income (expense)

60


(1
)
 
(1,046
)
 
352

TOTAL OTHER EXPENSE

(5,405
)

(4,182
)
 
(16,242
)
 
(11,278
)
NET INCOME (LOSS)

60,775


22,034

 
131,422

 
137,793

Net (income) loss attributable to noncontrolling interests

(22
)

20

 
(1
)
 
27

Distributions on Series A redeemable preferred units



(666
)
 
(25
)
 
(2,452
)
Distributions on Series B cumulative convertible preferred units

(5,250
)


 
(15,750
)
 

NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS

$
55,503


$
21,388

 
$
115,646

 
$
135,368

ALLOCATION OF NET INCOME (LOSS):

 


 

 
 

 
 

General partner interest

$


$

 
$

 
$

Common units

29,188


16,371

 
71,037

 
83,989

Subordinated units

26,315


5,017

 
44,609

 
51,379

 

$
55,503


$
21,388

 
$
115,646

 
$
135,368

NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:

 


 

 
 

 
 

Per common unit (basic)

$
0.27


$
0.16

 
$
0.67

 
$
0.86

Weighted average common units outstanding (basic)

106,706


101,623

 
105,254

 
97,777

Per subordinated unit (basic)

$
0.27


$
0.05

 
$
0.46

 
$
0.54

Weighted average subordinated units outstanding (basic)

96,329


95,388

 
96,021

 
95,269

Per common unit (diluted)

$
0.27


$
0.16

 
$
0.67

 
$
0.86

Weighted average common units outstanding (diluted)

106,706


101,623

 
105,254

 
97,777

Per subordinated unit (diluted)

$
0.27


$
0.05

 
$
0.46

 
$
0.54

Weighted average subordinated units outstanding (diluted)

96,329


95,388

 
96,021

 
95,269

DISTRIBUTIONS DECLARED AND PAID:

 


 

 
 
 
 
Per common unit

$
0.3375


$
0.3125

 
$
0.9625

 
$
0.8875

Per subordinated unit

$
0.3375


$
0.2088

 
$
0.7550

 
$
0.5763



 The accompanying notes are an integral part of these unaudited consolidated financial statements.

2



BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF EQUITY
(Unaudited)
(In thousands)

 
 
Common units
 
Subordinated units
 
Partners' equity — common units
 
Partners' equity — subordinated units
 
Noncontrolling interests
 
Total equity
BALANCE AT DECEMBER 31, 2017
 
103,456

 
95,388

 
$
603,116

 
$
164,138

 
$
867

 
$
768,121

Conversion of Series A redeemable preferred units
 
736

 
964

 
10,498

 
13,750

 

 
24,248

Repurchases of common and subordinated units
 
(486
)
 
(23
)
 
(8,729
)
 
(342
)
 

 
(9,071
)
Issuance of common units, net of offering costs
 
2,121

 

 
38,369

 

 

 
38,369

Issuance of common units for property acquisitions
 
1,227

 

 
22,530

 

 

 
22,530

Restricted units granted, net of forfeitures
 
1,276

 

 

 

 

 

Equity–based compensation
 

 

 
24,791

 
11,015

 

 
35,806

Distributions
 

 

 
(101,644
)
 
(72,532
)
 
(161
)
 
(174,337
)
Charges to partners' equity for accrued distribution equivalent rights
 

 

 
(2,365
)
 

 

 
(2,365
)
Distributions on Series A redeemable preferred units
 

 

 
(13
)
 
(12
)
 

 
(25
)
Distributions on Series B cumulative convertible preferred units
 

 

 
(15,750
)
 

 

 
(15,750
)
Net income (loss)
 

 

 
86,800

 
44,621

 
1

 
131,422

BALANCE AT SEPTEMBER 30, 2018
 
108,330

 
96,329

 
$
657,603

 
$
160,638

 
$
707

 
$
818,948

 
The accompanying notes are an integral part of these unaudited consolidated financial statements.

3



BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In thousands)

 
 
Nine Months Ended September 30,
 
 
2018
 
2017
CASH FLOWS FROM OPERATING ACTIVITIES
 
 

 
 

Net income (loss)
 
$
131,422

 
$
137,793

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 

 
 

Depreciation, depletion, and amortization
 
88,135

 
84,483

Accretion of asset retirement obligations
 
820

 
760

Amortization of deferred charges
 
653

 
661

(Gain) loss on commodity derivative instruments
 
68,194

 
(35,387
)
Net cash (paid) received on settlement of commodity derivative instruments
 
(20,461
)
 
12,339

Equity-based compensation
 
24,947

 
18,614

Exploratory dry hole expense
 
6,784

 

Deferred rent
 
802

 

(Gain) loss on sale of assets, net
 
(2
)
 
(931
)
Changes in operating assets and liabilities:
 
 
 
 
Accounts receivable
 
(29,989
)
 
(709
)
Prepaid expenses and other current assets
 
7

 
(234
)
Accounts payable, accrued liabilities, and other
 
18,515

 
(5,610
)
Settlement of asset retirement obligations
 
(108
)
 
(113
)
NET CASH PROVIDED BY OPERATING ACTIVITIES
 
289,719

 
211,666

CASH FLOWS FROM INVESTING ACTIVITIES
 
 

 
 

Acquisitions of oil and natural gas properties
 
(106,390
)
 
(89,030
)
Additions to oil and natural gas properties
 
(119,676
)
 
(38,346
)
Additions to oil and natural gas properties leasehold costs
 
(4,639
)
 
(2,334
)
Purchases of other property and equipment
 
(15
)
 
(118
)
Proceeds from the sale of oil and natural gas properties
 
8,390

 
6,754

Proceeds from farmouts of oil and natural gas properties
 
78,605

 
6,592

NET CASH USED IN INVESTING ACTIVITIES
 
(143,725
)
 
(116,482
)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 

 
 

Proceeds from issuance of common units, net of offering costs
 
38,369

 
31,267

Distributions to common and subordinated unitholders
 
(174,348
)
 
(142,575
)
Distributions to Series A redeemable preferred unitholders
 
(690
)
 
(3,111
)
Distributions to Series B cumulative convertible preferred unitholders
 
(12,425
)
 

Distributions to noncontrolling interests
 
(161
)
 
(90
)
Redemptions of Series A redeemable preferred units
 
(2,115
)
 
(19,641
)
Repurchases of common and subordinated units
 
(9,071
)
 
(7,845
)
Borrowings under credit facility
 
264,500

 
208,500

Repayments under credit facility
 
(250,500
)
 
(162,500
)
Debt issuance costs and other
 
(754
)
 
(50
)
NET CASH USED IN FINANCING ACTIVITIES
 
(147,195
)
 
(96,045
)
NET CHANGE IN CASH AND CASH EQUIVALENTS
 
(1,201
)
 
(861
)
CASH AND CASH EQUIVALENTS – beginning of the period
 
5,642

 
9,772

CASH AND CASH EQUIVALENTS – end of the period
 
$
4,441

 
$
8,911

SUPPLEMENTAL DISCLOSURE
 
 
 
 
Interest paid
 
$
14,607

 
$
11,041

 
The accompanying notes are an integral part of these unaudited consolidated financial statements.

4


BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


     
NOTE 1 — BUSINESS AND BASIS OF PRESENTATION
Description of the Business
Black Stone Minerals, L.P. (“BSM” or the “Partnership”) is a publicly traded Delaware limited partnership formed on September 16, 2014. On May 6, 2015, BSM completed its initial public offering (the “IPO”) of 22,500,000 common units representing limited partner interests at a price to the public of $19.00 per common unit. BSM received proceeds of $391.5 million from the sale of its common units, net of underwriting discount, structuring fee, and offering expenses (including costs previously incurred and capitalized). BSM used the net proceeds from the IPO to repay substantially all indebtedness outstanding under its Credit Facility, as defined in Note 7 – Credit Facility. On May 1, 2015, BSM’s common units began trading on the New York Stock Exchange under the symbol “BSM.”
Black Stone Minerals Company, L.P., a Delaware limited partnership, and its subsidiaries (collectively referred to as “BSMC” or the “Predecessor”) own oil and natural gas mineral interests in the United States ("U.S."). In connection with the IPO, BSMC was merged into a wholly owned subsidiary of BSM, with BSMC as the surviving entity. Pursuant to the merger, the Class A and Class B common units representing limited partner interests of the Predecessor were converted into an aggregate of 72,574,715 common units and 95,057,312 subordinated units of BSM at a conversion ratio of 12.9465:1 for 0.4329 common units and 0.5671 subordinated units, and the preferred units of BSMC were converted into an aggregate of 117,963 Series A redeemable preferred units of BSM at a conversion ratio of one to one. The merger was accounted for as a combination of entities under common control with assets and liabilities transferred at their carrying amounts in a manner similar to a pooling of interests. Unless otherwise stated or the context otherwise indicates, all references to the “Partnership” or similar expressions for time periods prior to the IPO refer to Black Stone Minerals Company, L.P. and its subsidiaries, the Predecessor, for accounting purposes. For time periods subsequent to the IPO, these terms refer to Black Stone Minerals, L.P. and its subsidiaries.
In addition to mineral interests, which make up the vast majority of the asset base, the Partnership’s assets also include nonparticipating and overriding royalty interests. These interests, which are non-cost-bearing, are collectively referred to as “mineral and royalty interests.” As of September 30, 2018, the Partnership’s mineral and royalty interests were located in 41 states and 64 onshore oil and natural gas producing basins of the continental U.S., including all of the major onshore producing basins. The Partnership also owns non-operated working interests in certain oil and natural gas properties.
Basis of Presentation
The accompanying unaudited interim consolidated financial statements of the Partnership have been prepared in accordance with generally accepted accounting principles in the United States ("U.S. GAAP") and pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). These unaudited interim consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q and, therefore, do not include all disclosures required for financial statements prepared in conformity with U.S. GAAP. Accordingly, the accompanying unaudited interim consolidated financial statements and related notes should be read in conjunction with the Partnership’s consolidated financial statements included in the Partnership’s 2017 Annual Report on Form 10-K.
The financial statements include the consolidated results of the Partnership. The results of operations for the nine months ended September 30, 2018 are not necessarily indicative of the results to be expected for the full year.
In the opinion of management, all adjustments, which are of a normal and recurring nature, necessary for the fair presentation of the financial results for all periods presented have been reflected. All intercompany balances and transactions have been eliminated. Certain reclassifications have been made to the prior periods presented to conform to the current period financial statement presentation. The reclassifications have no effect on the consolidated financial position, results of operations, or cash flows of the Partnership.

5


BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


The Partnership evaluates the significant terms of its investments to determine the method of accounting to be applied to each respective investment. Investments in which the Partnership has less than a 20% ownership interest and does not have control or exercise significant influence are accounted for under the cost method. The Partnership’s cost method investment is included in deferred charges and other long-term assets in the consolidated balance sheets. Investments in which the Partnership exercises control are consolidated, and the noncontrolling interests of such investments, which are not attributable directly or indirectly to the Partnership, are presented as a separate component of net income and equity in the accompanying consolidated financial statements.
The unaudited interim consolidated financial statements include undivided interests in oil and natural gas property rights. The Partnership accounts for its share of oil and natural gas property rights by reporting its proportionate share of assets, liabilities, revenues, costs, and cash flows within the relevant lines on the accompanying unaudited interim consolidated balance sheets, statements of operations, and statements of cash flows.
Segment Reporting
The Partnership operates in a single operating and reportable segment. Operating segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assess performance. The Partnership’s chief executive officer has been determined to be the chief operating decision maker and allocates resources and assesses performance based upon financial information at the consolidated level.
NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Significant Accounting Policies
Significant accounting policies are disclosed in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2017. There have been no changes in such policies or the application of such policies during the nine months ended September 30, 2018, with the exception of ASC 606, as defined below.
Accounts Receivable

The following table presents information about the Partnership's accounts receivable:
 
 
September 30, 2018
 
December 31, 2017
 
 
 
 
 
 
 
(in thousands)
Accounts receivable:
 
 
 
 
Revenues from contracts with customers
 
$
106,634

 
$
77,544

Other
 
4,848

 
3,151

Total accounts receivable
 
$
111,482

 
$
80,695

New Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers (Topic 606) that supersedes Accounting Standards Codification ("ASC") 605, Revenue Recognition. Under the new standard, entities are required to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services, which may require more judgment than under previous U.S. GAAP. See Note 3 – Impact of ASC 606 Adoption for further details related to the Partnership’s adoption of this standard.

6


BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which will supersede the lease requirements in Topic 840, Leases by requiring lessees to recognize lease assets and lease liabilities classified as operating leases on the balance sheet. The new lease standard will be effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, and early adoption is permitted.
The FASB recently issued ASU 2018-11, Leases (Topic 842), Targeted Improvements, which would allow entities to apply the transition provisions of the new standard at the adoption date instead of at the earliest comparative period presented in the consolidated financial statements, and will also allow entities to continue to apply the legacy guidance in Topic 840, including disclosure requirements, in the comparative period presented in the year the new leases standard is adopted. Entities that elect this option would still adopt the new leases standard using a modified retrospective transition method, but would recognize a cumulative catch-up adjustment in the period of adoption rather than in the earliest period presented. The Partnership plans to use a modified retrospective transition method to apply the new standard to leases that exist as of the adoption date of January 1, 2019. The Partnership does not plan to early adopt.
Based on evaluations to-date, the new guidance will not have a material impact on the Partnership's consolidated financial statements and related disclosures as this guidance does not apply to leases to explore for or use minerals, oil, natural gas, and similar resources.
In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820), which will remove, modify, and add certain required disclosures on fair value measurements. As amended, Topic 820 will no longer require the disclosure of the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, the policy of timing of transfers between levels, and the valuation processes for Level 3 fair value measurements. In addition, certain modifications to current disclosure requirements will be made, including clarifying that the measurement uncertainty disclosure is to communicate information about the uncertainty in measurement as of the reporting date. Certain disclosure requirements will also be added, including the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. For certain unobservable inputs, an entity may disclose other quantitative information in place of the weighted average if the entity determines that other quantitative information would be a more reasonable and rational method to reflect the distribution of unobservable inputs used to develop Level 3 fair value measurements. The new standard will be effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, and early adoption is permitted. The Partnership does not plan to early adopt and is evaluating the impact that the new accounting guidance will have on its consolidated financial statements and related disclosures.
NOTE 3 — IMPACT OF ASC 606 ADOPTION
ASC 606, Revenue from Contracts with Customers, requires the Partnership to identify the distinct promised goods and services within a contract which represent separate performance obligations and determine the transaction price to allocate to the performance obligations identified. The Partnership adopted ASC 606 using the modified retrospective method, which was applied to all existing contracts for which all (or substantially all) of the revenue had not been recognized under legacy revenue guidance as of the date of adoption, January 1, 2018.
  
Revenues from Contracts with Customers
Oil and natural gas sales
Sales of oil and natural gas are recognized at the point control of the product is transferred to the customer and collectability of the sales price is reasonably assured. Oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. The price the Partnership receives for natural gas is tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality and heat content of natural gas, and prevailing supply and demand conditions, so that the price of natural gas fluctuates to remain competitive with other available natural gas supplies. As each unit of product represents a separate performance obligation and the consideration is variable as it relates to oil and natural gas prices, we recognize revenue from oil and natural gas sales using the practical expedient for variable consideration in ASC 606.
Lease bonus and other income

7


BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


The Partnership also earns revenue from lease bonuses and delay rentals. The Partnership generates lease bonus revenue by leasing its mineral interests to exploration and production companies. A lease agreement represents the Partnership's contract with a customer and generally transfers the rights to any oil or natural gas discovered, grants the Partnership a right to a specified royalty interest, and requires that drilling and completion operations commence within a specified time period. Control is transferred to the lessee and the Partnership has satisfied its performance obligation when the lease agreement is executed, such that revenue is recognized when the lease bonus payment is received. At the time the Partnership executes the lease agreement, the Partnership expects to receive the lease bonus payment within a reasonable time, though in no case more than one year, such that the Partnership has not adjusted the expected amount of consideration for the effects of any significant financing component per the practical expedient in ASC 606. The Partnership also recognizes revenue from delay rentals to the extent drilling has not started within the specified period, payment has been received, and the Partnership has no further obligation to refund the payment.

8


BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


Production imbalances
The Partnership previously elected to utilize the entitlements method to account for natural gas production imbalances, which is no longer permitted under ASC 606. As of January 1, 2018, these amounts were de minimis. As such, upon adoption of ASC 606, there was no material impact to the financial statements due to this change in accounting for the Partnership's production imbalances.
Allocation of transaction price to remaining performance obligations
Oil and natural gas sales
The Partnership has utilized the practical expedient in ASC 606 which states the Partnership is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. As the Partnership has determined that each unit of product generally represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
Lease bonus and other income
Given that the Partnership does not recognize lease bonus or other income until a lease agreement has been executed, at which point its performance obligation has been satisfied, and payment is received, the Partnership does not record revenue for unsatisfied or partially unsatisfied performance obligations as of the end of the reporting period. Overall, there were no material changes in the timing of the satisfaction of the Partnership's performance obligations or the allocation of the transaction price to its performance obligations in applying the guidance in ASC 606 as compared to legacy U.S. GAAP.

Prior-period performance obligations
The Partnership records revenue in the month production is delivered to the purchaser. As a non-operator, the Partnership has limited visibility into the timing of when new wells start producing and production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, the Partnership is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The expected sales volumes and prices for these properties are estimated and recorded within the Accounts receivable line item in the accompanying consolidated balance sheets. The difference between the Partnership's estimates and the actual amounts received for oil and natural gas sales is recorded in the month that payment is received from the third party. For the three and nine months ended September 30, 2018, revenue recognized in the reporting periods related to performance obligations satisfied in prior reporting periods was immaterial.

9


BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


NOTE 4 — OIL AND NATURAL GAS PROPERTIES ACQUISITIONS    
Acquisitions of proved oil and natural gas properties and working interests are considered business combinations and are recorded at their estimated fair value as of the acquisition date. Acquisitions of unproved oil and natural gas properties are considered asset acquisitions and are recorded at cost.
2018 Acquisitions
During the nine months ended September 30, 2018, the Partnership closed on multiple acquisitions of mineral and royalty interests for total consideration of $132.1 million.
Acquisitions that included proved oil and natural gas properties were considered business combinations and were primarily located in the Permian Basin. The cash portion of the consideration paid for these acquisitions was funded with borrowings under the Partnership's Credit Facility and funds from operating activities. Acquisition related costs of $0.1 million were expensed and included in the General and administrative expense line item of the consolidated statement of operations for the nine months ended September 30, 2018. The following table summarizes these acquisitions which were considered business combinations:
 
Assets Acquired
 
Consideration Paid
 
Proved
 
Unproved
 
Net Working Capital
 
Total Fair Value
 
Cash
 
Fair Value of Common Units Issued
 
 
 
 
 
 
 
 
 
 
 
 
 
(in thousands)
 
 
March
$
984

 
$
21,452

 
$
133

 
$
22,569

 
$
22,569

 
$

June
883

 
13,688

 
8

 
14,579

 
14,579

 

July
4,349

 
7,944

 
215

 
12,508

 
3,764

 
8,744

August
5,000

 
34,673

 
74

 
39,747

 
26,461

 
13,286

September
1,176

 

 

 
1,176

 
1,176

 

Total fair value
$
12,392

 
$
77,757

 
$
430

 
$
90,579

 
$
68,549

 
$
22,030

In addition, during the nine months ended September 30, 2018, the Partnership acquired mineral and royalty interests in unproved oil and natural gas properties from various sellers for an aggregate of $41.5 million. These acquisitions were considered asset acquisitions and were primarily located in East Texas and the Permian Basin. The cash portion of the consideration paid for these acquisitions of $41.0 million was funded with borrowings under the Partnership's Credit Facility and funds from operating activities, and $0.5 million was funded through the issuance of common units of the Partnership based on the fair values of the common units issued on the acquisition dates.
Noble Acquisition

On November 28, 2017 (the "Close Date"), BSMC closed on the acquisition of (i) certain mineral interests and other non-cost bearing royalty interests from Noble Energy Inc., Noble Energy Wyco, LLC, and Rosetta Resources Operating LP and (ii) one hundred percent (100%) of the issued and outstanding securities of Samedan Royalty, LLC ("Samedan") from Noble Energy US Holdings, LLC, collectively, the "Noble Acquisition."

The mineral interests and other non-cost bearing royalty interests acquired in the Noble Acquisition, including interests owned by Samedan (the "Noble Assets") include approximately 1.1 million gross (140,000 net) mineral acres, 380,000 gross acres of non-participating royalty interests, and 600,000 gross acres of overriding royalty interests collectively spread over 20 states with significant concentrations in Texas, Oklahoma, and North Dakota.

The Partnership funded the $335.0 million purchase price (before customary post-closing adjustments) using (i) approximately $300.0 million in proceeds from its issuance of 14,711,219 Series B cumulative convertible preferred units to Mineral Royalties One, L.L.C., an affiliate of The Carlyle Group (the "Purchaser"), in a private placement which also closed on November 28, 2017, and (ii) approximately $35.0 million from borrowings under its Credit Facility. See additional discussion of the Series B cumulative convertible preferred units in Note 10 – Preferred Units.

10


BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS



The transaction was accounted for as a business combination using the acquisition method of accounting which requires, among other things, that the assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date. The final determination of fair value remains preliminary and will be completed after post-closing purchase price adjustments are finalized, but in no case later than one year from the acquisition date. Since December 31, 2017, the Partnership has recorded an adjustment to the purchase price to reduce the amount allocated to unproved properties by $3.2 million, which reduces the Acquisitions of oil and natural gas properties line item of the consolidated statement of cash flows for the nine months ended September 30, 2018.

The following table summarizes the adjusted allocation of the fair value of the assets acquired and the acquisition-related costs as of September 30, 2018:
 
Assets Acquired
 
Cash Consideration Paid1
 
Acquisition-Related Costs2
 
Proved
 
Unproved
 
Net Working Capital
 
Total Fair Value
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(in thousands)
Noble Assets
$
68,877

 
$
256,542

 
$
5,917

 
$
331,336

 
$
331,336

 
$
247

1
Represents cash consideration paid on the Close Date, as adjusted for the $3.2 million purchase price adjustment recorded during the nine months ended September 30, 2018.
2 
Acquisition-related costs were expensed and included in the General and administrative expense line item of the consolidated statement of operations for the year ended December 31, 2017.
The fair value of the Noble Assets was measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of: (i) oil and natural gas reserves; (ii) future commodity prices; (iii) estimated future cash flows; and (iv) market-based weighted average cost of capital. These inputs require significant judgments and estimates by the Partnership's management at the time of the valuation and are the most sensitive and subject to change.

Actual and Pro Forma Impact of Noble Acquisition (Unaudited)
Revenue attributable to the Noble Acquisition included in the Partnership's consolidated statements of operations for the three and nine months ended September 30, 2018 was $15.7 million and $41.3 million, respectively. The following table presents unaudited pro forma information for the Partnership as if the Noble Acquisition occurred on January 1, 2017.

11


BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


 
Three Months Ended
September 30, 2017
 
Nine Months Ended
September 30, 2017
 
 
 
 
 
(in thousands, except per unit amounts)
Revenue and other income
$
98,962

 
$
363,051

Net income
27,449

 
154,175

Net income attributable to noncontrolling interests
20

 
27

Distributions on Series A redeemable preferred units
(666
)
 
(2,452
)
Distributions on Series B cumulative convertible preferred units
(5,250
)
 
(15,750
)
Net income attributable to the general partner and common and subordinated units
$
21,553

 
$
136,000

Allocation of net income:
 
 
 
General partner interest
$

 
$

Common units
16,168

 
84,321

Subordinated units
5,385

 
51,679

 
$
21,553

 
$
136,000

Net income attributable to limited partners per common and subordinated unit:
 
 
 
Per common unit (basic)
$
0.16

 
$
0.86

Per subordinated unit (basic)
$
0.06

 
$
0.54

Per common unit (diluted)
$
0.16

 
$
0.86

Per subordinated unit (diluted)
$
0.06

 
$
0.54


12


BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


The historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the Noble Acquisition and are factually supportable. The unaudited pro forma consolidated results are not necessarily indicative of what the Partnership's consolidated results of operations would have been had the acquisition been completed on January 1, 2017. In addition, the unaudited pro forma consolidated results do not purport to project the future results of operations for the combined company.

The unaudited pro forma consolidated results reflect the following pro forma adjustments for the periods presented:
Adjustments to recognize incremental revenue, production costs and ad valorem taxes, and depreciation, depletion, and amortization expense attributable to the Noble Assets.
Adjustment to recognize additional interest expense associated with the incremental borrowings under the Partnership's Credit Facility.
Adjustment to recognize the quarterly distribution associated with the issuance of 14,711,219 Series B cumulative convertible preferred units.
The Series B cumulative convertible preferred units were not included in the calculation of pro forma diluted earnings per common unit for the three months ended September 30, 2017 as they were anti-dilutive under the if-converted method.
The Series B cumulative convertible preferred units were included in the calculation of pro forma diluted earnings per common unit for the nine months ended September 30, 2017 due to their dilutive effect under the if-converted method.
The Series B cumulative convertible preferred units do not have any impact to earnings per subordinated unit.
2017 Acquisitions
In addition to the Noble Acquisition, the Partnership closed on multiple acquisitions of mineral and royalty interests during the year ended December 31, 2017 for total consideration of $163.0 million.
Acquisitions that included proved oil and natural gas properties were considered business combinations and were primarily located in the Delaware Basin and East Texas. The cash portion of the consideration paid for these acquisitions was funded with borrowings under the Partnership's Credit Facility and funds from operating activities. The following table summarizes these acquisitions which were considered business combinations:
 
Assets Acquired
 
Consideration Paid
 
 
 
Proved
 
Unproved
 
Net Working Capital
 
Total Fair Value
 
Cash
 
Fair Value of Common Units Issued
 
Acquisition-Related Costs1
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(in thousands)
January
$
5,135

 
$
34,008

 
$
263

 
$
39,406

 
$
27,380

 
$
12,026

 
$
1,162

June
5,006

 
45,477

 

 
50,483

 
4,802

 
45,681

 
1,481

August
3,277

 
9,984

 

 
13,261

 
4,289

 
8,972

 
107

September
3,120

 

 

 
3,120

 
3,120

 

 

Total fair value
$
16,538

 
$
89,469

 
$
263

 
$
106,270

 
$
39,591

 
$
66,679

 
$
2,750

1  
Acquisition-related costs were expensed and included in the General and administrative expense line item of the consolidated statement of operations for the year ended December 31, 2017.
Additionally, during the year ended December 31, 2017, the Partnership acquired mineral and royalty interests in unproved oil and natural gas properties from various sellers for $56.7 million. These acquisitions were considered asset acquisitions and were primarily located in East Texas. The cash portion of the consideration paid for these acquisitions of $51.7 million was funded with borrowings under the Partnership's Credit Facility and funds from operating activities, and $5.0 million was funded through the issuance of common units of the Partnership based on the fair values of the common units issued on the acquisition dates.    

13


BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


Farmout Agreements
Canaan Farmout
On February 21, 2017, the Partnership announced that it had entered into a farmout agreement with Canaan Resource Partners ("Canaan") which covers certain Haynesville/Bossier acreage in San Augustine County, Texas operated by XTO Energy Inc. The Partnership has an approximate 50% working interest in the acreage and is the largest mineral owner. At its option, during the first three phases of the agreement, Canaan can commit on a phase-by-phase basis to fund a portion of the Partnership's drilling and completion costs to earn a percentage of the Partnership's working interest in wells drilled and completed during each phase. After the third phase, Canaan can earn a percentage of the Partnership's working interest in additional wells drilled in the area by committing on a well-by-well basis to fund a portion of the Partnership's costs for each well. The Partnership will receive an overriding royalty interest (“ORRI”) before payout and an increased ORRI after payout on all wells drilled under the agreement.
Since the inception of the agreement, the Partnership has received $62.2 million from Canaan under the agreement. All amounts received are included in the Other long-term liabilities line item of the September 30, 2018 consolidated balance sheet, as no working interest had been assigned to Canaan as of that date. Subsequent to September 30, 2018, the Partnership assigned to Canaan working interests in wells drilled and completed during the initial phase, reducing the Other long-term liabilities balance associated with the Canaan farmout agreement.
Pivotal Farmout
On November 21, 2017, the Partnership entered into a farmout agreement with a portfolio company of Tailwater Capital, LLC, Pivotal Petroleum Partners (“Pivotal”), that covers substantially all of the Partnership's remaining working interests under active development in the Shelby Trough area of East Texas targeting its Haynesville/Bossier acreage after giving effect to the Canaan Farmout (discussed above) over the next eight years. In wells operated by XTO Energy Inc. in San Augustine County, Texas, Pivotal will earn the Partnership's remaining working interest not covered by the Canaan Farmout, as well as the Partnership's working interests in wells operated by its other major operator in the area. After the funding of a designated group of wells by Pivotal and once Pivotal achieves a specified payout for such well group, the Partnership will obtain a majority of the original working interest in the designated group of wells.
Since the inception of the agreement, the Partnership has received $35.5 million from Pivotal under the agreement. As of September 30, 2018, the Partnership had assigned to Pivotal working interests in wells drilled and completed during the initial phase, and as such, only $27.5 million is included in the Other long-term liabilities line item of the consolidated balance sheet.
As of December 31, 2017, all amounts received from Canaan and Pivotal under the agreements were included in the Other long-term liabilities line item of the consolidated balance sheet, as no working interest had been assigned to Canaan or Pivotal as of that date.
NOTE 5 — COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS
The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To mitigate the inherent commodity price risk associated with its operations, the Partnership uses oil and natural gas derivative instruments. From time to time, such instruments may include variable-to-fixed-price swaps, costless collars, fixed-price contracts and other contractual arrangements. The Partnership enters into oil and natural gas derivative contracts that contain netting arrangements with each counterparty. The Partnership does not enter into derivative instruments for speculative purposes.

14


BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


As of September 30, 2018, the Partnership’s open derivative contracts consisted of fixed-price swap contracts and costless collar contracts. A fixed-price swap contract between the Partnership and the counterparty specifies a fixed commodity price and a future settlement date. A costless collar contract between the Partnership and the counterparty specifies a floor and a ceiling commodity price and a future settlement date. The Partnership has not designated any of its contracts as fair value or cash flow hedges. Accordingly, any changes in the fair value of the contracts are included in the consolidated statement of operations in the period of the change. All derivative gains and losses from the Partnership’s derivative contracts have been recognized in revenue in the Partnership's accompanying consolidated statements of operations. Derivative instruments that have not yet been settled in cash are reflected as either derivative assets or liabilities in the Partnership’s accompanying consolidated balance sheets as of September 30, 2018 and December 31, 2017. See Note 6 – Fair Value Measurements for further discussion.    
The Partnership's derivative contracts expose it to credit risk in the event of nonperformance by counterparties. While the Partnership does not require its derivative contract counterparties to post collateral, the Partnership does evaluate the credit standing of such counterparties as deemed appropriate. This evaluation includes reviewing a counterparty’s credit rating and latest financial information. As of September 30, 2018, the Partnership had ten counterparties, all of which are rated Baa1 or better by Moody’s. Nine of the Partnership's counterparties are lenders under the Credit Facility. The Partnership would have been at risk of losing a fair value amount of $6.2 million had the Partnership's counterparties as a group been unable to fulfill their obligations as of September 30, 2018
The tables below summarize the fair values and classifications of the Partnership’s derivative instruments as of each date:
 
 
 
 
September 30, 2018
Classification
 
Balance Sheet Location
 
Gross
Fair Value
 
Effect of Counterparty Netting
 
Net Carrying Value on Balance Sheet
 
 
 
 
 
 
 
 
 
 
 
 
 
(in thousands)
Assets:
 
 
 
 

 
 

 
 

Current asset
 
Commodity derivative assets
 
$
1,923

 
$
(1,923
)
 
$

Long-term asset
 
Deferred charges and other long-term assets
 
4,253

 
(4,247
)
 
6

Total assets
 
 
 
$
6,176

 
$
(6,170
)
 
$
6

Liabilities:
 
 
 
 

 
 

 
 

Current liability
 
Commodity derivative liabilities
 
$
42,724

 
$
(1,923
)
 
$
40,801

Long-term liability
 
Commodity derivative liabilities
 
16,213

 
(4,247
)
 
11,966

Total liabilities
 
 
 
$
58,937

 
$
(6,170
)
 
$
52,767

 
 
 
 
As of December 31, 2017
Classification
 
Balance Sheet Location
 
Gross
Fair Value
 
Effect of Counterparty Netting
 
Net Carrying Value on Balance Sheet
 
 
 
 
 
 
 
 
 
 
 
 
 
(in thousands)
Assets:
 
 
 
 

 
 

 
 

Current asset
 
Commodity derivative assets
 
$
10,713

 
$
(10,619
)
 
$
94

Long-term asset
 
Deferred charges and other long-term assets
 
1,392

 
(1,029
)
 
363

Total assets
 
 
 
$
12,105

 
$
(11,648
)
 
$
457

Liabilities:
 
 
 
 

 
 

 
 

Current liability
 
Commodity derivative liabilities
 
$
14,841

 
$
(10,619
)
 
$
4,222

Long-term liability
 
Commodity derivative liabilities
 
2,292

 
(1,029
)
 
1,263

Total liabilities
 
 
 
$
17,133

 
$
(11,648
)
 
$
5,485


15


BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


Changes in the fair values of the Partnership’s derivative instruments (both assets and liabilities) are presented on a net basis in the accompanying consolidated statements of operations and are as follows (in thousands):
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
Derivatives not designated as hedging instruments
 
2018
 
2017
 
2018
 
2017
 
 
 
 
 
 
 
 
 
Beginning fair value of commodity derivative instruments
 
$
(44,043
)
 
$
20,650

 
$
(5,028
)
 
$
(16,719
)
Gain (loss) on oil derivative instruments
 
(18,830
)
 
(9,493
)
 
(63,325
)
 
18,306

Gain (loss) on natural gas derivative instruments
 
316

 
152

 
(4,869
)
 
17,081

Net cash paid (received) on settlements of oil derivative instruments
 
11,280

 
(4,026
)
 
25,809

 
(10,682
)
Net cash paid (received) on settlements of natural gas derivative instruments
 
(1,484
)
 
(954
)
 
(5,348
)
 
(1,657
)
Net change in fair value of commodity derivative instruments
 
(8,718
)
 
(14,321
)
 
(47,733
)
 
23,048

Ending fair value of commodity derivative instruments
 
$
(52,761
)
 
$
6,329

 
$
(52,761
)
 
$
6,329

The Partnership had the following open derivative contracts for oil as of September 30, 2018:
 
 

 
Weighted Average Price (Per Bbl)
 
Range (Per Bbl)
Period and Type of Contract
 
Volume (Bbl)
 
 
Low
 
High
Oil Swap Contracts:
 
 

 
 

 
 

 
 

2018
 
 

 
 

 
 

 
 

Third Quarter
 
283,000

 
$
55.31

 
$
51.85

 
$
61.88

Fourth Quarter
 
854,000

 
55.18

 
51.85

 
61.88

2019
 


 


 


 


First Quarter
 
645,000

 
$
58.66

 
$
52.82

 
$
65.58

Second Quarter
 
645,000

 
58.66

 
52.82

 
65.58

Third Quarter
 
645,000

 
58.20

 
52.82

 
63.75

Fourth Quarter
 
645,000

 
58.20

 
52.82

 
63.75

 
 
 
 
Weighted Average
Floor Price (Per Bbl)
 
Weighted Average
Ceiling Price (Per Bbl)
Period and Type of Contract
 
Volume (Bbl)
 
 
Oil Collar Contracts:
 
 
 
 
 
 
2019
 
 
 
 
 
 
First Quarter
 
60,000

 
$
65.00
 
 
$
74.00
 
Second Quarter
 
60,000

 
65.00
 
 
74.00
 
Third Quarter
 
60,000

 
65.00
 
 
74.00
 
Fourth Quarter
 
60,000

 
65.00
 
 
74.00
 
2020
 
 
 
 
 
 
First Quarter
 
210,000

 
$
55.00
 
 
$
70.85
 
Second Quarter
 
210,000

 
55.00
 
 
70.85
 
Third Quarter
 
210,000

 
55.00
 
 
70.85
 
Fourth Quarter
 
210,000

 
55.00
 
 
70.85
 

16


BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


The Partnership had the following open derivative contracts for natural gas as of September 30, 2018:
 
 

 
Weighted Average Price (Per MMBtu)
 
Range (Per MMBtu)
Period and Type of Contract
 
Volume (MMBtu)
 
 
Low
 
High
Natural Gas Swap Contracts:
 
 

 
 

 
 

 
 

2018
 
 

 
 

 
 

 
 

Fourth Quarter
 
13,630,000

 
$
3.01

 
$
2.90

 
$
3.23

2019
 


 


 


 


First Quarter
 
7,200,000

 
$
2.86

 
$
2.81

 
$
2.93

Second Quarter
 
7,240,000

 
2.86

 
2.81

 
2.93

Third Quarter
 
7,280,000

 
2.86

 
2.81

 
2.93

Fourth Quarter
 
7,280,000

 
2.86

 
2.81

 
2.93

Subsequent to September 30, 2018, the Partnership entered into gas derivative contracts for an average of 608,333 MMBtu per month in 2019 at a weighted average price of $2.85 per MMBtu.

NOTE 6 — FAIR VALUE MEASUREMENTS
Fair value is defined as the amount at which an asset (or liability) could be bought (or incurred) or sold (or settled) in an orderly transaction between market participants at the measurement date. Further, ASC 820, Fair Value Measurement, establishes a framework for measuring fair value, establishes a fair value hierarchy based on the quality of inputs used to measure fair value, and includes certain disclosure requirements. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk.
ASC 820 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:
Level 1—Unadjusted quoted prices for identical assets or liabilities in active markets.
Level 2—Quoted prices for similar assets or liabilities in non-active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.
Level 3—Inputs that are unobservable and significant to the fair value measurement (including the Partnership’s own assumptions in determining fair value).
A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. There were no transfers into, or out of, the three levels of the fair value hierarchy for the nine months ended September 30, 2018 or the year ended December 31, 2017.
The carrying value of the Partnership's cash and cash equivalents, receivables, and payables approximate fair value due to the short-term nature of the instruments. The estimated carrying value of all debt as of September 30, 2018 and December 31, 2017 approximated the fair value due to variable market rates of interest. These debt fair values, which are Level 3 measurements, were estimated based on the Partnership’s incremental borrowing rates for similar types of borrowing arrangements, when quoted market prices were not available. The estimated fair values of the Partnership’s financial instruments are not necessarily indicative of the amounts that would be realized in a current market exchange.

17


BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


Assets and Liabilities Measured at Fair Value on a Recurring Basis
The Partnership estimated the fair value of derivative instruments using the market approach via a model that uses inputs that are observable in the market or can be derived from, or corroborated by, observable data. See Note 5 – Commodity Derivative Financial Instruments for further discussion.
The following table presents information about the Partnership’s assets and liabilities measured at fair value on a recurring basis: 
 
 
Fair Value Measurements Using
 
Effect of Counterparty Netting
 
Total
 
 
Level 1
 
Level 2
 
Level 3
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(in thousands)
As of September 30, 2018
 
 

 
 

 
 

 
 

 
 

Financial Assets
 
 

 
 

 
 

 
 

 
 

Commodity derivative instruments
 
$

 
$
6,176

 
$

 
$
(6,170
)
 
$
6

Financial Liabilities
 
 

 
 

 
 

 
 

 
 

Commodity derivative instruments
 
$

 
$
58,937

 
$

 
$
(6,170
)
 
$
52,767

As of December 31, 2017
 
 

 
 

 
 

 
 

 
 

Financial Assets
 
 

 
 

 
 

 
 

 
 

Commodity derivative instruments
 
$

 
$
12,105

 
$

 
$
(11,648
)
 
$
457

Financial Liabilities
 
 

 
 

 
 

 
 

 
 

Commodity derivative instruments
 
$

 
$
17,133

 
$

 
$
(11,648
)
 
$
5,485

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Nonfinancial assets and liabilities measured at fair value on a nonrecurring basis include certain nonfinancial assets and liabilities, as may be acquired in a business combination, and measurements of oil and natural gas property values for assessment of impairment.
The determination of the fair values of proved and unproved properties acquired in business combinations are estimated by discounting projected future cash flows. The factors used to determine fair value include estimates of economic reserves, future operating and development costs, future commodity prices, and a risk-adjusted discount rate. The Partnership has designated these measurements as Level 3. The Partnership’s fair value assessments for recent acquisitions are included in Note 4 – Oil and Natural Gas Properties Acquisitions.
Oil and natural gas properties are measured at fair value on a nonrecurring basis using the income approach when assessing for impairment. Proved and unproved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of those properties. When assessing producing properties for impairment, the Partnership compares the expected undiscounted projected future cash flows of the producing properties to the carrying amount of the producing properties to determine recoverability. When the carrying amount exceeds its estimated undiscounted future cash flows, the carrying amount is written down to its fair value, which is measured as the present value of the projected future cash flows of such properties. The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing of future production, future capital expenditures, and a risk-adjusted discount rate.
The Partnership’s estimates of fair value have been determined at discrete points in time based on relevant market data. These estimates involve uncertainty and cannot be determined with precision. There were no significant changes in valuation techniques or related inputs as of September 30, 2018 or December 31, 2017.
There were no assets measured at fair value on a nonrecurring basis, after initial recognition, for the three and nine months ended September 30, 2018 and 2017.


18


BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


NOTE 7 — CREDIT FACILITY
The Partnership maintains a senior secured revolving credit agreement, as amended (the “Credit Facility”). The Credit Facility has a maximum credit amount of $1.0 billion. The amount of the borrowing base is derived from the value of the Partnership’s oil and natural gas properties as determined by the lender syndicate using pricing assumptions that often differ from the current market for future prices. The borrowing base is redetermined semi-annually, usually in October and April.
Effective April 25, 2017, the borrowing base redetermination increased the borrowing base from $500.0 million to $550.0 million. On November 1, 2017, the Partnership amended and restated the credit agreement to create a swingline facility that permits short-term borrowings on same-day notice, make other changes to the hedging and restrictive covenants, and extend the maturity for a term of five years, which terminates on November 1, 2022. Effective May 4, 2018, the borrowing base was increased to $600.0 million and, effective October 31, 2018, the borrowing base was further increased to $675.0 million.
Borrowings under the Credit Facility bear interest at LIBOR plus a margin between 2.00% and 3.00%, or the Prime Rate plus a margin between 1.00% and 2.00%, with the margin depending on the borrowing base utilization. Effective October 31, 2018, the LIBOR margin was reduced to between 1.75% and 2.75% and the Prime Rate margin was reduced to between 0.75% and 1.75%.
The weighted-average interest rate of the Credit Facility was 4.75% and 4.06% as of September 30, 2018 and December 31, 2017, respectively. Accrued interest is payable at the end of each calendar quarter or at the end of each interest period, unless the interest period is longer than 90 days, in which case interest is payable at the end of every 90-day period. In addition, a commitment fee is payable at the end of each calendar quarter based on either a rate of 0.375% if the borrowing base utilization percentage is less than 50%, or 0.500% per annum if the borrowing base utilization percentage is equal to or greater than 50%. The Credit Facility is secured by substantially all of the Partnership’s producing properties.
The Credit Facility contains various limitations on future borrowings, leases, hedging, and sales of assets. Additionally, the Credit Facility requires the Partnership to maintain a current ratio of not less than 1.0:1.0 and a ratio of total debt to EBITDAX (Earnings before Interest, Taxes, Depreciation, Amortization, and Exploration) of not more than 3.5:1.0. As of September 30, 2018, the Partnership was in compliance with all financial covenants in the Credit Facility.
The aggregate principal balance outstanding was $402.0 million and $388.0 million at September 30, 2018 and December 31, 2017, respectively. The unused portion of the available borrowings under the Credit Facility was $198.0 million and $162.0 million at September 30, 2018 and December 31, 2017, respectively.
NOTE 8 — COMMITMENTS AND CONTINGENCIES
Environmental Matters
The Partnership’s business includes activities that are subject to U.S. federal, state, and local environmental regulations with regard to air, land, and water quality and other environmental matters.
The Partnership does not consider the potential remediation costs that could result from issues identified in any environmental site assessments to be significant to the consolidated financial statements, and no provision for potential remediation costs has been recorded.
Put Option Related to Noble Acquisition
By acquiring 100% of the issued and outstanding securities of Samedan, now NAMP Holdings, LLC, on November 28, 2017 as part of the Noble Acquisition, the Partnership acquired a 100% interest in Comin-Temin, LLC, now NAMP GP, LLC ("Holdings"), Comin 1989 Partnership LLLP, now NAMP 1, LP ("Comin"), and Temin 1987 Partnership LLLP, now NAMP 2, LP ("Temin"). Pursuant to certain co-ownership agreements, various co-owners hold undivided beneficial ownership interests in 47.34% and 44.39% of the minerals interests held of record by Holdings and Temin, respectively. Based on the terms of the co-ownership agreements, the co-owners each have an unconditional option to require Comin or Temin, as applicable, to purchase their beneficial ownership interest in the mineral interests held of record by Holdings or Temin, as applicable, at any time within 30 days of receiving such repurchase notice. The purchase price of the beneficial ownership interest shall be based on an

19


BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


evaluation performed by Comin or Temin, as applicable, in good faith. As of September 30, 2018, the Partnership had not received notice from any co-owner to exercise their repurchase option, and as such, no liability was recorded.
Litigation
From time to time, the Partnership is involved in legal actions and claims arising in the ordinary course of business. The Partnership believes existing claims as of September 30, 2018 will be resolved without material adverse effect on the Partnership’s financial condition or operations. 
NOTE 9 — INCENTIVE COMPENSATION
The table below summarizes incentive compensation expense recorded in general and administrative expenses in the consolidated statements of operations for the three and nine months ended September 30, 2018 and 2017:
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 
2018
 
2017
 
2018
 
2017
 
 
 
 
 
 
 
 
 
 
 
(in thousands)
Cash—short and long-term incentive plans
 
$
4,366

 
$
1,017

 
$
7,568

 
$
2,995

Equity-based compensation—restricted common and subordinated units
 
3,404

 
3,364

 
10,180

 
10,246

Equity-based compensation—restricted performance units
 
5,611

 
3,767

 
13,026

 
6,710

Board of Directors incentive plan
 
581

 
544

 
1,741

 
1,658

Total incentive compensation expense
 
$
13,962

 
$
8,692

 
$
32,515

 
$
21,609

 
NOTE 10 — PREFERRED UNITS
Series A Redeemable Preferred Units
As of September 30, 2018, there were no Series A redeemable preferred units outstanding, while as of December 31, 2017 there were 26,363 Series A redeemable preferred units outstanding with a carrying value of $27.0 million. This carrying value included accrued distributions of $0.7 million. The Series A redeemable preferred units are classified as mezzanine equity on the consolidated balance sheets since redemption was outside the control of the Partnership. The Series A redeemable preferred units were entitled to an annual distribution of 10% of the outstanding funded capital of the Series A redeemable preferred units, payable on a quarterly basis in arrears.
The Series A redeemable preferred units were convertible into common and subordinated units at any time at the option of the Series A redeemable preferred unitholders. The Series A redeemable preferred units had an adjusted conversion price of $14.2683 and an adjusted conversion rate of 30.3431 common units and 39.7427 subordinated units per redeemable preferred unit, which reflects the reverse split described in Note 1 – Business and Basis of Presentation and the capital restructuring related to the IPO.
For the year ended December 31, 201719,704 Series A redeemable preferred units were redeemed for $20.2 million, including accrued unpaid yield. For the year ended December 31, 20176,624 Series A redeemable preferred units totaling $6.6 million were converted into 200,996 common units and 263,247 subordinated units as a result of the mandatory conversion subsequent to December 31, 2016.
The Series A redeemable preferred unitholders had the option to elect to have the Partnership redeem, at face value, all remaining Series A redeemable preferred units, effective as of December 31, 2017, plus any accrued and unpaid distributions.  All Series A redeemable preferred units not redeemed by March 31, 2018 automatically converted to common and subordinated units effective as of January 1, 2018 or as soon as practicable thereafter.
For the nine months ended September 30, 2018, 2,115 Series A redeemable preferred units were redeemed for $2.1 million, including accrued unpaid yield, and 24,248 Series A redeemable preferred units totaling $24.2 million were converted into 735,758 common units and 963,681 subordinated units as a result of the mandatory conversion subsequent to December 31, 2017.

20


BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


Series B Cumulative Convertible Preferred Units
On November 28, 2017, the Partnership issued and sold in a private placement 14,711,219 Series B cumulative convertible preferred units representing limited partner interests in the Partnership to the Purchaser for a cash purchase price of $20.3926 per Series B cumulative convertible preferred unit, resulting in total proceeds of approximately $300 million.
The Series B cumulative convertible preferred units are entitled to an annual distribution of 7%, payable on a quarterly basis in arrears. For the eight quarters consisting of the quarter in respect of which the initial distribution is paid and the seven full quarters thereafter, the quarterly distribution may be paid, at the sole option of the Partnership, (i) in-kind in the form of additional Series B cumulative convertible preferred units (the "Series B PIK Units"), (ii) in cash, or (iii) in a combination of Series B PIK Units and cash. Beginning with the ninth quarter, all Series B cumulative convertible preferred unit distributions shall be paid in cash. The number of Series B PIK Units to be issued, if any, shall equal the quotient of the Series B cumulative convertible preferred unit distribution amount (or portion thereof) divided by the Series B cumulative convertible preferred unit purchase price of $20.3926.
The Series B cumulative convertible preferred units are convertible into common units of the Partnership on November 29, 2019 and once per quarter thereafter. At such time, the Series B cumulative convertible preferred units may be converted by each holder at its option, in whole or in part, into common units on a one-for-one basis, adjusted to give effect to any accrued but unpaid accumulated distributions on the applicable Series B cumulative convertible preferred units through the most recent declaration date. However, the Partnership shall not be obligated to honor any request for such conversion if such request does not involve an underlying value of common units of at least $10.0 million based on the closing trading price of common units on the trading day immediately preceding the conversion notice date, or such lesser amount to the extent such exercise covers all of a holder's Series B cumulative convertible preferred units.
The Series B cumulative convertible preferred units had a carrying value of $298.4 million and $295.4 million, including accrued distributions of $5.3 million and $1.9 million, as of September 30, 2018 and December 31, 2017, respectively. The Series B cumulative convertible preferred units are classified as mezzanine equity on the consolidated balance sheets since certain provisions of redemption are outside the control of the Partnership.


21


BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


NOTE 11 — EARNINGS PER UNIT    
The Partnership applies the two-class method for purposes of calculating earnings per unit (“EPU”). The holders of the Partnership’s restricted common and subordinated units have all the rights of a unitholder, including non-forfeitable distribution rights. As participating securities, the restricted common and subordinated units are included in the calculation of basic earnings per unit. For the periods presented, the amount of earnings allocated to these participating units was not material.
Net income (loss) attributable to the Partnership is allocated to the Partnership’s general partner and the common and subordinated unitholders in proportion to their pro rata ownership after giving effect to distributions, if any, declared during the period. The Series B cumulative convertible preferred units could be converted into approximately 15.0 million common units as of September 30, 2018.
At September 30, 2018, if the outstanding Series B cumulative convertible preferred units were converted to common units, the effect would be anti-dilutive; therefore, they are not included in the calculation of diluted EPU for the three and nine months ended September 30, 2018.
The Partnership’s restricted performance unit awards are contingently issuable units that are considered in the calculation of diluted EPU. The Partnership assesses the number of units that would be issuable, if any, under the terms of the arrangement if the end of the reporting period were the end of the contingency period. At September 30, 2018, there were no units related to the Partnership’s restricted performance unit awards included in the calculation of diluted EPU.
The following table sets forth the computation of basic and diluted earnings per common and subordinated unit:
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 
2018
 
2017
 
2018
 
2017
 
 
 
 
 
 
 
 
 
 
 
(in thousands, except per unit amounts)
NET INCOME (LOSS)
 
$
60,775

 
$
22,034

 
$
131,422

 
$
137,793

Net (income) loss attributable to noncontrolling interests
 
(22
)
 
20

 
(1
)
 
27

Distributions on Series A redeemable preferred units
 

 
(666
)
 
(25
)
 
(2,452
)
Distributions on Series B cumulative convertible preferred units
 
(5,250
)
 

 
(15,750
)
 

NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS
 
$
55,503

 
$
21,388

 
$
115,646

 
$
135,368

ALLOCATION OF NET INCOME (LOSS):
 
 
 
 

 
 
 
 

General partner interest
 
$

 
$

 
$

 
$

Common units
 
29,188

 
16,371

 
71,037

 
83,989

Subordinated units
 
26,315

 
5,017

 
44,609

 
51,379

 
 
$
55,503

 
$
21,388

 
$
115,646

 
$
135,368

NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:
 
 

 
 

 
 

 
 

Per common unit (basic)
 
$
0.27

 
$
0.16

 
$
0.67

 
$
0.86

Weighted average common units outstanding (basic)
 
106,706

 
101,623

 
105,254

 
97,777

Per subordinated unit (basic)
 
$
0.27

 
$
0.05

 
$
0.46

 
$
0.54

Weighted average subordinated units outstanding (basic)
 
96,329

 
95,388

 
96,021

 
95,269

Per common unit (diluted)
 
$
0.27

 
$
0.16

 
$
0.67

 
$
0.86

Weighted average common units outstanding (diluted)
 
106,706

 
101,623

 
105,254

 
97,777

Per subordinated unit (diluted)
 
$
0.27

 
$
0.05

 
$
0.46

 
$
0.54

Weighted average subordinated units outstanding (diluted)
 
96,329

 
95,388

 
96,021

 
95,269



22


BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


NOTE 12 — AT-THE-MARKET OFFERING PROGRAM

On May 26, 2017, the Partnership commenced an at-the-market offering program (the “ATM Program”) and in connection therewith entered into an Equity Distribution Agreement with Wells Fargo Securities, LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, and UBS Securities LLC, as Sales Agents (each a “Sales Agent” and collectively the “Sales Agents”). Pursuant to the terms of the ATM Program, the Partnership may sell, from time to time through the Sales Agents, the Partnership’s common units representing limited partner interests having an aggregate offering amount of up to $100,000,000. Sales of common units, if any, may be made in negotiated transactions or transactions that are deemed to be “at the market” offerings as defined in Rule 415 under the Securities Act of 1933, as amended (the “Securities Act”), including sales made directly on the New York Stock Exchange or sales made to or through a market maker other than on an exchange.
Under the terms of the ATM Program, the Partnership may also sell common units to one or more of the Sales Agents as principal for its own account at a price to be agreed upon at the time of sale. Any sale of common units to a Sales Agent as principal would be pursuant to the terms of a separate agreement between the Partnership and such Sales Agent.
The Partnership intends to use the net proceeds from any sales pursuant to the ATM Program, after deducting the Sales Agents’ commissions and the Partnership’s offering expenses, for general partnership purposes, which may include, among other things, repayment of indebtedness outstanding under the Partnership’s Credit Facility.
Common units sold pursuant to the Equity Distribution Agreement are offered and sold pursuant to the Partnership’s existing effective shelf-registration statement on Form S-3 (File No. 333-215857), which was declared effective by the SEC on February 8, 2017.
The Equity Distribution Agreement contains customary representations, warranties and agreements, indemnification obligations, including for liabilities under the Securities Act, other obligations of the parties and termination provisions.
For the nine months ended September 30, 2018, the Partnership sold 2,121,643 common units under the ATM Program for net proceeds of $38.4 million. As of September 30, 2018, the Partnership has raised net proceeds of $70.9 million under the ATM Program.
NOTE 13 — SUBSEQUENT EVENTS    
Effective October 31, 2018, the borrowing base of the Credit Facility was increased to $675.0 million from $600.0 million and the applicable margin rates were reduced, as discussed in Note 7 - Credit Facility.
On October 26, 2018, the Board of Directors of the Partnership's general partner approved a distribution for the three months ended September 30, 2018 of $0.37 per common unit and $0.37 per subordinated unit. Distributions will be payable on November 21, 2018 to unitholders of record at the close of business on November 14, 2018.
On November 5, 2018, the Board authorized a $75.0 million unit repurchase program. The unit repurchase program authorizes the Partnership to make repurchases on a discretionary basis as determined by management, subject to market conditions, applicable legal requirements, available liquidity, and other appropriate factors. The repurchase program does not obligate the Partnership to acquire any particular amount of common units and may be modified or suspended at any time and could be terminated prior to completion. The program will be funded from the Partnership's cash on hand or through borrowings under the credit facility. Any repurchased units will be canceled.



23


Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our unaudited consolidated financial statements and notes thereto presented in this Quarterly Report on Form 10-Q, as well as our audited financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2017. This discussion and analysis contains forward-looking statements that involve risks, uncertainties, and assumptions. Actual results may differ materially from those anticipated in these forward-looking statements as a result of a number of factors, including those set forth under “Cautionary Note Regarding Forward-Looking Statements” and “Part II, Item 1A. Risk Factors.”
Unless the context clearly indicates otherwise, references in this Quarterly Report on Form 10-Q to “BSM,” the “Partnership,” “we,” “our,” “us,” or similar terms for time periods prior to the IPO refer to Black Stone Minerals Company, L.P. and its subsidiaries, the predecessor for accounting purposes. For time periods subsequent to the IPO, these terms refer to Black Stone Minerals, L.P. and its subsidiaries.
Cautionary Note Regarding Forward-Looking Statements
Certain statements and information in this Quarterly Report on Form 10-Q 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;



24


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 filing.
For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see “Risk Factors” in our Annual Report on Form 10-K.
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.
Overview
We are one of the largest owners of oil and natural gas mineral interests in the United States. Our principal business is maximizing the value of our existing portfolio of mineral and royalty assets through active management and expanding our asset base through acquisitions of additional mineral and royalty interests. We maximize value through the marketing of our mineral assets for lease, creative structuring of 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 interests. Our primary business objective is to grow our reserves, production, and cash generated from operations over the long term, while paying, to the extent practicable, a quarterly distribution to our unitholders.
As of September 30, 2018, our mineral and royalty interests were located in 41 states and 64 onshore basins in the continental United States. These non-cost-bearing interests include ownership in over 55,000 producing wells. We also own non-operated working interests, a significant portion of which are on our positions where we also have a mineral and royalty interest. We recognize oil and natural gas revenue from our mineral and royalty and non-operated working interests in producing wells when control of the oil and natural gas produced is transferred to the customer and collectability of the sales price is reasonably assured. Our other sources of revenue include mineral lease bonus and delay rentals, which are recognized as revenue according to the terms of the lease agreements.
Recent Developments
Acquisitions
In the first nine months of 2018, we acquired mineral and royalty interests primarily in the Permian Basin and in East Texas for aggregate consideration of $109.6 million in cash and $22.5 million in our common units. Additional information regarding acquisitions is contained in Note 4 – Oil and Natural Gas Properties Acquisitions to our unaudited consolidated financial statements included herein for further discussion.

25


PepperJack Prospect
We have cumulatively spent approximately $13.1 million to drill two wells within our PepperJack prospect in Hardin and Liberty counties, Texas. The PepperJack A#1 well targeting the Lower Wilcox formation was drilled during the fourth quarter of 2017 and the first quarter of 2018. The PepperJack B#1 well, also targeting the Lower Wilcox formation, was drilled during the second quarter of 2018 to further delineate the prospect.
Based on the log results, we believe the PepperJack A#1 well is highly prospective and will be completed as a commercially productive well. The PepperJack B#1 well, which was a significant step-out from the PepperJack A#1 well, is not likely to be completed in the near term. Accordingly, we have recorded $6.8 million of capitalized costs for the PepperJack B#1 well to the Exploration expense line item of the consolidated statements of operations for the nine months ended September 30, 2018.
On September 21, 2018, we entered into an exploration agreement with a consortium of private exploration and production companies (the “Development Partners”) to further delineate and develop the PepperJack prospect. As part of the agreement, we assigned 75% of our working interest in the PepperJack A#1 well and acreage in the associated unit to the Development Partners and transferred our status as the operator of record. We received proceeds of $6.4 million for the assignment, which represented a reimbursement for 100% of the drilling costs and associated acreage, proceeds of $1.0 million for an option covering our minerals and leases in the PepperJack prospect area, and an overriding royalty interest in the PepperJack prospect area. The Development Partners will begin completion operations on the PepperJack A#1 well in the fourth quarter of 2018 and we will participate as a 25% non-operated working interest owner.
Business Environment
The information presented below is designed to give a broad overview of the oil and natural gas business environment as it affects us.

Commodity Prices
Oil and natural gas prices have been historically volatile based upon the dynamics of supply and demand. The U.S. Energy Information Administration ("EIA") forecasts that the WTI spot oil price will average $68.00 per Bbl in 2018 and $69.00 per Bbl in 2019 and that the Henry Hub spot natural gas prices will average $2.99 per MMBtu in 2018 and $3.12 per MMBtu in 2019.
To manage the variability in cash flows associated with the projected sale of our oil and natural gas production, we use various derivative instruments consisting of fixed-price swap contracts and costless collar contracts.
The following table reflects commodity prices at the end of each quarter presented:
 
 
2018
 
2017
Benchmark Prices1
 
Third Quarter
Second Quarter
 
First Quarter
 
Third Quarter
Second Quarter
 
First Quarter
WTI spot oil price ($/Bbl)
 
$
73.16

$
74.13

 
$
64.87

 
$
48.18

$
46.02

 
$
50.54

Henry Hub spot natural gas ($/MMBtu)
 
$
3.01

$
2.96

 
$
2.81

 
$
2.95

$
2.98

 
$
3.13

1    Source: EIA

26


Rig Count
As we are not the operator of record on any producing properties, drilling on our acreage is dependent upon the exploration and production companies that lease our acreage. In addition to drilling plans that we seek from our operators, we also monitor rig counts in an effort to identify existing and future leasing and drilling activity on our acreage.
The following table shows the rig count at the close of each quarter presented:
 
 
2018
 
2017
U.S. Rotary Rig Count1
 
Third Quarter
Second Quarter
 
First Quarter
 
Third Quarter
Second Quarter
 
First Quarter
Oil
 
863

858

 
797

 
750

756

 
662

Natural gas
 
189

187

 
194

 
189

184

 
160

Other
 
2

2

 
2

 
1


 
2

Total
 
1,054

1,047

 
993

 
940