Black Stone Minerals, L.P. - Quarter Report: 2018 March (Form 10-Q)

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 March 31, 2018



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

For the transition period _______________ to _______________

Commission File Number: 001-37362

Black Stone Minerals, L.P.

(Exact name of registrant as specified in its charter)



Delaware		47-1846692
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1001 Fannin Street, Suite 2020 Houston, Texas		77002
(Address of principal executive offices)		(Zip code)

(713) 445-3200

(Registrant’s telephone number, including area code)

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):



Large accelerated filer	ý		Accelerated filer	☐
Non-accelerated filer	☐	(Do not check if a smaller reporting company)	Smaller reporting company	☐
			Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

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

As of May 2, 2018, there were 105,220,326 common units, 96,328,836 subordinated units, and 14,711,219 Series B cumulative convertible preferred units of the registrant outstanding.

TABLE OF CONTENTS



		Page
PART I – FINANCIAL INFORMATION

Item 1.	Financial Statements (Unaudited)
	Consolidated Balance Sheets as of March 31, 2018 and December 31, 2017	1
	Consolidated Statements of Operations for the Three Months Ended March 31, 2018 and 2017	2
	Consolidated Statement of Equity for the Three Months Ended March 31, 2018	3
	Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2018 and 2017	4
	Notes to Unaudited Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	33
Item 4.	Controls and Procedures	33

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	34
Item 1A.	Risk Factors	34
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	34
Item 5.	Other Information	35
Item 6.	Exhibits	36

	Signatures	38

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In thousands)



	March 31, 2018			December 31, 2017
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	6,297		$	5,642
Accounts receivable	92,855			80,695
Commodity derivative assets	—			94
Prepaid expenses and other current assets	1,472			1,212
TOTAL CURRENT ASSETS	100,624			87,643
PROPERTY AND EQUIPMENT
Oil and natural gas properties, at cost, using the successful efforts method of accounting, includes unproved properties of $1,018,695 and $988,720 at March 31, 2018 and December 31, 2017, respectively	3,320,859			3,247,613
Accumulated depreciation, depletion, amortization, and impairment	(1,794,006		)	(1,766,842		)
Oil and natural gas properties, net	1,526,853			1,480,771
Other property and equipment, net of accumulated depreciation of $14,471 and $14,433 at March 31, 2018 and December 31, 2017, respectively	515			559
NET PROPERTY AND EQUIPMENT	1,527,368			1,481,330
DEFERRED CHARGES AND OTHER LONG-TERM ASSETS	7,986			7,478
TOTAL ASSETS	$	1,635,978		$	1,576,451
LIABILITIES, MEZZANINE EQUITY, AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	2,282		$	2,464
Accrued liabilities	35,292			52,631
Commodity derivative liabilities	17,290			4,222
Other current liabilities	350			417
TOTAL CURRENT LIABILITIES	55,214			59,734
LONG–TERM LIABILITIES
Credit facility	436,000			388,000
Accrued incentive compensation	4,079			3,648
Commodity derivative liabilities	947			1,263
Asset retirement obligations	14,382			14,092
Other long-term liabilities	38,876			19,171
TOTAL LIABILITIES	549,498			485,908
COMMITMENTS AND CONTINGENCIES (Note 8)
MEZZANINE EQUITY
Partners' equity – Series A redeemable convertible preferred units, zero and 26 units outstanding at March 31, 2018 and December 31, 2017, respectively	—			27,028
Partners' equity – Series B cumulative convertible preferred units, 14,711 and 14,711 units outstanding at March 31, 2018 and December 31, 2017, respectively	300,644			295,394
EQUITY
Partners' equity – general partner interest	—			—
Partners' equity – common units, 104,926 and 103,456 units outstanding at March 31, 2018 and December 31, 2017, respectively	614,720			603,116
Partners' equity – subordinated units, 96,329 and 95,388 units outstanding at March 31, 2018 and December 31, 2017, respectively	170,274			164,138
Noncontrolling interests	842			867
TOTAL EQUITY	785,836			768,121
TOTAL LIABILITIES, MEZZANINE EQUITY, AND EQUITY	$	1,635,978		$	1,576,451

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

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands, except per unit amounts)



	Three Months Ended March 31,
	2018			2017
REVENUE
Oil and condensate sales	$	72,983		$	40,474
Natural gas and natural gas liquids sales	53,245			47,701
Lease bonus and other income	4,599			13,682
Revenue from contracts with customers	130,827			101,857
Gain (loss) on commodity derivative instruments	(16,333		)	22,725
TOTAL REVENUE	114,494			124,582
OPERATING (INCOME) EXPENSE
Lease operating expense	4,248			4,189
Production costs and ad valorem taxes	14,925			11,902
Exploration expense	3			562
Depreciation, depletion, and amortization	28,570			26,379
General and administrative	18,521			17,212
Accretion of asset retirement obligations	269			247
(Gain) loss on sale of assets, net	(2		)	(924		)
TOTAL OPERATING EXPENSE	66,534			59,567
INCOME (LOSS) FROM OPERATIONS	47,960			65,015
OTHER INCOME (EXPENSE)
Interest and investment income	33			6
Interest expense	(4,521		)	(3,507		)
Other income (expense)	(1,515		)	69
TOTAL OTHER EXPENSE	(6,003		)	(3,432		)
NET INCOME (LOSS)	41,957			61,583
Net (income) loss attributable to noncontrolling interests	(27		)	(9		)
Distributions on Series A redeemable preferred units	(25		)	(1,114		)
Distributions on Series B cumulative convertible preferred units	(5,250		)	—
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS	$	36,655		$	60,460
ALLOCATION OF NET INCOME (LOSS):
General partner interest	$	—		$	—
Common units	24,329			35,517
Subordinated units	12,326			24,943
	$	36,655		$	60,460
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:
Per common unit (basic)	$	0.23		$	0.37
Weighted average common units outstanding (basic)	103,774			96,901
Per subordinated unit (basic)	$	0.13		$	0.26
Weighted average subordinated units outstanding (basic)	95,395			95,149
Per common unit (diluted)	$	0.23		$	0.37
Weighted average common units outstanding (diluted)	103,838			97,590
Per subordinated unit (diluted)	$	0.13		$	0.26
Weighted average subordinated units outstanding (diluted)	95,395			95,149
DISTRIBUTIONS DECLARED AND PAID:
Per common unit	$	0.3125		$	0.2875
Per subordinated unit	$	0.2088		$	0.1838

The accompanying notes are an integral part of these unaudited 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, 2017	103,456		95,388		$	603,116		$	164,138		$	867		$	768,121
Conversion of Series A redeemable preferred units	736		964		10,498			13,750			—			24,248
Repurchases of common and subordinated units	(451	)	(23	)	(8,099		)	(342		)	—			(8,441		)
Issuance of common units, net of offering costs	8		—		138			—			—			138
Restricted units granted, net of forfeitures	1,177		—		—			—			—			—
Equity–based compensation	—		—		17,980			314			—			18,294
Distributions	—		—		(32,581		)	(19,912		)	(52		)	(52,545		)
Charges to partners' equity for accrued distribution equivalent rights	—		—		(661		)	—			—			(661		)
Distributions on Series A redeemable preferred units	—		—		(13		)	(12		)	—			(25		)
Distributions on Series B cumulative convertible preferred units	—		—		(5,250		)	—			—			(5,250		)
Net income (loss)	—		—		29,592			12,338			27			41,957
BALANCE AT MARCH 31, 2018	104,926		96,329		$	614,720		$	170,274		$	842		$	785,836

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

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)



	Three Months Ended March 31,
	2018			2017
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	41,957		$	61,583
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization	28,570			26,379
Accretion of asset retirement obligations	269			247
Amortization of deferred charges	205			215
(Gain) loss on commodity derivative instruments	16,333			(22,725		)
Net cash (paid) received on settlement of commodity derivative instruments	(4,375		)	4,278
Equity-based compensation	6,226			4,661
(Gain) loss on sale of assets, net	(2		)	(924		)
Changes in operating assets and liabilities:
Accounts receivable	(11,851		)	(6,568		)
Prepaid expenses and other current assets	(260		)	(85		)
Accounts payable, accrued liabilities, and other	(565		)	(3,064		)
Settlement of asset retirement obligations	(33		)	(43		)
NET CASH PROVIDED BY OPERATING ACTIVITIES	76,474			63,954
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisitions of oil and natural gas properties	(32,154		)	(48,371		)
Additions to oil and natural gas properties	(46,250		)	(16,279		)
Additions to oil and natural gas properties leasehold costs	(524		)	(1,336		)
Purchases of other property and equipment	(5		)	(93		)
Proceeds from the sale of oil and natural gas properties	752			1,993
Proceeds from farmouts of oil and natural gas properties	18,015			—
NET CASH USED IN INVESTING ACTIVITIES	(60,166		)	(64,086		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of common units, net of offering costs	138			—
Distributions to common and subordinated unitholders	(52,493		)	(45,404		)
Distributions to Series A redeemable preferred unitholders	(690		)	(1,619		)
Distributions to noncontrolling interests	(52		)	(25		)
Redemptions of Series A redeemable preferred units	(2,115		)	(12,742		)
Repurchases of common and subordinated units	(8,441		)	(7,845		)
Borrowings under credit facility	105,000			103,000
Repayments under credit facility	(57,000		)	(31,000		)
NET CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES	(15,653		)	4,365
NET CHANGE IN CASH AND CASH EQUIVALENTS	655			4,233
CASH AND CASH EQUIVALENTS – beginning of the period	5,642			9,772
CASH AND CASH EQUIVALENTS – end of the period	$	6,297		$	14,005
SUPPLEMENTAL DISCLOSURE
Interest paid	$	4,326		$	3,156

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

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 — BUSINESS AND BASIS OF PRESENTATION

Description of the Business

Black Stone Minerals, L.P. (“BSM” or the “Partnership”) is a publicly traded Delaware limited partnership formed on September 16, 2014. On May 6, 2015, BSM completed its initial public offering (the “IPO”) of 22,500,000 common units representing limited partner interests at a price to the public of $19.00 per common unit. BSM received proceeds of $391.5 million from the sale of its common units, net of underwriting discount, structuring fee, and offering expenses (including costs previously incurred and capitalized). BSM used the net proceeds from the IPO to repay substantially all indebtedness outstanding under its Credit Facility, as defined in Note 7 – Credit Facility. On May 1, 2015, BSM’s common units began trading on the New York Stock Exchange under the symbol “BSM.”

Black Stone Minerals Company, L.P., a Delaware limited partnership, and its subsidiaries (collectively referred to as “BSMC” or the “Predecessor”) own oil and natural gas mineral interests in the United States ("U.S."). In connection with the IPO, BSMC was merged into a wholly owned subsidiary of BSM, with BSMC as the surviving entity. Pursuant to the merger, the Class A and Class B common units representing limited partner interests of the Predecessor were converted into an aggregate of 72,574,715 common units and 95,057,312 subordinated units of BSM at a conversion ratio of 12.9465:1 for 0.4329 common units and 0.5671 subordinated units, and the preferred units of BSMC were converted into an aggregate of 117,963 Series A redeemable preferred units of BSM at a conversion ratio of one to one. The merger was accounted for as a combination of entities under common control with assets and liabilities transferred at their carrying amounts in a manner similar to a pooling of interests. Unless otherwise stated or the context otherwise indicates, all references to the “Partnership” or similar expressions for time periods prior to the IPO refer to Black Stone Minerals Company, L.P. and its subsidiaries, the Predecessor, for accounting purposes. For time periods subsequent to the IPO, these terms refer to Black Stone Minerals, L.P. and its subsidiaries.

In addition to mineral interests, which make up the vast majority of the asset base, the Partnership’s assets also include nonparticipating and overriding royalty interests. These interests, which are non-cost-bearing, are collectively referred to as “mineral and royalty interests.” As of March 31, 2018, the Partnership’s mineral and royalty interests were located in 41 states and 64 onshore oil and natural gas producing basins of the continental U.S., including all of the major onshore producing basins. The Partnership also owns non-operated working interests in certain oil and natural gas properties.

Basis of Presentation

The accompanying unaudited interim consolidated financial statements of the Partnership have been prepared in accordance with generally accepted accounting principles in the United States ("U.S. GAAP") and pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). These unaudited interim consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q and, therefore, do not include all disclosures required for financial statements prepared in conformity with U.S. GAAP. Accordingly, the accompanying unaudited interim consolidated financial statements and related notes should be read in conjunction with the Partnership’s consolidated financial statements included in the Partnership’s 2017 Annual Report on Form 10-K.

The financial statements include the consolidated results of the Partnership. The results of operations for the three months ended March 31, 2018 are not necessarily indicative of the results to be expected for the full year.

In the opinion of management, all material adjustments, which are of a normal and recurring nature, necessary for the fair presentation of the financial results for all periods presented have been reflected. 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.

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

The Partnership evaluates the significant terms of its investments to determine the method of accounting to be applied to each respective investment. Investments in which the Partnership has less than a 20% ownership interest and does not have control or exercise significant influence are accounted for under the cost method. The Partnership’s cost method investment is included in deferred charges and other long-term assets in the consolidated balance sheets. Investments in which the Partnership exercises control are consolidated, and the noncontrolling interests of such investments, which are not attributable directly or indirectly to the Partnership, are presented as a separate component of net income and equity in the accompanying consolidated financial statements.

The unaudited interim consolidated financial statements include undivided interests in oil and natural gas property rights. The Partnership accounts for its share of oil and natural gas property rights by reporting its proportionate share of assets, liabilities, revenues, costs, and cash flows within the relevant lines on the accompanying unaudited interim consolidated balance sheets, statements of operations, and statements of cash flows.

Segment Reporting

The Partnership operates in a single operating and reportable segment. Operating segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assess performance. The Partnership’s chief executive officer has been determined to be the chief operating decision maker and allocates resources and assesses performance based upon financial information at the consolidated level.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Significant Accounting Policies

Significant accounting policies are disclosed in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2017. There have been no changes in such policies or the application of such policies during the three months ended March 31, 2018, with the exception of ASC 606, as defined below.

Accounts Receivable

The following table presents information about the Partnership's accounts receivable:



	March 31, 2018		December 31, 2017

	(in thousands)
Accounts receivable:
Revenues from contracts with customers	$	89,616	$	77,544
Other	3,239		3,151
Total accounts receivable	$	92,855	$	80,695

New Accounting Pronouncements

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

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires lessees to recognize the lease assets and lease liabilities classified as operating leases on the balance sheet. In January 2018, the FASB issued an amendment to this guidance in ASU 2018-01, Leases (Topic 842), "Land Easement Practical Expedient for Transition to Topic 842," which provides an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under the current leases guidance in Topic 840.

The new standard will be effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, and early adoption is permitted. The Partnership will use the modified retrospective adoption approach with respect to ASU 2016-02 and does not plan to early adopt. Based on evaluations to-date, the new guidance will not have a material impact on the Partnership's consolidated financial statements and related disclosures as this guidance does not apply to leases to explore for or use minerals, oil, natural gas, and similar resources.

NOTE 3 — IMPACT OF ASC 606 ADOPTION

ASC 606, Revenue from Contracts with Customers, requires the Partnership to identify the distinct promised goods and services within a contract which represent separate performance obligations and determine the transaction price to allocate to the performance obligations identified. The Partnership adopted ASC 606 using the modified retrospective method, which was applied to all existing contracts for which all (or substantially all) of the revenue had not been recognized under legacy revenue guidance as of January 1, 2018.

Revenues from Contracts with Customers

Oil and natural gas sales

Sales of oil and natural gas are recognized at the point control of the product is transferred to the customer and collectability of the sales price is reasonably assured. Oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. The price the Partnership receives for natural gas is tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality and heat content of natural gas, and prevailing supply and demand conditions, so that the price of natural gas fluctuates to remain competitive with other available natural gas supplies. These market indices are determined on a monthly basis.

Lease bonus and other income

The Partnership also earns revenue from lease bonuses and delay rentals. The Partnership generates lease bonus revenue by leasing its mineral interests to exploration and production companies. A lease agreement represents the Partnership's contract with a customer and generally transfers the rights to any oil or natural gas discovered, grants the Partnership a right to a specified royalty interest, and requires that drilling and completion operations commence within a specified time period. Control is transferred to the lessee and the Partnership has satisfied its performance obligation when the lease agreement is executed, such that revenue is recognized when the lease bonus payment is received. At the time the Partnership executes the lease agreement, the Partnership expects to receive the lease bonus payment within a reasonable time, though in no case more than one year, such that the Partnership has not adjusted the expected amount of consideration for the effects of any significant financing component per the practical expedient in ASC 606-10-32-18. The Partnership also recognizes revenue from delay rentals to the extent drilling has not started within the specified period, payment has been received, and the Partnership has no further obligation to refund the payment.

Production imbalances

The Partnership previously elected to utilize the entitlements method to account for natural gas production imbalances, which is no longer permitted under ASC 606. As of January 1, 2018, these amounts were de minimis. As such, upon adoption of ASC 606, there was no material impact to the financial statements due to this change in accounting for our production imbalances.

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

Allocation of transaction price to remaining performance obligations

Oil and natural gas sales

The Partnership has utilized the practical expedient in ASC 606 which states the Partnership is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. As the Partnership has determined that each unit of product generally represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

Lease bonus and other income

Given that the Partnership does not recognize lease bonus or other income until a lease agreement has been executed, at which point its performance obligation has been satisfied, and payment is received, the Partnership does not typically record revenue for unsatisfied or partially unsatisfied performance obligations as of the end of the reporting period. Overall, there were no material changes in the timing of the satisfaction of the Partnership's performance obligations or the allocation of the transaction price to its performance obligations in applying the guidance in ASC 606 as compared to legacy U.S. GAAP.

Prior-period performance obligations

The Partnership records revenue in the month production is delivered to the purchaser. As a non-operator, the Partnership has limited visibility into the timing of when new wells start producing and production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, the Partnership is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The expected sales volumes and prices for these properties are estimated and recorded within the Accounts receivable line item in the accompanying consolidated balance sheets. The difference between the Partnership's estimates and the actual amounts received for oil and natural gas sales is recorded in the month that payment is received from the third party. For the three months ended March 31, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was immaterial.

NOTE 4 — OIL AND NATURAL GAS PROPERTIES ACQUISITIONS

Acquisitions of proved oil and natural gas properties and working interests are considered business combinations and are recorded at their estimated fair value as of the acquisition date. Acquisitions of unproved oil and natural gas properties are considered asset acquisitions and are recorded at cost.

2018 Acquisitions

During the three months ended March 31, 2018, the Partnership closed on an acquisition of mineral and royalty interests, which also included producing properties, in the Permian Basin. The following table summarizes the acquisition:



	Assets Acquired								Cash Consideration Paid
	Proved		Unproved		Net Working Capital		Total Fair Value		Cash Consideration Paid

	(in thousands)
March 2018	$	984	$	21,452	$	133	$	22,569	$	22,569

In addition, the Partnership acquired mineral and royalty interests from various sellers in the East Texas Basin for $9.6 million in cash. All 2018 acquisitions were funded via borrowings under the Partnership's Credit Facility as well as funds from operating activities.

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

Noble Acquisition

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

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

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

The transaction was accounted for as a business combination using the acquisition method of accounting which requires, among other things, that the assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date. The final determination of fair value remains preliminary and will be completed after post-closing purchase price adjustments are finalized, but in no case later than one year from the acquisition date.

The following table summarizes the preliminary estimate and allocation of the fair value of the assets acquired and the acquisition-related costs.



	Assets Acquired								Cash Consideration Paid		Acquisition-Related Costs¹
	Proved		Unproved		Net Working Capital		Total Fair Value		Cash Consideration Paid		Acquisition-Related Costs¹

	(in thousands)
Noble Assets	$	68,877	$	259,749	$	5,917	$	334,543	$	334,543	$	247


¹	Acquisition-related costs were expensed and included in the General and administrative expense line item of the consolidated statement of operations for the year ended December 31, 2017.

The fair value of the Noble Assets was measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of: (i) oil and natural gas reserves; (ii) future commodity prices; (iii) estimated future cash flows; and (iv) market-based weighted average cost of capital. These inputs require significant judgments and estimates by the Partnership's management at the time of the valuation and are the most sensitive and subject to change.

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

Actual and Pro Forma Impact of Noble Acquisition (Unaudited)

Revenue attributable to the Noble Acquisition included in the Partnership's consolidated statement of operations for the three months ended March 31, 2018 was $10.0 million. The following table presents unaudited pro forma information for the Partnership as if the Noble Acquisition occurred on January 1, 2017.



	Three Months Ended March 31, 2017
	(in thousands, except per unit amounts)
Revenue and other income	$	134,193
Net income	67,045
Net income attributable to noncontrolling interests	(9		)
Distributions on Series A redeemable preferred units	(1,114		)
Distributions on Series B cumulative convertible preferred units	(5,250		)
Net income attributable to the general partner and common and subordinated units	$	60,672
Allocation of net income:
General partner interest	$	—
Common units	35,624
Subordinated units	25,048
	$	60,672
Net income attributable to limited partners per common and subordinated unit:
Per common unit (basic)	$	0.37
Per subordinated unit (basic)	$	0.26
Per common unit (diluted)	$	0.37
Per subordinated unit (diluted)	$	0.26

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


•	Adjustments to recognize incremental revenue, production costs and ad valorem taxes, and DD&A expense attributable to the Noble Assets.


•	Adjustment to recognize additional interest expense associated with the incremental borrowings under the Partnership's Credit Facility.


•	Adjustment to recognize the quarterly distribution associated with the issuance of 14,711,219 Series B cumulative convertible preferred units.


•	The Series B cumulative convertible preferred units were included in the calculation of pro forma diluted earnings per common unit for the period presented above due to their dilutive effect under the if-converted method; the Series B cumulative convertible preferred units do not have any impact to earnings per subordinated unit.

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

2017 Acquisitions

In addition to the Noble Acquisition, the Partnership closed on multiple acquisitions of mineral and royalty interests during the year ended December 31, 2017, which also included producing properties, as reflected in the table below. These acquisitions were primarily focused in the Delaware Basin and East Texas. The cash portion of all acquisitions below was funded via borrowings under the Partnership's Credit Facility.



	Assets Acquired								Consideration Paid
	Proved		Unproved		Net Working Capital		Total Fair Value		Cash		Fair Value of Common Units Issued		Acquisition-Related Costs¹

	(in thousands)
January	$	5,135	$	34,008	$	263	$	39,406	$	27,380	$	12,026	$	1,162
June	5,006		45,477		—		50,483		4,802		45,681		$	1,481
August	3,277		9,984		—		13,261		4,289		8,972		107
September	3,120		—		—		3,120		3,120		—		—
Total fair value	$	16,538	$	89,469	$	263	$	106,270	$	39,591	$	66,679	$	2,750


¹	Acquisition-related costs were expensed and included in the General and administrative expense line item of the consolidated statement of operations for the year ended December 31, 2017.

Additionally, the Partnership acquired mineral and royalty interests totaling $56.7 million from various sellers in East Texas during the year ended December 31, 2017. The cash portion of these acquisitions of $51.7 million was funded via borrowings under the Partnership's Credit Facility, with an additional $5.0 million funded through the issuance of common units of the Partnership based on the fair values of the common units issued on the acquisition dates.

Farmout Agreements

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. As of March 31, 2018, 16 wells had been drilled during the initial phase. At its option, Canaan may participate in two additional phases with each phase continuing for the lesser of 2 years or until 20 wells have been drilled. During the first three phases of the agreement, Canaan will commit on a phase-by-phase basis and fund 80% of 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. Since the inception of the agreement, the Partnership has received $24.8 million from Canaan under the agreement. All amounts received are included in the Long-term liabilities – other long-term liabilities line item of the March 31, 2018 and December 31, 2017 consolidated balance sheets, as none of the drilled wells had been completed nor had any working interest been assigned to Canaan as of the balance sheet dates herein.

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

On November 21, 2017, we entered into a farmout agreement with a portfolio company of Tailwater Capital, LLC, Pivotal Petroleum Partners (“Pivotal”), that covers substantially all of the Partnership's remaining working interests under active development in the Shelby Trough area of East Texas targeting the Haynesville and Bossier shale acreage after giving effect to the Canaan Farmout (discussed above) over the next eight years. In wells operated by XTO Energy Inc. in San Augustine County, Texas, Pivotal will earn the Partnership's remaining approximate 20% working interest (10% working interest on an 8/8th basis) not covered by the Canaan Farmout, as well as 100% of the Partnership's working interests (ranging from approximately 12.5% to 25% on an 8/8ths basis) in wells operated by its other major operator in the area. Initially, Pivotal will be obligated to fund the development of up to 80 wells across several development areas and then will have options to continue funding the Partnership's working interest across those areas for the duration of the eight year term. After the funding of a designated group of wells by Pivotal and once Pivotal achieves a specified payout for such well group, the Partnership will obtain a majority of the original working interest in the designated group of wells. Since the inception of the agreement, the Partnership has received $12.4 million from Pivotal under the agreement. All amounts received are included in the Long-term liabilities – other long-term liabilities line item of the March 31, 2018 and December 31, 2017 consolidated balance sheets, as none of the drilled wells had been completed nor had any working interest been assigned to Pivotal as of the balance sheet dates herein.

NOTE 5 — COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS

The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To mitigate the inherent commodity price risk associated with its operations, the Partnership uses oil and natural gas derivative instruments. From time to time, such instruments may include variable-to-fixed-price swaps, costless collars, fixed-price contracts and other contractual arrangements. The Partnership enters into oil and natural gas derivative contracts that contain netting arrangements with each counterparty. The Partnership does not enter into derivative instruments for speculative purposes.

As of March 31, 2018, 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 March 31, 2018 and December 31, 2017. See Note 6 – Fair Value Measurements for further discussion.

The Partnership's derivative contracts expose it to credit risk in the event of nonperformance by counterparties. While the Partnership does not require its derivative contract counterparties to post collateral, the Partnership does evaluate the credit standing of such counterparties as deemed appropriate. This evaluation includes reviewing a counterparty’s credit rating and latest financial information. As of March 31, 2018, the Partnership had nine counterparties, all of which are rated Baa1 or better by Moody’s. Eight of the Partnership's counterparties are lenders under the Credit Facility. The Partnership would have been at risk of losing a fair value amount of $9.5 million had the Partnership's counterparties as a group been unable to fulfill their obligations as of March 31, 2018.

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

The tables below summarize the fair values and classifications of the Partnership’s derivative instruments as of each date:



		March 31, 2018
Classification	Balance Sheet Location	Gross Fair Value		Effect of Counterparty Netting			Net Carrying Value on Balance Sheet

		(in thousands)
Assets:
Current asset	Commodity derivative assets	$	6,300	$	(6,300	)	$	—
Long-term asset	Deferred charges and other long-term assets	3,167		(1,916		)	1,251
Total assets		$	9,467	$	(8,216	)	$	1,251
Liabilities:
Current liability	Commodity derivative liabilities	$	23,590	$	(6,300	)	$	17,290
Long-term liability	Commodity derivative liabilities	2,863		(1,916		)	947
Total liabilities		$	26,453	$	(8,216	)	$	18,237



		December 31, 2017
Classification	Balance Sheet Location	Gross Fair Value		Effect of Counterparty Netting			Net Carrying Value on Balance Sheet

		(in thousands)
Assets:
Current asset	Commodity derivative assets	$	10,713	$	(10,619	)	$	94
Long-term asset	Deferred charges and other long-term assets	1,392		(1,029		)	363
Total assets		$	12,105	$	(11,648	)	$	457
Liabilities:
Current liability	Commodity derivative liabilities	$	14,841	$	(10,619	)	$	4,222
Long-term liability	Commodity derivative liabilities	2,292		(1,029		)	1,263
Total liabilities		$	17,133	$	(11,648	)	$	5,485

Changes in the fair values of the Partnership’s derivative instruments (both assets and liabilities) are presented on a net basis in the accompanying consolidated statements of operations and are as follows:



	Three Months Ended March 31,
Derivatives not designated as hedging instruments	2018			2017

	(in thousands)
Beginning fair value of commodity derivative instruments	$	(5,028	)	$	(16,719	)
Gain (loss) on oil derivative instruments	(14,476		)	14,305
Gain (loss) on natural gas derivative instruments	(1,857		)	8,420
Net cash paid (received) on settlements of oil derivative instruments	5,148			(2,809		)
Net cash received on settlements of natural gas derivative instruments	(773		)	(1,469		)
Net change in fair value of commodity derivative instruments	(11,958		)	18,447
Ending fair value of commodity derivative instruments	$	(16,986	)	$	1,728

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

The Partnership had the following open derivative contracts for oil as of March 31, 2018:



				Range (Per Bbl)
Period and Type of Contract	Volume (Bbl)	Weighted Average Price (Per Bbl)		Low		High
Oil Swap Contracts:
2018
First Quarter	285,000	$	55.18	$	52.09	$	61.88
Second Quarter	841,000	55.27		52.09		61.88
Third Quarter	849,000	55.28		51.85		61.88
Fourth Quarter	854,000	55.18		51.85		61.88
2019
First Quarter	495,000	$	56.57	$	52.82	$	58.69
Second Quarter	495,000	56.57		52.82		58.69
Third Quarter	495,000	56.57		52.82		58.69
Fourth Quarter	495,000	56.57		52.82		58.69

The Partnership had the following open derivative contracts for natural gas as of March 31, 2018:



				Range (Per MMBtu)
Period and Type of Contract	Volume (MMBtu)	Weighted Average Price (Per MMBtu)		Low		High
Natural Gas Swap Contracts:
2018
Second Quarter	13,660,000	$	3.02	$	2.86	$	3.23
Third Quarter	13,600,000	3.01		2.90		3.23
Fourth Quarter	13,630,000	3.01		2.90		3.23
2019
First Quarter	7,200,000	$	2.86	$	2.81	$	2.93
Second Quarter	7,240,000	2.86		2.81		2.93
Third Quarter	7,280,000	2.86		2.81		2.93
Fourth Quarter	7,280,000	2.86		2.81		2.93

NOTE 6 — FAIR VALUE MEASUREMENTS

Fair value is defined as the amount at which an asset (or liability) could be bought (or incurred) or sold (or settled) in an orderly transaction between market participants at the measurement date. Further, ASC 820, Fair Value Measurement, establishes a framework for measuring fair value, establishes a fair value hierarchy based on the quality of inputs used to measure fair value, and includes certain disclosure requirements. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk.

ASC 820 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:

Level 1—Unadjusted quoted prices for identical assets or liabilities in active markets.

Level 2—Quoted prices for similar assets or liabilities in non-active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

Level 3—Inputs that are unobservable and significant to the fair value measurement (including the Partnership’s own assumptions in determining fair value).

A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. There were no transfers into, or out of, the three levels of the fair value hierarchy for the three months ended March 31, 2018 or the year ended December 31, 2017.

The carrying value of the Partnership's cash and cash equivalents, receivables, and payables approximate fair value due to the short-term nature of the instruments. The estimated carrying value of all debt as of March 31, 2018 and December 31, 2017 approximated the fair value due to variable market rates of interest. These debt fair values, which are Level 3 measurements, were estimated based on the Partnership’s incremental borrowing rates for similar types of borrowing arrangements, when quoted market prices were not available. The estimated fair values of the Partnership’s financial instruments are not necessarily indicative of the amounts that would be realized in a current market exchange.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The Partnership estimated the fair value of derivative instruments using the market approach via a model that uses inputs that are observable in the market or can be derived from, or corroborated by, observable data. See Note 5 – Commodity Derivative Financial Instruments for further discussion.

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



	Fair Value Measurements Using						Effect of Counterparty Netting			Total
	Level 1		Level 2		Level 3		Effect of Counterparty Netting			Total

	(in thousands)
As of March 31, 2018
Financial Assets
Commodity derivative instruments	$	—	$	9,467	$	—	$	(8,216	)	$	1,251
Financial Liabilities
Commodity derivative instruments	$	—	$	26,453	$	—	$	(8,216	)	$	18,237
As of December 31, 2017
Financial Assets
Commodity derivative instruments	$	—	$	12,105	$	—	$	(11,648	)	$	457
Financial Liabilities
Commodity derivative instruments	$	—	$	17,133	$	—	$	(11,648	)	$	5,485

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Nonfinancial assets and liabilities measured at fair value on a nonrecurring basis include certain nonfinancial assets and liabilities, as may be acquired in a business combination, and measurements of oil and natural gas property values for assessment of impairment.

The determination of the fair values of proved and unproved properties acquired in business combinations are estimated by discounting projected future cash flows. The factors used to determine fair value include estimates of economic reserves, future operating and development costs, future commodity prices, and a risk-adjusted discount rate. The Partnership has designated these measurements as Level 3. The Partnership’s fair value assessments for recent acquisitions are included in Note 4 – Oil and Natural Gas Properties Acquisitions.

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

Oil and natural gas properties are measured at fair value on a nonrecurring basis using the income approach when assessing for impairment. Proved and unproved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of those properties. When assessing producing properties for impairment, the Partnership compares the expected undiscounted projected future cash flows of the producing properties to the carrying amount of the producing properties to determine recoverability. When the carrying amount exceeds its estimated undiscounted future cash flows, the carrying amount is written down to its fair value, which is measured as the present value of the projected future cash flows of such properties. The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing of future production, future capital expenditures, and a risk-adjusted discount rate.

The Partnership’s estimates of fair value have been determined at discrete points in time based on relevant market data. These estimates involve uncertainty and cannot be determined with precision. There were no significant changes in valuation techniques or related inputs as of March 31, 2018 or December 31, 2017.

There were no assets measured at fair value on a nonrecurring basis for the three months ended March 31, 2018 and 2017.

NOTE 7 — CREDIT FACILITY

The Partnership maintains a senior secured revolving credit agreement, as amended (the “Credit Facility”). The Credit Facility has a maximum credit amount of $1.0 billion. The amount of the borrowing base is derived from the value of the Partnership’s oil and natural gas properties as determined by the lender syndicate using pricing assumptions that often differ from the current market for future prices. The borrowing base is redetermined semi-annually, usually in October and April.

Effective April 25, 2017, the borrowing base redetermination increased the borrowing base from $500.0 million to $550.0 million. On November 1, 2017, the Partnership amended and restated the credit agreement to create a swingline facility that permits short-term borrowings on same-day notice, make other changes to the hedging and restrictive covenants, and extend the maturity for a term of five years, which terminates on November 1, 2022. Effective May 4, 2018, the borrowing base was increased to $600.0 million.

Borrowings under the Credit Facility bear interest at LIBOR plus a margin between 2.00% and 3.00%, or the Prime Rate plus a margin between 1.00% and 2.00%, with the margin depending on the borrowing base utilization.

The weighted-average interest rate of the Credit Facility was 4.71% and 4.06% as of March 31, 2018 and December 31, 2017, respectively. Accrued interest is payable at the end of each calendar quarter or at the end of each interest period, unless the interest period is longer than 90 days, in which case interest is payable at the end of every 90-day period. In addition, a commitment fee is payable at the end of each calendar quarter based on either a rate of 0.375% if the borrowing base utilization percentage is less than 50%, or 0.500% per annum if the borrowing base utilization percentage is equal to or greater than 50%. The Credit Facility is secured by substantially all of the Partnership’s producing properties.

The Credit Facility contains various limitations on future borrowings, leases, hedging, and sales of assets. Additionally, the Credit Facility requires the Partnership to maintain a current ratio of not less than 1.0:1.0 and a ratio of total debt to EBITDAX (Earnings before Interest, Taxes, Depreciation, Amortization, and Exploration) of not more than 3.5:1.0. As of March 31, 2018, the Partnership was in compliance with all financial covenants in the Credit Facility.

The aggregate principal balance outstanding was $436.0 million and $388.0 million at March 31, 2018 and December 31, 2017, respectively. The unused portion of the available borrowings under the Credit Facility was $114.0 million and $162.0 million at March 31, 2018 and December 31, 2017, respectively.

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 8 — COMMITMENTS AND CONTINGENCIES

Environmental Matters

The Partnership’s business includes activities that are subject to U.S. federal, state, and local environmental regulations with regard to air, land, and water quality and other environmental matters.

The Partnership does not consider the potential remediation costs that could result from issues identified in any environmental site assessments to be significant to the consolidated financial statements, and no provision for potential remediation costs has been made.

Put Option Related to Noble Acquisition

By acquiring 100% of the issued and outstanding securities of Samedan, now NAMP Holdings, LLC, on November 28, 2017 as part of the Noble Acquisition, the Partnership acquired a 100% interest in Comin-Temin, LLC, now NAMP GP, LLC ("Holdings"), Comin 1989 Partnership LLLP, now NAMP 1, LP ("Comin"), and Temin 1987 Partnership LLLP, now NAMP 2, LP ("Temin"). Pursuant to certain co-ownership agreements, various co-owners hold undivided beneficial ownership interests in 47.34% and 44.39% of the minerals interests held of record by Holdings and Temin, respectively. Based on the terms of the co-ownership agreements, the co-owners each have an unconditional option to require Comin or Temin, as applicable, to purchase their beneficial ownership interest in the mineral interests held of record by Holdings or Temin, as applicable, at any time within 30 days of receiving such repurchase notice. The purchase price of the beneficial ownership interest shall be based on an evaluation performed by Comin or Temin, as applicable, in good faith. As of March 31, 2018, the Partnership had not received notice from any co-owner to exercise their repurchase option, and as such, no liability was recorded.

Litigation

From time to time, the Partnership is involved in legal actions and claims arising in the ordinary course of business. The Partnership believes existing claims as of March 31, 2018 will be resolved without material adverse effect on the Partnership’s financial condition or operations.

NOTE 9 — INCENTIVE COMPENSATION

The table below summarizes incentive compensation expense recorded in general and administrative expenses in the consolidated statements of operations for the three months ended March 31, 2018 and 2017:



	Three Months Ended March 31,
	2018		2017

	(in thousands)
Cash — long-term incentive plan	$	818	$	422
Equity-based compensation — restricted common and subordinated units	3,405		1,808
Equity-based compensation — restricted performance units	2,242		2,353
Board of Directors incentive plan	579		500
Total incentive compensation expense	$	7,044	$	5,083

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 10 — PREFERRED UNITS

Series A Redeemable Preferred Units

As of March 31, 2018, there were no Series A redeemable preferred units outstanding, while as of December 31, 2017 there were 26,363 Series A redeemable preferred units outstanding with a carrying value of $27.0 million. This carrying value included accrued distributions of $0.7 million. The Series A redeemable preferred units are classified as mezzanine equity on the consolidated balance sheets since redemption was outside the control of the Partnership. The Series A redeemable preferred units were entitled to an annual distribution of 10% of the outstanding funded capital of the Series A redeemable preferred units, payable on a quarterly basis in arrears.

The Series A redeemable preferred units were convertible into common and subordinated units at any time at the option of the Series A redeemable preferred unitholders. The Series A redeemable preferred units had an adjusted conversion price of $14.2683 and an adjusted conversion rate of 30.3431 common units and 39.7427 subordinated units per redeemable preferred unit, which reflects the reverse split described in Note 1 – Business and Basis of Presentation and the capital restructuring related to the IPO.

For the year ended December 31, 2017, 19,704 Series A redeemable preferred units were redeemed for $20.2 million, including accrued unpaid yield. For the year ended December 31, 2017, 6,624 Series A redeemable preferred units totaling $6.6 million were converted into 200,996 common units and 263,247 subordinated units as a result of the mandatory conversion subsequent to December 31, 2016.

The Series A redeemable preferred unitholders had the option to elect to have the Partnership redeem, at face value, all remaining Series A redeemable preferred units, effective as of December 31, 2017, plus any accrued and unpaid distributions. All Series A redeemable preferred units not redeemed by March 31, 2018 automatically converted to common and subordinated units effective as of January 1, 2018 or as soon as practicable thereafter.

For the three months ended March 31, 2018, 2,115 Series A redeemable preferred units were redeemed for $2.1 million, including accrued unpaid yield, and 24,248 Series A redeemable preferred units totaling $24.2 million were converted into 735,758 common units and 963,681 subordinated units as a result of the mandatory conversion subsequent to December 31, 2017.

Series B Cumulative Convertible Preferred Units

On November 28, 2017, the Partnership issued and sold in a private placement 14,711,219 Series B cumulative convertible preferred units representing limited partner interests in the Partnership to the Purchaser for a cash purchase price of $20.3926 per Series B cumulative convertible preferred unit, resulting in total proceeds of approximately $300 million.

The Series B cumulative convertible preferred units are entitled to an annual distribution of 7%, payable on a quarterly basis in arrears. For the eight quarters consisting of the quarter in respect of which the initial distribution is paid and the seven full quarters thereafter, the quarterly distribution may be paid, at the sole option of the Partnership, (i) in-kind in the form of additional Series B cumulative convertible preferred units (the "Series B PIK Units"), (ii) in cash, or (iii) in a combination of Series B PIK Units and cash. Beginning with the ninth quarter, all Series B cumulative convertible preferred unit distributions shall be paid in cash. The number of Series B PIK Units to be issued, if any, shall equal the quotient of the Series B cumulative convertible preferred unit distribution amount (or portion thereof) divided by the Series B cumulative convertible preferred unit purchase price of $20.3926.

The Series B cumulative convertible preferred units are convertible into common units of the Partnership on November 29, 2019 and once per quarter thereafter. At such time, the Series B cumulative convertible preferred units may be converted by each holder at its option, in whole or in part, into common units on a one-for-one basis at the purchase price of $20.3926, adjusted to give effect to any accrued but unpaid accumulated distributions on the applicable Series B cumulative convertible preferred units through the most recent declaration date. However, the Partnership shall not be obligated to honor any request for such conversion if such request does not involve an underlying value of common units of at least $10.0 million based on the closing trading price of common units on the trading day immediately preceding the conversion notice date, or such lesser amount to the extent such exercise covers all of a holder's Series B cumulative convertible preferred units.

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

The Series B cumulative convertible preferred units had a carrying value of $300.6 million and $295.4 million, including accrued distributions of $5.3 million and $1.9 million, as of March 31, 2018 and December 31, 2017, respectively. The Series B cumulative convertible preferred units are classified as mezzanine equity on the consolidated balance sheets since certain provisions of redemption are outside the control of the Partnership.

NOTE 11 — EARNINGS PER UNIT

The Partnership applies the two-class method for purposes of calculating earnings per unit (“EPU”). The holders of the Partnership’s restricted common and subordinated units have all the rights of a unitholder, including non-forfeitable distribution rights. As participating securities, the restricted common and subordinated units are included in the calculation of basic earnings per unit. For the periods presented, the amount of earnings allocated to these participating units was not material.

Net income (loss) attributable to the Partnership is allocated to the Partnership’s general partner and the common and subordinated unitholders in proportion to their pro rata ownership after giving effect to distributions, if any, declared during the period. The Series B cumulative convertible preferred units could be converted into 15.1 million common units as of March 31, 2018.

At March 31, 2018, if the outstanding Series B cumulative convertible preferred units were converted to common units, the effect would be anti-dilutive; therefore, they are not included in the calculation of diluted EPU for the three months ended March 31, 2018.

The Partnership’s restricted performance unit awards are contingently issuable units that are considered in the calculation of diluted EPU. The Partnership assesses the number of units that would be issuable, if any, under the terms of the arrangement if the end of the reporting period were the end of the contingency period. At March 31, 2018, there were 0.1 million 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 UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

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



	Three Months Ended March 31,
	2018			2017

	(in thousands, except per unit amounts)
NET INCOME (LOSS)	$	41,957		$	61,583
Net (income) loss attributable to noncontrolling interests	(27		)	(9		)
Distributions on Series A redeemable preferred units	(25		)	(1,114		)
Distributions on Series B cumulative convertible preferred units	(5,250		)	—
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS	$	36,655		$	60,460
ALLOCATION OF NET INCOME (LOSS):
General partner interest	$	—		$	—
Common units	24,329			35,517
Subordinated units	12,326			24,943
	$	36,655		$	60,460
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:
Per common unit (basic)	$	0.23		$	0.37
Weighted average common units outstanding (basic)	103,774			96,901
Per subordinated unit (basic)	$	0.13		$	0.26
Weighted average subordinated units outstanding (basic)	95,395			95,149
Per common unit (diluted)	$	0.23		$	0.37
Weighted average common units outstanding (diluted)	103,838			97,590
Per subordinated unit (diluted)	$	0.13		$	0.26
Weighted average subordinated units outstanding (diluted)	95,395			95,149

NOTE 12 — AT-THE-MARKET OFFERING PROGRAM

On May 26, 2017, the Partnership commenced an at-the-market offering program (the “ATM Program”) and in connection therewith entered into an Equity Distribution Agreement with Wells Fargo Securities, LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, and UBS Securities LLC, as Sales Agents (each a “Sales Agent” and collectively the “Sales Agents”). Pursuant to the terms of the ATM Program, the Partnership may sell, from time to time through the Sales Agents, the Partnership’s common units representing limited partner interests having an aggregate offering price of up to $100,000,000. Sales of common units, if any, may be made in negotiated transactions or transactions that are deemed to be “at the market” offerings as defined in Rule 415 under the Securities Act of 1933, as amended (the “Securities Act”), including sales made directly on the New York Stock Exchange or sales made to or through a market maker other than on an exchange.

Under the terms of the ATM Program, the Partnership may also sell common units to one or more of the Sales Agents as principal for its own account at a price to be agreed upon at the time of sale. Any sale of common units to a Sales Agent as principal would be pursuant to the terms of a separate agreement between the Partnership and such Sales Agent.

The Partnership intends to use the net proceeds from any sales pursuant to the ATM Program, after deducting the Sales Agents’ commissions and the Partnership’s offering expenses, for general partnership purposes, which may include, among other things, repayment of indebtedness outstanding under the Partnership’s Credit Facility.

Common units sold pursuant to the Equity Distribution Agreement are offered and sold pursuant to the Partnership’s existing effective shelf-registration statement on Form S-3 (File No. 333-215857), which was declared effective by the SEC on February 8, 2017.

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

The Equity Distribution Agreement contains customary representations, warranties and agreements, indemnification obligations, including for liabilities under the Securities Act, other obligations of the parties and termination provisions.

For the three months ended March 31, 2018, the Partnership sold 8,204 common units under the ATM Program for net proceeds of $0.1 million.

NOTE 13 — SUBSEQUENT EVENTS

Effective May 4, 2018, the borrowing base of the Credit Facility was increased to $600.0 million from $550.0 million, as discussed in Note 7 – Credit Facility.

On May 7, 2018, the Board of Directors of the Partnership's general partner approved a distribution for the three months ended March 31, 2018 of $0.3125 per common unit and $0.20875 per subordinated unit. Distributions will be payable on May 24, 2018 to unitholders of record at the close of business on May 17, 2018.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our unaudited consolidated financial statements and notes thereto presented in this Quarterly Report on Form 10-Q, as well as our audited financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2017. This discussion and analysis contains forward-looking statements that involve risks, uncertainties, and assumptions. Actual results may differ materially from those anticipated in these forward-looking statements as a result of a number of factors, including those set forth under “Cautionary Note Regarding Forward-Looking Statements” and “Part II, Item 1A. Risk Factors.”

Unless the context clearly indicates otherwise, references in this Quarterly Report on Form 10-Q to “BSM,” the “Partnership,” “we,” “our,” “us,” or similar terms for time periods prior to the IPO refer to Black Stone Minerals Company, L.P. and its subsidiaries, the predecessor for accounting purposes. For time periods subsequent to the IPO, these terms refer to Black Stone Minerals, L.P. and its subsidiaries.

Cautionary Note Regarding Forward-Looking Statements

Certain statements and information in this Quarterly Report on Form 10-Q may constitute “forward-looking statements.” The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could,” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:


•	our ability to execute our business strategies;


•	the volatility of realized oil and natural gas prices;


•	the level of production on our properties;


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


•	our ability to replace our oil and natural gas reserves;


•	our ability to identify, complete, and integrate acquisitions;


•	general economic, business, or industry conditions;


•	competition in the oil and natural gas industry;


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


•	title defects in the properties in which we invest;


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


•	restrictions on the use of water;


•	the availability of transportation facilities;


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


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


•	future operating results;


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


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


•	operating hazards faced by our operators;


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


•	certain factors discussed elsewhere in this filing.

For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see “Risk Factors” in our Annual Report on Form 10-K.

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

Overview

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

As of March 31, 2018, our mineral and royalty interests were located in 41 states and 64 onshore basins in the continental United States. These non-cost-bearing interests include ownership in over 55,000 producing wells. We also own non-operated working interests, a significant portion of which are on our positions where we also have a mineral and royalty interest. We recognize oil and natural gas revenue from our mineral and royalty and non-operated working interests in producing wells when control of the oil and natural gas produced is transferred to the customer and collectability of the sales price is reasonably assured. Our other sources of revenue include mineral lease bonus and delay rentals, which are recognized as revenue according to the terms of the lease agreements.

Recent Developments

Acquisitions

In the first quarter of 2018, we acquired mineral and royalty interests, which also included producing properties, in the Permian Basin for $22.6 million in cash, as well as mineral and royalty interests in the East Texas Basin for $9.6 million in cash. Additional information regarding acquisitions is contained in Note 4 – Oil and Natural Gas Properties Acquisitions to our unaudited consolidated financial statements included herein for further discussion.

PepperJack Prospect

We expect to invest approximately $12.0 million to $15.0 million in the evaluation of our PepperJack prospect in Hardin and Liberty counties, Texas. The PepperJack A#1 well targeting the Lower Wilcox formation has been drilled and was logged in mid-February of 2018. Based on the encouraging results from that well, we plan to drill and log a step-out well in the second quarter of 2018 to further delineate the prospect. We believe the data provided by these wells will substantially improve our ability to structure a deal with an operating partner.

Business Environment

The information presented below is designed to give a broad overview of the oil and natural gas business environment as it affects us.

Commodity Prices

Oil and natural gas prices have been historically volatile based upon the dynamics of supply and demand. The U.S. Energy Information Administration ("EIA") forecasts that the WTI spot oil price will average $59.00 per Bbl in both 2018 and 2019, while Henry Hub spot natural gas prices will rise from an annual average of $2.99 per MMbtu in 2018 to $3.07 per MMbtu in 2019.

To manage the variability in cash flows associated with the projected sale of our oil and natural gas production, we use various derivative instruments, which have recently consisted exclusively of fixed-price swap contracts.

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



	2018		2017
Benchmark Prices	First Quarter		First Quarter
WTI spot oil price ($/Bbl)¹	$	64.87	$	50.54
Henry Hub spot natural gas ($/MMBtu)¹	$	2.81	$	3.13

¹Source: EIA

Rig Count

As we are the operator of record on only three properties, drilling on our acreage is dependent upon the exploration and production companies that lease our acreage. In addition to drilling plans that we seek from our operators, we also monitor rig counts in an effort to identify existing and future leasing and drilling activity on our acreage.

The following table shows the rig count at the close of each quarter presented:



	2018	2017
U.S. Rotary Rig Count¹	First Quarter	First Quarter
Oil	797	662
Natural gas	194	160
Other	2	2
Total	993	824


¹	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, growing U.S. natural gas production is expected to support both increasing domestic consumption and higher natural gas exports. The EIA forecasts that natural gas inventories will reach almost 3.8 trillion cubic feet on October 31, 2018, which would be 2% lower than the previous five-year average.

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



	2018	2017
Region¹	First Quarter	First Quarter

	(Bcf)
East	229	268
Midwest	266	479
Mountain	87	142
Pacific	166	216
South Central	606	946
Total	1,354	2,051


¹	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 and distributable cash flow.

Volumes of Oil and Natural Gas Produced

In order to track and assess the performance of our assets, we monitor and analyze our production volumes from the various basins and plays that comprise our extensive asset base. We also regularly compare projected volumes to actual reported volumes and investigate unexpected variances.

Commodity Prices

Factors Affecting the Sales Price of Oil and Natural Gas

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

•

Oil. The substantial majority of our oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of our control. NYMEX light sweet crude oil, commonly referred to as WTI, is the prevailing domestic oil pricing index. The majority of our oil production is priced at the prevailing market price with the final realized price affected by both quality and location differentials.

The chemical composition of crude oil plays an important role in its refining and subsequent sale as petroleum products. As a result, variations in chemical composition relative to the benchmark crude oil, usually WTI, will result in price adjustments, which are often referred to as quality differentials. The characteristics that most significantly affect quality differentials include the density of the oil, as characterized by its American Petroleum Institute (“API”) gravity, and the presence and concentration of impurities, such as sulfur.

Location differentials generally result from transportation costs based on the produced oil’s proximity to consuming and refining markets and major trading points.


•	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 variable-to-fixed-price swaps, fixed-price contracts, costless collars, and other contractual arrangements. The impact of these derivative instruments could affect the amount of revenue we ultimately realize. Since 2015, we have only entered into fixed-price swap contracts. Under fixed-price swap contracts, a counterparty is required to make a payment to us if the settlement price is less than the swap strike price. Conversely, we are required to make a payment to the counterparty if the settlement price is greater than the swap strike price. We may employ contractual arrangements other than fixed-price swap contracts in the future to mitigate the impact of price fluctuations. If commodity prices decline in the future, our hedging contracts will partially mitigate the effect of lower prices on our future revenue.

Our open oil and natural gas derivative contracts as of March 31, 2018 are detailed in Note 5 – Commodity Derivative Financial Instruments to our unaudited consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q. Prior to amending and restating our credit agreement on November 1, 2017, we were allowed to hedge all of our estimated production from our proved developed producing reserves based on the most recent reserve information provided to our lenders.

Pursuant to our Fourth Amended and Restated Credit Agreement, we are allowed to hedge certain percentages of expected future monthly production volumes equal to the lesser of (i) internally forecasted production and (ii) the average of reported production for the most recent three months. We are allowed to hedge up to 90% of such volumes for the first 24 months, 70% for months 25 through 36, and 50% for months 37 through 48. Pursuant to our updated hedge provisions, we have hedged 92.2% and 53.3% of our available oil and condensate hedge volumes for 2018 and 2019, respectively. Also, we have hedged 98.7% and 52.3% of our available natural gas hedge volumes for 2018 and 2019, respectively.

We intend to continuously monitor the production from our assets and the commodity price environment, and will, from time to time, add additional hedges within the percentages described above to remain significantly hedged for the following 12 to 24 months. We do not enter into derivative instruments for speculative purposes.

Non-GAAP Financial Measures

Adjusted EBITDA and distributable cash flow 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.

Adjusted EBITDA and distributable cash flow 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 in the United States (“U.S. GAAP”) as measures of our financial performance.

Adjusted EBITDA and distributable cash flow have important limitations as analytical tools because they exclude some but not all items that affect net income (loss), the most directly comparable U.S. GAAP financial measure. Our computation of Adjusted EBITDA and distributable cash flow may differ from computations of similarly titled measures of other companies.

The following table presents a reconciliation of net income, the most directly comparable U.S. GAAP financial measure, to Adjusted EBITDA and distributable cash flow for the periods indicated:



	Three Months Ended March 31,
	2018			2017

	(in thousands)
Net income	$	41,957		$	61,583
Adjustments to reconcile to Adjusted EBITDA:
Depreciation, depletion and amortization	28,570			26,379
Interest expense	4,521			3,507
Income tax expense	1,507			—
Accretion of asset retirement obligations	269			247
Equity–based compensation	6,226			4,661
Unrealized (gain) loss on commodity derivative instruments	11,958			(18,447		)
Adjusted EBITDA	95,008			77,930
Adjustments to reconcile to distributable cash flow:
Deferred revenue	1,303			(325		)
Cash interest expense	(4,316		)	(3,292		)
(Gain) loss on sale of assets, net	(2		)	(924		)
Estimated replacement capital expenditures¹	(3,250		)	(3,750		)
Cash paid to noncontrolling interests	(52		)	(25		)
Preferred unit distributions	(5,275		)	(1,114		)
Distributable cash flow	$	83,416		$	68,500


¹	On August 3, 2016, the Board of Directors of our general partner (the “Board”) approved 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 approved a replacement capital expenditure estimate of $13.0 million for the period of April 1, 2017 to March 31, 2018.

Results of Operations

Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017

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



	Three Months Ended March 31,
	2018			2017		Variance

	(Dollars in thousands, except for realized prices)
Production:
Oil and condensate (MBbls)	1,190			861		329			38.2	%
Natural gas (MMcf)¹	15,742			14,060		1,682			12.0	%
Equivalents (MBoe)	3,814			3,204		610			19.0	%
Revenue:
Oil and condensate sales	$	72,983		$	40,474	$	32,509		80.3	%
Natural gas and natural gas liquids sales¹	53,245			47,701		5,544			11.6	%
Lease bonus and other income	4,599			13,682		(9,083		)	(66.4	)%
Revenue from contracts with customers	130,827			101,857		28,970			28.4	%
Gain (loss) on commodity derivative instruments	(16,333		)	22,725		(39,058		)	(171.9	)%
Total revenue	$	114,494		$	124,582	$	(10,088	)	(8.1	)%
Realized prices:
Oil and condensate ($/Bbl)	$	61.33		$	47.01	$	14.32		30.5	%
Natural gas ($/Mcf)¹	3.38			3.39		(0.01		)	(0.3	)%
Equivalents ($/Boe)	$	33.10		$	27.52	$	5.58		20.3	%
Operating expenses:
Lease operating expense	$	4,248		$	4,189	$	59		1.4	%
Production costs and ad valorem taxes	14,925			11,902		3,023			25.4	%
Exploration expense	3			562		(559		)	(99.5	)%
Depreciation, depletion, and amortization	28,570			26,379		2,191			8.3	%
General and administrative	18,521			17,212		1,309			7.6	%

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 March 31, 2018 decreased compared to the quarter ended March 31, 2017. Production for the quarter ended March 31, 2018 averaged 42.4 MBoe per day, an increase of 6.8 MBoe per day compared to the corresponding period in 2017. Despite higher oil and condensate production and realized oil and condensate prices, and higher revenue from increased natural gas and NGL production, increased losses on commodity derivative instruments and less lease bonus and other income as compared to the corresponding period in 2017 resulted in a decrease in total revenue period over period.

Oil and condensate sales. Oil and condensate sales during the period were higher than the first quarter of 2017 primarily due to higher production volumes from our Bakken and Wolfcamp assets. Our mineral-and-royalty-interest oil and condensate volumes increased 54.8% in the first quarter of 2018 relative to the corresponding period in 2017 primarily as a result of the Bakken increase. Our mineral-and-royalty-interest oil and condensate volumes accounted for 89.2% and 79.6% of total oil and condensate volumes for the quarters ended March 31, 2018 and 2017, respectively. There was also an increase in commodity prices between the comparative periods.

Natural gas and natural gas liquids sales. Natural gas and NGL sales increased for the quarter ended March 31, 2018 as compared to the same period for 2017. Higher production volumes, largely in the Haynesville, Bakken, and Lance–Mesa Verde plays, were primarily responsible for the increase in our natural gas and NGL revenues. Mineral-and-royalty-interest production accounted for 57.1% and 51.4% of our natural gas volumes for the quarters ended March 31, 2018 and 2017, respectively.

Gain (loss) on commodity derivative instruments. During the first quarter of 2018, we recognized $14.5 million of losses from oil commodity contracts, which included cash payments of $5.2 million, compared to recognized gains of $14.3 million in the same period of 2017. During the first quarter of 2018, we recognized $1.8 million of losses from natural gas commodity contracts, which included cash received of $0.8 million, compared to recognized gains of $8.4 million in the same period of 2017.

Lease bonus and other income. When we lease our mineral interests, we generally receive an upfront cash payment, or a lease bonus. Lease bonus and other income for the first quarter of 2018 was $9.1 million lower than the same period of 2017. Lease bonus income can vary substantively between periods because it is derived from individual transactions with operators, some of which may be significant. Leasing activity in the Canyon Lime trend in Potter County, Texas, the Douglas trend in Hemphill County, Texas, the Frio trend in Brazoria County, Texas, the Cherry Canyon trend in Ward County, Texas, the Smackover trend in Escambia County, Alabama and the Mississippian trend in Pecos County, Texas made up the majority of lease bonus in the first quarter of 2018, while a substantial portion of first quarter 2017 activity came from the Williston Basin, Canyon Lime, Mississippian/Woodford, Haynesville/Bossier and Permian trends.

Operating and Other Expenses

Lease operating expense. Lease operating expense was relatively flat for the quarter ended March 31, 2018 as compared to the same period in 2017, primarily due to the absence of any significant remedial projects being performed by our operators and our non-operated working interest well count remaining stable during the periods presented.

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 March 31, 2018, production costs and ad valorem taxes increased from the quarter ended March 31, 2017, generally as a result of higher oil and condensate prices as well as increased oil and condensate and natural gas production volumes.

Exploration expense. Exploration expense typically consists of dry-hole expenses, delay rentals, and geological and geophysical costs, including seismic costs, and is expensed as incurred under the successful efforts method of accounting. Exploration expense was a deminimus amount for the three months ended March 31, 2018, as compared to the same period in 2017. Exploration expense in 2017 represented 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 increased for the quarter ended March 31, 2018 as compared to the same period in 2017, primarily due to the impact of higher production partially offset by lower depletion rates.

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 quarters ended March 31, 2018 or 2017.

General and administrative. General and administrative expenses are costs not directly associated with the production of oil and natural gas and includes expenses such as the cost of employee salaries and related benefits, office expenses, and fees for professional services. For the quarter ended March 31, 2018, general and administrative expenses increased as compared to the same period in 2017, primarily due to higher costs associated with our incentive compensation plans partially offset by lower brokerage fees associated with our acquisition activity.

Interest expense. Interest expense was higher in the first quarter of 2018 due to increased borrowings under our credit facility. Average outstanding borrowings during the first quarter of 2018 were higher than the first quarter of 2017 due to funding of acquisitions in 2018 and 2017 and redemptions associated with our preferred units.

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.

The Board has adopted a policy pursuant to which distributions equal in amount to the applicable minimum quarterly distribution will be paid on each common and subordinated unit for each quarter to the extent we have sufficient cash generated from our operations after establishment of cash reserves, if any, and after we have made the required distributions to the holders of our outstanding preferred units. However, we do not have a legal or contractual obligation to pay distributions on our common and subordinated units quarterly or on any other basis, at the applicable minimum quarterly distribution rate or at any other rate, and there is no guarantee that we will pay distributions to our common and subordinated unitholders in any quarter. Our minimum quarterly distribution provides the common unitholders a specified priority right to distributions over the subordinated unitholders. The Board may change the foregoing distribution policy at any time and from time to time.

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 our executed farmout agreements and internally-generated cash flows, although at times we may fund a portion of these expenditures through other 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. On June 8, 2017, the Board approved a replacement capital expenditure estimate of $13.0 million for the period of April 1, 2017 to March 31, 2018. On April 27, 2018, the Board approved a replacement capital expenditure estimate of $11.0 million for the period of April 1, 2018 to March 31, 2019.

Cash Flows

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



	Three Months Ended March 31,
	2018			2017

	(in thousands)
Cash flows provided by operating activities	$	76,474		$	63,954
Cash flows used in investing activities	(60,166		)	(64,086		)
Cash flows provided by (used in) financing activities	(15,653		)	4,365

Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017

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 $64.0 million for the three months ended March 31, 2017 to $76.5 million for the three months ended March 31, 2018. The increase was primarily due to increased commodity revenue driven by higher oil and natural gas production and higher realized oil prices, offset by a decrease in lease bonus and other income period over period.

Investing Activities. Net cash used in investing activities decreased by $3.9 million in the first three months of 2018 as compared to the corresponding period in 2017 due to less cash used for net capital expenditures, primarily related to increased proceeds received from farmouts of our working interests.

Financing Activities. Cash flows used in financing activities for the three months ended March 31, 2018 increased by $20.0 million compared to the three months ended March 31, 2017 primarily due to increased distributions to common and subordinated unitholders and increased repayments of borrowings under our credit facility, which were partially offset by decreased redemptions of Series A redeemable preferred units.

Capital Expenditures

Our 2018 capital expenditure budget is estimated at $32.0 million to $40.0 million. We expect to spend between $20.0 million and $25.0 million, net of reimbursements under our farmout agreements, in our working-interest participation program, substantially all of which will be invested in the Haynesville/Bossier play. We also expect to spend approximately $12.0 million to $15.0 million to drill two 100% working interest exploratory wells to evaluate a Lower Wilcox prospect in East Texas.

During the three months ended March 31, 2018, our working-interest participation program capital expenditures, net of farmout proceeds, were $21.9 million, and we drilled and logged one of the Lower Wilcox prospect wells at a cost of $6.3 million. We also incurred approximately $32.2 million related to acquisitions of mineral and royalty interests, which included producing properties, in the same period. See Note 4 – Oil and Natural Gas Properties Acquisitions to our unaudited consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for further discussion.

Credit Facility

Pursuant to our $1.0 billion senior secured revolving credit agreement, 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. Borrowings under the credit facility may be used for the acquisition of properties, cash distributions, and other general corporate purposes. On November 1, 2017, we entered into the Fourth Amended and Restated Credit Agreement to extend the maturity date for a term of five years, create a swingline facility that permits short-term borrowings on same-day notice, and make other changes to the hedging and restrictive covenants. The borrowing base was reconfirmed at $550.0 million with our fall 2017 redetermination, and was increased to $600.0 million effective May 4, 2018 with our spring 2018 redetermination. Our credit facility terminates on November 1, 2022. As of March 31, 2018, we had outstanding borrowings of $436.0 million at a weighted-average interest rate of 4.71%.

The borrowing base 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. Under the Fourth Amended and Restated Credit Agreement, we additionally have the right to request a redetermination following acquisition of oil and natural gas properties in excess of 10% of the value of the borrowing base immediately prior to such acquisition.

Outstanding borrowings under the credit agreement 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. 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 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. Our credit facility is secured by liens on substantially all of our producing properties.

Our 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 credit agreement contains two financial covenants: total debt to EBITDAX of 3.5:1.0 or less and a 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 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 credit agreement. The lenders have the right to accelerate all of the indebtedness under the credit agreement upon the occurrence and during the continuance of any event of default, and the 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 March 31, 2018, we were in compliance with all debt covenants.

Contractual Obligations

As of March 31, 2018, there have been no material changes to our contractual obligations previously disclosed in our 2017 Annual Report on Form 10-K.

Off-Balance Sheet Arrangements

As of March 31, 2018, we did not have any material off-balance sheet arrangements.

Critical Accounting Policies and Related Estimates

As of March 31, 2018, there have been no significant changes to our critical accounting policies and related estimates previously disclosed in our 2017 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 NGLs 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 NGLs 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 – Commodity Derivative Financial Instruments and Note 6 – Fair Value Measurements to the unaudited consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for additional information.

To estimate the effect lower prices would have on our reserves, we reduced the SEC commodity pricing for the twelve months ended March 31, 2018 by 10%. This results in an approximate 2.2% reduction of proved reserve volumes as compared to the unadjusted March 31, 2018 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 March 31, 2018, we had nine counterparties, all of which were rated Baa1 or better by Moody’s. Eight 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 March 31, 2018, we had $436.0 million of outstanding borrowings under our credit facility, bearing interest at a weighted-average interest rate of 4.71%. 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 $1.1 million for the three months ended March 31, 2018, 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 March 31, 2018.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended March 31, 2018 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 2017 Annual Report on Form 10-K. There has been no material change in our risk factors from those described in our 2017 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

None.

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 March 31, 2018:



	Purchases of Common Units
Period	Total Number of Common Units Purchased¹	Average Price Paid Per Unit		Total Number of Common Units Purchased as Part of Publicly Announced Plans or Programs		Maximum Dollar Value of Common Units That May Yet Be Purchased Under the Plans or Programs
January 1 - January 31, 2018	154,092	$	18.37		—	$	—
February 1 - February 28, 2018	220,578	$	17.95		—		—
March 1 - March 31, 2018	76,812	$	17.05		—		—

	Purchases of Subordinated Units
Period	Total Number of Subordinated Units Purchased¹	Average Price Paid Per Unit²		Total Number of Subordinated Units Purchased as Part of Publicly Announced Plans or Programs		Maximum Dollar Value of Subordinated Units That May Yet Be Purchased Under the Plans or Programs
March 1 - March 31, 2018	23,269	$	—		—		—

	Purchases of Series A Redeemable Preferred Units
Period	Total Number of Series A Redeemable Preferred Units Purchased³	Average Price Paid Per Unit		Total Number of Series A Redeemable Preferred Units Purchased as Part of Publicly Announced Plans or Programs		Maximum Dollar Value of Series A Redeemable Preferred Units That May Yet Be Purchased Under the Plans or Programs
January 1 - January 31, 2018	1,560	$	1,000		—	$	—
March 1 - March 31, 2018	555	$	1,000		—		—


¹	Includes units withheld to satisfy tax withholding obligations upon the vesting of certain restricted common and subordinated units held by our executive officers and certain other employees.


²	For tax withholding purposes, the value of the subordinated units was fixed at a discount to the closing price of our common units as of the date of each vesting event.

Pursuant to our partnership agreement, on December 31 of each year through 2017 (each date, a “Scheduled Redemption Date”), each Series A redeemable preferred unitholder could, upon written notice, require us to redeem a portion of its Series A redeemable preferred units for a cash price per 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 paid to the redeeming Series A redeemable preferred unitholders 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 Series A redeemable preferred unitholder). This year, unitholders redeemed 2,115 Series A redeemable preferred units for a total cost of approximately $2.1 million. In addition, the Series A redeemable preferred units could be converted, at the option of the unitholder thereof, at any time, and without the payment of additional consideration, into common units and subordinated units at the then-effective conversion rate. The Series A redeemable preferred units had a conversion rate of 30.3431 common units and 39.7427 subordinated units per preferred unit, subject to adjustment. As of March 31, 2018, there were no Series A redeemable preferred units outstanding. All units were either redeemed or converted.

Item 5. Other Information

None.

Item 6. Exhibits




Exhibit Number		Description

2.1**		Purchase and Sale Agreement, dated as of November 22, 2017, by and among Noble Energy Inc., Noble Energy Wyco, LLC, Noble Energy US Holdings, LLC, Rosetta Resources Operating LP, and Black Stone Minerals Company, L.P. (incorporated herein by reference to Exhibit 2.1 of Black Stone Minerals, L.P.'s Current Report on Form 8-K filed on November 29, 2017 (SEC File No. 001-37362)).

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., (incorporated herein by reference to Exhibit 3.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on May 6, 2015 (SEC File No. 001-37362)).

3.4		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 3.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on April 19, 2016 (SEC File No. 001-37362)).

3.5		Amendment No. 2 to First Amended and Restated Agreement of Limited Partnership of Black Stone Minerals, L.P., dated as of November 28, 2017 (incorporated herein by reference to Exhibit 3.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on November 29, 2017 (SEC File No. 001-37362)).

3.6		Amendment No. 3 to First Amended and Restated Agreement of Limited Partnership of Black Stone Minerals, L.P., dated as of December 11, 2017 (incorporated herein by reference to Exhibit 3.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on December 12, 2017 (SEC File No. 001-37362)).

4.1		Registration Rights Agreement, dated as of November 28, 2017, by and between Black Stone Minerals, L.P. and Mineral Royalties One, L.L.C. (incorporated herein by reference to Exhibit 4.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on November 29, 2017 (SEC File No. 001-37362)).

10.1		First Amendment to Fourth Amended and Restated Credit Agreement among Black Stone Minerals Company, L.P., as Borrower, Wells Fargo Bank, National Association, as Administrative Agent and Swingline Lender, Bank of America, N.A. and Compass Bank, as Co-Syndication Agents, ZB Bank, N.A., DBA Amegy Bank, National Association, as Documentation Agent, and a syndicate of lenders dated as of February 7, 2018 (incorporated herein by reference to Exhibit 10.4 of Black Stone Minerals, L.P.’s Annual Report on Form 10-K filed on February 28, 2018 (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.


**	Schedules and exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The Partnership agrees to furnish supplementally a copy of the omitted schedules and exhibits to the SEC upon request.

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: May 8, 2018	By:	/s/ Thomas L. Carter, Jr.
		Thomas L. Carter, Jr.
		President and Chief Executive Officer
		(Principal Executive Officer)

Date: May 8, 2018	By:	/s/ Jeffrey P. Wood
		Jeffrey P. Wood
		Senior Vice President and Chief Financial Officer
		(Principal Financial Officer)