Document
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM
8-K
CURRENT REPORT PURSUANT TO
SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
 Date of Report (Date of earliest event reported): August 5, 2019
Black Stone Minerals, L.P.

(Exact name of registrant as specified in its charter)
 
Delaware
 
001-37362
 
47-1846692
 
 
(State or other jurisdiction
 
(Commission File Number)
 
(I.R.S. Employer
 
 
of incorporation or organization)
 
 
 
Identification No.)
 
 
1001 Fannin Street, Suite 2020
 
 
Houston,
Texas
 
 77002
(Address of principal executive offices)
 
(Zip code)
 
Registrant’s telephone number, including area code:  

 Not Applicable
(Former name or former address, if changed since last report)

(713)
445-3200

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
o
Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
o
Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
o
Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
o
Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))
Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).
Emerging growth company o
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. o
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Trading Symbol(s)
 
Name of each exchange on which registered
Common Units Representing Limited Partner Interests
 
BSM
 
New York Stock Exchange

1


The information included in this Current Report, including the exhibit attached hereto as Exhibit 99.1, is being furnished and shall not be deemed “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of that Section. That information shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, as amended, except as otherwise expressly stated in such filing.

Item 2.02  Results of Operations and Financial Condition
 
On August 5, 2019, Black Stone Minerals, L.P. (“Black Stone Minerals”) issued a press release that announced its second quarter 2019 financial and operating results. A copy of the press release is furnished herewith as Exhibit 99.1.

Item 7.01  Regulation FD Disclosure
 
On August 5, 2019, Black Stone Minerals provided revised summary guidance for 2019. This information is contained in the press release included in this report as Exhibit 99.1.

Item 9.01  Financial Statements and Exhibits

(d)    Exhibits

Exhibit Number
 
Description
 
Black Stone Minerals, L.P. Press Release, dated August 5, 2019

2


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 hereunto duly authorized.
 
 
BLACK STONE MINERALS, L.P.
 
 
 
 
By:
Black Stone Minerals GP, L.L.C.,
its general partner
 
 
 
 
 
Date: August 5, 2019
By:
/s/ Steve Putman
 
 
 
Steve Putman
 
 
 
Senior Vice President, General Counsel, and Secretary
 

3


Exhibit Index
 
Exhibit Number
 
Description
 
Black Stone Minerals, L.P. Press Release, dated August 5, 2019


4
Exhibit
http://api.tenkwizard.com/cgi/image?quest=1&rid=23&ipage=13043522&doc=3
Exhibit 99.1
 
 
News
For Immediate Release
 
Black Stone Minerals, L.P. Reports Second Quarter Results;
Raises Production Guidance for 2019


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 second quarter of 2019.

Highlights

Reported record production of 52.2 MBoe/d for the second quarter of 2019, led by a 19% quarter-over-quarter increase in royalty production.
Reported oil and natural gas revenues of $127.7 million, lease bonus and other income of $6.7 million, and net income of $95.1 million for the quarter.
Generated Adjusted EBITDA for the second quarter of $108.3 million.
Reported Distributable cash flow of $98.0 million, resulting in distribution coverage for all common units of 1.3x at the previously announced distribution attributable to the second quarter of $0.37 per unit or $1.48 annualized.
Raised production guidance for 2019 to range of 47.5 MBoe/d to 50.5 MBoe/d, a 5% increase midpoint to midpoint from prior guidance.
Acquired $20.7 million in mineral and royalty assets in the Permian Basin and in East Texas for cash during the second quarter.


Management Commentary

Thomas L. Carter, Jr., Black Stone Minerals’ Chief Executive Officer and Chairman, commented, "Despite a challenging environment for the broader energy sector, Black Stone posted a solid quarter with new records for both total and royalty volumes. We generated distribution coverage of 1.3x while maintaining the $1.48 per unit annualized distribution. Our excess coverage for the quarter funded substantially all of our acquisition and unit repurchase activity during the period. Based on the success of the first six months of the year, we are increasing our production guidance for the year."


Quarterly Financial and Operating Results

Production

Black Stone reported average total production of 52.2 MBoe/d (76% mineral and royalty, 72% natural gas) for the second quarter of 2019. This represents a 17% increase over average total production of 44.7 MBoe/d for the corresponding period in 2018 and an increase of 12% from the first quarter of 2019.

Royalty production was 39.7 MBoe/d (66% natural gas) for the second quarter. This is a sequential increase of 19% from the 33.5 MBoe/d reported in the first quarter of 2019. Royalty production in the corresponding period of 2018 was 31.1 MBoe/d.

Consistent with the Partnership's decision to farm out its working interest participation to third-party capital providers, working interest production continued to decline in the second quarter of 2019 to 12.4 MBoe/d (92% natural gas). This represents declines of 7% and 9%, respectively, from the first quarter of 2019 and the second quarter of 2018.

Realized Prices, Revenues, and Net Income    

The Partnership’s average realized price per Boe, excluding the effect of derivative settlements, was $26.90 for the quarter ended June 30, 2019. This represents a 5% decrease from the preceding quarter and reflects lower prices and slightly wider differentials for natural gas and NGLs. Realized prices in the second quarter of 2019 were 17% lower than the $32.22 per Boe reported for the quarter ended June 30, 2018.


1


Black Stone reported oil and gas revenues of $127.7 million (58% oil and condensate, 42% natural gas and natural gas liquids) for the second quarter of 2019, an increase from $119.3 million in the first quarter of 2019. The increase in oil and gas revenue was driven primarily by higher reported production volumes during the quarter. This increase was partially offset by a lower realized natural gas price for the quarter. Oil and gas revenue in the second quarter of 2018 was $131.1 million.

The Partnership recognized a gain on commodity derivative instruments of $29.2 million in the second quarter of 2019, composed of a $2.9 million realized gain and a $26.3 million unrealized gain that reflects the change in value of the Partnership’s derivative positions during the quarter. Black Stone reported net losses of $41.2 million and $33.3 million on commodity derivative instruments for the quarters ended March 31, 2019 and June 30, 2018, respectively.

Black Stone recognized $6.7 million in lease bonus and other income in the second quarter of 2019, led by leasing activity focused on acreage in the Permian Basin. The Partnership reported $5.6 million and $11.6 million in lease bonus and other income for the first quarter of 2019 and second quarter of 2018, respectively.

The Partnership reported net income of $95.1 million, which includes the non-cash derivative gain described above, for the quarter ended June 30, 2019, compared to net income of $9.0 million in the preceding quarter. Net income for the second quarter of 2018 was $28.7 million.

Adjusted EBITDA and Distributable Cash Flow

Black Stone reported Adjusted EBITDA of $108.3 million for the second quarter of 2019, compared to $94.9 million in the first quarter of 2019 and $100.3 million for the corresponding quarter in 2018. Distributable cash flow for the second quarter of 2019 was $98.0 million, an increase over $81.4 million and $87.2 million in the first quarter of 2019 and second quarter of 2018, respectively.

Financial Position and Activities

As of June 30, 2019, the Partnership had $3.9 million in cash and $436.0 million outstanding under its credit facility.

As of August 2, 2019, the Partnership had $391.0 million outstanding under the credit facility and $6.3 million in cash, providing over $290 million in available liquidity. Black Stone Minerals is in compliance with all financial covenants associated with its credit facility.

During the second quarter of 2019, the Partnership repurchased approximately 137,000 units at an average unit price of $15.90 per unit under the Board-approved $75 million unit repurchase program. This program authorizes Black Stone to make repurchases on a discretionary basis as determined by management, subject to market conditions, applicable legal requirements, available liquidity, and other appropriate factors. All or a portion of any repurchases may be made under a Rule 10b5-1 plan, which would permit common units to be repurchased when the Partnership might otherwise be precluded from doing so under applicable laws. Any repurchased units will be canceled.

Hedge Position

Black Stone has commodity derivative contracts in place covering portions of its anticipated production for the remainder of 2019 and 2020. The Partnership's current hedge position is summarized in the following tables:

Oil Hedge Position
 
 
 
 
 
 
 
Oil Swap
Oil Swap Price
 
Oil Costless Collars
Collar Floor
Collar Ceiling
 
MBbl
$/Bbl
 
MBbl
$/Bbl
$/Bbl
3Q19
855
$58.37
 
60
$65.00
$74.00
4Q19
855
$58.37
 
60
$65.00
$74.00
1Q20
510
$57.14
 
210
$56.43
$67.14
2Q20
510
$57.14
 
210
$56.43
$67.14
3Q20
510
$57.14
 
210
$56.43
$67.14
4Q20
510
$57.14
 
210
$56.43
$67.14


2


Natural Gas Hedge Position
 
 
 
Gas Swap
Gas Swap Price
 
MMcf
$/Mcf
3Q19
14,640
$2.96
4Q19
14,640
$2.96
1Q20
8,190
$2.73
2Q20
8,190
$2.73
3Q20
8,280
$2.73
4Q20
8,280
$2.73

More detailed information about the Partnership's existing hedging program can be found in the Quarterly Report on Form 10-Q for the second quarter of 2019, which is expected to be filed on or around August 6, 2019.

Acquisitions

Black Stone acquired $20.7 million of properties in the second quarter of 2019, all of which were purchased with cash. Approximately two-thirds of the acquisitions made during the quarter related to additions in the Permian Basin, with additions in East Texas making up the remainder of the acquisition program for the quarter. Through June 30, 2019, the Partnership has completed $41.6 million in acquisitions in 2019.

Distributions

As previously reported, the Board of Directors of the general partner (the "Board") has approved cash distributions attributable to the second quarter of 2019 of $0.37 per unit for common units. This represents a quarterly distribution coverage ratio of approximately 1.3x. Distributions will be payable on August 22, 2019 to unitholders of record on August 15, 2019.


Activity Update

Well Additions

For the quarter ended June 30, 2019, Black Stone added 382 gross wells (5.25 net). The Partnership is on track to meet or exceed its 2018 additions of approximately 1,465 gross wells and approximately 21 net wells.

Shelby Trough Update

Black Stone expects drilling activity to slow temporarily on its Shelby Trough acreage in East Texas, in part due to the current natural gas price environment. XTO Energy has informed Black Stone that it intends to complete previously drilled wells and, due to constraints in gathering and treating capacity, will pause new drilling activity in the area until the third quarter of 2020. In addition, BPX Energy (“BPX”) recently decided to limit its Shelby Trough drilling activity to a specific area encompassing approximately 17,000 gross acres. Under the terms of the Partnership’s development agreement with BPX, which requires continuous drilling activity to hold acreage, BPX has released over 100,000 gross acres containing an estimated 6 Tcf of potential recoverable resource. Much of this area has been delineated through BPX’s drilling to date with successful wells in both the Haynesville and Bossier shales, and Black Stone intends to place it with another operator or operators. The Partnership estimates this temporary reduction in drilling activity to have a limited impact to its 2019 outlook.

Black Stone recognizes that the natural gas market globally has current challenges that may persist for some time, but believes that growth in U.S. LNG exports, global increases in energy demand and for natural gas demand in particular, and proximity to Gulf Coast markets bode well for its Shelby Trough acreage. “We own this mineral position in perpetuity and have confidence in the long-term potential of this tremendous resource,” said Mr. Carter. “We are very appreciative of the significant de-risking of this asset base done by BPX and look forward to continue working with them on a smaller scale. Our job now is to attract additional capital to our resources here and rationally exploit decades' worth of locations on our Shelby Trough acreage.”



3


Revised 2019 Guidance

The following table provides the assumptions for Black Stone's original and current 2019 guidance:
 
Original Guidance
 
Revised Guidance
Mineral and royalty production (MBoe/d)
 
35 - 37
 
 
 
36 - 38
 
Working interest production
 
10 - 11
 
 
 
11.5 - 12.5
 
Total production (MBoe/d)
 
45 - 48
 
 
 
47.5 - 50.5
 
Percentage natural gas
 
~71%
 
 
 
~73%
 
Percentage royalty interest
 
~77%
 
 
 
~75%
 
 
 
 
 
 
 
 
 
Lease bonus and other income ($MM)
 
$30 - $40
 
 
 
$20 - $30
 
 
 
 
 
 
 
 
 
Lease operating expense ($MM)
 
$17 - $19
 
 
 
$17 - $19
 
Production costs and ad valorem taxes (as % of total pre-derivative O&G revenue)
 
11% - 13%
 
 
 
11% - 13%
 
Exploration expense ($MM)
 
$1.0 - $2.0
 
 
 
$0.5 - $1.5
 
 
 
 
 
 
 
 
 
G&A — cash ($MM)
 
$45 - $47
 
 
 
$44 - $46
 
G&A — non-cash ($MM)
 
$21 - $23
 
 
 
$21 - $23
 
G&A — total ($MM)
 
$66 - $70
 
 
 
$65 - $69
 
 
 
 
 
 
 
 
 
DD&A ($/Boe)
 
$7.00 - $8.00
 
 
 
$6.50 - $7.50
 

Elimination of Replacement Capital Expenditures

Prior to the conversion of the subordinated units, Black Stone was required under the terms of its partnership agreement to include an estimate of replacement capital expenditures in its calculation of distributable cash flow. With the conversion of the subordinated units being completed in May 2019, the Partnership will no longer make this estimate.


Conference Call

Black Stone Minerals will host a conference call and webcast for investors and analysts to discuss its results for the second quarter of 2019 on Tuesday, August 6, 2019 at 9:00 a.m. Central Time. To listen to the call by phone, participants should dial (877) 447-4732 and use conference code 5659678; callers are advised to dial into the call 10 minutes in advance of the call start time. 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 September 5, 2019.


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 in the continental United States.  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

4


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 37.0% for individuals.

Black Stone Minerals, L.P. Contact

Brent Collins
Vice President, Investor Relations
Telephone: (713) 445-3200
investorrelations@blackstoneminerals.com



5


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

 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
 
2019
 
2018
 
2019
 
2018
 
 
 
 
 
 
 
 
 
REVENUE
 
 
 
 

 
 
 
 
Oil and condensate sales
 
$
74,072

 
$
77,225

 
$
131,776

 
$
150,208

Natural gas and natural gas liquids sales
 
53,642

 
53,854

 
115,282

 
107,099

Lease bonus and other income
 
6,717

 
11,577

 
12,362

 
16,176

Revenue from contracts with customers
 
134,431

 
142,656

 
259,420

 
273,483

Gain (loss) on commodity derivative instruments
 
29,187

 
(33,347
)
 
(11,996
)
 
(49,680
)
TOTAL REVENUE
 
163,618

 
109,309

 
247,424

 
223,803

OPERATING (INCOME) EXPENSE
 
 
 
 

 
 
 
 
Lease operating expense
 
3,849

 
4,290

 
9,141

 
8,538

Production costs and ad valorem taxes
 
14,450

 
14,373

 
29,042

 
29,298

Exploration expense
 
304

 
6,745

 
308

 
6,748

Depreciation, depletion, and amortization
 
29,725

 
30,292

 
57,558

 
58,862

General and administrative
 
14,347

 
19,812

 
35,561

 
38,333

Accretion of asset retirement obligations
 
277

 
273

 
554

 
542

(Gain) loss on sale of assets, net
 

 

 

 
(2
)
TOTAL OPERATING EXPENSE
 
62,952

 
75,785

 
132,164

 
142,319

INCOME (LOSS) FROM OPERATIONS
 
100,666

 
33,524

 
115,260

 
81,484

OTHER INCOME (EXPENSE)
 
 
 
 
 
 
 
 
Interest and investment income
 
47

 
37

 
93

 
70

Interest expense
 
(5,652
)
 
(5,280
)
 
(11,177
)
 
(9,801
)
Other income (expense)
 
26

 
409

 
(72
)
 
(1,106
)
TOTAL OTHER EXPENSE
 
(5,579
)
 
(4,834
)
 
(11,156
)
 
(10,837
)
NET INCOME (LOSS)
 
95,087

 
28,690

 
104,104

 
70,647

Net (income) loss attributable to noncontrolling interests
 

 
48

 

 
22

Distributions on Series A redeemable preferred units
 

 

 

 
(25
)
Distributions on Series B cumulative convertible preferred units
 
(5,250
)
 
(5,250
)
 
(10,500
)
 
(10,500
)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS
 
$
89,837

 
$
23,488

 
$
93,604

 
$
60,144

ALLOCATION OF NET INCOME (LOSS):
 
 
 
 

 
 
 
 
General partner interest
 
$

 
$

 

 

Common units
 
67,718

 
17,540

 
69,611

 
41,877

Subordinated units
 
22,119

 
5,948

 
23,993

 
18,267

 
 
$
89,837

 
$
23,488

 
$
93,604

 
$
60,144

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

 
 

 
 
 
 
Per common unit (basic)
 
$
0.45

 
$
0.17

 
0.54

 
0.40

Weighted average common units outstanding (basic)
 
150,101

 
105,250

 
129,873

 
104,516

Per subordinated unit (basic)
 
$
0.39

 
$
0.06

 
0.32

 
0.19

Weighted average subordinated units outstanding (basic)
 
56,104

 
96,329

 
76,105

 
95,864

Per common unit (diluted)
 
$
0.44

 
$
0.17

 
0.54

 
0.40

Weighted average common units outstanding (diluted)
 
165,070

 
105,250

 
129,873

 
104,516

Per subordinated unit (diluted)
 
$
0.39

 
$
0.06

 
0.32

 
0.19

Weighted average subordinated units outstanding (diluted)
 
56,104

 
96,329

 
76,105

 
95,864







6


The following table shows the Partnership’s production, revenues, pricing, and expenses for the periods presented:
 
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
 
2019
 
2018
 
2019
 
2018
 
 
 
 
 
 
 
 
 
 
 
(Unaudited)
(Dollars in thousands, except for realized prices and per Boe data)
Production:
 
 

 
 

 
 
 
 
Oil and condensate (MBbls)
 
1,316

 
1,183

 
2,424

 
2,372

Natural gas (MMcf)1
 
20,594

 
17,311

 
39,209

 
33,052

Equivalents (MBoe)
 
4,748

 
4,068

 
8,959

 
7,881

Equivalents/day (MBoe)
 
52.2

 
44.7

 
49.5

 
43.5
Revenue:
 
 

 
 

 
 
 
 
Oil and condensate sales
 
$
74,072

 
$
77,225

 
$
131,776

 
$
150,208

Natural gas and natural gas liquids sales1
 
53,642

 
53,854

 
115,282

 
107,099

Lease bonus and other income
 
6,717

 
11,577

 
12,362

 
16,176

Revenue from contracts with customers
 
134,431

 
142,656

 
259,420

 
273,483

Gain (loss) on commodity derivative instruments
 
29,187

 
(33,347
)
 
(11,996
)
 
(49,680
)
Total revenue
 
$
163,618

 
$
109,309

 
$
247,424

 
$
223,803

Realized prices, without derivatives:
 
 

 
 

 
 
 
 
Oil and condensate ($/Bbl)
 
$
56.30

 
$
65.28

 
$
54.37

 
$
63.33

Natural gas ($/Mcf)1
 
2.60

 
3.11
 
2.94

 
3.24

Equivalents ($/Boe)
 
$
26.90

 
$
32.22

 
$
27.58

 
$
32.65

Operating expenses:
 
 

 
 

 
 
 
 
Lease operating expense
 
$
3,849

 
$
4,290

 
$
9,141

 
$
8,538

Production costs and ad valorem taxes
 
14,450

 
14,373

 
29,042

 
29,298

Exploration expense
 
304

 
6,745

 
308

 
6,748

Depreciation, depletion, and amortization
 
29,725

 
30,292

 
57,558

 
58,862

General and administrative
 
14,347

 
19,812

 
35,561

 
38,333

Per Boe:
 
 
 
 
 
 
 
 
Lease operating expense (per working interest Boe)
 
$
3.40

 
$
3.45

 
$
3.92

 
$
3.42

Production costs and ad valorem taxes
 
3.04

 
3.53

 
3.24

 
3.72

Depreciation, depletion, and amortization
 
6.26

 
7.45

 
6.42

 
7.47

General and administrative
 
3.02

 
4.87

 
3.97

 
4.86

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.



7


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 during the subordination period, 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 (“GAAP”) in the United States 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 GAAP financial measure. Our computation of Adjusted EBITDA and Distributable cash flow may differ from computations of similarly titled measures of other companies.
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
 
2019
 
2018
 
2019
 
2018
 
 
 
 
 
 
 
 
 
 
 
(Unaudited)
(In thousands, except per unit amounts)
Net income (loss)
 
$
95,087

 
$
28,690

 
$
104,104

 
$
70,647

Adjustments to reconcile to Adjusted EBITDA:
 
 
 
 
 
 
 
 
Depreciation, depletion, and amortization
 
29,725

 
30,292

 
57,558

 
58,862

Interest expense
 
5,652

 
5,280

 
11,177

 
9,801

Income tax expense (benefit)
 
35

 
(446
)
 
166

 
1,061

Accretion of asset retirement obligations
 
277

 
273

 
554

 
542

Equity–based compensation
 
3,816

 
9,124

 
13,039

 
15,350

Unrealized (gain) loss on commodity derivative instruments
 
(26,256
)
 
27,057

 
16,670

 
39,015

Adjusted EBITDA
 
108,336

 
100,270

 
203,268

 
195,278

Adjustments to reconcile to Distributable cash flow:
 
 

 
 

 
 
 
 
Change in deferred revenue
 
294

 
(1
)
 
(10
)
 
1,302

Cash interest expense
 
(5,392
)
 
(4,969
)
 
(10,661
)
 
(9,285
)
(Gain) loss on sale of assets, net
 

 

 

 
(2
)
Estimated replacement capital expenditures1
 

 
(2,750
)
 
(2,750
)
 
(6,000
)
Cash paid to noncontrolling interests
 

 
(62
)
 

 
(114
)
Preferred unit distributions
 
(5,250
)
 
(5,250
)
 
(10,500
)
 
(10,525
)
Distributable cash flow
 
$
97,988

 
$
87,238

 
$
179,347

 
$
170,654

 
 
 
 
 
 
 
 
 
Total units outstanding2
 
205,962

 
203,148

 
 
 
 
Distributable cash flow per unit
 
$
0.476

 
$
0.429

 
 
 
 
Common unit price as of August 2, 2019 and August 3, 2018, respectively
 
$
14.97

 
$
17.17

 
 
 
 
Implied Distributable cash flow yield
 
12.7
%
 
10.0
%
 
 
 
 
1  
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. No replacement capital expenditure estimate will be established for periods subsequent to March 31, 2019.
2  
The distribution attributable to the three months ended June 30, 2019 is estimated using 205,961,594 common units as of July 30, 2019; the exact amount of the distribution attributable to the three months ended June 30, 2019 will be determined based on units outstanding as of the record date of August 15, 2019. Distributions attributable to the three months ended June 30, 2018 were calculated using 106,819,353 common units and 96,328,836 subordinated units as of the record date of August 16, 2018.

8