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SEC Filings
10-Q
BLACK STONE MINERALS, L.P. filed this Form 10-Q on 11/07/2017
Entire Document
 
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, 2017
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, or a smaller reporting 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 November 1, 2017, there were 103,417,081 common limited partner units, 95,388,424 subordinated limited partner units, and 26,426 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, 2017
 
December 31, 2016
ASSETS
 
 

 
 

CURRENT ASSETS
 
 

 
 

Cash and cash equivalents
 
$
8,911

 
$
9,772

Accounts receivable
 
68,895

 
68,181

Commodity derivative assets
 
4,724

 

Prepaid expenses and other current assets
 
1,269

 
1,036

TOTAL CURRENT ASSETS
 
83,799

 
78,989

PROPERTY AND EQUIPMENT
 
 

 
 

Oil and natural gas properties, at cost, using the successful efforts method of accounting, includes unproved properties of $731,978 and $605,736 at September 30, 2017 and December 31, 2016, respectively
 
2,892,447

 
2,697,073

Accumulated depreciation, depletion, amortization, and impairment
 
(1,736,695
)
 
(1,652,930
)
Oil and natural gas properties, net
 
1,155,752

 
1,044,143

Other property and equipment, net of accumulated depreciation of $14,384 and $14,327 at September 30, 2017 and December 31, 2016, respectively
 
519

 
528

NET PROPERTY AND EQUIPMENT
 
1,156,271

 
1,044,671

DEFERRED CHARGES AND OTHER LONG-TERM ASSETS
 
6,000

 
5,167

TOTAL ASSETS
 
$
1,246,070

 
$
1,128,827

LIABILITIES, MEZZANINE EQUITY AND EQUITY
 
 

 
 

CURRENT LIABILITIES
 
 

 
 

Accounts payable
 
$
3,659

 
$
4,142

Accrued liabilities
 
38,336

 
50,952

Commodity derivative liabilities
 

 
16,237

Other current liabilities
 
302

 

TOTAL CURRENT LIABILITIES
 
42,297

 
71,331

LONG-TERM LIABILITIES
 
 

 
 

Credit facility
 
362,000

 
316,000

Accrued incentive compensation
 
2,883

 
1,485

Commodity derivative liabilities
 

 
482

Deferred revenue
 

 
518

Asset retirement obligations
 
13,909

 
13,350

Other long-term liability
 
6,592

 

TOTAL LIABILITIES
 
427,681

 
403,166

COMMITMENTS AND CONTINGENCIES (Note 8)
 


 


MEZZANINE EQUITY
 
 

 
 

Partners' equity - convertible redeemable preferred units, 26 and 53 units outstanding at September 30, 2017 and December 31, 2016, respectively
 
27,092

 
54,015

EQUITY
 
 

 
 

Partners' equity - general partner interest
 

 

Partners' equity - common units, 103,324 and 95,721 units outstanding at September 30, 2017 and December 31, 2016, respectively
 
608,998

 
489,023

Partners' equity - subordinated units, 95,388 and 95,164 units outstanding at September 30, 2017 and December 31, 2016, respectively
 
181,395

 
181,602

Noncontrolling interests
 
904

 
1,021

TOTAL EQUITY
 
791,297

 
671,646

TOTAL LIABILITIES, MEZZANINE EQUITY AND EQUITY
 
$
1,246,070

 
$
1,128,827

The accompanying notes are an integral part of these 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
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2017
 
2016
 
2017
 
2016
REVENUE
 
 

 
 

 
 

 
 

Oil and condensate sales
 
$
41,361

 
$
42,780

 
$
119,097

 
$
104,581

Natural gas and natural gas liquids sales
 
45,047

 
38,986

 
142,651

 
85,706

Gain (loss) on commodity derivative instruments
 
(9,341
)
 
7,813

 
35,387

 
(12,295
)
Lease bonus and other income
 
12,044

 
9,592

 
37,082

 
26,129

TOTAL REVENUE
 
89,111

 
99,171

 
334,217

 
204,121

OPERATING (INCOME) EXPENSE
 
 

 
 

 
 

 
 

Lease operating expense
 
4,569

 
5,007

 
12,906

 
14,179

Production costs and ad valorem taxes
 
11,549

 
9,228

 
35,314

 
23,301

Exploration expense
 
8

 
6

 
616

 
643

Depreciation, depletion, and amortization
 
29,204

 
28,731

 
84,483

 
79,654

Impairment of oil and natural gas properties
 

 

 

 
6,775

General and administrative
 
17,305

 
16,677

 
51,998

 
52,213

Accretion of asset retirement obligations
 
260

 
206

 
760

 
680

(Gain) loss on sale of assets, net
 

 

 
(931
)
 
(4,772
)
TOTAL OPERATING EXPENSE
 
62,895

 
59,855

 
185,146

 
172,673

INCOME (LOSS) FROM OPERATIONS
 
26,216

 
39,316

 
149,071

 
31,448

OTHER INCOME (EXPENSE)
 
 

 
 

 
 

 
 

Interest and investment income
 
(9
)
 
460

 
30

 
651

Interest expense
 
(4,172
)
 
(2,282
)
 
(11,660
)
 
(4,773
)
Other income (expense)
 
(1
)
 
41

 
352

 
148

TOTAL OTHER EXPENSE
 
(4,182
)
 
(1,781
)
 
(11,278
)
 
(3,974
)
NET INCOME (LOSS)
 
22,034

 
37,535

 
137,793

 
27,474

NET (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS
 
20

 
8

 
27

 
15

DISTRIBUTIONS ON REDEEMABLE PREFERRED UNITS
 
(666
)
 
(1,324
)
 
(2,452
)
 
(4,439
)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS
 
$
21,388

 
$
36,219

 
$
135,368

 
$
23,050

ALLOCATION OF NET INCOME (LOSS):
 
 

 
 

 
 

 
 

General partner interest
 
$

 
$

 
$

 
$

Common units
 
16,371

 
23,114

 
83,989

 
24,343

Subordinated units
 
5,017

 
13,105

 
51,379

 
(1,293
)
 
 
$
21,388

 
$
36,219

 
$
135,368

 
$
23,050

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

 
 

 
 

 
 

Per common unit (basic)
 
$
0.16

 
$
0.24

 
$
0.86

 
$
0.26

Weighted average common units outstanding (basic)
 
101,623

 
95,740

 
97,777

 
95,086

Per subordinated unit (basic)
 
$
0.05

 
$
0.14

 
$
0.54

 
$
(0.01
)
Weighted average subordinated units outstanding (basic)
 
95,388

 
95,189

 
95,269

 
95,125

Per common unit (diluted)
 
$
0.16

 
$
0.24

 
$
0.86

 
$
0.26

Weighted average common units outstanding (diluted)
 
101,623

 
96,011

 
97,777

 
95,619

Per subordinated unit (diluted)
 
$
0.05

 
$
0.14

 
$
0.54

 
$
(0.01
)
Weighted average subordinated units outstanding (diluted)
 
95,388

 
95,189

 
95,269

 
95,467

DISTRIBUTIONS DECLARED AND PAID:
 
 

 
 

 
 

 
 

Per common unit
 
$
0.3125

 
$
0.2875

 
$
0.8875

 
$
0.8125

Per subordinated unit
 
$
0.2088

 
$
0.1838

 
$
0.5763

 
$
0.5513


 The accompanying notes are an integral part of these 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, 2016
 
95,721

 
95,164

 
$
489,023

 
$
181,602

 
$
1,021

 
$
671,646

Restricted units granted, net of forfeitures
 
1,576

 

 

 

 

 

Equity-based compensation
 

 

 
26,430

 
(114
)
 

 
26,316

Conversion of redeemable preferred units
 
201

 
263

 
2,868

 
3,756

 

 
6,624

Repurchases of common and subordinated units
 
(427
)
 
(39
)
 
(7,553
)
 
(292
)
 

 
(7,845
)
Issuance of units for property acquisitions
 
4,341

 

 
71,592

 

 

 
71,592

Distributions
 

 

 
(87,651
)
 
(54,924
)
 
(90
)
 
(142,665
)
Charges to partners' equity for accrued distribution equivalent rights
 

 

 
(979
)
 

 

 
(979
)
Net income (loss)
 

 

 
85,243

 
52,577

 
(27
)
 
137,793

Issuance of common units, net of offering costs
 
1,912

 

 
31,267

 

 

 
31,267

Distributions on redeemable preferred units
 

 

 
(1,242
)
 
(1,210
)
 

 
(2,452
)
BALANCE AT SEPTEMBER 30, 2017
 
103,324

 
95,388

 
$
608,998

 
$
181,395

 
$
904

 
$
791,297

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

3

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


 
 
Nine Months Ended
 
 
September 30,
 
 
2017
 
2016
CASH FLOWS FROM OPERATING ACTIVITIES
 
 

 
 

Net income (loss)
 
$
137,793

 
$
27,474

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

 
 

Depreciation, depletion, and amortization
 
84,483

 
79,654

Impairment of oil and natural gas properties
 

 
6,775

Accretion of asset retirement obligations
 
760

 
680

Amortization of deferred charges
 
661

 
594

(Gain) loss on commodity derivative instruments
 
(35,387
)
 
12,295

Net cash received on settlement of commodity derivative instruments
 
12,339

 
39,220

Equity-based compensation
 
18,614

 
33,120

(Gain) loss on sale of assets, net
 
(931
)
 
(4,772
)
Changes in operating assets and liabilities:
 
 

 
 

Accounts receivable
 
(709
)
 
(23,144
)
Prepaid expenses and other current assets
 
(234
)
 
(862
)
Accounts payable and accrued liabilities
 
(3,940
)
 
(29,063
)
Deferred revenue
 
(1,670
)
 
(175
)
Settlement of asset retirement obligations
 
(113
)
 
(237
)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES
 
211,666

 
141,559

CASH FLOWS FROM INVESTING ACTIVITIES
 
 

 
 

Acquisitions of oil and natural gas properties
 
(89,030
)
 
(140,893
)
Additions to oil and natural gas properties
 
(40,680
)
 
(63,039
)
Purchases of other property and equipment
 
(118
)
 
(5
)
Proceeds from farmout of oil and gas properties
 
6,592

 

Proceeds from the sale of oil and natural gas properties
 
6,754

 
177

NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES
 
(116,482
)
 
(203,760
)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 

 
 

Borrowings under senior line of credit
 
208,500

 
304,500

Repayments of borrowings under senior line of credit
 
(162,500
)
 
(71,500
)
Distributions to Black Stone Minerals, L.P. common and subordinated unitholders
 
(142,575
)
 
(130,883
)
Distributions to redeemable preferred unitholders
 
(3,111
)
 
(5,061
)
Distributions to non-controlling interests
 
(90
)
 
(83
)
Proceeds from issuance of common units
 
31,267

 

Redemptions of redeemable preferred units
 
(19,641
)
 
(18,461
)
Loan origination fees
 
(50
)
 

Repurchases of common and subordinated units
 
(7,845
)
 
(24,696
)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES
 
(96,045
)
 
53,816

NET CHANGE IN CASH AND CASH EQUIVALENTS
 
(861
)
 
(8,385
)
CASH AND CASH EQUIVALENTS - beginning of the period
 
9,772

 
13,233

CASH AND CASH EQUIVALENTS - end of the period
 
$
8,911

 
$
4,848

SUPPLEMENTAL DISCLOSURE
 
 
 
 
Interest paid
 
$
11,041

 
$
4,060

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

4

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO 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. 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. 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 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, 2017, the Partnership’s mineral and royalty interests were located in 41 states and 64 onshore oil and natural gas producing basins of the continental United States, 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 2016 Annual Report on Form 10-K. The financial statements include the consolidated results of the Partnership. 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. 
In the opinion of management, all material 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. The results of operations for the nine months ended September 30, 2017 are not necessarily indicative of the results to be expected for the full year.
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.

5

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

The 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 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, 2016. There have been no changes in such policies or the application of such policies during the nine months ended September 30, 2017.
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 will supersede Accounting Standards Codification (“ASC”) 605, Revenue Recognition. Under the new standard, entities will be required to use judgment and make estimates, including identifying performance obligations in a contract, estimating the amount of variable consideration to include in the transaction price, allocating the transaction price to each separate performance obligation, and determining when an entity satisfies its performance obligations. The new standard also requires more detailed disclosures related to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The new guidance is effective for fiscal years and interim periods beginning after December 15, 2017, with early adoption permitted. The standard allows for either “full retrospective” adoption, meaning that the standard is applied to all of the periods presented with a cumulative catch-up adjustment as of the earliest period presented, or “modified retrospective” adoption, meaning the standard is applied only to the most current period presented in the financial statements with a cumulative catch-up as of the current period. 
The Partnership intends to use the modified retrospective adoption approach and does not plan to early adopt. The Partnership has completed its review of a representative sample of revenue contracts covering its material revenue streams that was designed to evaluate any potential changes in revenue recognition upon adoption of the new standard, and based on evaluations to-date, the implementation of the new standard is not anticipated to have a material impact on the consolidated financial statements. The Partnership is concurrently evaluating the information technology and internal control changes that will be required to implement the new standard based on the results of its contract review process. The Partnership continues to evaluate the disclosure requirements of this new guidance, and expects to fully complete its evaluation of the impacts of ASU 2014-09 to the consolidated financial statements and related disclosures by 2017 year end.
In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires lessees to recognize the lease assets and lease liabilities classified as operating leases on the balance sheet. The new 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 Partnership will use the modified retrospective adoption approach and does not plan to early adopt. Based on current evaluations to-date, the Partnership does not anticipate this new guidance will have a material impact on its 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 2016, the FASB issued ASU 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments (Topic 230), to address diversity in practice of how certain cash receipts and cash payments are currently presented and classified in the statement of cash flows. The ASU addresses the topic of separately identifiable cash flows and application of the predominance principle. Classification of cash receipts and payments that have aspects of more than one class of cash flows should be determined first by applying specific guidance, and then by the nature of each separately identifiable cash flow. In situations where there is an absence of specific guidance and the cash flow has aspects of more than one type of classification, the predominance principle should be applied whereby the cash flow classification should depend on

6

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

the activity that is likely to be the predominant source or use of cash flows. The new guidance is effective for public business entities for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, and early adoption is permitted. The Partnership intends to use the retrospective transition method, 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.
In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805), which clarifies the definition of a business in order to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The FASB issued this ASU in response to stakeholder feedback that the current definition of a business in ASC 805 is being applied too broadly and the application of the guidance was not resulting in consistent application in a cost-effective manner. This ASU provides a screen whereby a transaction will be accounted for as an asset purchase (or disposal) if substantially all of the fair value of the gross assets acquired (disposed) is concentrated in a single identifiable asset or a group of similar identifiable assets. If the screen is not met, the entity will evaluate whether it is a business acquisition under revised criteria. The ASU is effective for public business entities for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted under certain circumstances. The amendments in this ASU should be applied prospectively as of the beginning of the period of adoption. 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.
In May 2017, the FASB issued ASU 2017-09 Compensation-Stock Compensation: Scope of Modification Accounting (Topic 718). The update provides guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting under Topic 718. The amendments require an entity to account for the effects of a modification unless all of the following conditions are met:

The fair value (or intrinsic or calculated value if elected) of the modified award is the same as the value of the original award immediately before the original award was modified.
The vesting conditions of the modified award are the same as the vesting conditions of the original award immediately before the original award is modified.
The classification of the modified award as an equity instrument or a liability instrument is the same as the classification of the original award immediately before the original award is modified.
This ASU is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. The amendments in this ASU should be applied prospectively to an award modified on or after the adoption date. 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—ASSET RETIREMENT OBLIGATIONS
The asset retirement obligations (“ARO”) liability reflects the present value of estimated costs of dismantlement, removal, site reclamation, and similar activities associated with the Partnership’s working-interest oil and natural gas properties. The Partnership utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. The Partnership estimates the ultimate productive life of its properties, a credit-adjusted risk-free rate, and an inflation factor in order to determine the current present value of these obligations. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and natural gas property balance. The following table describes changes to the Partnership’s ARO liability during the period:

7

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

 
For the nine months ended
 
September 30, 2017
 
(In thousands)
Beginning asset retirement obligations
$
13,350

  Liabilities incurred
290

  Liabilities settled
(113
)
  Accretion expense
760

  Dispositions
(5
)
  Revisions
(71
)
Ending asset retirement obligations
$
14,211

  Current asset retirement obligations
$
302

  Non-current asset retirement obligations
$
13,909

 
 
NOTE 4—ACQUISITIONS AND DISPOSITIONS
    
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.
2017 Acquisitions
During the nine months ended September 30, 2017, the Partnership closed on multiple acquisitions of mineral and royalty interests in the Delaware Basin and East Texas, which also included producing properties.
The following table summarizes the asset acquisitions which included producing properties:
    

Proved
Unproved
Net Working Capital
Total Fair Value
Acquisition-Related Costs1

Cash
Fair Value of Common Units Issued

(in thousands)
January
$
5,135

$
34,008

$
263

$
39,406
 
$
1,162


$
27,380

$
12,026

June
5,006

45,477


50,483
 
1,468


4,802

45,681

August
3,277

9,984


13,261
 
89


4,289

8,972

September
3,120



3,120
 


3,120


   Total fair value
$
16,538

$
89,469

$
263

$
106,270
 
$
2,719


$
39,591

$
66,679

1 Acquisition-related costs were expensed and included in the general and administrative line item of the 2017 consolidated statement of operations.
In addition, the Partnership acquired mineral and royalty interests from various sellers in East Texas as follows:
        

Unproved
Cash
Fair Value of Common Units Issued

(in thousands)
Q1 2017
$
21,189

$
21,017

$
172

Q2 2017
13,329

13,329


Q3 2017
19,946

15,205

4,741


$
54,464

$
49,551

$
4,913



8

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

The cash portion of all acquisitions during the nine months ended September 30, 2017 was funded via borrowings under the Partnership's credit facility.
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 and Bossier shale 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. A total of 18 wells are anticipated to be drilled over an initial phase, beginning with wells spud after January 1, 2017. At its option, Canaan may participate in two additional phases with each phase continuing for the lesser of two years or until an additional 20 wells have been drilled. During the first three phases of the agreement, Canaan will commit on a phase-by-phase basis and fund 80% of the Partnership's drilling and completion costs and will be assigned 80% of the Partnership's working interests in such wells (40% working interest on an 8/8ths basis). After the third phase, Canaan can earn 40% of the Partnership’s working interest (20% working interest on an 8/8ths basis) in additional wells drilled in the area by continuing to fund 40% of the Partnership's costs for those wells on a well-by-well basis. The Partnership will receive an overriding royalty interest (“ORRI”) before payout and an increased ORRI after payout on all wells drilled under the agreement. The execution of this agreement is anticipated to offset the Partnership's future capital expenditures by approximately $30 to $35 million in 2017 and by an average of $40 to $50 million annually during the term of the agreement.
2016 Acquisitions
    
During the nine months ended September 30, 2016, the Partnership acquired producing oil and natural gas properties and unproved acreage across a diverse oil and natural gas mineral asset package, including an acquisition in June 2016 in the DJ Basin. The following table summarizes the fair values assigned to the properties acquired:

Proved
Unproved
Net Working Capital
ARO
Total Fair Value

Cash

(in thousands)
June
$
39,735

$
79,827

$
2,064

$
(50
)
$
121,576


$
121,576

The Partnership also acquired unproved mineral and royalty interests in the Permian Basin and Midland Basin for $10 million and $8.3 million in cash, respectively. Additionally, throughout 2016, the Partnership funded certain other oil and natural gas asset acquisitions for an aggregate amount of $1.0 million in cash. All 2016 acquisition transactions were funded via borrowings under the Partnership's credit facility.
NOTE 5—DERIVATIVES AND 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 fixed-price-swap contracts, costless collars, 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.
As of September 30, 2017, the Partnership’s open derivative contracts consisted of only fixed-price-swap contracts. A fixed-price-swap contract between the Partnership and the counterparty specifies a fixed 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, 2017 and December 31, 2016. See Note 6 – Fair Value Measurement 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, 2017, the Partnership had nine counterparties, all of which are rated Baa1 or better by Moody’s. Seven of the Partnership's counterparties are lenders under the Partnership's credit facility. The Partnership would have been at risk of losing a fair value amount of $7.2 million had the Partnership's counterparties as a group been unable to fulfill their obligations as of September 30, 2017

9

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

The table below summarizes the fair value and classification of the Partnership’s derivative instruments:

As of September 30, 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
 
$
5,338

 
$
(614
)
 
$
4,724

Long-term asset
 
Deferred charges and other
long-term assets
 
1,822

 
(217
)
 
1,605

Total assets
 
 
 
$
7,160

 
$
(831
)
 
$
6,329

Liabilities:
 
 
 
 

 
 

 
 

Current liability
 
Commodity derivative liabilities
 
$
614

 
$
(614
)
 
$

Long-term liability
 
Commodity derivative liabilities
 
217

 
(217
)
 

Total liabilities
 
 
 
$
831

 
$
(831
)
 
$

 
As of December 31, 2016
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
 
$
3,879

 
$
(3,879
)
 
$

Long-term asset
 
Deferred charges and other
long-term assets
 

 

 

Total assets
 
 
 
$
3,879

 
$
(3,879
)
 
$

Liabilities:
 
 
 
 

 
 

 
 

Current liability
 
Commodity derivative liabilities
 
$
20,116

 
$
(3,879
)
 
$
16,237

Long-term liability
 
Commodity derivative liabilities
 
482

 

 
482

Total liabilities
 
 
 
$
20,598

 
$
(3,879
)
 
$
16,719

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. Changes in the fair value of the Partnership’s commodity derivative instruments (both assets and liabilities) are as follows:
 
 
For the Nine Months Ended September 30,
Derivatives not designated as hedging instruments
 
2017
 
2016
 
 
(In thousands)
Beginning fair value of commodity derivative instruments
 
$
(16,719
)
 
$
64,534

Gain (loss) on oil derivative instruments
 
18,306

 
(8,906
)
Gain (loss) on natural gas derivative instruments
 
17,081

 
(3,389
)
Net cash received on settlements of oil derivative
   instruments
 
(10,682
)
 
(23,034
)
Net cash received on settlements of natural gas
   derivative instruments
 
(1,657
)
 
(16,186
)
Net change in fair value of commodity derivative
   instruments
 
23,048

 
(51,515
)
Ending fair value of commodity derivative instruments
 
$
6,329

 
$
13,019


10

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

The Partnership had the following open derivative contracts for oil as of September 30, 2017:
 
 

 

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

 
 

 
 

 
 

2017
 
 

 
 

 
 

 
 

Third Quarter
 
172,000

 
$
53.31

 
$
52.40

 
$
55.23

Fourth Quarter
 
687,000

 
53.21

 
52.02

 
55.23

2018
 


 


 


 


First Quarter
 
611,000

 
$
54.18

 
$
52.09

 
$
55.05

Second Quarter
 
573,000

 
54.16

 
52.09

 
54.90

Third Quarter
 
541,000

 
54.16

 
51.85

 
54.90

Fourth Quarter
 
502,000

 
54.22

 
51.85

 
54.90

The Partnership had the following open derivative contracts for natural gas as of September 30, 2017:
 
 

 

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

 
 

 
 

 
 

2017
 
 

 
 

 
 

 
 

Fourth Quarter
 
13,130,000

 
$
3.13

 
$
2.92

 
$
3.57

2018
 


 


 


 


First Quarter
 
12,570,000

 
$
3.06

 
$
2.96

 
$
3.45

Second Quarter
 
11,340,000

 
3.03

 
2.86

 
3.23

Third Quarter
 
9,630,000

 
3.02

 
2.90

 
3.23

Fourth Quarter
 
8,210,000

 
3.01

 
2.90

 
3.23


Subsequent to September 30, 2017, the Partnership entered into the following oil derivative contracts:






Range (Per Bbl)
Period and Type of Contract

Volume
(Bbl)

Weighted Average Price
(Per Bbl)

Low

High
Oil Swap Contracts:








2017








Fourth Quarter

30,000


$
56.51


$
55.87


$
57.15

2018








First Quarter

130,000


$
55.02


$
53.99


$
57.15

Second Quarter

175,000


54.73


53.99


56.75

Third Quarter

215,000


54.71


53.99


55.87

Fourth Quarter

255,000


54.22


52.82


55.87

2019








First Quarter

165,000


$
53.58


$
52.82


$
54.02

Second Quarter

165,000


53.58


52.82


54.02

Third Quarter

165,000


53.58


52.82


54.02

Fourth Quarter

165,000


53.58


52.82


54.02





11

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

Additionally, subsequent to September 30, 2017, the Partnership entered into the following natural gas derivative contracts:
    






Range (Per MMBtu)
Period and Type of Contract

Volume
(MMBtu)

Weighted Average Price
(per MMBtu)

Low

High
Natural Gas Swap Contracts:

 


 


 


 

2018












First Quarter

1,020,000


$
3.11


$
3.01


$
3.21

Second Quarter

2,320,000


3.00


2.93


3.04

Third Quarter

3,970,000


3.00


2.93


3.04

Fourth Quarter

5,420,000


3.00


2.92


3.04

2019








First Quarter

3,600,000


$
2.91


$
2.90


$
2.93

Second Quarter

3,600,000


2.91


2.90


2.93

Third Quarter

3,600,000


2.91


2.90


2.93

Fourth Quarter

3,600,000


2.91


2.90


2.93




NOTE 6—FAIR VALUE MEASUREMENT
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 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, 2017 or the year ended December 31, 2016.
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, 2017 and December 31, 2016 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.

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 – Derivatives and Financial Instruments for further discussion.

12

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

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
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
 
Total
 
 
(In thousands)
As of September 30, 2017
 
 

 
 

 
 

 
 

 
 

Financial Assets
 
 

 
 

 
 

 
 

 
 

Commodity derivative instruments
 
$

 
$
7,160

 
$

 
$
(831
)
 
$
6,329

Financial Liabilities
 
 

 
 

 
 

 
 

 
 

Commodity derivative instruments
 
$

 
$
831

 
$

 
$
(831
)
 
$

As of December 31, 2016
 
 

 
 

 
 

 
 

 
 

Financial Assets
 
 

 
 

 
 

 
 

 
 

Commodity derivative instruments
 
$

 
$
3,879

 
$

 
$
(3,879
)
 
$

Financial Liabilities
 
 

 
 

 
 

 
 

 
 

Commodity derivative instruments
 
$

 
$
20,598

 
$

 
$
(3,879
)
 
$
16,719


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 – Acquisitions and Dispositions.
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 economic reserves, future operating and development costs, future commodity prices, 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, 2017 or December 31, 2016.
The following table presents information about the Partnership’s assets measured at fair value on a nonrecurring basis:

13

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

 
 
Fair Value Measurements Using1
 
Net Book
Value
1
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
 
Impairment
 
 
(In thousands)
Three months ended September 30, 2017
 
 

 
 

 
 

 
 

 
 

Impaired oil and natural gas properties
 
$


$

 
$

 
$

 
$

Three months ended September 30, 2016
 
 
 
 
 
 
 
 
 
 
Impaired oil and natural gas properties
 
$

 
$

 
$

 
$

 
$

Nine months ended September 30, 2017
 
 
 
 
 
 
 
 
 
 
Impaired oil and natural gas properties
 
$


$

 
$

 
$

 
$

Nine months ended September 30, 2016
 
 
 
 
 
 
 
 
 
 
Impaired oil and natural gas properties
 
$


$

 
$
3,042

 
$
9,817

 
$
6,775

1 Amounts represent value on the dates of assessment.
 
 
NOTE 7—CREDIT FACILITY
The Partnership maintains a senior secured revolving credit agreement, as amended (the “Senior Line of Credit”). The Senior Line of Credit 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. Drawings on the Senior Line of Credit are used for the acquisition of oil and natural gas properties and for other general business purposes.
Effective April 15, 2016, the borrowing base was $450.0 million. The Partnership's fall 2016 borrowing base redetermination process resulted in an increase in the borrowing base to $500.0 million, which became effective October 31, 2016. Effective April 25, 2017, the borrowing base redetermination resulted in an increase to $550.0 million.
On November 1, 2017, the Partnership amended and restated the credit agreement to extend the maturity thereof for a term of five years, create a swingline facility and make other changes to the hedging and restrictive covenants. There was no change to the borrowing base. The Senior Line of Credit now terminates on November 1, 2022.
Prior to October 31, 2016, borrowings under the Senior Line of Credit bore interest at LIBOR plus a margin between 1.50% and 2.50%, or the Prime Rate plus a margin between 0.50% and 1.50%, with the margin depending on the borrowing base utilization percentage. The Prime Rate was determined to be the higher of the financial institution’s prime rate or the federal funds effective rate plus 0.50% per annum.
Effective October 31, 2016, borrowings under the Senior Line of Credit bore 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.
The weighted-average interest rate of the Senior Line of Credit was 3.74% and 3.26% as of September 30, 2017 and December 31, 2016, 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 Senior Line of Credit is secured by substantially all of the Partnership’s producing oil and natural gas assets.
The Senior Line of Credit contains various limitations on future borrowings, leases, hedging, and sales of assets. Additionally, the Senior Line of Credit 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, 2017, the Partnership was in compliance with all financial covenants for the Senior Line of Credit.
The aggregate principal balance outstanding was $362.0 million and $316.0 million at September 30, 2017 and December 31, 2016, respectively. The unused portion of the available borrowings under the Senior Line of Credit was $188.0 million and $184.0 million at September 30, 2017 and December 31, 2016, respectively.
 

14

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

 
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 made.
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, 2017 will be resolved without material adverse effect on the Partnership’s financial condition or operations.
 
 
NOTE 9—INCENTIVE COMPENSATION
On January 7, 2017, the Compensation Committee of the Board of Directors of the Partnership’s general partner (the “Board”) approved a special grant of 312,825 restricted common units to Thomas L. Carter, Jr., the President and Chief Executive Officer of the Partnership’s general partner. Such restricted common units are subject to limitations on transferability, customary forfeiture provisions, and service-based graded vesting requirements through January 7, 2020.
On January 11, 2017, each non-employee director on the Board, other than Robert E. W. Sinclair, was granted 9,095 fully vested common units for service during 2016. Mr. Sinclair was granted 3,653 fully vested common units for services during 2016 prior to his resignation from the Board. On July 28, 2017, Mr. William Randall, the newly elected member of the Board, was issued 6,426 fully vested common units.
On February 15, 2017, the Compensation Committee of the Board approved a grant of awards to each of the Partnership’s executive officers and certain other employees. These awards consisted of 438,067 restricted common units and 438,067 restricted performance units (in the form of phantom units) with distribution equivalent rights. The restricted common units are subject to limitations on transferability, customary forfeiture provisions, and service-based graded vesting requirements through January 7, 2020.
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, 2017 and 2016, respectively:
 
 
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
Incentive compensation expense
 
2017
 
2016
 
2017
 
2016
 
 
(In thousands)
 
(In thousands)
Cash—long-term incentive plan
 
$
359

 
$
580

 
$
995

 
$
2,990

Equity-based compensation—restricted common and subordinated units
 
3,364

 
4,487

 
10,246

 
10,420

Equity-based compensation—restricted performance units
 
3,767

 
3,066

 
6,710

 
11,105

Board of Directors incentive plan
 
544

 
428

 
1,658

 
1,385

Total incentive compensation expense
 
$
8,034

 
$
8,561

 
$
19,609

 
$
25,900



 
NOTE 10—REDEEMABLE PREFERRED UNITS
The Partnership had 26,426 and 52,691 redeemable preferred units outstanding with a carrying value of $27.1 million and $54.0 million as of September 30, 2017 and December 31, 2016, respectively. The aforementioned amounts included accrued distributions of $0.7 million as of September 30, 2017 and $1.3 million as of December 31, 2016. The redeemable preferred units are classified as mezzanine equity on the consolidated balance sheets since redemption is outside the control of

15

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

the Partnership. The redeemable preferred units are entitled to an annual distribution of 10% of the outstanding funded capital of the redeemable preferred units, payable on a quarterly basis in arrears.
The redeemable preferred units are convertible into common and subordinated units at any time at the option of the redeemable preferred unitholders. The redeemable preferred units have 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.
The redeemable preferred unitholders can elect to have the Partnership redeem, at face value, all remaining redeemable preferred units as of December 31, 2017, plus any accrued and unpaid distributions.  All redeemable preferred units not redeemed as of 2017 year end shall automatically convert to common and subordinated units during the first quarter of 2018.
For the nine months ended September 30, 2017, 19,641 redeemable preferred units were redeemed for $20.1 million, including accrued unpaid yield, and 6,624 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. For the year ended December 31, 2016, 6,064 redeemable preferred units totaling $6.1 million were converted into the equivalent of 184,006 common units and 240,986 subordinated units on an adjusted basis.

16

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO 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 redeemable preferred units could be converted into 0.8 million common units and 1.0 million subordinated units as of September 30, 2017. At September 30, 2017, if the outstanding redeemable preferred units were converted to common and subordinated units, the effect would be anti-dilutive. 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, 2017, 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:
 
 
For the Three Months Ended
September 30,
 
For the Nine Months Ended
September 30,
 
 
2017
 
2016
 
2017
 
2016
 
 
(In thousands, except per unit  amounts)
 
(In thousands, except per unit  amounts)
NET INCOME (LOSS)
 
$
22,034

 
$
37,535

 
$
137,793

 
$
27,474

NET (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS
 
20

 
8

 
27

 
15

DISTRIBUTIONS ON REDEEMABLE PREFERRED UNITS
 
(666
)
 
(1,324
)
 
(2,452
)
 
(4,439
)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS
 
$
21,388

 
$
36,219

 
$
135,368

 
$
23,050

ALLOCATION OF NET INCOME (LOSS):
 
 

 
 

 
 

 
 

General partner interest
 
$

 
$

 
$

 
$

Common units
 
16,371

 
23,114

 
83,989

 
24,343

Subordinated units
 
5,017

 
13,105

 
51,379

 
(1,293
)
 
 
$
21,388

 
$
36,219

 
$
135,368

 
$
23,050

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

 
 

 
 

 
 

Per common unit (basic)
 
$
0.16

 
$
0.24

 
$
0.86

 
$
0.26

Weighted average common units outstanding (basic)
 
101,623

 
95,740

 
97,777

 
95,086

Per subordinated unit (basic)
 
$
0.05

 
$
0.14

 
$
0.54

 
$
(0.01
)
Weighted average subordinated units outstanding (basic)
 
95,388

 
95,189

 
95,269

 
95,125

Per common unit (diluted)
 
$
0.16

 
$
0.24

 
$
0.86

 
$
0.26

Weighted average common units outstanding (diluted)
 
101,623

 
96,011

 
97,777

 
95,619

Per subordinated unit (diluted)
 
$
0.05

 
$
0.14

 
$
0.54

 
$
(0.01
)
Weighted average subordinated units outstanding (diluted)
 
95,388

 
95,189

 
95,269

 
95,467






17

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO 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 price 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 Securities and Exchange Commission 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.
Through September 30, 2017, the Partnership sold 1.9 million common units under the ATM Program for net proceeds of $31.3 million.

NOTE 13—SUBSEQUENT EVENTS    

On November 1, 2017, the Partnership amended and restated its credit agreement, as discussed further in Note 7Credit Facility.    

On November 6, 2017, the Board approved a distribution for the three months ended September 30, 2017 of $0.3125 per common unit and $0.20875 per subordinated unit. Distributions will be payable on November 24, 2017 to unitholders of record at the close of business on November 17, 2017.

Additionally, on November 6, 2017, the Partnership entered into oil and natural gas commodity derivative contracts, as summarized in Note 5Derivatives and Financial Instruments.

18




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, 2016. 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;


19


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 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 growing quarterly distribution to our unitholders.
As of September 30, 2017, 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 approximately 53,000 producing wells. We also own non-operated working interests, largely on our mineral and royalty interests. We recognize oil and natural gas revenue from our mineral and royalty and non-operated working interests in producing wells when the oil and natural gas production from the associated acreage is sold. Our other sources of revenue include mineral lease bonus and delay rentals, which are recognized as revenue according to the terms of the lease agreements.
Recent Developments

Acquisitions
During the first nine months of 2017, we closed numerous acquisitions consisting of various mineral and royalty interests in several Texas counties. In the first quarter of 2017, we acquired mineral and royalty interests in East Texas prospective for the Haynesville and Bossier shales for a total of $17.6 million in cash and $0.2 million in our common units, as well as mineral and royalty interests in the Delaware Basin for $30.8 million in cash and $12.0 million in common units. In the second quarter of 2017, we acquired additional mineral and royalty interests in East Texas for $18.1 million in cash and $45.7 million in our common units, primarily through the acquisition of the Angelina County Lumber Company. In the third quarter of 2017, we acquired additional mineral and royalty interests in East Texas for $22.2 million in cash and $13.7 million in our common units, as well as mineral and royalty interests in the Anadarko Basin for $0.4 million in cash. Additional information regarding acquisitions is contained in Note 4 - Acquisitions and Dispositions to our unaudited consolidated financial statements included herein for further discussion.



20


At-the-Market Offering Program

In the second quarter of 2017, we commenced an at-the-market offering program (the “ATM Program”) and in connection therewith entered into an Equity Distribution Agreement. The ATM Program permits us from time to time through our Sales Agents to sell our common units having an aggregate offering price of up to $100,000,000. We intend to use the net proceeds from any sales pursuant to the ATM Program, after deducting commissions and offering expenses, for general partnership purposes, which may include, among other things, repayment of indebtedness outstanding under our credit facility. Common units to be sold pursuant to the Equity Distribution Agreement will be offered and sold pursuant to our existing effective shelf-registration statement on Form S-3 (File No. 333-215857), which was declared effective by the Securities and Exchange Commission on February 8, 2017. Proceeds, net of commissions and expenses, of these sales through September 30, 2017 amounted to $31.3 million. See Note 12 - At-the-Market Offering Program to our unaudited consolidated financial statements included herein for further discussion.

Farmout Agreement

On February 21, 2017, we announced that we entered into a farmout agreement with Canaan Resource Partners ("Canaan", and such farmout, the "Canaan Farmout"), which covers certain Haynesville and Bossier shale acreage in San Augustine County, Texas operated by XTO Energy Inc. We have an approximate 50% working interest in the acreage. A total of 18 wells are anticipated to be drilled over an initial phase, beginning with wells spud after January 1, 2017. At its option, Canaan may participate in two additional phases with each phase continuing for the lesser of two years or until 20 wells have been drilled. During the first three phases of the agreement, Canaan will commit on a phase-by-phase basis and fund 80% of our drilling and completion costs and will be assigned 80% of our working interests in such wells (40% working interest on an 8/8ths basis). After the third phase, Canaan can earn 40% of our working interest (20% working interest on an 8/8ths basis) in additional wells drilled in the area by continuing to fund 40% of our costs for those wells on a well-by-well basis. We will receive a base overriding royalty interest (“ORRI”) before payout and an additional ORRI after payout on all wells drilled under the agreement. The execution of this agreement is anticipated to offset our future capital expenditures by approximately $40 to $50 million annually during the term of the agreement.

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. U.S. crude oil and petroleum product markets were significantly disrupted by Hurricane Harvey's landfall in Texas and Louisiana at the end of August. At the peak of disruption, the Energy Information Agency ("EIA") estimates that 3.9 million barrels per day of U.S. Gulf Coast refining capacity was taken offline. Oil transportation capacity in the region was also restricted after the hurricane. According to the EIA, producers also curtailed production in the Eagle Ford region of South Texas; however production declines in that area were offset by growth in other areas of the lower 48 states onshore region. In early to mid-September, the petroleum supply system on the Gulf Coast began to return to service. The EIA reported that lower refinery demand for crude oil in the Gulf Coast region more than offset reductions in crude oil production as a result of the storm, which contributed to lower West Texas Intermediate ("WTI") prices and simultaneously contributed to higher product prices.
Higher crude oil prices in September reflected declining global inventories, thus increasing expectations for global economic and oil demand growth; falling production from the Organization of the Petroleum Exporting countries contributed to global oil inventory withdrawals in 2017. The EIA believes the appearance of strengthening economic conditions could contribute to oil demand growth in 2018. The EIA forecasts that the WTI spot price will average $50.50 per barrel in 2018.
As rising natural gas production is keeping pace with increasing consumption and demand for exports, particularly for liquefied natural gas ("LNG"), the EIA projects a balanced market from the last quarter of 2017 through 2018. The EIA expects LNG export capacity to increase, with LNG exports projected to exceed 3 Bcf per day in 2018. In addition, increased takeaway capacity out of the Marcellus/Utica shale plays, as a result of several new pipeline projects, is anticipated to increase overall production. The EIA estimates that Henry Hub natural gas spot prices will rise from an annual average of $3.03 per MMbtu in 2017 to $3.19 per MMbtu in 2018.
To manage the variability in cash flows associated with the projected sale of our oil and natural gas production, we use various derivative instruments, which have recently consisted exclusively of fixed-price swap contracts.
 

21


The following table reflects commodity prices at the end of each quarter presented:

 
 
2017
 
2016
Benchmark Prices
 
Third
Quarter
 
Second
Quarter
 
First Quarter
 
Third
Quarter
 
Second
Quarter
 
First Quarter
WTI spot oil price ($/Bbl)
 
$
48.18

 
$
46.02

 
$
50.54

 
$
47.72

 
$
48.27

 
$
36.94

Henry Hub spot natural gas ($/MMBtu)
 
$
2.95

 
$
2.98

 
$
3.13

 
$
2.84

 
$
2.94

 
$
1.98

 
Source: EIA
Rig Count
As we are the operator of record on only three 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:
 
 
2017
 
2016
U.S. Rotary Rig Count
 
Third
Quarter
 
Second
Quarter
 
First Quarter
 
Third
Quarter
 
Second
Quarter
 
First Quarter
Oil
 
750

 
756

 
662

 
425

 
330

 
372

Natural gas
 
189

 
184

 
160

 
96

 
90

 
92

Other
 
1

 

 
2

 
1

 
1

 

Total
 
940

 
940

 
824

 
522

 
421

 
464

 
Source: Baker Hughes Incorporated
Natural Gas Storage
A substantial portion of our revenue is derived from sales of oil production attributable to our interests; however, the majority of our production is natural gas. Natural gas prices are significantly influenced by storage levels throughout the year. Accordingly, we monitor the natural gas storage reports regularly in the evaluation of our business and its outlook.
Historically, natural gas supply and demand fluctuates on a seasonal basis. From April to October, when the weather is warmer and natural gas demand is lower, natural gas storage levels generally increase. From November to March, storage levels typically decline as utility companies draw natural gas from storage to meet increased heating demand due to colder weather. In order to maintain sufficient storage levels for increased seasonal demand, a portion of natural gas production during the summer months must be used for storage injection. The portion of production used for storage varies from year to year depending on the demand from the previous winter and the demand for electricity used for cooling during the summer months. According to the EIA, injections of natural gas into underground storage exceeded market expectations and historical averages for the first three weeks of September 2017.

22


The following table shows natural gas storage volumes by region at the close of each quarter presented:
 
 
 
2017
 
2016
Region
 
Third
Quarter
 
Second
Quarter
 
First Quarter
 
Third
Quarter
 
Second
Quarter
 
First Quarter
 
 
(Bcf)
East
 
861

 
564

 
268

 
899

 
632

 
439

Midwest
 
989

 
699

 
479

 
1,045

 
742

 
555

Mountain
 
220

 
187

 
142

 
237

 
198

 
147

Pacific
 
311

 
287

 
216

 
318

 
315

 
262

South Central
 
1,127

 
1,151

 
946

 
1,181

 
1,253

 
1,065

Total
 
3,508

 
2,888

 
2,051

 
3,680

 
3,140

 
2,468

 
Source: EIA
How We Evaluate Our Operations
We use a variety of operational and financial measures to assess our performance. Among the measures considered by management are the following:

volumes of oil and natural gas produced;

commodity prices including the effect of derivative instruments; and

Adjusted EBITDA, distributable cash flow, and distributable cash flow after net working interest capital expenditures.
Volumes of Oil and Natural Gas Produced
In order to track and assess the performance of our assets, we monitor and analyze our production volumes from the various basins and plays that comprise our extensive asset base. We also regularly compare projected volumes to actual reported volumes and investigate unexpected variances.

Commodity Prices
Factors Affecting the Sales Price of Oil and Natural Gas
The prices we receive for oil, natural gas, and natural gas liquids (“NGLs”) vary by geographical area. The relative prices of these products are determined by the factors affecting global and regional supply and demand dynamics, such as economic conditions, production levels, availability of transportation, weather cycles, and other factors. In addition, realized prices are influenced by product quality and proximity to consuming and refining markets. Any differences between realized prices and NYMEX prices are referred to as differentials. All of our production is derived from properties located in the United States.

Oil. The substantial majority of our oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of our control. NYMEX light sweet crude oil, commonly referred to as WTI, is the prevailing domestic oil pricing index. The majority of our oil production is priced at the prevailing market price with the final realized price affected by both quality and location differentials.
The chemical composition of crude oil plays an important role in its refining and subsequent sale as petroleum products.  As a result, variations in chemical composition relative to the benchmark crude oil, usually WTI, will result in price adjustments, which are often referred to as quality differentials. The characteristics that most significantly affect quality differentials include the density of the oil, as characterized by its American Petroleum Institute (“API”) gravity, and the presence and concentration of impurities, such as sulfur.
Location differentials generally result from transportation costs based on the produced oil’s proximity to consuming and refining markets and major trading points.

23



Natural Gas. The NYMEX price quoted at Henry Hub is a widely used benchmark for the pricing of natural gas in the United States. The actual volumetric prices realized from the sale of natural gas differ from the quoted NYMEX price as a result of quality and location differentials. 
Quality differentials result from the heating value of natural gas measured in Btus and the presence of impurities, such as hydrogen sulfide, carbon dioxide, and nitrogen. Natural gas containing ethane and heavier hydrocarbons has a higher Btu value and will realize a higher volumetric price than natural gas which is predominantly methane, which has a lower Btu value. Natural gas with a higher concentration of impurities will realize a lower volumetric price due to the presence of the impurities in the natural gas when sold or the cost of treating the natural gas to meet pipeline quality specifications.
Natural gas, which currently has a limited global transportation system, is subject to price variances based on local supply and demand conditions and the cost to transport natural gas to end user markets.
Hedging
We use derivative instruments to partially mitigate the impact of commodity price volatility on our cash generated from operations. From time to time, such instruments may include fixed-price swaps, costless collars, and other contractual arrangements. The impact of these derivative instruments could affect the amount of revenue we ultimately realize. Since 2015, we have only entered into fixed-price swap contracts. Under fixed-price swap contracts, a counterparty is required to make a payment to us if the settlement price is less than the swap strike price. Conversely, we are required to make a payment to the counterparty if the settlement price is greater than the swap strike price. We may employ contractual arrangements other than fixed-price swap contracts in the future to mitigate the impact of price fluctuations. If commodity prices decline in the future, our hedging contracts will partially mitigate the effect of lower prices on our future revenue.
Our open oil and natural gas derivative contracts as of September 30, 2017, and as of the date of this filing, are detailed in Note 5 – Derivatives and Financial Instruments to our unaudited consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q. Our credit agreement limits the extent to which we can hedge our future production.
As of September 30, 2017, per the terms of our credit agreement, we were allowed to hedge all of our estimated production from our proved developed producing reserves based on the most recent reserve information provided to our lenders. Under these terms, we hedged approximately 92.5% and 98.7% of our available oil and condensate hedge volumes, respectively, and almost 92.4% and 99% of our available natural gas hedge volumes for the remainder of 2017 and 2018, respectively.
Pursuant to the closing of our Fourth Amended and Restated credit agreement on November 1, 2017, we are allowed to hedge expected production volumes in excess of estimated production from our proved developed reserves. The revised provisions in our credit agreement allow us to hedge certain percentages of future monthly production equal to the lesser of internally forecasted production or the average of reported production for the most recent three months. We are allowed to hedge up to 90% of production for the first 24 months, 70% for months 25 through 36, and 50% for months 37 through 48. Pursuant to our updated hedge provisions, we have hedged approximately 95%, 99%, and 23% of our available oil and condensate hedge volumes for the remainder of 2017, 2018, and 2019, respectively.  Also, we have hedged 99%, 99%, and 28% of our available natural gas hedge volumes for the remainder of 2017, 2018, and 2019, respectively. 
The Company intends to continuously monitor the production from our assets and the commodity price environment, and will, from time to time, add additional hedges within the percentages described above to remain significantly hedged for the following 12 to 24 months. We do not enter into derivative instruments for speculative purposes.
Non-GAAP Financial Measures