Black Stone Minerals, L.P. Reports Third Quarter 2017 Results and Declares Cash Distribution on Common and Subordinated Units

HOUSTON--(BUSINESS WIRE)--Black Stone Minerals, L.P. (NYSE: BSM) ("Black Stone Minerals," "Black Stone," or "the Partnership") today announces its financial and operating results for the third quarter of 2017 and recent developments after quarter-end.

Highlights

• Despite estimated shut-ins of 500 Boe/d associated with Hurricane Harvey, reported production for the third quarter averaged 37.0 MBoe/d.
• Reported oil and gas revenues of $86.4 million and lease bonus and other income of $12.0 million for the quarter.
• Generated net income of $22.0 million and Adjusted EBITDA of $77.7 million.
• Reported distributable cash flow of $69.1 million and distributable cash flow after net working interest capital expenditures of $67.3 million for the quarter, resulting in distribution coverage for all units of 1.3x and 1.3x, respectively.
• After quarter end, reconfirmed borrowing base at $550 million and amended credit facility with existing lender group to allow for increased commodity hedging capacity and extend maturity date to November 1, 2022.

Management Commentary

Thomas L. Carter, Jr., Black Stone Minerals’ President, Chief Executive Officer, and Chairman, commented, "Black Stone had a solid quarter despite production shut-ins resulting from Hurricane Harvey. Reported total production remained steady from last quarter and reported royalty volumes grew on a sequential basis despite the effects of the storm. We also had another very good quarter on the lease bonus front that was driven primarily by leasing in the Delaware Basin. Our business is performing well and we continue to be successful in extracting full value from our assets for the benefit of our unitholders."

Quarterly Financial and Operating Results

Production

Black Stone Minerals reported average production of 37.0 MBoe/d (58% mineral and royalty, 73% natural gas) for the third quarter of 2017. This represents an increase of 6% over average production of 35.0 MBoe/d for the corresponding period in 2016 and is essentially flat compared to the second quarter of 2017. The Partnership estimates that production for the third quarter of 2017 was adversely impacted by approximately 500 Boe/d due to Hurricane Harvey.

Realized Prices, Revenues, and Net Income

The Partnership’s average realized price per Boe, excluding the effect of derivative settlements, was $25.36 for the quarter ended September 30, 2017. This represents a 1% decrease from the preceding quarter and is comparable to the $25.42 per Boe for the quarter ended September 30, 2016.

Black Stone Minerals reported oil and gas revenues of $86.4 million for the third quarter of 2017, an increase of 6% from $81.8 million for the third quarter of 2016 that reflects higher production volumes between the periods. Oil and gas revenue in the second quarter of 2017 was $87.2 million.

The Partnership recognized a loss on commodity derivative instruments of $9.3 million in the third quarter of 2017, composed of a $5.0 million gain from realized settlements and a $14.3 million unrealized loss due to the change in value of the Partnership’s derivative positions during the quarter. In the third quarter of 2016, the Partnership reported a gain on commodity derivative instruments of $7.8 million.

Significant leasing activity in the Delaware Basin drove lease bonus and other income to $12.0 million for the third quarter of 2017, an increase from $9.6 million in lease bonus and other income from the same period last year. For the nine months ended September 30, 2017, the Partnership reported $37.1 million in lease bonus and other income compared to $26.1 million for the same period in 2016.

The Partnership reported net income of $22.0 million, which includes the non-cash derivative loss described above, for the quarter ended September 30, 2017, compared to net income of $37.5 million in the corresponding period in 2016.

Financial Position

As of September 30, 2017, the Partnership had $8.9 million in cash and $362.0 million outstanding under its credit facility. Subsequent to quarter end, the borrowing base was reconfirmed at $550.0 million as part of a regularly scheduled semi-annual redetermination process. As of November 6, 2017, the Partnership had $332.0 million outstanding under the credit facility and $6.4 million in cash, providing approximately $224.0 million in available liquidity. Black Stone Minerals is in compliance with all financial covenants associated with its credit facility.

Earlier this year, Black Stone Minerals put in place an at-the-market ("ATM") offering program. The ATM program allows the Partnership to sell common units into the open market from time to time. During the third quarter of 2017, Black Stone sold approximately 1.8 million units through the ATM program for proceeds net of expenses of $30.3 million.

Acquisitions

Black Stone's acquisition activity in the third quarter of 2017 was focused on the Haynesville/Bossier play in East Texas. In total, the Partnership invested $22.6 million in cash and $13.7 million in equity for acquired assets during the quarter.

For the nine months ended September 30, 2017, the Partnership had invested $89.1 million in cash and $71.6 million worth of common units for assets primarily in East Texas and the Delaware Basin.

Working Interest Participation

In 2017, the Partnership had cash working interest expenditures of $6.8 million in the third quarter and $40.7 million through September 30 participating as a non-operating working interest owner on its own minerals. As a result of reimbursements associated with the Partnership's working interest farmout with Canaan Resource Partners ("Canaan"), net working interest capital expenditures were $1.8 million in the third quarter of 2017 and $34.1 million for the first nine months of 2017. Capital expenditures net of farmout reimbursements for 2017 are now expected to be between $50 million to $60 million, with almost the entire budget allocated to the Haynesville/Bossier play. Due to the timing of cash calls and invoices received from the operator of the Haynesville/Bossier properties and the reimbursement by Canaan, net working interest capital expenditures can vary between periods.

Distributions

The Board of Directors of the general partner (the "Board") has approved cash distributions attributable to the third quarter of 2017 of $0.3125 per common unit and $0.20875 per subordinated unit. Distributions will be payable on November 24, 2017 to unitholders of record on November 17, 2017.

In determining the amount of distributions to common and subordinated unitholders, the Board takes into account numerous factors, including the level of distribution coverage. In addition to the industry-accepted method of calculating distribution coverage, the Partnership also evaluates distribution coverage after deducting net working interest capital expenditures with a goal over the long-term of funding working interest capital expenditures with retained cash flow. The quarterly distribution coverage attributable to the third quarter of 2017 for all units was approximately 1.3x before net working interest capital expenditures and approximately 1.3x after net working interest capital expenditures.

Credit Facility Amendment and Extension

On November 1, 2017, Black Stone entered into a fourth amended and restated credit agreement with its existing group of lenders. The amended credit agreement increases the Partnership's capacity to hedge commodity volumes and extends the maturity date from February 2019 to November 2022.

Conference Call

Black Stone Minerals will host a conference call and webcast for investors and analysts to discuss its results for the third quarter 2017 on Tuesday, November 7, 2017 at 9:00 a.m. Central Time. To join the call, participants should dial [phone] and use conference code 96210757. A live broadcast of the call will also be available at http://investor.blackstoneminerals.com. A recording of the conference call will be available at that site through November 30, 2017.

About Black Stone Minerals, L.P.

Black Stone Minerals is one of the largest owners of oil and natural gas mineral interests in the United States. The Partnership owns mineral interests and royalty interests in 41 states and 64 onshore basins in the continental United States. The Partnership also owns and selectively participates as a non-operating working interest partner in established development programs, primarily on its mineral and royalty holdings. The Partnership expects that its large, diversified asset base and long-lived, non-cost-bearing mineral and royalty interests will result in production and reserve growth, as well as increasing quarterly distributions to its unitholders.

Forward-Looking Statements

This news release includes forward-looking statements. All statements, other than statements of historical facts, included in this news release that address activities, events, or developments that the Partnership expects, believes, or anticipates will or may occur in the future are forward-looking statements. Terminology such as "will," "may," "should," "expect," "anticipate," "plan," "project," "intend," "estimate," "believe," "target," "continue," "potential," the negative of such terms, or other comparable terminology often identify forward-looking statements. Except as required by law, Black Stone Minerals undertakes no obligation, and does not intend, to update these forward-looking statements to reflect events or circumstances occurring after this news release. You are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this news release. All forward-looking statements are qualified in their entirety by these cautionary statements. These forward-looking statements involve risks and uncertainties, many of which are beyond the control of Black Stone Minerals, which may cause the Partnership’s actual results to differ materially from those implied or expressed by the forward-looking statements. 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:

• the Partnership’s ability to execute its business strategies;
• the volatility of realized oil and natural gas prices;
• the level of production on the Partnership’s properties;
• regional supply and demand factors, delays, or interruptions of production;
• the Partnership’s ability to replace its oil and natural gas reserves; and
• the Partnership’s ability to identify, complete, and integrate acquisitions.

For an important discussion of risks and uncertainties that may impact our operations, see our annual and quarterly filings with the Securities and Exchange Commission, which are available on our website.

Information for Non-U.S. Investors

This press release is intended to be a qualified notice under Treasury Regulation Section 1.1446-4(b). Although a portion of Black Stone Minerals’ income may not be effectively connected income and may be subject to alternative withholding procedures, brokers and nominees should treat 100% of Black Stone Minerals’ distributions to non-U.S. investors as being attributable to income that is effectively connected with a United States trade or business. Accordingly, Black Stone Minerals’ distributions to non-U.S. investors are subject to federal income tax withholding at the highest marginal rate, currently 39.6% for individuals.

BLACK STONE MINERALS, L.P. CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) (In thousands, except per unit amounts)
	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
REVENUE
Oil and condensate sales	$	41,361		$	42,780		$	119,097		$	104,581
Natural gas and natural gas liquids sales	45,047			38,986			142,651			85,706
Gain (loss) on commodity derivative instruments	(9,341		)	7,813			35,387			(12,295		)
Lease bonus and other income	12,044			9,592			37,082			26,129
TOTAL REVENUE	89,111			99,171			334,217			204,121
OPERATING (INCOME) EXPENSE
Lease operating expense	4,569			5,007			12,906			14,179
Production costs and ad valorem taxes	11,549			9,228			35,314			23,301
Exploration expense	8			6			616			643
Depreciation, depletion, and amortization	29,204			28,731			84,483			79,654
Impairment of oil and natural gas properties	—			—			—			6,775
General and administrative	17,305			16,677			51,998			52,213
Accretion of asset retirement obligations	260			206			760			680
(Gain) loss on sale of assets, net	—			—			(931		)	(4,772		)
TOTAL OPERATING EXPENSE	62,895			59,855			185,146			172,673
INCOME (LOSS) FROM OPERATIONS	26,216			39,316			149,071			31,448
OTHER INCOME (EXPENSE)
Interest and investment income	(9		)	460			30			651
Interest expense	(4,172		)	(2,282		)	(11,660		)	(4,773		)
Other income (expense)	(1		)	41			352			148
TOTAL OTHER EXPENSE	(4,182		)	(1,781		)	(11,278		)	(3,974		)
NET INCOME (LOSS)	22,034			37,535			137,793			27,474
NET (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS	20			8			27			15
DISTRIBUTIONS ON REDEEMABLE PREFERRED UNITS	(666		)	(1,324		)	(2,452		)	(4,439		)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS	$	21,388		$	36,219		$	135,368		$	23,050
ALLOCATION OF NET INCOME (LOSS):
General partner interest	$	—		$	—		$	—		$	—
Common units	16,371			23,114			83,989			24,343
Subordinated units	5,017			13,105			51,379			(1,293		)
	$	21,388		$	36,219		$	135,368		$	23,050
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:
Per common unit (basic)	$	0.16		$	0.24		$	0.86		$	0.26
Weighted average common units outstanding (basic)	101,623			95,740			97,777			95,086
Per subordinated unit (basic)	$	0.05		$	0.14		$	0.54		$	(0.01	)
Weighted average subordinated units outstanding (basic)	95,388			95,189			95,269			95,125
Per common unit (diluted)	$	0.16		$	0.24		$	0.86		$	0.26
Weighted average common units outstanding (diluted)	101,623			96,011			97,777			95,619
Per subordinated unit (diluted)	$	0.05		$	0.14		$	0.54		$	(0.01	)
Weighted average subordinated units outstanding (diluted)	95,388			95,189			95,269			95,467
DISTRIBUTIONS DECLARED AND PAID:
Per common unit	$	0.3125		$	0.2875		$	0.8875		$	0.8125
Per subordinated unit	$	0.2088		$	0.1838		$	0.5763		$	0.5513

The following table shows the Partnership’s production, revenues, realized prices, and expenses for the periods presented.

	Three Months Ended September 30,					Nine Months Ended September 30,
	2017			2016		2017		2016
	(Unaudited)
	(Dollars in thousands, except for realized prices and
	per Boe data)
Production:
Oil and condensate (MBbls)	911			1,015		2,597		2,848
Natural gas (MMcf)^1	14,974			13,207		44,459		36,014
Equivalents (MBoe)	3,407			3,216		10,007		8,850
Revenue:
Oil and condensate sales	$	41,361		$	42,780	$	119,097	$	104,581
Natural gas and natural gas liquids sales^1	45,047			38,986		142,651		85,706
Gain (loss) on commodity derivative instruments	(9,341		)	7,813		35,387		(12,295		)
Lease bonus and other income	12,044			9,592		37,082		26,129
Total revenue	$	89,111		$	99,171	$	334,217	$	204,121
Realized prices:
Oil and condensate ($/Bbl)	$	45.39		$	42.15	$	45.87	$	36.72
Natural gas ($/Mcf)^1	3.01			2.95		3.21		2.38
Equivalents ($/Boe)	$	25.36		$	25.42	$	26.16	$	21.50
Operating expenses:
Lease operating expense	$	4,569		$	5,007	$	12,906	$	14,179
Production costs and ad valorem taxes	11,549			9,228		35,314		23,301
Exploration expense	8			6		616		643
Depreciation, depletion, and amortization	29,204			28,731		84,483		79,654
Impairment of oil and natural gas properties	—			—		—		6,775
General and administrative	17,305			16,677		51,998		52,213
Per Boe:
Lease operating expense (per working interest Boe)	$	3.19		$	4.25	$	3.06	$	4.71
Production costs and ad valorem taxes	3.39			2.87		3.53		2.63
Depreciation, depletion, and amortization	8.57			8.93		8.44		9.00
General and administrative	5.08			5.19		5.20		5.90

^1

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

Non-GAAP Financial Measures

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

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

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

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(Unaudited)
	(In thousands)
Net income (loss)	$	22,034		$	37,535		$	137,793		$	27,474
Adjustments to reconcile to Adjusted EBITDA:
Depreciation, depletion and amortization	29,204			28,731			84,483			79,654
Interest expense	4,172			2,282			11,660			4,773
Impairment of oil and natural gas properties	—			—			—			6,775
Accretion of asset retirement obligations	260			206			760			680
Equity-based compensation^1	7,675			7,981			18,614			33,120
Unrealized (gain) loss on commodity derivative instruments	14,320			(2,511		)	(23,048		)	51,515
Adjusted EBITDA	77,665			74,224			230,262			203,991
Adjustments to reconcile to distributable cash flow:
Change in deferred revenue	(701		)	(396		)	(1,670		)	(175		)
Cash interest expense	(3,946		)	(2,083		)	(10,999		)	(4,179		)
(Gain) loss on sales of assets, net	—			—			(931		)	(4,772		)
Estimated replacement capital expenditures^2	(3,250		)	(3,750		)	(10,250		)	(7,500		)
Cash paid to noncontrolling interests	(24		)	(29		)	(90		)	(83		)
Redeemable preferred unit distributions	(666		)	(1,324		)	(2,452		)	(4,439		)
Distributable Cash Flow	69,078			66,642			203,870			182,843
Net working interest capital expenditures	(1,793		)	(26,329		)	(34,088		)	(63,039		)
Distributable cash flow after net working interest capital expenditures	$	67,285		$	40,313		$	169,782		$	119,804

^1	On April 25, 2016, the Compensation Committee of the Board approved a resolution to change the settlement feature of certain employee long-term incentive compensation plans from cash to equity. As a result of the modification, $10.1 million of cash-settled liabilities were reclassified to equity-settled liabilities during the second quarter of 2016.
^2	On August 3, 2016, the Board established a replacement capital expenditure estimate of $15.0 million for the period of April 1, 2016 to March 31, 2017. There was no established estimate of replacement capital expenditures prior to this period. On June 8, 2017, the Board established a replacement capital expenditure estimate of $13.0 million for the period of April 1, 2017 to March 31, 2018.