Black Stone Minerals, L.P. - FORM 10-Q

Attached files

file	filename
EX-32.1 - EXHIBIT 32.1 - Black Stone Minerals, L.P.	bsm6302017form10-qexhibit321.htm
EX-31.2 - EXHIBIT 31.2 - Black Stone Minerals, L.P.	bsm6302017form10-qexhibit312.htm
EX-31.1 - EXHIBIT 31.1 - Black Stone Minerals, L.P.	bsm6302017form10-qexhibit311.htm

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 June 30, 2017



☐	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 August 2, 2017, there were 100,660,009 common limited partner units, 95,388,424 subordinated limited partner units, and 26,426 preferred units of the registrant outstanding.

TABLE OF CONTENTS



		Page
PART I – FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
	Consolidated Balance Sheets as of June 30, 2017 and December 31, 2016	1
	Consolidated Statements of Operations for the Three Months and Six Months Ended June 30, 2017 and 2016	2
	Consolidated Statement of Equity for the Six Months Ended June 30, 2017	3
	Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2017 and 2016	4
	Notes to Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	18
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	32
Item 4.	Controls and Procedures	32
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	33
Item 1A.	Risk Factors	33
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	33
Item 6.	Exhibits	34

	Signatures	35

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands)



(Unaudited)	June 30, 2017			December 31, 2016
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	7,487		$	9,772
Accounts receivable	72,255			68,181
Commodity derivative assets	13,329			—
Prepaid expenses and other current assets	1,765			1,036
TOTAL CURRENT ASSETS	94,836			78,989
PROPERTY AND EQUIPMENT
Oil and natural gas properties, at cost, using the successful efforts method of accounting, includes unproved properties of $730,435 and $605,736 at June 30, 2017 and December 31, 2016, respectively	2,850,183			2,697,073
Accumulated depreciation, depletion, amortization, and impairment	(1,707,534		)	(1,652,930		)
Oil and natural gas properties, net	1,142,649			1,044,143
Other property and equipment, net of accumulated depreciation of $14,341 and $14,327 at June 30, 2017 and December 31, 2016, respectively	542			528
NET PROPERTY AND EQUIPMENT	1,143,191			1,044,671
Deferred charges and other long-term assets	12,059			5,167
TOTAL ASSETS	$	1,250,086		$	1,128,827
LIABILITIES, MEZZANINE EQUITY AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	3,533		$	4,142
Accrued liabilities	39,541			50,952
Commodity derivative liabilities	—			16,237
Other current liabilities	203			—
TOTAL CURRENT LIABILITIES	43,277			71,331
LONG-TERM LIABILITIES
Credit facility	393,000			316,000
Accrued incentive compensation	2,295			1,485
Commodity derivative liabilities	—			482
Deferred revenue	—			518
Asset retirement obligations	13,627			13,350
TOTAL LIABILITIES	452,199			403,166
COMMITMENTS AND CONTINGENCIES (Note 8)
MEZZANINE EQUITY
Partners' equity - convertible redeemable preferred units, 26 and 53 units outstanding at June 30, 2017 and December 31, 2016, respectively	27,085			54,015
EQUITY
Partners' equity - general partner interest	—			—
Partners' equity - common units, 100,559 and 95,721 units outstanding at June 30, 2017 and December 31, 2016, respectively	573,817			489,023
Partners' equity - subordinated units, 95,388 and 95,164 units outstanding at June 30, 2017 and December 31, 2016, respectively	196,037			181,602
Noncontrolling interests	948			1,021
TOTAL EQUITY	770,802			671,646
TOTAL LIABILITIES, MEZZANINE EQUITY AND EQUITY	$	1,250,086		$	1,128,827

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

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands, except per unit amounts)



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
REVENUE
Oil and condensate sales	$	37,262		$	34,553		$	77,736		$	61,801
Natural gas and natural gas liquids sales	49,903			21,607			97,604			46,719
Gain (loss) on commodity derivative instruments	22,003			(30,733		)	44,728			(20,107		)
Lease bonus and other income	11,356			15,142			25,038			16,537
TOTAL REVENUE	120,524			40,569			245,106			104,950
OPERATING (INCOME) EXPENSE
Lease operating expense	4,148			4,283			8,337			9,172
Production costs and ad valorem taxes	11,863			7,012			23,765			14,074
Exploration expense	46			629			608			637
Depreciation, depletion, and amortization	28,900			29,202			55,279			50,923
Impairment of oil and natural gas properties	—			679			—			6,775
General and administrative	17,481			18,134			34,693			35,535
Accretion of asset retirement obligations	253			200			500			474
(Gain) loss on sale of assets, net	(7		)	(92		)	(931		)	(4,772		)
TOTAL OPERATING EXPENSE	62,684			60,047			122,251			112,818
INCOME (LOSS) FROM OPERATIONS	57,840			(19,478		)	122,855			(7,868		)
OTHER INCOME (EXPENSE)
Interest and investment income	33			38			39			191
Interest expense	(3,981		)	(1,443		)	(7,488		)	(2,491		)
Other income (expense)	282			73			351			107
TOTAL OTHER EXPENSE	(3,666		)	(1,332		)	(7,098		)	(2,193		)
NET INCOME (LOSS)	54,174			(20,810		)	115,757			(10,061		)
NET (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS	16			9			7			7
DISTRIBUTIONS ON REDEEMABLE PREFERRED UNITS	(672		)	(1,310		)	(1,786		)	(3,114		)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS	$	53,518		$	(22,111	)	$	113,978		$	(13,168	)
ALLOCATION OF NET INCOME (LOSS):
General partner interest	$	—		$	—		$	—		$	—
Common units	32,100			(7,445		)	67,617			862
Subordinated units	21,418			(14,666		)	46,361			(14,030		)
	$	53,518		$	(22,111	)	$	113,978		$	(13,168	)
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:
Per common unit (basic)	$	0.33		$	(0.08	)	$	0.69		$	0.01
Weighted average common units outstanding (basic)	97,990			96,356			97,448			96,418
Per subordinated unit (basic)	$	0.22		$	(0.15	)	$	0.49		$	(0.15	)
Weighted average subordinated units outstanding (basic)	95,388			95,189			95,269			95,092
Per common unit (diluted)	$	0.33		$	(0.08	)	$	0.69		$	0.01
Weighted average common units outstanding (diluted)	97,990			96,418			97,448			96,481
Per subordinated unit (diluted)	$	0.22		$	(0.15	)	$	0.49		$	(0.15	)
Weighted average subordinated units outstanding (diluted)	95,388			95,092			95,269			95,092
DISTRIBUTIONS DECLARED AND PAID:
Per common unit	$	0.2875		$	0.2625		$	0.5750		$	0.5250
Per subordinated unit	$	0.1838		$	0.1838		$	0.3675		$	0.3675

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

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	1,565		—		—			—			—			—
Equity-based compensation	—		—		21,045			(379		)	—			20,666
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	3,434		—		56,447			—			—			56,447
Distributions	—		—		(56,008		)	(35,011		)	(66		)	(91,085		)
Charges to partners' equity for accrued distribution equivalent rights	—		—		(613		)	—			—			(613		)
Net income (loss)	—		—		68,520			47,244			(7		)	115,757
Issuance of common units, net of offering costs	65		—		991			—			—			991
Distributions on redeemable preferred units	—		—		(903		)	(883		)	—			(1,786		)
BALANCE AT JUNE 30, 2017	100,559		95,388		$	573,817		$	196,037		$	948		$	770,802

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

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)



	Six Months Ended
	June 30,
	2017			2016
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	115,757		$	(10,061	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization	55,279			50,923
Impairment of oil and natural gas properties	—			6,775
Accretion of asset retirement obligations	500			474
Amortization of deferred charges	436			394
(Gain) loss on commodity derivative instruments	(44,728		)	20,107
Net cash received on settlement of commodity derivative instruments	7,359			33,918
Equity-based compensation	10,939			25,139
(Gain) loss on sale of assets, net	(931		)	(4,772		)
Changes in operating assets and liabilities:
Accounts receivable	(4,318		)	(6,585		)
Prepaid expenses and other current assets	(729		)	(1,003		)
Accounts payable and accrued liabilities	658			(31,859		)
Deferred revenue	(969		)	221
Settlement of asset retirement obligations	(89		)	(127		)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	139,164			83,544
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisitions of oil and natural gas properties	(66,501		)	(136,340		)
Additions to oil and natural gas properties	(33,903		)	(36,710		)
Purchase of other property and equipment	(96		)	(5		)
Proceeds from the sale of oil and natural gas properties	2,133			177
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES	(98,367		)	(172,878		)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings under senior line of credit	159,500			230,000
Repayments of borrowings under senior line of credit	(82,500		)	(11,000		)
Distributions to Black Stone Minerals, L.P. common and subordinated unitholders	(91,019		)	(85,866		)
Distributions to redeemable preferred unitholders	(2,452		)	(3,751		)
Distributions to non-controlling interests	(66		)	(54		)
Proceeds from issuance of common units	991			—
Payments for capitalized offering costs	—			(301		)
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	(43,082		)	85,871
NET CHANGE IN CASH AND CASH EQUIVALENTS	(2,285		)	(3,463		)
CASH AND CASH EQUIVALENTS - beginning of the period	9,772			13,233
CASH AND CASH EQUIVALENTS - end of the period	$	7,487		$	9,770
SUPPLEMENTAL DISCLOSURE
Interest paid	$	7,062		$	1,928

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

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 June 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 (“GAAP”) in the United States 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 a fair presentation of the results for the periods presented have been reflected. The results of operations for the six months ended June 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.

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.

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 six months ended June 30, 2017.

New accounting pronouncements: In May 2014, the Financial Accounting Standards Board (the “FASB”) issued an accounting standards update on a comprehensive new revenue recognition standard that will supersede Accounting Standards Codification (“ASC”) 605, Revenue Recognition. The new accounting guidance creates a framework under which an entity will allocate the transaction price to separate performance obligations and recognize revenue when each performance obligation is satisfied. 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 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. In July 2015, the FASB decided to defer the original effective date by one year to be effective for annual reporting periods beginning after December 15, 2017 instead of December 15, 2016 for public entities, with early adoption permitted. The Partnership intends to use the modified retrospective adoption approach. The Partnership has identified all of its revenue streams and based on current evaluations to-date, the Partnership does not anticipate this new guidance will have a material impact on its consolidated financial statements. The Partnership is continuing to evaluate the disclosure requirements of this new guidance and does not plan on early adopting this guidance.

In February 2016, the FASB issued Accounting Standard Update (“ASU”) No. 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 amendment will be effective for reporting periods beginning on or after December 15, 2018, and early adoption is permitted. The Partnership will use the modified retrospective adoption approach. 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 will not early adopt.

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments, 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 the activity that is likely to be the predominant source or use of cash flows. The amendments in this ASU are effective for public business entities for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. Early adoption is permitted; however the Partnership will not adopt this guidance early. The Partnership intends to use the retrospective transition method and is evaluating the impact that the new accounting guidance will have on its consolidated financial statements and related disclosure.

In January 2017, the FASB issued ASU No. 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 in fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. Early adoption is permitted under certain circumstances; however the Partnership will not adopt this guidance early. The amendments in this ASU should be applied prospectively as of the

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

beginning of the period of adoption. The Partnership 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 (Topic 718): Scope of Modification Accounting. 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 all entities for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted, including adoption in any interim period, for public business entities for reporting periods for which financial statements have not yet been issued. The Partnership is not planning to adopt this guidance early. The amendments in this ASU should be applied prospectively to an award modified on or after the adoption date. The Partnership is evaluating the impact that the new accounting guidance will have on its consolidated financial statements and related disclosure.

NOTE 3—ASSET RETIREMENT OBLIGATIONS

The asset retirement obligation (“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 this obligation. 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:



	For the six months ended
	June 30, 2017
	(In thousands)
Beginning asset retirement obligations	$	13,350
Liabilities incurred	74
Liabilities settled	(89		)
Accretion expense	500
Dispositions	(5		)
Revisions	—
Ending asset retirement obligations	$	13,830
Current asset retirement obligation	$	203
Non-current asset retirement obligation	$	13,627

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 and Dispositions

During the second quarter of 2017, the Partnership executed the following transactions:

In June 2017, the Partnership closed a series of related mineral and royalty interests acquisitions, on properties previously owned by Angelina County Lumber Company and various other sellers, in twelve Texas counties, primarily Angelina and Nacogdoches counties. Consideration consisted of approximately $4.8 million in cash and $45.7 million of the Partnership’s common units, of which $1.4 million of the common units were recorded as a liability on the June 30, 2017

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

balance sheet due to delays in processing the units by the Partnership's transfer agent. Acquisition-related costs of $1.0 million were expensed and included in the general and administrative line item of the 2017 consolidated statement of operations.



	(In thousands)
Proved oil and natural gas properties	$	5,006
Unproved oil and natural gas properties	45,477
Total fair value	$	50,483

The Partnership acquired additional mineral and royalty interests in Angelina County, Texas for $12.3 million in cash and San Augustine County Texas for $1.0 million in cash.

During the first quarter of 2017, the Partnership executed the following transactions:

On January 4, 2017, the Partnership acquired mineral and royalty interests in Loving County, Texas for approximately $22.3 million in cash.



	(In thousands)
Proved oil and natural gas properties	$	3,331
Unproved oil and natural gas properties	18,802
Net working capital	204
Total fair value	$	22,337

On January 10, 2017, the Partnership acquired mineral and royalty interests in Loving and Winkler counties of Texas for approximately $5.0 million in cash and $12.0 million of the Partnership’s common units. In addition, acquisition related costs of $1.2 million were expensed and included in the general and administrative line item of the 2017 consolidated statement of operations.



	(In thousands)
Proved oil and natural gas properties	$	1,804
Unproved oil and natural gas properties	15,206
Net working capital	59
Total fair value	$	17,069

In addition, several mineral and royalty interest acquisitions were closed in Angelina County, Texas for an aggregate amount of approximately $16.6 million in cash and $0.2 million of the Partnership’s common units. There were two additional mineral and royalty interest acquisitions in Loving and Winkler Counties in Texas for approximately $3.4 million in cash. One additional royalty interest purchase closed in San Augustine County, Texas for approximately $1.0 million. The cash portion of all acquisitions in the first half of 2017 was funded via borrowings under the Partnership's credit facility.

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 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 reduce the Partnership's future capital expenditures by approximately $30-$35 million in 2017 and

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

by an average of $40-$50 million annually, thereafter.

2016 Acquisitions

On January 8, 2016, the Partnership acquired mineral and royalty interests in the Permian Basin for $10.0 million in cash.

On June 15, 2016, the Partnership acquired an oil and natural gas mineral asset package primarily located in Weld County, Colorado for $34.0 million in cash. The following table summarizes the fair values assigned to the properties acquired:



	(In thousands)
Proved oil and natural gas properties	$	18,948
Unproved oil and natural gas properties	14,082
Net working capital	1,038
Asset retirement obligations	(50		)
Total fair value	$	34,018

On June 17, 2016, the Partnership acquired a diverse oil and natural gas mineral package from Freeport-McMoRan Oil and Gas, Inc. for $87.6 million in cash. The following table summarizes the fair values assigned to the properties acquired:



	(In thousands)
Proved oil and natural gas properties	$	20,787
Unproved oil and natural gas properties	65,745
Net working capital	1,026
Total fair value	$	87,558

The cash portion of all 2016 acquisition transactions was 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, fixed price 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 June 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 June 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 June 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 $21.8 million had the Partnership's counterparties as a group been unable to fulfill their obligations as of June 30, 2017.

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 June 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	$	14,434	$	(1,105	)	$	13,329
Long-term asset	Deferred charges and other long-term assets	7,321		—			7,321
Total assets		$	21,755	$	(1,105	)	$	20,650
Liabilities:
Current liability	Commodity derivative liabilities	$	1,105	$	(1,105	)	$	—
Long-term liability	Commodity derivative liabilities	—		—			—
Total liabilities		$	1,105	$	(1,105	)	$	—



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 Six Months Ended June 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	27,799			(12,615		)
Gain (loss) on natural gas derivative instruments	16,929			(7,492		)
Net cash received on settlements of oil derivative instruments	(6,656		)	(18,766		)
Net cash received on settlements of natural gas derivative instruments	(703		)	(15,152		)
Net change in fair value of commodity derivative instruments	37,369			(54,025		)
Ending fair value of commodity derivative instruments	$	20,650		$	10,509

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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



				Range (Per Bbl)
Period and Type of Contract	Volume (Bbl)	Weighted Average (Per Bbl)		Low		High
Oil Swap Contracts:
2017
Second Quarter	195,000	$	54.19	$	51.86	$	55.23
Third Quarter	556,000	53.29		52.04		55.23
Fourth Quarter	516,000	53.56		52.57		55.23
2018
First Quarter	475,000	$	54.74	$	54.50	$	55.05
Second Quarter	445,000	54.73		54.50		54.90
Third Quarter	425,000	54.72		54.50		54.90
Fourth Quarter	405,000	54.72		54.50		54.90

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



				Range (Per MMBtu)
Period and Type of Contract	Volume (MMBtu)	Weighted Average (Per MMBtu)		Low		High
Natural Gas Swap Contracts:
2017
Third Quarter	12,490,000	$	3.08	$	2.90	$	3.45
Fourth Quarter	11,280,000	3.14		2.92		3.57
2018
First Quarter	9,870,000	$	3.05	$	2.96	$	3.45
Second Quarter	8,840,000	3.01		2.86		3.23
Third Quarter	7,730,000	3.00		2.90		3.23
Fourth Quarter	6,860,000	3.00		2.90		3.23

The Partnership has not entered into any additional derivative contracts for oil or natural gas subsequent to June 30, 2017.

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).

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 six months ended June 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 June 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.

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		Effect of Counterparty Netting			Total
	(In thousands)
As of June 30, 2017
Financial Assets
Commodity derivative instruments	$	—	$	21,755	$	—	$	(1,105	)	$	20,650
Financial Liabilities
Commodity derivative instruments	$	—	$	1,105	$	—	$	(1,105	)	$	—
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 the projected 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.

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 June 30, 2017 or December 31, 2016.

The following table presents information about the Partnership’s assets measured at fair value on a nonrecurring basis:



	Fair Value Measurements Using							Net Book Value¹
	Level 1			Level 2		Level 3		Net Book Value¹		Impairment
	(In thousands)
Three months ended June 30, 2017
Impaired oil and natural gas properties	$	—	—	$	—	$	—	$	—	$	—
Three months ended June 30, 2016
Impaired oil and natural gas properties	$	—		$	—	$	543	$	1,222	$	679
Six months ended June 30, 2017
Impaired oil and natural gas properties	$	—	—	$	—	$	—	$	—	$	—
Six months ended June 30, 2016
Impaired oil and natural gas properties	$	—	—	$	—	$	3,042	$	9,817	$	6,775

¹Amount represents net book value at the date 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. On October 28, 2015, the Senior Line of Credit was amended to extend the term of the agreement from February 3, 2017 to February 4, 2019. 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. 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. Drawings on the Senior Line of Credit are used for the acquisition of oil and natural gas properties and for other general business purposes.

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 3.73% and 3.26% as of June 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 June 30, 2017, the Partnership was in compliance with all financial covenants for the Senior Line of Credit.

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The aggregate principal balance outstanding was $393.0 million and $316.0 million at June 30, 2017 and December 31, 2016, respectively. The unused portion of the available borrowings under the Senior Line of Credit was $157.0 million and $184.0 million at June 30, 2017 and December 31, 2016, 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 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 June 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. Subsequent to June 30, 2017, Mr. William Randall, the newly elected member of the Board, was issued 6,426 fully vested common units on July 28, 2017. 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 six months ended June 30, 2017 and 2016, respectively:



	Three Months Ended June 30,				Six Months Ended June 30,
Incentive compensation expense	2017		2016		2017		2016
	(In thousands)				(In thousands)
Cash—long-term incentive plan	$	214	$	560	$	636	$	2,410
Equity-based compensation—restricted common and subordinated units	2,940		3,190		4,748		5,933
Equity-based compensation—restricted performance units	2,723		5,426		5,076		8,039
Board of Directors incentive plan	614		476		1,114		957
Total incentive compensation expense	$	6,491	$	9,652	$	11,574	$	17,339

NOTE 10—REDEEMABLE PREFERRED UNITS

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 June 30, 2017 and December 31, 2016, respectively. The aforementioned amounts included accrued distributions of $0.7 million as of June 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 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, up to 26,426 redeemable preferred units as of December 31, 2017, plus any accrued and unpaid distributions.

The Partnership shall have the right, at its sole option, to redeem an amount of redeemable preferred units equal to the units being redeemed by an owner of preferred units as of each December 31. Any amount of a given year’s redeemable preferred units eligible for redemption not redeemed as of December 31 shall automatically convert to common and subordinated units during the first quarter of the following year.

For the six months ended June 30, 2017, 19,641 redeemable preferred units were redeemed for $20.1 million, including accrued unpaid yield. For the three months ended June 30, 2017, 6,899 redeemable preferred units were redeemed for $7.1 million, including accrued unpaid yield. For the six months ended June 30, 2017, 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.

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 June 30, 2017. At June 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 June 30, 2017, there were no units related to the Partnership’s restricted performance unit awards included in the calculation of diluted EPU.

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table sets forth the computation of basic and diluted earnings per common and subordinated unit:



	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2017			2016			2017			2016
	(In thousands, except per unit amounts)						(In thousands, except per unit amounts)
NET INCOME (LOSS)	$	54,174		$	(20,810	)	$	115,757		$	(10,061	)
NET (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS	16			9			7			7
DISTRIBUTIONS ON REDEEMABLE PREFERRED UNITS	(672		)	(1,310		)	(1,786		)	(3,114		)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS	$	53,518		$	(22,111	)	$	113,978		$	(13,168	)
ALLOCATION OF NET INCOME (LOSS):
General partner interest	$	—		$	—		$	—		$	—
Common units	32,100			(7,445		)	67,617			862
Subordinated units	21,418			(14,666		)	46,361			(14,030		)
	$	53,518		$	(22,111	)	$	113,978		$	(13,168	)
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:
Per common unit (basic)	$	0.33		$	(0.08	)	$	0.69		$	0.01
Weighted average common units outstanding (basic)	97,990			96,356			97,448			96,418
Per subordinated unit (basic)	$	0.22		$	(0.15	)	$	0.49		$	(0.15	)
Weighted average subordinated units outstanding (basic)	95,388			95,189			95,269			95,092
Per common unit (diluted)	$	0.33		$	(0.08	)	$	0.69		$	0.01
Weighted average common units outstanding (diluted)	97,990			96,418			97,448			96,481
Per subordinated unit (diluted)	$	0.22		$	(0.15	)	$	0.49		$	(0.15	)
Weighted average subordinated units outstanding (diluted)	95,388			95,092			95,269			95,092

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 to be sold pursuant to the Equity Distribution Agreement will be 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 June 30, 2017, the Partnership sold 65,003 common units under the ATM Program for net proceeds of $1.0 million.

NOTE 13—SUBSEQUENT EVENTS

On August 7, 2017, the Board approved a distribution for the three months ended June 30, 2017 of $0.3125 per common unit and $0.20875 per subordinated unit. Distributions will be payable on August 24, 2017 to unitholders of record at the close of business on August 17, 2017.

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


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;


•	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 June 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 six 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. Additional information regarding acquisitions is contained in Note 4 - Acquisitions and Dispositions to our unaudited consolidated financial statements included herein for further discussion.

At-the-Market Offering Program

In the second quarter of 2017, we commenced an at-the-market offering (the “ATM Program”) 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 in the second quarter amounted to $1.0 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"), 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 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 reduce our future capital expenditures by approximately $40-$50 million annually.

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 Energy Information Agency ("EIA") estimates that global petroleum and other liquid fuels inventory builds averaged 0.3 million Bbls per day in 2016, marking the third consecutive year of inventory builds.

The EIA projects that the Organization of Petroleum Exporting Countries ("OPEC") crude oil output will rise by 0.5 MMBbls per day in 2018, driven by an increase in output in Iraq. In both 2017 and 2018, the EIA expects crude oil production to increase in Libya and Nigeria, which are countries not covered by the current supply reduction agreement.

The EIA forecasts total U.S. crude oil production to average 9.3 MMBbls per day in 2017, up 0.5 MMBbls from 2016. In 2018, crude oil production is anticipated to rise to an average of 9.9 MMBbls per day, which if achieved, would surpass the previous record of 9.6 MMBbls set in 1970. U.S. crude oil production is forecast to reach 10.1 MMBbls per day in December 2018.

The average West Texas Intermediate ("WTI") price is forecast by the EIA to be $49 per Bbl in 2017 and $50 per Bbl in 2018. Global oil inventories are forecast to be relatively unchanged in the second half of 2017 before returning to average inventory builds of 0.2 million Bbl per day in 2018. Given this expectation of relative balance in the global oil market through the forecast period, crude oil spot prices are expected to remain fairly flat in the coming months.

The EIA estimates that dry natural gas production averaged 72.5 Bcf per day in June 2017, which reflects a 0.9 Bcf per day increase from 2016. The EIA expects production to rise through 2017 and 2018 in response to anticipated price increases and large increases in liquefied natural gas ("LNG") exports. The EIA also expects dry natural gas production to rise by 1.0 Bcf per day in 2017 and by 3.1 Bcf per day in 2018. The EIA projects the United States will become a net exporter of natural

gas, on average in 2017, with net exports expected to average 0.4 Bcf per day. As LNG exports increase, 2018 net exports are forecast to average 1.3 Bcf per day. Henry Hub spot prices have been relatively flat in 2017, averaging $3.04 per MMBtu during the first half of the year, which is approximately the same price as in the fourth quarter of 2016. Prices averaged $2.98 per MMBtu in June 2017. The EIA expects closer-to-normal winter temperatures this winter, which could contribute to growth in residential and commercial consumption. Forecast Henry Hub natural gas spot prices are anticipated to average $3.10 per MMBtu in 2017 and $3.40 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 of fixed-price swap contracts.

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



	2017					2016
Benchmark Prices		Second Quarter		First Quarter			Second Quarter		First Quarter
WTI spot oil price ($/Bbl)		$	46.02	$	50.54		$	48.27	$	36.94
Henry Hub spot natural gas ($/MMBtu)		$	2.98	$	3.13		$	2.94	$	1.98

Source: EIA

Rig Count

As we are not an operator, 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		Second Quarter	First Quarter		Second Quarter	First Quarter
Oil		756	662		330	372
Natural gas		184	160		90	92
Other		—	2		1	—
Total		940	824		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, natural gas inventories reached a record high of 4,047 Bcf on November 11, 2016 and inventories ended the winter heating season at 2,072 Bcf in March 2017. The EIA projects that natural gas inventories will be 3,940 Bcf at the end of October 2017, which would be approximately 2% higher than the five year average but approximately 2% lower than the record high level experienced in November 2016.

The following table shows natural gas storage volumes by region at the close of each quarter presented:



	2017			2016
Region		Second Quarter	First Quarter		Second Quarter	First Quarter
	(Bcf)
East		564	268		632	439
Midwest		699	479		742	555
Mountain		187	142		198	147
Pacific		287	216		315	262
South Central		1,151	946		1,253	1,065
Total		2,888	2,051		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. As a result of our geographic diversification, we are not exposed to concentrated differential risks associated with any single play, trend, or basin.

•

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.


•	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 enter into 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, fixed-price contracts, costless collars, and other contractual arrangements. We generally employ a “rolling hedge” strategy whereby we hedge a significant portion of our proved developed producing reserves 12 to 24 months into the future. 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 June 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. Under the terms of our credit agreement, we are able to hedge all of our estimated production from our proved developed producing reserves based on the most recent reserve information provided to our lenders. We do not enter into derivative instruments for speculative purposes. We have hedged 95.5% and 95.5% of our available oil and condensate hedge volumes, respectively and 99.7% and 99.4% of our available natural gas hedge volumes for the remainder of 2017 and 2018, respectively.

Non-GAAP Financial Measures

Adjusted EBITDA, distributable cash flow, and distributable cash flow after net working interest capital expenditures are supplemental non-GAAP financial measures used by our management and external users of our financial statements such as investors, research analysts, and others, to assess the financial performance of our assets and our ability to sustain distributions over the long term without regard to financing methods, capital structure, or historical cost basis.

We define Adjusted EBITDA as net income (loss) before interest expense, income taxes and depreciation, depletion, and amortization adjusted for impairment of oil and natural gas properties, accretion of asset retirement obligations, unrealized gains and losses on commodity derivative instruments, and non-cash equity-based compensation. We define distributable cash flow as Adjusted EBITDA plus or minus amounts for certain non-cash operating activities, estimated replacement capital expenditures, cash interest expense, and distributions to noncontrolling interests and preferred unitholders. We define distributable cash flow after net working interest capital expenditures as distributable cash flow less net working interest capital expenditures. Net working interest capital expenditures consists of all capital expenditures related to working interest wells less the recoupment of working interest expenditures under our farmout agreement.

Adjusted EBITDA, distributable cash flow, and distributable cash flow after net working interest capital expenditures should not be considered an alternative to, or more meaningful than, net income (loss), income (loss) from operations, cash flows from operating activities, or any other measure of financial performance presented in accordance with generally accepted accounting principles (“GAAP”) in the United States as measures of our financial performance.

Adjusted EBITDA, distributable cash flow, and distributable cash flow after net working interest capital expenditures have important limitations as analytical tools because they exclude some but not all items that affect net income (loss), the most

directly comparable GAAP financial measure. Our computation of Adjusted EBITDA, distributable cash flow, and distributable cash flow after net working interest capital expenditures may differ from computations of similarly titled measures of other companies.

The following table presents a reconciliation of Adjusted EBITDA, distributable cash flow and distributable cash flow after net working interest capital expenditures to net income (loss), the most directly comparable GAAP financial measure, for the periods indicated:



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
	(Unaudited) (In thousands)
Net income (loss)	$	54,174		$	(20,810	)	$	115,757		$	(10,061	)
Adjustments to reconcile to Adjusted EBITDA:
Depreciation, depletion and amortization	28,900			29,202			55,279			50,923
Interest expense	3,981			1,443			7,488			2,491
Impairment of oil and natural gas properties	—			679			—			6,775
Accretion of asset retirement obligations	253			200			500			474
Equity-based compensation²	6,278			19,239			10,939			25,139
Unrealized (gain) loss on commodity derivative instruments	(18,921		)	44,070			(37,368		)	54,025
Adjusted EBITDA	74,665			74,023			152,595			129,766
Adjustments to reconcile to distributable cash flow:
Change in deferred revenue	(643		)	424			(969		)	221
Cash interest expense	(3,760		)	(1,246		)	(7,053		)	(2,097		)
(Gain) loss on sales of assets, net	(7		)	(92		)	(931		)	(4,772		)
Estimated replacement capital expenditures¹	(3,250		)	(3,750		)	(7,000		)	(3,750		)
Cash paid to noncontrolling interests	(41		)	(21		)	(66		)	(54		)
Redeemable preferred unit distributions	(672		)	(1,310		)	(1,786		)	(3,114		)
Distributable Cash Flow	66,292			68,028			134,790			116,200
Net working interest capital expenditures	(15,330		)	(11,600		)	(32,295		)	(36,710		)
Distributable cash flow after net working interest capital expenditures	$	50,962		$	56,428		$	102,495		$	79,490

¹On August 3, 2016, the Board of Directors of our general partner (the “Board”) established a replacement capital expenditure estimate of $15.0 million for the period of April 1, 2016 to March 31, 2017. There was no established estimate of replacement capital expenditures prior to this period. On June 8, 2017, the Board established a replacement capital expenditure estimate of $13.0 million for the period of April 1, 2017 to March 31, 2018.

²On April 25, 2016, the Compensation Committee of the Board approved a resolution to change the settlement feature of certain employee long-term incentive

compensation plans from cash to equity. As a result of the modification, $10.1 million of cash-settled liabilities were reclassified to equity-settled liabilities

during the second quarter of 2016.

Results of Operations

Three Months Ended June 30, 2017 Compared to Three Months Ended June 30, 2016

The following table shows our production, revenues, pricing, and expenses for the periods presented:



	Three Months Ended June 30,
	2017		2016			Variance
	(Unaudited) (Dollars in thousands, except for realized prices)
Production:
Oil and condensate (MBbls)	824		947			(123		)	(13.0	)%
Natural gas (MMcf)¹	15,425		11,558			3,867			33.5	%
Equivalents (MBoe)	3,395		2,873			522			18.2	%
Revenue:
Oil and condensate sales	$	37,262	$	34,553		$	2,709		7.8	%
Natural gas and natural gas liquids sales	49,903		21,607			28,296			131.0	%
Gain (loss) on commodity derivative instruments	22,003		(30,733		)	52,736			(171.6	)%
Lease bonus and other income	11,356		15,142			(3,786		)	(25.0	)%
Total revenue	$	120,524	$	40,569		$	79,955		197.1	%
Realized prices:
Oil and condensate ($/Bbl)	$	45.22	$	36.49		$	8.73		23.9	%
Natural gas ($/Mcf)¹	3.24		1.87			1.37			73.3	%
Equivalents ($/Boe)	$	25.67	$	19.55		$	6.12		31.3	%
Operating expenses:
Lease operating expense	$	4,148	$	4,283		$	(135	)	(3.2	)%
Production costs and ad valorem taxes	11,863		7,012			4,851			69.2	%
Exploration expense	46		629			(583		)	(92.7	)%
Depreciation, depletion, and amortization	28,900		29,202			(302		)	(1.0	)%
Impairment of oil and natural gas properties	—		679			(679		)	(100.0	)%
General and administrative	17,481		18,134			(653		)	(3.6	)%

As a mineral-and-royalty-interest owner, we are often provided insufficient and inconsistent data on NGL volumes by our operators. As a result, we are unable to reliably determine the total volumes of NGLs associated with the production of natural gas on our acreage. Accordingly, no NGL volumes are included in our reported production; however, revenue attributable to NGLs is included in our natural gas revenue and our calculation of realized prices for natural gas.

Revenue

Total revenue for the quarter ended June 30, 2017 increased compared to the quarter ended June 30, 2016. Production for the quarter ended June 30, 2017 averaged 37.3 MBoe per day, an increase of 5.7 MBoe per day compared to the corresponding period in 2016. The increase in total revenue is primarily due to higher commodity prices, increased production, and gains from commodity derivative instruments, as compared to the corresponding period in 2016.

Oil and condensate sales. Oil and condensate sales during the period were higher than the second quarter of 2016 due to higher realized prices. Our total oil and condensate production was lower than the second quarter of 2016. Our mineral-and-royalty-interest oil and condensate volumes accounted for 86.8% and 79.3% of total oil and condensate volumes for the quarters ended June 30, 2017 and 2016, respectively. Our mineral-and-royalty-interest oil and condensate volumes decreased 4.7% in the second quarter of 2017 relative to the corresponding period in 2016, primarily driven by lower production in our Eagle Ford Shale assets.

Natural gas and natural gas liquids sales. Natural gas and NGL sales increased for the quarter ended June 30, 2017 as compared to the same period for 2016. Higher commodity prices and higher production volumes, largely driven by new wells

in the Haynesville play, were primarily responsible for the increase in our natural gas and NGL revenues. Mineral-and-royalty-interest production accounted for 47.1% and 62.5% of our natural gas volumes for the quarters ended June 30, 2017 and 2016, respectively.

Gain (loss) on commodity derivative instruments. During the second quarter of 2017, we recognized $13.5 million of gains from oil commodity contracts, which included cash received of $3.8 million, compared to recognized losses of $15.5 million in the same period of 2016. During the second quarter of 2017, we recognized $8.5 million of gains from natural gas commodity contracts, which included cash paid of $0.8 million, compared to recognized losses of $15.2 million in the same period of 2016.

Lease bonus and other income. When we lease our mineral interests, we generally receive an upfront cash payment, or a lease bonus. Leasing activity in the Bakken/Three Forks and the Wolfcamp trends made up the majority of leases written in the second quarter of 2017.

Operating and Other Expenses

Lease operating expense. Lease operating expense includes normally recurring expenses associated with our non-operated working interests necessary to produce hydrocarbons from our oil and natural gas wells, as well as certain nonrecurring expenses, such as well repairs. Lease operating expense decreased for the quarter ended June 30, 2017 as compared to the same period in 2016, primarily due to fewer producing wells and fewer remedial projects initiated by our operators.

Production costs and ad valorem taxes. Production taxes include statutory amounts deducted from our production revenues by various state taxing entities. Depending on the regulations of the states where the production originates, these taxes may be based on a percentage of the realized value or a fixed amount per production unit. This category also includes the costs to process and transport our production to applicable sales points. Ad valorem taxes are jurisdictional taxes levied on the value of oil and natural gas minerals and reserves. Rates, methods of calculating property values, and timing of payments vary between taxing authorities. For the quarter ended June 30, 2017, production costs and ad valorem taxes increased from the quarter ended June 30, 2016, generally as a result of higher commodity prices and natural gas production volumes.

Exploration expense. Exploration expense typically consists of dry-hole expenses and geological and geophysical costs, including seismic costs, and is expensed as incurred under the successful efforts method of accounting. Exploration expense decreased for the three months ended June 30, 2017 as compared to the same period in 2016. The 2017 and 2016 expense represents costs incurred to acquire 3-D seismic information, related to our mineral and royalty interests, from a third-party service provider.

Depreciation, depletion, and amortization. Depletion is an estimate of the amount of cost basis of oil and natural gas properties attributable to the volume of hydrocarbons extracted during a period, calculated on a units-of-production basis. Estimates of proved developed producing reserves are a major component of the calculation of depletion. We adjust our depletion rates semi-annually based upon mid-year and year-end reserve reports, except when circumstances indicate that there has been a significant change in reserves or costs. Depreciation, depletion, and amortization decreased for the quarter ended June 30, 2017 as compared to the same period in 2016, primarily due to the impact of lower depletion rates partially offset by higher production.

Impairment of oil and natural gas properties. Individual categories of oil and natural gas properties are assessed periodically to determine if the net book value for these properties has been impaired. Management periodically conducts an in-depth evaluation of the carrying amounts of property acquisitions, successful exploratory wells, development activity, undeveloped leasehold, and mineral interests to identify impairments. There were no impairments for the quarter ended June 30, 2017. Impairments totaled $0.7 million for the quarter ended June 30, 2016 primarily due to drilling costs in the Mississippian play exceeding our expected realizable net cash flow.

General and administrative. General and administrative expenses are costs not directly associated with the production of oil and natural gas and include the cost of employee salaries and related benefits, office expenses, and fees for professional services. For the quarter ended June 30, 2017, general and administrative expenses decreased as compared to the same period in 2016. In 2017, costs attributable to our long-term incentive plans were lower than in the corresponding period in 2016.

Interest expense. Interest expense was higher in the second quarter of 2017 due to increased borrowings under our credit facility. Average outstanding borrowings during the second quarter of 2017 were higher than the second quarter of 2016 due to

funding of acquisitions in 2017 and 2016, common unit repurchases in 2016, and redemptions associated with our preferred units.

Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016

The following table shows our production, revenues, pricing, and expenses for the periods presented:



	Six Months Ended June 30,
	2017		2016			Variance
	(Dollars in thousands, except for realized prices and per Boe data)
Production:
Oil and condensate (MBbls)	1,685		1,833			(148		)	(8.1	)%
Natural gas (MMcf)¹	29,485		22,807			6,678			29.3	%
Equivalents (MBoe)	6,599		5,634			965			17.1	%
Revenue:
Oil and condensate sales	$	77,736	$	61,801		$	15,935		25.8	%
Natural gas and natural gas liquids sales	97,604		46,719			50,885			108.9	%
Gain (loss) on commodity derivative instruments	44,728		(20,107		)	64,835			(322.4	)%
Lease bonus and other income	25,038		16,537			8,501			51.4	%
Total revenue	$	245,106	$	104,950		$	140,156		133.5	%
Realized prices:
Oil and condensate ($/Bbl)	$	46.13	$	33.72		$	12.41		36.8	%
Natural gas ($/Mcf)¹	3.31		2.05			1.26			61.5	%
Equivalents ($/Boe)	$	26.57	$	19.26		$	7.31		38.0	%
Operating expenses:
Lease operating expense	$	8,337	$	9,172		$	(835	)	(9.1	)%
Production costs and ad valorem taxes	23,765		14,074			9,691			68.9	%
Exploration expense	608		637			(29		)	(4.6	)%
Depreciation, depletion, and amortization	55,279		50,923			4,356			8.6	%
Impairment of oil and natural gas properties	—		6,775			(6,775		)	(100.0	)%
General and administrative	34,693		35,535			(842		)	(2.4	)%

Revenue

Total revenues for the six months ended June 30, 2017 increased compared to the six months ended June 30, 2016. Production for the six months ended June 30, 2017 averaged 36.5 MBoe per day, an increase of 5.5 MBoe per day, compared to the corresponding period in 2016. The increase in total revenue from the corresponding prior period is primarily due to a $64.8 million increase in revenue from our commodity derivative instruments; higher realized commodity prices, the impact of which totaled $58.1 million, an $8.7 million increase in net production volumes; and $8.5 million higher lease bonus and other income.

Oil and condensate sales. Oil and condensate sales during the six months ended June 30, 2017 were higher than the corresponding period in 2016 primarily due to higher realized prices. Oil and condensate production for the six months ended June 30, 2017 was lower than in the six months ended June 30, 2016, but the decreased production was more than offset by an increase in realized prices. Our mineral-and-royalty-interest oil and condensate volumes accounted for 83.1% and 78.9% of total oil and condensate volumes for the six months ended June 30, 2017 and 2016, respectively. Our mineral-and-royalty-interest oil and condensate volumes decreased 3.2% for the six months ended June 30, 2017 relative to the corresponding period in 2016, primarily driven by production decreases in the Eagle Ford play. Our working-interest oil and condensate volumes decreased by 26.4% to 1.6 MBbls per day during the six months ended June 30, 2017 as compared to the same period in 2016 primarily due to decreased activity in the Bakken play.

Natural gas and natural gas liquids sales. Natural gas and NGL sales increased for the six months ended June 30, 2017 as compared to the same period for 2016. An increase in production volumes, primarily from new wells in the Haynesville/Bossier and Wilcox plays, and an increase in the realized natural gas and NGL prices for the six months ended June 30, 2017 compared to the corresponding period in 2016 was primarily responsible for the increase in our natural gas and NGL revenues. Mineral-and-royalty-interest production accounted for 49.3% and 62.0% of our natural gas volumes for the six months ended June 30, 2017 and 2016, respectively.

Gain (loss) on commodity derivative instruments. During the six months ended June 30, 2017, we recognized a $27.8 million gain on our oil commodity contracts, which included $6.7 million in cash received, compared to a recognized loss of $12.6 million in the same period of 2016. During the first six months of 2017, we recognized $16.9 million of gains from natural gas commodity contracts, which included $0.7 million of cash received, compared to a recognized loss of $7.5 million in the same period of 2016.

Lease bonus and other income. Lease bonus and other income increased for the six months ended June 30, 2017 as compared to the same period in 2016. In the first six months of 2017, we successfully closed several significant lease transactions in San Augustine, Midland, Potter and Ward counties of Texas, in Red River parish of Louisiana and Dunn and McKenzie counties of North Dakota.

Operating and Other Expenses

Lease operating expense. Lease operating expense decreased for the six months ended June 30, 2017 as compared to the same period in 2016, primarily due to fewer producing wells and fewer remedial projects initiated by our operators.

Production costs and ad valorem taxes. For the six months ended June 30, 2017, production costs and ad valorem taxes increased from the six months ended June 30, 2016, generally as a result of higher commodity prices and natural gas production volumes.

Exploration expense. Exploration expense decreased for the six months ended June 30, 2017 as compared to the same period in 2016. Exploration expense for the six months ended June 30, 2017 and 2016 represents costs incurred to acquire 3-D seismic information, related to our mineral and royalty interests, from a third-party service provider.

Depreciation, depletion, and amortization. Depreciation, depletion, and amortization increased for the six months ended June 30, 2017 as compared to the same period in 2016, primarily due to higher production partially offset by lower depletion rates.

Impairment of oil and natural gas properties. Impairments totaled $6.8 million for the six months ended June 30, 2016 primarily due to changes in reserve values resulting from declines in future expected realized net cash flows.

General and administrative. For the six months ended June 30, 2017, general and administrative expenses decreased as compared to the same period in 2016 due to lower costs attributable to our long-term incentive plans.

Interest expense. Interest expense increased due to higher average outstanding borrowings under our credit facility. Average outstanding borrowings during the first six months of 2017 were higher than the six months ended June 30, 2016, primarily due to funding of acquisitions, common unit repurchases in 2016, and redemptions associated with our preferred units in 2017.

Liquidity and Capital Resources

Overview

Our primary sources of liquidity are cash generated from operations, borrowings under our credit facility, and proceeds from the issuance of equity and debt. Our primary uses of cash are for distributions to our unitholders and for investing in our business, specifically the acquisition of mineral and royalty interests and our selective participation on a non-operated working-interest basis in the development of our oil and natural gas properties.

We intend to finance our future acquisitions with cash generated from operations, borrowings from our credit facility, and proceeds from any future issuances of equity and debt. Over the long-term, we intend to finance our working-interest capital needs with internally-generated cash flows, although at times we may fund a portion of these expenditures through

external financing sources such as borrowings under our credit facility. Replacement capital expenditures are expenditures necessary to replace our existing oil and natural gas reserves or otherwise maintain our asset base over the long-term. Like a number of other master limited partnerships, we are required by our partnership agreement to retain cash from our operations in an amount equal to our estimated replacement capital requirements. The Board of Directors of our general partner (the “Board”) established a replacement capital expenditure estimate of $15.0 million for the period of April 1, 2016 to March 31, 2017. On June 8, 2017, the Board established a replacement capital expenditure estimate of $13.0 million for the period of April 1, 2017 to March 31, 2018.

Cash Flows

The following table shows our cash flows for the periods presented:



	Six Months Ended June 30,
	2017			2016
	(Unaudited) (In thousands)
Cash flows provided by (used in) operating activities	$	139,164		$	83,544
Cash flows provided by (used in) investing activities	(98,367		)	(172,878		)
Cash flows provided by (used in) financing activities	(43,082		)	85,871

Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016

Operating Activities. Our operating cash flows are dependent, in large part, on our production, realized commodity prices, derivative settlements, lease bonus revenue, and operating expenses. Our cash flows from operations increased from $83.5 million for the six months ended June 30, 2016 to $139.2 million for the six months ended June 30, 2017. The increase was primarily due to higher cash collections of $76.4 million related to higher oil and natural gas sales and other changes in working capital as compared to the corresponding period in 2016.

Investing Activities. Net cash used in investing activities decreased by $74.5 million in the first six months of 2017 as compared to the corresponding period in 2016 primarily due to mineral and property acquisitions being higher during the first six months of 2016. Lower capital expenditures for our working interest properties added to the overall decrease in investing activities.

Financing Activities. Cash flows from financing activities decreased in the first six months of 2017 as compared to the corresponding period in 2016. Net cash used in financing activities for the six months ended June 30, 2017 consisted of distributions to our common and subordinated unit holders, redemptions of redeemable preferred units and repurchases of common and subordinated units. These cash outflows were partially offset by net borrowings under our credit facility and proceeds from the issuance of common units under the ATM Program. Net cash provided by financing activities for the six months ended June 30, 2016 consisted of net borrowings under our credit facility partially offset by distributions to our common and subordinated unit holders, redemptions of redeemable preferred units and repurchases of common and subordinated units.

Capital Expenditures

Our 2017 drilling expenditures are expected to be between $40 million to $50 million down from our previous estimate of $50 million to $60 million. Approximately 90% of our drilling capital budget will be spent in the Haynesville/Bossier play with the remainder expected to be spent in various plays including the Bakken/Three Forks and Wolfcamp plays. On February 16, 2017, we entered into a farmout agreement which will reduce our future capital requirements and will generate additional royalty income. The farmout covers our working interests within an approximate 34,000-acre block in San Augustine County, Texas.

During the six months ended June 30, 2017, we incurred $30.8 million related to drilling and completion costs, primarily in the Haynesville/Bossier play. During the six months ended June 30, 2017, we also completed mineral and royalty interests acquisitions for $124.4 million in cash and equity. See Note 4 – Acquisitions and Dispositions to our unaudited consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for further discussion.

Credit Facility

On January 23, 2015, we amended and restated our $1.0 billion senior secured revolving credit agreement. Under this third amended and restated credit facility, the commitment of the lenders equals the lesser of the aggregate maximum credit amounts of the lenders and the borrowing base, which is determined based on the lenders’ estimated value of our oil and natural gas properties. On October 28, 2015, the third amended and restated credit facility was further amended to extend the term of the agreement from February 3, 2017 to February 4, 2019. Borrowings under the third amended and restated credit facility may be used for the acquisition of properties, cash distributions, and other general corporate purposes. Our regular, semi-annual borrowing base redetermination process resulted in a decrease of the borrowing base from $550.0 million to $450.0 million, effective April 15, 2016. Our 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. As of June 30, 2017, we had outstanding borrowings of $393.0 million at a weighted-average interest rate of 3.73%.

The borrowing base under the third amended and restated credit agreement is redetermined semi-annually, typically in April and October of each year, by the administrative agent, taking into consideration the estimated loan value of our oil and natural gas properties consistent with the administrative agent’s normal lending criteria. The administrative agent’s proposed redetermined borrowing base must be approved by all lenders to increase our existing borrowing base, and by two-thirds of the lenders to maintain or decrease our existing borrowing base. In addition, we and the lenders (at the election of two-thirds of the lenders) each have discretion to have the borrowing base redetermined once between scheduled redeterminations.

Outstanding borrowings under the third amended and restated credit facility bear interest at a floating rate elected by us equal to an alternative base rate (which is equal to the greatest of the Prime rate, the Federal Funds effective rate plus 0.50%, or 1-month LIBOR plus 1.00%) or LIBOR, in each case, plus the applicable margin. Through October 2016, the applicable margin ranged from 0.50% to 1.50% in the case of the alternative base rate and from 1.50% to 2.50% in the case of LIBOR, in each case depending on the amount of borrowings outstanding in relation to the borrowing base. Subsequent to the closing of our fall redetermination on October 31, 2016, the applicable margin ranges from 1.00% to 2.00% in the case of the alternative base rate and from 2.00% to 3.00% in the case of LIBOR, depending on the borrowings outstanding in relation to the borrowing base.

We are obligated to pay a quarterly commitment fee ranging from a 0.375% to 0.500% annualized rate on the unused portion of the borrowing base, depending on the amount of the borrowings outstanding in relation to the borrowing base. Principal may be optionally repaid from time to time without premium or penalty, other than customary LIBOR breakage, and is required to be paid (a) if the amount outstanding exceeds the borrowing base, whether due to a borrowing base redetermination or otherwise, in some cases subject to a cure period, or (b) at the maturity date. The third amended and restated credit facility is secured by liens on substantially all of our producing properties.

The third amended and restated credit agreement contains various affirmative, negative, and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates, and entering into certain swap agreements, as well as require the maintenance of certain financial ratios. The third amended and restated credit agreement contains two financial covenants: total debt to EBITDAX of 3.5:1.0 or less and a modified current ratio of 1.0:1.0 or greater as defined in the credit agreement. Distributions are not permitted if there is a default under the third amended and restated credit agreement (including due to a failure to satisfy one of the financial covenants) or during any time that our borrowing base is lower than the loans outstanding under the third amended and restated credit facility. The lenders have the right to accelerate all of the indebtedness under the third amended and restated credit facility upon the occurrence and during the continuance of any event of default, and the third amended and restated credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy, and change of control. There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods. As of June 30, 2017, we were in compliance with all debt covenants.

Contractual Obligations

As of June 30, 2017, there have been no material changes to our contractual obligations previously disclosed in our 2016 Annual Report on Form 10-K.

Off-Balance Sheet Arrangements

As of June 30, 2017, we did not have any material off-balance sheet arrangements.

Critical Accounting Policies and Related Estimates

As of June 30, 2017, there have been no significant changes to our critical accounting policies and related estimates previously disclosed in our 2016 Annual Report on Form 10-K.

New and Revised Financial Accounting Standards

The effects of new accounting pronouncements are discussed in the notes to our unaudited consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q.


Item 3.	Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Risk

Our major market risk exposure is the pricing of oil, natural gas, and natural gas liquids produced by our operators. Realized prices are primarily driven by the prevailing global prices for oil and prices for natural gas and NGLs in the United States. Prices for oil, natural gas, and natural gas liquids have been volatile for several years, and we expect this unpredictability to continue in the future. The prices that our operators receive for production depend on many factors outside of our or their control. To reduce the impact of fluctuations in oil and natural gas prices on our revenues, we use commodity derivative instruments to reduce our exposure to price volatility of oil and natural gas. The counterparties to the contracts are unrelated third parties. The contracts settle monthly in cash based on a designated floating price. The designated floating price is based on the NYMEX benchmark for oil and natural gas. We have not designated any of our contracts as fair value or cash flow hedges. Accordingly, the changes in fair value of the contracts are included in net income in the period of the change. See Note 5 – Derivatives and Financial Instruments and Note 6 – Fair Value Measurement to the unaudited consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for additional information.

Commodity prices have declined in recent years. To estimate the effect lower prices would have on our reserves, we applied a 10% discount to the SEC commodity pricing for the twelve months ended June 30, 2017. Applying this discount results in an approximate 2.2% reduction of proved reserve volumes as compared to the undiscounted June 30, 2017 SEC pricing scenario.

Counterparty and Customer Credit Risk

Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require our counterparties to our derivative contracts to post collateral, we do evaluate the credit standing of such counterparties as we deem appropriate. This evaluation includes reviewing a counterparty’s credit rating and latest financial information. As of June 30, 2017, we had nine counterparties, all of which are rated Baa1 or better by Moody’s. Seven of our counterparties are lenders under our credit facility.

Our principal exposure to credit risk results from receivables generated by the production activities of our operators. The inability or failure of our significant operators to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. However, we believe the credit risk associated with our operators and customers is acceptable.

Interest Rate Risk

We have exposure to changes in interest rates on our indebtedness. As of June 30, 2017, we had $393.0 million of outstanding borrowings under our credit facility, bearing interest at a weighted-average interest rate of 3.73%. The impact of a 1% increase in the interest rate on this amount of debt would have resulted in an increase in interest expense, and a corresponding decrease in our results of operations, of $2.0 million for the six months ended June 30, 2017, assuming that our indebtedness remained constant throughout the period. We may use certain derivative instruments to hedge our exposure to variable interest rates in the future, but we do not currently have any interest rate hedges in place.


Item 4.	Controls and Procedures

Disclosure Controls and Procedures

As required by Rule 13a-15(b) under the Securities Exchange Act of 1934 (the “Exchange Act”), we have evaluated, under the supervision and with the participation of management of our general partner, including our general partner’s principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report on Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to management, including our general partner’s principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our general partner’s principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of June 30, 2017.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended June 30, 2017 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II – OTHER INFORMATION


Item 1.	Legal Proceedings

Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities. In the opinion of our management, none of the pending litigation, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations.


Item 1A.	Risk Factors

In addition to the other information set forth in this report, readers should carefully consider the risks under the heading “Risk Factors” in our 2016 Annual Report on Form 10-K. There has been no material change in our risk factors from those described in our 2016 Annual Report on Form 10-K. These risks are not the only risks that we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may materially adversely affect our business, financial condition or results of operations.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Recent Sales of Unregistered Securities

On June 30, 2017, we closed on the acquisition of certain mineral interests using, in the aggregate, 90,649 common units valued at approximately $1.4 million to fund a portion of the total consideration.

The issuance of the common units was made in reliance upon an exemption from the registration requirements of the Securities Act of 1933, as amended, pursuant to Rule 506(c) of Regulation D thereunder. The investors are "accredited investors" (as defined in Regulation D), the investors acquired the common units for investment purposes only and not for resale and the Partnership took appropriate measures to restrict the transfer of the common units issued and verify the accredited investor status of the investors.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following tables set forth our purchases of our common, subordinated, and preferred units during the three months ended June 30, 2017:

Purchases of Preferred Units

Period

Total Number of Preferred Units Purchased

Average Price Paid Per Unit

Total Number of Preferred Units Purchased as Part of Publicly Announced Plans or Programs

Maximum Dollar Value of Preferred Units That May Yet Be Purchased Under the Plans or Programs

April 1 - April 30, 2017

6,899

1,026

6,899 ¹

—

¹ Pursuant to our partnership agreement, on December 31 of each year through 2017 (each date, a “Scheduled Redemption Date”), each preferred unitholder may, upon written notice, require us to redeem a portion of its preferred units for a cash price per preferred unit equal to the sum of $1,000.00 plus the unpaid accrued yield through that date (the aggregate amount, the “Holder Redemption Price”). We will pay to the redeeming preferred unitholder the Holder Redemption Price plus, in the event of a payment after the Scheduled Redemption Date, interest on the Holder Redemption Price at a rate of 10% per annum (subject to adjustment following certain events of default by us from the Scheduled Redemption Date until the date paid to the redeeming preferred unitholder.) This year, holders redeemed 19,641 preferred units for a total cost of approximately $20.1 million. The maximum number of preferred units that may yet be purchased represents all preferred units outstanding as of June 30, 2017, which could be redeemed during the final redemption window in early 2018. In addition, the preferred units may be converted, at the option of the holder thereof, at any time, and without the payment of additional consideration, into common units and subordinated units at the then-effective conversion rate. The preferred units have a conversion rate of 30.3431 common units and 39.7427 subordinated units per preferred unit, subject to adjustment.

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Item 6.	Exhibits

The information required by this Item 6 is set forth in the Index to Exhibits accompanying this Quarterly Report on Form 10-Q and is incorporated herein by reference.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



	BLACK STONE MINERALS, L.P.

	By:	Black Stone Minerals GP, L.L.C., its general partner

Date: August 9, 2017	By:	/s/ Thomas L. Carter, Jr.
		Thomas L. Carter, Jr.
		President and Chief Executive Officer
		(Principal Executive Officer)

Date: August 9, 2017	By:	/s/ Jeffrey P. Wood
		Jeffrey P. Wood
		Senior Vice President and Chief Financial Officer
		(Principal Financial Officer)

Exhibit Index




Exhibit Number		Description

3.1		Certificate of Limited Partnership of Black Stone Minerals, L.P. (incorporated herein by reference to Exhibit 3.1 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on March 19, 2015 (SEC File No. 333-202875)).

3.2		Certificate of Amendment to Certificate of Limited Partnership of Black Stone Minerals, L.P. (incorporated herein by reference to Exhibit 3.2 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on March 19, 2015 (SEC File No. 333-202875)).

3.3		First Amended and Restated Agreement of Limited Partnership of Black Stone Minerals, L.P., dated May 6, 2015, by and among Black Stone Minerals GP, L.L.C. and Black Stone Minerals Company, L.P., as amended by Amendment No. 1 to First Amended and Restated Agreement of Limited Partnership of Black Stone Minerals, L.P. dated as of April 15, 2016 (incorporated herein by reference to Exhibit 3.2 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on April 19, 2016 (SEC File No. 001-37362)).

*31.1		Certification of Chief Executive Officer of Black Stone Minerals, L.P. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

*31.2		Certification of Chief Financial Officer of Black Stone Minerals, L.P. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

*32.1		Certification of Chief Executive Officer and Chief Financial Officer of Black Stone Minerals, L.P. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002


*101.INS		XBRL Instance Document

*101.SCH		XBRL Schema Document

*101.CAL		XBRL Calculation Linkbase Document

*101.LAB		XBRL Label Linkbase Document

*101.PRE		XBRL Presentation Linkbase Document

*101.DEF		XBRL Definition Linkbase Document

* Filed or furnished herewith.

Black Stone Minerals, L.P. - FORM 10-Q - August 9, 2017

Attached files

Black Stone Minerals, L.P. Reports