![](/cdn/assets/images/search/clock.png)
We could not find any results for:
Make sure your spelling is correct or try broadening your search.
Share Name | Share Symbol | Market | Type |
---|---|---|---|
Black Stone Minerals LP | NYSE:BSM | NYSE | Common Stock |
Price Change | % Change | Share Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
---|---|---|---|---|---|---|---|---|
0.01 | 0.06% | 15.64 | 15.65 | 15.61 | 15.63 | 44,824 | 15:14:55 |
|
FORM 10-K
|
x
|
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|
¨
|
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934
|
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)
|
Title of each class
|
|
Name of each exchange on which registered
|
Common Units Representing Limited Partner Interests
|
|
New York Stock Exchange
|
Securities registered pursuant to Section 12(g) of the Act: None
|
Large Accelerated Filer
|
|
x
|
|
|
Accelerated Filer
|
|
¨
|
|
|
|
|
|
|
|
|
Non-Accelerated Filer
|
|
¨
|
(Do not check if a smaller reporting company)
|
|
Smaller Reporting Company
|
|
¨
|
|
|
|
PAGE
|
|
||
|
||
|
||
|
||
•
|
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 Annual Report.
|
•
|
nonparticipating royalty interests
(“NPRIs”), which are royalty interests that are carved out of the mineral estate and represent the right, which is typically perpetual, to receive a fixed, cost-free percentage of production or revenue from production, without an associated right to lease or receive lease bonus; and
|
•
|
overriding royalty interests
(“ORRIs”), which are royalty interests that burden working interests and represent the right to receive a fixed, cost-free percentage of production or revenue from production from a lease. ORRIs remain in effect until the associated leases expire.
|
|
|
Acreage as of December 31, 2016
|
|
Average Daily
Production (Boe/d)
For the Year Ended
December 31, 2016
|
||||||||||||||
|
|
Mineral and Royalty Interests
|
|
Working Interests
1
|
|
|||||||||||||
USGS Petroleum Province
2
|
|
Mineral Interests
|
|
NPRIs
|
|
ORRIs
|
|
Gross
|
|
Net
|
|
|||||||
Louisiana-Mississippi Salt Basins
|
|
5,446,455
|
|
|
162,199
|
|
|
18,846
|
|
|
49,170
|
|
|
6,203
|
|
|
5,053
|
|
Western Gulf (onshore)
|
|
1,597,765
|
|
|
213,111
|
|
|
98,752
|
|
|
116,134
|
|
|
17,394
|
|
|
6,191
|
|
Williston Basin
|
|
1,323,172
|
|
|
62,133
|
|
|
31,884
|
|
|
54,734
|
|
|
7,741
|
|
|
4,061
|
|
Palo Duro Basin
|
|
1,016,847
|
|
|
22,791
|
|
|
1,120
|
|
|
—
|
|
|
—
|
|
|
24
|
|
Permian Basin
|
|
1,016,197
|
|
|
587,167
|
|
|
177,275
|
|
|
8,113
|
|
|
4,731
|
|
|
1,441
|
|
Anadarko Basin
|
|
550,740
|
|
|
13,723
|
|
|
180,157
|
|
|
31,313
|
|
|
21,294
|
|
|
1,909
|
|
Appalachian Basin
|
|
490,274
|
|
|
416
|
|
|
14,836
|
|
|
—
|
|
|
—
|
|
|
874
|
|
East Texas Basin
|
|
456,110
|
|
|
44,429
|
|
|
30,640
|
|
|
151,811
|
|
|
51,589
|
|
|
6,906
|
|
Arkoma Basin
|
|
338,767
|
|
|
9,087
|
|
|
37,957
|
|
|
9,045
|
|
|
2,333
|
|
|
1,614
|
|
Bend Arch-Fort Worth Basin
|
|
144,246
|
|
|
55,205
|
|
|
40,249
|
|
|
53,606
|
|
|
13,585
|
|
|
427
|
|
Southwestern Wyoming
|
|
22,338
|
|
|
—
|
|
|
75,577
|
|
|
15,336
|
|
|
2,477
|
|
|
454
|
|
Other
|
|
3,113,014
|
|
|
310,992
|
|
|
798,542
|
|
|
39,408
|
|
|
8,924
|
|
|
2,729
|
|
Total
|
|
15,515,925
|
|
|
1,481,253
|
|
|
1,505,835
|
|
|
528,670
|
|
|
136,271
|
|
|
31,683
|
|
•
|
Louisiana-Mississippi Salt Basins.
The Louisiana-Mississippi Salt Basins region ranges from northern Louisiana and southern Arkansas through south central and southern Mississippi, southern Alabama, and the Florida Panhandle. The Haynesville/Bossier plays, which have been extensively delineated through drilling, are the most prospective and most active unconventional plays for natural gas production and reserves within this region. Approximately half of the Haynesville/Bossier plays’ prospective acreage is within the Louisiana-Mississippi Salt Basins region, where we own significant mineral and royalty interests and working interests. There are a number of additional conventional and unconventional plays in this region in which we hold considerable mineral and royalty interests, including the Brown Dense, Cotton Valley, Hosston, Norphlet, Smackover, Tuscaloosa Marine Shale, and Wilcox plays.
|
•
|
Western Gulf (onshore).
The Western Gulf region, which ranges from South Texas through southeastern Louisiana, includes a variety of both conventional and unconventional plays. We have extensive exposure to the Eagle Ford Shale in South Texas, where we are experiencing a significant level of development drilling on our mineral interests within the oil and rich-gas and condensate areas of the play. In addition to the Eagle Ford Shale play, there are a number of other conventional and unconventional plays to which we have exposure to in the region, including the Austin Chalk, Buda, Eaglebine (or Maness) Shale, Frio, Glenrose, Olmos, Woodbine, Vicksburg, Wilcox, and Yegua plays.
|
•
|
Williston Basin.
The Williston Basin stretches through the western half of North Dakota, the northwest part of South Dakota, and eastern Montana and includes plays such as the Bakken/Three Forks plays, where we have significant exposure through our mineral and royalty interests as well as through our working interests. We are also exposed to
|
•
|
Palo Duro Basin.
The Palo Duro Basin covers much of the Texas Panhandle but also occupies a small portion of the Oklahoma Panhandle and extends partially into New Mexico to the west. We have a significant acreage position in the Palo Duro Basin, much of which underlies an unconventional oil play in the Canyon Lime. We are also well positioned relative to a number of other conventional and unconventional plays in the Palo Duro Basin, including the Brown Dolomite, Canyon Wash, Cisco Sand, and Strawn Wash plays.
|
•
|
Permian Basin.
The Permian Basin ranges from southeastern New Mexico into West Texas and is currently one of the most active areas for drilling in the United States. It includes three geologic provinces: the Midland Basin to the east, the Delaware Basin to the west, and the Central Basin Platform in between. Our acreage underlies prospective areas for the Wolfcamp play in the Midland and Delaware Basins, the Spraberry formation in the Midland Basin, and the Bone Spring formation in the Delaware Basin, which are among the plays most actively targeted by drillers within the basin. In addition to these plays, we own mineral and royalty interests that are prospective for a number of other conventional and unconventional plays in the Permian Basin, including the Atoka, Clearfork, Ellenberger, San Andres, Strawn, and Wichita Albany plays.
|
•
|
Anadarko Basin.
The Anadarko Basin encompasses the Texas Panhandle, southeastern Colorado, southwestern Kansas, and western Oklahoma. We own mineral and royalty interests as well as working interests in prospective areas for most of the prolific plays in this basin, including the Granite Wash, Atoka, Cleveland, Meramac, and Woodford Shale plays. Other plays in which we hold interests in prospective acreage include the Cottage Grove, Hogshooter, Marmaton, Springer, and Tonkawa plays.
|
•
|
Appalachian Basin.
The Appalachian Basin covers most of Pennsylvania, eastern Ohio, West Virginia, western Maryland, eastern Kentucky, central Tennessee, western Virginia, northwestern Georgia, and northern Alabama. The basin’s most active plays in which we have acreage are the Marcellus Shale and Utica plays, which cover most of western Pennsylvania, northern West Virginia, and eastern Ohio. In addition to the Marcellus Shale, there are a number of other conventional and unconventional plays to which we have material exposure in the Appalachian Basin, including the Berea, Big Injun, Devonian, Huron, Rhinestreet, and Utica plays.
|
•
|
East Texas Basin.
The East Texas Basin ranges from central East Texas to northeast Texas and includes the Haynesville/Bossier plays and the Cotton Valley play, which are among the most prolific natural gas plays in the basin. We own a material acreage position in the southern Shelby Trough area of the Haynesville/Bossier plays located in San Augustine, Nacogdoches, and Angelina Counties, which is one of the most active areas being drilled today for that play in the East Texas Basin. There are other active plays to which we have significant exposure, including the Bossier Sand, Goodland Lime, James Lime, Pettit, Travis Peak, Smackover, and Woodbine plays.
|
•
|
Arkoma Basin.
The Arkoma Basin stretches from southeast Oklahoma through central Arkansas. The Fayetteville Shale play is one of the basin’s most significant unconventional natural gas plays. We own material mineral and royalty interests within the prospective area of the Fayetteville Shale. In addition, we have exposure to a number of other conventional and unconventional plays in the basin, including the Atoka, Cromwell, Dunn, Hale, and Woodford Shale plays.
|
•
|
Bend Arch-Fort Worth Basin.
The Bend Arch-Fort Worth Basin covers much of north central Texas and includes the Barnett Shale play as its most active unconventional play. Through our mineral and royalty interests in this basin, we have significant exposure to the Barnett Shale as well as a number of other active conventional and unconventional plays in the basin, including the Bend Conglomerate, Caddo, Marble Falls, and Mississippian Lime plays.
|
•
|
Southwestern Wyoming.
The Southwestern Wyoming region covers most of southern and western Wyoming. The Pinedale Anticline is one of the region’s largest producing fields and mainly produces from the Lance formation. We have a meaningful position in the Pinedale Anticline, and we have interests prospective for other plays as well, including the Mesaverde, Niobrara, and Wasatch plays.
|
|
|
|
|
|
|
|
|
Average Daily Production (Boe/d)
|
||||||||||
|
|
As of December 31, 2016
|
|
For the Year Ended December 31,
|
||||||||||||||
USGS Petroleum Province
1
|
|
Acres
|
|
Average
Ownership
Interest
2
|
|
Average
Ownership
Leased
3
|
|
2016
|
|
2015
|
|
2014
|
||||||
Louisiana-Mississippi Salt Basins
|
|
5,446,455
|
|
|
53.4
|
%
|
|
9.6
|
%
|
|
3,415
|
|
|
3,384
|
|
|
4,061
|
|
Western Gulf (onshore)
|
|
1,597,765
|
|
|
55.0
|
%
|
|
34.7
|
%
|
|
4,526
|
|
|
5,021
|
|
|
4,099
|
|
Williston Basin
|
|
1,323,172
|
|
|
14.8
|
%
|
|
35.4
|
%
|
|
2,534
|
|
|
2,430
|
|
|
1,989
|
|
Palo Duro Basin
|
|
1,016,847
|
|
|
46.5
|
%
|
|
7.2
|
%
|
|
24
|
|
|
23
|
|
|
16
|
|
Permian Basin
|
|
1,016,197
|
|
|
14.0
|
%
|
|
66.6
|
%
|
|
1,035
|
|
|
585
|
|
|
566
|
|
Black Warrior Basin
|
|
592,968
|
|
|
54.6
|
%
|
|
2.3
|
%
|
|
—
|
|
|
39
|
|
|
41
|
|
Eastern Great Basin
|
|
567,749
|
|
|
96.7
|
%
|
|
0.1
|
%
|
|
39
|
|
|
—
|
|
|
—
|
|
Anadarko Basin
|
|
550,740
|
|
|
32.7
|
%
|
|
59.6
|
%
|
|
673
|
|
|
959
|
|
|
790
|
|
Appalachian Basin
|
|
490,274
|
|
|
39.8
|
%
|
|
22.1
|
%
|
|
163
|
|
|
80
|
|
|
89
|
|
East Texas Basin
|
|
456,110
|
|
|
52.7
|
%
|
|
39.4
|
%
|
|
1,854
|
|
|
884
|
|
|
793
|
|
Arkoma Basin
|
|
338,767
|
|
|
53.7
|
%
|
|
27.6
|
%
|
|
1,302
|
|
|
1,458
|
|
|
1,646
|
|
Western Great Basin
|
|
338,303
|
|
|
90.5
|
%
|
|
–
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Piedmont
|
|
179,879
|
|
|
67.8
|
%
|
|
–
|
|
|
—
|
|
|
—
|
|
|
—
|
|
North-Central Montana
|
|
171,026
|
|
|
13.7
|
%
|
|
27.8
|
%
|
|
9
|
|
|
4
|
|
|
7
|
|
Atlantic Coastal Plain
|
|
164,670
|
|
|
12.8
|
%
|
|
28.8
|
%
|
|
199
|
|
|
—
|
|
|
—
|
|
Bend Arch-Fort Worth Basin
|
|
144,246
|
|
|
20.5
|
%
|
|
33.3
|
%
|
|
—
|
|
|
392
|
|
|
252
|
|
Cherokee Platform
|
|
111,027
|
|
|
13.8
|
%
|
|
32.4
|
%
|
|
34
|
|
|
41
|
|
|
46
|
|
Florida Peninsula
|
|
90,744
|
|
|
12.1
|
%
|
|
47.6
|
%
|
|
2
|
|
|
—
|
|
|
—
|
|
Illinois Basin
|
|
80,864
|
|
|
53.1
|
%
|
|
8.0
|
%
|
|
3
|
|
|
2
|
|
|
1
|
|
Powder River Basin
|
|
67,055
|
|
|
11.3
|
%
|
|
12.3
|
%
|
|
—
|
|
|
56
|
|
|
3
|
|
Other
|
|
771,067
|
|
|
32.1
|
%
|
|
20.4
|
%
|
|
1,295
|
|
|
301
|
|
|
317
|
|
Total
|
|
15,515,925
|
|
|
45.7
|
%
|
|
22.0
|
%
|
|
17,107
|
|
|
15,659
|
|
|
14,716
|
|
|
|
|
|
|
|
|
|
Average Daily Production (Boe/d)
|
||||||||||
|
|
As of December 31, 2016
|
|
For the Year Ended December 31,
|
||||||||||||||
USGS Petroleum Province
1
|
|
Acres
|
|
Average
Royalty
Interest
2
|
|
Average
Percent
Leased
3
|
|
2016
|
|
2015
|
|
2014
|
||||||
Permian Basin
|
|
587,167
|
|
|
2.1
|
%
|
|
47.5
|
%
|
|
19
|
|
|
31
|
|
|
11
|
|
Western Gulf (onshore)
|
|
213,111
|
|
|
4.6
|
%
|
|
46.0
|
%
|
|
14
|
|
|
10
|
|
|
14
|
|
Louisiana-Mississippi Salt Basins
|
|
162,199
|
|
|
4.9
|
%
|
|
48.3
|
%
|
|
1
|
|
|
—
|
|
|
<1
|
|
North-Central Montana
|
|
134,559
|
|
|
3.0
|
%
|
|
9.3
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
Marathon Thrust Belt
|
|
117,442
|
|
|
4.9
|
%
|
|
1.6
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
Williston Basin
|
|
62,133
|
|
|
2.6
|
%
|
|
33.0
|
%
|
|
92
|
|
|
106
|
|
|
64
|
|
Bend Arch-Fort Worth Basin
|
|
55,205
|
|
|
4.1
|
%
|
|
12.1
|
%
|
|
1
|
|
|
—
|
|
|
3
|
|
East Texas Basin
|
|
44,429
|
|
|
2.7
|
%
|
|
80.3
|
%
|
|
179
|
|
|
381
|
|
|
2
|
|
Powder River Basin
|
|
33,467
|
|
|
6.1
|
%
|
|
7.2
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
Palo Duro Basin
|
|
22,791
|
|
|
3.8
|
%
|
|
1.7
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
Anadarko Basin
|
|
13,723
|
|
|
3.6
|
%
|
|
94.3
|
%
|
|
18
|
|
|
8
|
|
|
2
|
|
Arkoma Basin
|
|
9,087
|
|
|
2.6
|
%
|
|
83.8
|
%
|
|
13
|
|
|
21
|
|
|
—
|
|
Cambridge Arch-Central Kansas Uplift
|
|
8,903
|
|
|
5.5
|
%
|
|
83.7
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
Southwest Montana
|
|
4,367
|
|
|
6.2
|
%
|
|
7.3
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
Cherokee Platform
|
|
2,635
|
|
|
4.6
|
%
|
|
33.4
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
Nemaha Uplift
|
|
2,334
|
|
|
1.6
|
%
|
|
41.4
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
Montana Thrust Belt
|
|
2,242
|
|
|
4.1
|
%
|
|
–
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Sedgwick Basin
|
|
1,850
|
|
|
2.5
|
%
|
|
82.2
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
Black Warrior Basin
|
|
1,500
|
|
|
0.3
|
%
|
|
100.0
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
Uinta-Piceance Basin
|
|
560
|
|
|
1.0
|
%
|
|
–
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Other
|
|
1,549
|
|
|
5.7
|
%
|
|
22.6
|
%
|
|
180
|
|
|
185
|
|
|
151
|
|
Total
|
|
1,481,253
|
|
|
3.4
|
%
|
|
38.4
|
%
|
|
518
|
|
|
742
|
|
|
247
|
|
|
|
|
|
|
|
Average Daily Production (Boe/d)
|
|||||||||
|
|
As of December 31, 2016
|
|
For the Year Ended December 31,
|
|||||||||||
USGS Petroleum Province
1
|
|
Acres
|
|
Average
Royalty
Interest
2
|
|
2016
|
|
2015
|
|
2014
|
|||||
North-Central Montana
|
|
457,897
|
|
|
2.5
|
%
|
|
13
|
|
|
35
|
|
|
36
|
|
Anadarko Basin
|
|
180,157
|
|
|
2.4
|
%
|
|
200
|
|
|
232
|
|
|
253
|
|
Permian Basin
|
|
177,275
|
|
|
0.8
|
%
|
|
64
|
|
|
72
|
|
|
60
|
|
Western Gulf (onshore)
|
|
98,752
|
|
|
1.7
|
%
|
|
157
|
|
|
262
|
|
|
166
|
|
Powder River Basin
|
|
85,078
|
|
|
3.6
|
%
|
|
45
|
|
|
98
|
|
|
50
|
|
Southwestern Wyoming
|
|
75,577
|
|
|
2.0
|
%
|
|
451
|
|
|
529
|
|
|
530
|
|
Uinta-Piceance Basin
|
|
63,503
|
|
|
1.6
|
%
|
|
24
|
|
|
37
|
|
|
32
|
|
Michigan Basin
|
|
56,512
|
|
|
1.0
|
%
|
|
18
|
|
|
21
|
|
|
21
|
|
Bend Arch-Fort Worth Basin
|
|
40,249
|
|
|
4.7
|
%
|
|
108
|
|
|
160
|
|
|
166
|
|
Arkoma Basin
|
|
37,957
|
|
|
3.0
|
%
|
|
23
|
|
|
29
|
|
|
23
|
|
San Juan Basin
|
|
36,239
|
|
|
1.1
|
%
|
|
6
|
|
|
3
|
|
|
3
|
|
Williston Basin
|
|
31,884
|
|
|
2.1
|
%
|
|
59
|
|
|
76
|
|
|
54
|
|
East Texas Basin
|
|
30,640
|
|
|
3.6
|
%
|
|
96
|
|
|
81
|
|
|
100
|
|
Northern Alaska
|
|
20,039
|
|
|
1.7
|
%
|
|
28
|
|
|
32
|
|
|
27
|
|
Paradox Basin
|
|
19,269
|
|
|
1.1
|
%
|
|
—
|
|
|
2
|
|
|
2
|
|
Louisiana-Mississippi Salt Basins
|
|
18,846
|
|
|
3.3
|
%
|
|
705
|
|
|
1,185
|
|
|
903
|
|
Denver Basin
|
|
15,880
|
|
|
3.2
|
%
|
|
117
|
|
|
83
|
|
|
91
|
|
Appalachian Basin
|
|
14,836
|
|
|
2.6
|
%
|
|
693
|
|
|
—
|
|
|
—
|
|
Wind River Basin
|
|
7,090
|
|
|
1.3
|
%
|
|
27
|
|
|
33
|
|
|
31
|
|
Cambridge Arch-Central Kansas Uplift
|
|
5,762
|
|
|
3.8
|
%
|
|
3
|
|
|
5
|
|
|
4
|
|
Other
|
|
32,393
|
|
|
1.6
|
%
|
|
156
|
|
|
911
|
|
|
884
|
|
Total
|
|
1,505,835
|
|
|
2.2
|
%
|
|
2,993
|
|
|
3,886
|
|
|
3,436
|
|
|
|
|
|
|
|
Average Daily Production (Boe/d)
|
|||||||||
|
|
As of December 31, 2016
|
|
For the Year Ended December 31,
|
|||||||||||
USGS Petroleum Province
1
|
|
Gross Acres
2
|
|
Net Acres
2
|
|
2016
|
|
2015
|
|
2014
|
|||||
East Texas Basin
|
|
151,811
|
|
|
51,589
|
|
|
4,776
|
|
|
2,341
|
|
|
1,564
|
|
Western Gulf (onshore)
|
|
116,134
|
|
|
17,394
|
|
|
1,494
|
|
|
1,234
|
|
|
786
|
|
Williston Basin
|
|
54,734
|
|
|
7,741
|
|
|
1,377
|
|
|
1,425
|
|
|
1,386
|
|
Bend Arch-Fort Worth Basin
|
|
53,606
|
|
|
13,585
|
|
|
118
|
|
|
108
|
|
|
129
|
|
Louisiana-Mississippi Salt Basins
|
|
49,170
|
|
|
6,203
|
|
|
932
|
|
|
1,007
|
|
|
2,077
|
|
Anadarko Basin
|
|
31,313
|
|
|
21,294
|
|
|
1,018
|
|
|
1,205
|
|
|
1,402
|
|
Southwestern Wyoming
|
|
15,336
|
|
|
2,477
|
|
|
11
|
|
|
1
|
|
|
6
|
|
Michigan Basin
|
|
13,287
|
|
|
1,330
|
|
|
6
|
|
|
6
|
|
|
6
|
|
Powder River Basin
|
|
13,016
|
|
|
3,389
|
|
|
103
|
|
|
169
|
|
|
121
|
|
Arkoma Basin
|
|
9,045
|
|
|
2,333
|
|
|
277
|
|
|
341
|
|
|
360
|
|
Permian Basin
|
|
8,113
|
|
|
4,731
|
|
|
323
|
|
|
214
|
|
|
204
|
|
Denver Basin
|
|
4,923
|
|
|
1,040
|
|
|
130
|
|
|
5
|
|
|
4
|
|
Paradox Basin
|
|
2,602
|
|
|
1,281
|
|
|
4
|
|
|
5
|
|
|
5
|
|
North-Central Montana
|
|
2,080
|
|
|
605
|
|
|
1
|
|
|
1
|
|
|
1
|
|
Uinta-Piceance Basin
|
|
1,005
|
|
|
482
|
|
|
68
|
|
|
—
|
|
|
—
|
|
San Juan Basin
|
|
960
|
|
|
334
|
|
|
15
|
|
|
11
|
|
|
9
|
|
Wind River Basin
|
|
440
|
|
|
43
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Southern Oklahoma
|
|
390
|
|
|
92
|
|
|
132
|
|
|
174
|
|
|
141
|
|
Cherokee Platform
|
|
328
|
|
|
137
|
|
|
1
|
|
|
5
|
|
|
9
|
|
Illinois Basin
|
|
200
|
|
|
16
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Other
|
|
177
|
|
|
176
|
|
|
279
|
|
|
128
|
|
|
109
|
|
Total
|
|
528,670
|
|
|
136,272
|
|
|
11,065
|
|
|
8,380
|
|
|
8,319
|
|
Mineral and Royalty Interests
|
|
Working Interests
|
||||||
USGS Petroleum Province
1
|
|
Gross Well Count
2
|
|
USGS Petroleum Province
1
|
|
Gross Well Count
2
|
||
Permian Basin
|
|
21,887
|
|
|
Anadarko Basin
|
|
2,777
|
|
Anadarko Basin
|
|
3,672
|
|
|
Uinta-Piceance Basin
|
|
1,037
|
|
Williston Basin
|
|
3,034
|
|
|
Permian Basin
|
|
796
|
|
Louisiana-Mississippi Salt Basin
|
|
2,981
|
|
|
Arkoma Basin
|
|
727
|
|
East Texas Basin
|
|
2,925
|
|
|
Western Gulf (onshore)
|
|
595
|
|
Western Gulf (onshore)
|
|
2,887
|
|
|
East Texas Basin
|
|
567
|
|
Arkoma Basin
|
|
1,889
|
|
|
Williston Basin
|
|
541
|
|
Uinta-Piceance Basin
|
|
1,321
|
|
|
Louisiana-Mississippi Salt Basin
|
|
433
|
|
Bend Arch - Fort Worth Basin
|
|
1,173
|
|
|
Southern Oklahoma
|
|
408
|
|
Michigan Basin
|
|
971
|
|
|
Bend Arch - Fort Worth Basin
|
|
198
|
|
Appalachian Basin
|
|
826
|
|
|
Appalachian Basin
|
|
192
|
|
Southwestern Wyoming
|
|
684
|
|
|
Nemaha Uplift
|
|
105
|
|
Cherokee Platform
|
|
664
|
|
|
Powder River Basin
|
|
66
|
|
Denver Basin
|
|
558
|
|
|
Michigan Basin
|
|
62
|
|
North-Central Montana
|
|
532
|
|
|
Denver Basin
|
|
21
|
|
San Juan Basin
|
|
530
|
|
|
Cherokee Platform
|
|
14
|
|
Nemaha Uplift
|
|
502
|
|
|
North-Central Montana
|
|
10
|
|
San Joaquin Basin
|
|
465
|
|
|
Paradox Basin
|
|
8
|
|
Powder River Basin
|
|
399
|
|
|
Black Warrior Basin
|
|
5
|
|
Southern Oklahoma
|
|
376
|
|
|
Southwestern Wyoming
|
|
5
|
|
Other
|
|
1,666
|
|
|
Other
|
|
10
|
|
Total
|
|
49,942
|
|
|
Total
|
|
8,577
|
|
|
|
Acreage as of December 31, 2016
1
|
|||||||||||||
|
|
Mineral and Royalty Interests
|
|
Working Interests
|
|||||||||||
Resource Play
2
|
|
Mineral Interests
|
|
NPRIs
|
|
ORRIs
|
|
Gross
|
|
Net
|
|||||
Bakken Shale
|
|
309,892
|
|
|
36,341
|
|
|
13,210
|
|
|
50,159
|
|
|
7,105
|
|
Three Forks
|
|
296,343
|
|
|
33,522
|
|
|
12,530
|
|
|
50,361
|
|
|
6,732
|
|
Haynesville Shale
|
|
283,401
|
|
|
7,255
|
|
|
14,719
|
|
|
183,337
|
|
|
53,546
|
|
Bossier Shale
|
|
252,458
|
|
|
1,816
|
|
|
8,642
|
|
|
170,716
|
|
|
52,130
|
|
Marcellus Shale
|
|
240,784
|
|
|
—
|
|
|
13,356
|
|
|
—
|
|
|
—
|
|
Canyon Lime
|
|
219,279
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Wolfcamp - Midland
|
|
187,152
|
|
|
97,860
|
|
|
125,817
|
|
|
160
|
|
|
4
|
|
Tuscaloosa Marine Shale
|
|
181,497
|
|
|
23,397
|
|
|
689
|
|
|
—
|
|
|
—
|
|
Granite Wash
|
|
102,786
|
|
|
5,031
|
|
|
86,556
|
|
|
4,840
|
|
|
1,254
|
|
Fayetteville Shale
|
|
71,089
|
|
|
3,918
|
|
|
11,708
|
|
|
—
|
|
|
—
|
|
Barnett Shale
|
|
62,732
|
|
|
4,164
|
|
|
36,155
|
|
|
13,417
|
|
|
7,747
|
|
Eagle Ford Shale
|
|
60,743
|
|
|
86,152
|
|
|
48,920
|
|
|
1,147
|
|
|
87
|
|
Wolfcamp - Delaware
|
|
44,520
|
|
|
28,061
|
|
|
4,643
|
|
|
2,642
|
|
|
971
|
|
|
|
|
|
|
|
|
|
Average Daily Production (Boe/d)
|
||||||||||
|
|
As of December 31, 2016
|
|
For the Year Ended December 31,
|
||||||||||||||
Resource Play
1
|
|
Acres
|
|
Average
Ownership
Interest
2
|
|
Average
Ownership
Leased
3
|
|
2016
|
|
2015
|
|
2014
|
||||||
Bakken Shale
|
|
309,892
|
|
|
18.1
|
%
|
|
72.0
|
%
|
|
1,659
|
|
|
1,746
|
|
|
1,275
|
|
Three Forks
|
|
296,343
|
|
|
17.7
|
%
|
|
73.4
|
%
|
|
968
|
|
|
823
|
|
|
626
|
|
Haynesville Shale
|
|
283,401
|
|
|
63.6
|
%
|
|
66.7
|
%
|
|
3,727
|
|
|
2,728
|
|
|
3,152
|
|
Bossier Shale
|
|
252,458
|
|
|
69.0
|
%
|
|
64.6
|
%
|
|
330
|
|
|
351
|
|
|
548
|
|
Marcellus Shale
|
|
240,784
|
|
|
14.5
|
%
|
|
34.8
|
%
|
|
111
|
|
|
71
|
|
|
74
|
|
Canyon Lime
|
|
219,279
|
|
|
30.6
|
%
|
|
20.8
|
%
|
|
16
|
|
|
8
|
|
|
1
|
|
Wolfcamp - Midland
|
|
187,152
|
|
|
4.8
|
%
|
|
97.3
|
%
|
|
136
|
|
|
76
|
|
|
27
|
|
Tuscaloosa Marine Shale
|
|
181,497
|
|
|
60.8
|
%
|
|
68.0
|
%
|
|
52
|
|
|
46
|
|
|
6
|
|
Granite Wash
|
|
102,786
|
|
|
15.2
|
%
|
|
57.7
|
%
|
|
167
|
|
|
194
|
|
|
241
|
|
Fayetteville Shale
|
|
71,089
|
|
|
55.8
|
%
|
|
77.6
|
%
|
|
1,181
|
|
|
1,349
|
|
|
1,529
|
|
Barnett Shale
|
|
62,732
|
|
|
15.5
|
%
|
|
58.0
|
%
|
|
181
|
|
|
239
|
|
|
228
|
|
Eagle Ford Shale
|
|
60,743
|
|
|
15.5
|
%
|
|
83.8
|
%
|
|
2,095
|
|
|
2,355
|
|
|
1,595
|
|
Wolfcamp - Delaware
|
|
44,520
|
|
|
19.2
|
%
|
|
94.9
|
%
|
|
437
|
|
|
148
|
|
|
132
|
|
|
|
|
|
|
|
|
|
Average Daily Production (Boe/d)
|
||||||||||
|
|
As of December 31, 2016
|
|
For the Year Ended December 31,
|
||||||||||||||
Resource Play
1
|
|
Acres
|
|
Average
Royalty
Interest
2
|
|
Average
Percent
Leased
3
|
|
2016
|
|
2015
|
|
2014
|
||||||
Wolfcamp - Midland
|
|
97,860
|
|
|
0.7
|
%
|
|
75.3
|
%
|
|
11
|
|
|
22
|
|
|
5
|
|
Eagle Ford Shale
|
|
86,152
|
|
|
1.5
|
%
|
|
28.4
|
%
|
|
14
|
|
|
3
|
|
|
7
|
|
Bakken Shale
|
|
36,341
|
|
|
1.4
|
%
|
|
51.3
|
%
|
|
63
|
|
|
56
|
|
|
37
|
|
Three Forks
|
|
33,522
|
|
|
1.2
|
%
|
|
54.8%
|
|
|
36
|
|
|
50
|
|
|
27
|
|
Wolfcamp - Delaware
|
|
28,061
|
|
|
0.4
|
%
|
|
83.1%
|
|
|
4
|
|
|
1
|
|
|
2
|
|
Tuscaloosa Marine Shale
|
|
23,397
|
|
|
0.5
|
%
|
|
93.2
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
Haynesville Shale
|
|
7,255
|
|
|
4.1
|
%
|
|
97.1
|
%
|
|
167
|
|
|
325
|
|
|
—
|
|
Granite Wash
|
|
5,031
|
|
|
0.8
|
%
|
|
100.0
|
%
|
|
16
|
|
|
5
|
|
|
<1
|
|
Barnett Shale
|
|
4,164
|
|
|
2.7
|
%
|
|
86.9
|
%
|
|
1
|
|
|
—
|
|
|
2
|
|
Fayetteville Shale
|
|
3,918
|
|
|
0.1
|
%
|
|
100.0%
|
|
|
13
|
|
|
—
|
|
|
—
|
|
Bossier Shale
|
|
1,816
|
|
|
2.8
|
%
|
|
54.1
|
%
|
|
11
|
|
|
53
|
|
|
—
|
|
Canyon Lime
|
|
—
|
|
|
–
|
|
|
–
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Marcellus Shale
|
|
—
|
|
|
–
|
|
|
–
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
Average Daily Production (Boe/d)
|
|||||||||
|
|
As of December 31, 2016
|
|
For the Year Ended December 31,
|
|||||||||||
Resource Play
1
|
|
Acres
|
|
Average
Royalty
Interest
2
|
|
2016
|
|
2015
|
|
2014
|
|||||
Wolfcamp - Midland
|
|
125,817
|
|
|
0.3
|
%
|
|
<1
|
|
|
5
|
|
|
3
|
|
Granite Wash
|
|
86,556
|
|
|
1.2
|
%
|
|
155
|
|
|
115
|
|
|
191
|
|
Eagle Ford Shale
|
|
48,920
|
|
|
2.2
|
%
|
|
95
|
|
|
204
|
|
|
96
|
|
Barnett Shale
|
|
36,155
|
|
|
4.9
|
%
|
|
109
|
|
|
158
|
|
|
163
|
|
Haynesville Shale
|
|
14,719
|
|
|
4.4
|
%
|
|
686
|
|
|
1,111
|
|
|
816
|
|
Marcellus Shale
|
|
13,356
|
|
|
2.3
|
%
|
|
37
|
|
|
6
|
|
|
—
|
|
Bakken Shale
|
|
13,210
|
|
|
1.2
|
%
|
|
34
|
|
|
41
|
|
|
27
|
|
Three Forks
|
|
12,530
|
|
|
1.2
|
%
|
|
21
|
|
|
27
|
|
|
18
|
|
Fayetteville Shale
|
|
11,708
|
|
|
4.1
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
Bossier Shale
|
|
8,642
|
|
|
4.7
|
%
|
|
28
|
|
|
57
|
|
|
60
|
|
Wolfcamp - Delaware
|
|
4,643
|
|
|
2.1
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
Tuscaloosa Marine Shale
|
|
689
|
|
|
7.8
|
%
|
|
<1
|
|
|
—
|
|
|
<1
|
|
Canyon Lime
|
|
—
|
|
|
–
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
Average Daily Production (Boe/d)
|
|||||||||
|
|
As of December 31, 2016
|
|
For the Year Ended December 31,
|
|||||||||||
Resource Play
1
|
|
Gross Acres
2
|
|
Net Acres
2
|
|
2016
|
|
2015
|
|
2014
|
|||||
Haynesville Shale
|
|
183,337
|
|
|
53,546
|
|
|
5,077
|
|
|
2,909
|
|
|
3,136
|
|
Bossier Shale
|
|
170,716
|
|
|
52,130
|
|
|
309
|
|
|
135
|
|
|
199
|
|
Three Forks
|
|
50,361
|
|
|
6,732
|
|
|
491
|
|
|
551
|
|
|
491
|
|
Bakken Shale
|
|
50,159
|
|
|
7,105
|
|
|
864
|
|
|
792
|
|
|
855
|
|
Barnett Shale
|
|
13,417
|
|
|
7,747
|
|
|
87
|
|
|
104
|
|
|
124
|
|
Granite Wash
|
|
4,840
|
|
|
1,254
|
|
|
429
|
|
|
537
|
|
|
647
|
|
Wolfcamp - Delaware
|
|
2,642
|
|
|
971
|
|
|
150
|
|
|
23
|
|
|
33
|
|
Eagle Ford Shale
|
|
1,147
|
|
|
87
|
|
|
76
|
|
|
11
|
|
|
—
|
|
Wolfcamp - Midland
|
|
160
|
|
|
4
|
|
|
1
|
|
|
—
|
|
|
1
|
|
Canyon Lime
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Fayetteville Shale
|
|
—
|
|
|
—
|
|
|
23
|
|
|
—
|
|
|
—
|
|
Marcellus Shale
|
|
—
|
|
|
—
|
|
|
<1
|
|
|
—
|
|
|
—
|
|
Tuscaloosa Marine Shale
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
•
|
Comparison of historical operating expenses from the lease operating statements to the operating costs input in the reserves database;
|
•
|
Review of working interests and net revenue interests in the reserves database against our well ownership system;
|
•
|
Review of historical realized commodity prices and differentials from index prices compared to the differentials used in the reserves database;
|
•
|
Evaluation of capital cost assumptions derived from Authority for Expenditure ("AFE") estimates received;
|
•
|
Review of actual historical production volumes compared to projections in the reserve report;
|
•
|
Discussion of material reserve variances among our internal reservoir engineers and our Senior Vice President, Engineering and Geology; and
|
•
|
Review of preliminary reserve estimates by our President and Chief Executive Officer with our internal technical staff.
|
|
As of
December 31, 2016
1
|
As of
December 31, 2015
|
||
|
(Unaudited)
|
(Unaudited)
|
||
Estimated proved developed reserves
2
:
|
|
|
||
Oil (MBbls)
|
18,150
|
|
15,497
|
|
Natural gas (MMcf)
|
223,057
|
|
174,555
|
|
Total (MBoe)
|
55,327
|
|
44,590
|
|
Estimated proved undeveloped reserves
3
:
|
|
|
||
Oil (MBbls)
|
218
|
|
345
|
|
Natural gas (MMcf)
|
47,282
|
|
29,120
|
|
Total (MBoe)
|
8,098
|
|
5,198
|
|
Estimated proved reserves:
|
|
|
||
Oil (MBbls)
|
18,368
|
|
15,842
|
|
Natural gas (MMcf)
|
270,339
|
|
203,675
|
|
Total (MBoe)
|
63,425
|
|
49,788
|
|
Percent proved developed
|
87.2
|
%
|
89.6
|
%
|
|
Proved Undeveloped Reserves
|
|
|
(Unaudited)
|
|
Balance as of December 31, 2015
|
5,198
|
|
Acquisitions of reserves
|
—
|
|
Extensions and discoveries
|
7,403
|
|
Revisions of previous estimates
|
548
|
|
Transfers to estimated proved developed
|
(5,051
|
)
|
Balance as of December 31, 2016
|
8,098
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
Production:
|
|
|
|
|
|
|
|
|
|
|||
Oil and condensate (MBbls)
1
|
|
3,680
|
|
|
3,565
|
|
|
3,005
|
|
|||
Natural gas (MMcf)
1
|
|
47,498
|
|
|
41,389
|
|
|
42,273
|
|
|||
Total (MBoe)
|
|
11,596
|
|
|
10,463
|
|
|
10,051
|
|
|||
Average daily production (MBoe/d)
|
|
31.7
|
|
|
28.7
|
|
|
27.5
|
|
|||
Realized Prices
2
:
|
|
|
|
|
|
|
|
|
|
|||
Oil and condensate (per Bbl)
|
|
$
|
38.69
|
|
|
$
|
45.87
|
|
|
$
|
85.65
|
|
Natural gas and natural gas liquids (per Mcf)
1
|
|
$
|
2.59
|
|
|
$
|
2.80
|
|
|
$
|
4.91
|
|
Unit Cost per Boe:
|
|
|
|
|
|
|
|
|
|
|||
Production costs and ad valorem taxes
|
|
$
|
3.06
|
|
|
$
|
3.42
|
|
|
$
|
4.93
|
|
State
|
|
Developed Acreage
|
|
Undeveloped Acreage
|
|
Total Acreage
|
|||
Texas
|
|
345,935
|
|
|
3,942,268
|
|
|
4,288,203
|
|
Mississippi
|
|
4,816
|
|
|
2,389,431
|
|
|
2,394,247
|
|
Alabama
|
|
2,699
|
|
|
2,045,661
|
|
|
2,048,360
|
|
Arkansas
|
|
4,767
|
|
|
1,264,324
|
|
|
1,269,091
|
|
North Dakota
|
|
16,041
|
|
|
994,028
|
|
|
1,010,069
|
|
Nevada
|
|
—
|
|
|
792,428
|
|
|
792,428
|
|
Florida
|
|
—
|
|
|
744,341
|
|
|
744,341
|
|
Louisiana
|
|
35,354
|
|
|
518,604
|
|
|
553,958
|
|
Montana
|
|
20,765
|
|
|
479,028
|
|
|
499,793
|
|
Oklahoma
|
|
117,952
|
|
|
367,857
|
|
|
485,809
|
|
Other
|
|
81,557
|
|
|
1,348,069
|
|
|
1,429,626
|
|
Total
|
|
629,886
|
|
|
14,886,039
|
|
|
15,515,925
|
|
State
|
|
Developed Acreage
|
|
Undeveloped Acreage
|
|
Total Acreage
|
|||
Texas
|
|
203,655
|
|
|
818,363
|
|
|
1,022,018
|
|
Montana
|
|
11,684
|
|
|
169,409
|
|
|
181,093
|
|
Mississippi
|
|
10,506
|
|
|
62,798
|
|
|
73,304
|
|
Louisiana
|
|
10,508
|
|
|
62,203
|
|
|
72,711
|
|
North Dakota
|
|
18,540
|
|
|
18,616
|
|
|
37,156
|
|
Arkansas
|
|
3,974
|
|
|
29,070
|
|
|
33,044
|
|
Wyoming
|
|
1,360
|
|
|
17,160
|
|
|
18,520
|
|
New Mexico
|
|
14,289
|
|
|
960
|
|
|
15,249
|
|
Oklahoma
|
|
6,976
|
|
|
5,749
|
|
|
12,725
|
|
Kansas
|
|
9,042
|
|
|
2,983
|
|
|
12,025
|
|
Other
|
|
367
|
|
|
3,041
|
|
|
3,408
|
|
Total
|
|
290,901
|
|
|
1,190,352
|
|
|
1,481,253
|
|
State
|
|
Developed Acreage
|
|
Undeveloped Acreage
|
|
Total Acreage
|
|||
Montana
|
|
295,401
|
|
|
165,496
|
|
|
460,897
|
|
Texas
|
|
292,352
|
|
|
57,002
|
|
|
349,354
|
|
Wyoming
|
|
133,702
|
|
|
40,045
|
|
|
173,747
|
|
Oklahoma
|
|
157,339
|
|
|
2,006
|
|
|
159,345
|
|
Utah
|
|
40,510
|
|
|
26,163
|
|
|
66,673
|
|
New Mexico
|
|
46,151
|
|
|
13,868
|
|
|
60,019
|
|
Michigan
|
|
55,272
|
|
|
1,239
|
|
|
56,511
|
|
Colorado
|
|
27,108
|
|
|
9,899
|
|
|
37,007
|
|
Louisiana
|
|
15,264
|
|
|
17,886
|
|
|
33,150
|
|
Alaska
|
|
7,664
|
|
|
12,375
|
|
|
20,039
|
|
Other
|
|
74,448
|
|
|
14,641
|
|
|
89,089
|
|
Total
|
|
1,145,211
|
|
|
360,620
|
|
|
1,505,831
|
|
|
|
Developed Acreage
|
|
Undeveloped Acreage
|
|
Total Acreage
|
||||||||||||
State
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
Texas
|
|
196,818
|
|
|
53,438
|
|
|
148,661
|
|
|
44,391
|
|
|
345,479
|
|
|
97,829
|
|
North Dakota
|
|
43,369
|
|
|
6,381
|
|
|
7,564
|
|
|
763
|
|
|
50,933
|
|
|
7,144
|
|
Louisiana
|
|
31,608
|
|
|
4,114
|
|
|
14,408
|
|
|
1,436
|
|
|
46,016
|
|
|
5,550
|
|
Wyoming
|
|
22,290
|
|
|
4,168
|
|
|
6,358
|
|
|
1,596
|
|
|
28,648
|
|
|
5,764
|
|
Michigan
|
|
13,208
|
|
|
1,330
|
|
|
79
|
|
|
—
|
|
|
13,287
|
|
|
1,330
|
|
Oklahoma
|
|
11,703
|
|
|
3,070
|
|
|
10
|
|
|
3
|
|
|
11,713
|
|
|
3,073
|
|
Colorado
|
|
7,725
|
|
|
2,601
|
|
|
—
|
|
|
—
|
|
|
7,725
|
|
|
2,601
|
|
Kansas
|
|
6,480
|
|
|
6,213
|
|
|
921
|
|
|
—
|
|
|
7,401
|
|
|
6,213
|
|
New Mexico
|
|
6,238
|
|
|
3,622
|
|
|
160
|
|
|
80
|
|
|
6,398
|
|
|
3,702
|
|
South Dakota
|
|
2,160
|
|
|
504
|
|
|
880
|
|
|
55
|
|
|
3,040
|
|
|
559
|
|
Other
|
|
6,536
|
|
|
2,146
|
|
|
1,494
|
|
|
361
|
|
|
8,030
|
|
|
2,507
|
|
Total
|
|
348,135
|
|
|
87,587
|
|
|
180,535
|
|
|
48,685
|
|
|
528,670
|
|
|
136,272
|
|
|
|
2017 Expirations
|
|
2018 Expirations
|
|
2019 Expirations
|
|||||||||||||
Net Undeveloped
Acreage
|
|
Net Acreage
without Ext. Opt.
|
|
Net Acreage
with Ext. Opt.
|
|
Net Acreage
without Ext. Opt.
|
|
Net Acreage
with Ext. Opt.
|
|
Net Acreage
without Ext. Opt.
|
|
Net Acreage
with Ext. Opt.
|
|||||||
48,685
|
|
|
17,204
|
|
|
151
|
|
|
12,491
|
|
|
—
|
|
|
1,652
|
|
|
281
|
|
|
|
For the Year Ended December 31,
|
|||||||
|
|
2016
|
|
2015
|
|
2014
|
|||
Gross development wells:
|
|
|
|
|
|
|
|
|
|
Productive
|
|
47.0
|
|
|
74.0
|
|
|
222.0
|
|
Dry
|
|
—
|
|
|
1.0
|
|
|
1.0
|
|
Total
|
|
47.0
|
|
|
75.0
|
|
|
223.0
|
|
Net development wells:
|
|
|
|
|
|
|
|
|
|
Productive
|
|
4.7
|
|
|
2.9
|
|
|
7.3
|
|
Dry
|
|
—
|
|
|
<0.1
|
|
|
—
|
|
Total
|
|
4.7
|
|
|
2.9
|
|
|
7.3
|
|
Gross exploratory wells:
|
|
|
|
|
|
|
|
|
|
Productive
|
|
—
|
|
|
—
|
|
|
1.0
|
|
Dry
|
|
—
|
|
|
—
|
|
|
1.0
|
|
Total
|
|
—
|
|
|
—
|
|
|
2.0
|
|
Net exploratory wells:
|
|
|
|
|
|
|
|
|
|
Productive
|
|
—
|
|
|
—
|
|
|
<0.1
|
|
Dry
|
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
|
—
|
|
|
—
|
|
|
<0.1
|
|
|
|
For the Year Ended December 31,
|
||||||
|
|
2016
|
|
2015
|
|
2014
|
||
Exxon Mobil
|
|
11.0
|
%
|
|
*
|
|
*
|
|
Chesapeake Energy Corporation
|
|
*
|
|
*
|
|
10.0
|
%
|
*
|
Accounted for less than 10% of total revenues for the period indicated.
|
•
|
the domestic and foreign supply of and demand for oil and natural gas;
|
•
|
market expectations about future prices of oil and natural gas;
|
•
|
the level of global oil and natural gas exploration and production;
|
•
|
the cost of exploring for, developing, producing, and delivering oil and natural gas;
|
•
|
the price and quantity of foreign imports;
|
•
|
political and economic conditions in oil producing regions, including the Middle East, Africa, South America, and Russia;
|
•
|
the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
|
•
|
trading in oil and natural gas derivative contracts;
|
•
|
the level of consumer product demand;
|
•
|
weather conditions and natural disasters;
|
•
|
technological advances affecting energy consumption;
|
•
|
domestic and foreign governmental regulations and taxes;
|
•
|
the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East;
|
•
|
the proximity, cost, availability, and capacity of oil and natural gas pipelines and other transportation facilities;
|
•
|
the price and availability of alternative fuels; and
|
•
|
overall domestic and global economic conditions.
|
•
|
recoverable reserves;
|
•
|
future oil and natural gas prices and their applicable differentials;
|
•
|
development plans;
|
•
|
operating costs; and
|
•
|
potential environmental and other liabilities.
|
•
|
the validity of our assumptions about estimated proved reserves, future production, prices, revenues, capital expenditures, operating expenses, and costs;
|
•
|
a decrease in our liquidity by using a significant portion of our cash generated from operations or borrowing capacity to finance acquisitions;
|
•
|
a significant increase in our interest expense or financial leverage if we incur debt to finance acquisitions;
|
•
|
the assumption of unknown liabilities, losses, or costs for which we are not indemnified or for which any indemnity we receive is inadequate;
|
•
|
mistaken assumptions about the overall cost of equity or debt;
|
•
|
our ability to obtain satisfactory title to the assets we acquire;
|
•
|
an inability to hire, train, or retain qualified personnel to manage and operate our growing business and assets; and
|
•
|
the occurrence of other significant changes, such as impairment of oil and natural gas properties, goodwill or other intangible assets, asset devaluation, or restructuring charges.
|
•
|
the capital costs required for drilling activities by our operators, which could be significantly more than anticipated;
|
•
|
the ability of our operators to access capital;
|
•
|
prevailing commodity prices;
|
•
|
the availability of suitable drilling equipment, production and transportation infrastructure, and qualified operating personnel;
|
•
|
the operators’ expertise, operating efficiency, and financial resources;
|
•
|
approval of other participants in drilling wells;
|
•
|
the operators’ expected return on investment in wells drilled on our acreage as compared to opportunities in other areas;
|
•
|
the selection of technology;
|
•
|
the selection of counterparties for the marketing and sale of production; and
|
•
|
the rate of production of the reserves.
|
•
|
provisions related to the unitization or pooling of the oil and natural gas properties;
|
•
|
the establishment of maximum rates of production from wells;
|
•
|
the spacing of wells;
|
•
|
the plugging and abandonment of wells; and
|
•
|
the removal of related production equipment.
|
•
|
incur indebtedness;
|
•
|
grant liens;
|
•
|
make certain acquisitions and investments;
|
•
|
enter into hedging arrangements;
|
•
|
enter into transactions with our affiliates;
|
•
|
make distributions to our unitholders; or
|
•
|
enter into a merger, consolidation, or sale of assets.
|
•
|
amount and timing of asset purchases and sales;
|
•
|
cash expenditures;
|
•
|
borrowings;
|
•
|
entry into and repayment of current and future indebtedness;
|
•
|
issuance of additional units; and
|
•
|
the creation, reduction, or increase of reserves in any quarter.
|
•
|
enabling holders of subordinated units to receive distributions; or
|
•
|
hastening the expiration of the subordination period.
|
•
|
the proportionate ownership interest of common and subordinated unitholders in us immediately prior to the issuance will decrease;
|
•
|
the amount of cash distributions on each common and subordinated unit may decrease;
|
•
|
the ratio of our taxable income to distributions may increase;
|
•
|
the relative voting strength of each previously outstanding common and subordinated unit may be diminished; and
|
•
|
the market price of the common units may decline.
|
|
|
Price Range of Common Units
|
|
Distributions
1
|
||||||||||||
|
|
High
|
|
Low
|
|
Per Common Unit
|
|
Per Subordinated Unit
|
||||||||
2015
|
|
|
|
|
|
|
|
|
||||||||
Second Quarter
2
|
|
$
|
19.00
|
|
|
$
|
16.59
|
|
|
$
|
0.1615
|
|
|
$
|
0.1615
|
|
Third Quarter
|
|
$
|
17.50
|
|
|
$
|
13.27
|
|
|
$
|
0.2625
|
|
|
$
|
0.2625
|
|
Fourth Quarter
|
|
$
|
16.50
|
|
|
$
|
12.03
|
|
|
$
|
0.2625
|
|
|
$
|
0.18375
|
|
|
|
|
|
|
|
|
|
|
||||||||
2016
|
|
|
|
|
|
|
|
|
||||||||
First Quarter
|
|
$
|
15.76
|
|
|
$
|
10.71
|
|
|
$
|
0.2625
|
|
|
$
|
0.18375
|
|
Second Quarter
|
|
$
|
17.15
|
|
|
$
|
13.61
|
|
|
$
|
0.2875
|
|
|
$
|
0.18375
|
|
Third Quarter
|
|
$
|
19.65
|
|
|
$
|
14.71
|
|
|
$
|
0.2875
|
|
|
$
|
0.18375
|
|
Fourth Quarter
|
|
$
|
19.86
|
|
|
$
|
16.94
|
|
|
$
|
0.2875
|
|
|
$
|
0.18375
|
|
1
|
Represents cash distributions attributable to the quarter. Cash distributions declared in respect of a quarter are paid in the following quarter.
|
2
|
The price range of our common units includes our $19.00 per common unit initial public offering price on April 30, 2015. Distributions were prorated for the period from the completion of our initial public offering on May 6, 2015 through June 30, 2015.
|
|
|
As of April 30, 2015
|
|
As of December 31, 2015
|
|
As of December 31, 2016
|
||||||
Black Stone Minerals, L.P.
|
|
$
|
100.00
|
|
|
$
|
78.22
|
|
|
$
|
109.07
|
|
S&P 500 Index
|
|
100.00
|
|
|
99.47
|
|
|
111.37
|
|
|||
Alerian MLP Index
|
|
100.00
|
|
|
66.99
|
|
|
79.25
|
|
Purchases of Common Units
|
|||||||||||||
Period
|
|
Total Number of Common Units Purchased
|
|
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
|
|||||
November 1 – November 30, 2016
|
|
110,878
1
|
|
$
|
18.91
|
|
|
—
|
|
|
$
|
—
|
|
December 1 – December 31, 2016
|
|
29,044
1
|
|
$
|
18.55
|
|
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|||||
Purchases of Subordinated Units
|
|||||||||||||
Period
|
|
Total Number of Common Units Purchased
|
|
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
|
|||||
November 1 – November 30, 2016
|
|
7,195
1
|
|
$
|
14.66
|
|
|
—
|
|
|
$
|
—
|
|
•
|
first
, to the holders of preferred units in an amount of approximately $25.00 per preferred unit;
|
•
|
second
, to the holders of common units, until each common unit has received the applicable minimum quarterly distribution in the amounts specified below plus any arrearages from prior quarters; and
|
•
|
third
, to the holders of subordinated units, until each subordinated unit has received the applicable minimum quarterly distribution.
|
|
|
Minimum Quarterly Distribution
(per unit)
|
||
Four Quarters Ending March 31,
|
|
Per Quarter
|
|
Annualized
|
2017
|
|
0.2875
|
|
1.15
|
2018
|
|
0.3125
|
|
1.25
|
2019 and thereafter
|
|
0.3375
|
|
1.35
|
•
|
Our common and subordinated unitholders have no contractual or other legal right to receive cash distributions from us on a quarterly or other basis, and if distributions are paid, common and subordinated unitholders will receive distributions only to the extent the distribution amount exceeds distributions that are required to be paid to our preferred unitholders.
|
•
|
Our credit facility restricts our distributions if there is a default under our credit facility or if our borrowing base is lower than the outstanding loans under our credit facility. Among other covenants, our credit facility requires we maintain a ratio of total debt to EBITDAX of 3.50:1.00 or less and a current ratio of 1.00:1.00 or greater. If we are unable to comply with these financial covenants or if we breach any other covenant under our credit facility or any future debt agreements, we could be prohibited from making distributions notwithstanding our stated distribution policy.
|
•
|
Our general partner has the authority to establish cash reserves for the prudent conduct of our business, and the establishment of, or increase in, those reserves could result in a reduction in cash distributions to our unitholders. Our partnership agreement does not limit the amount of cash reserves that our general partner may establish. Any decision to establish cash reserves made by our general partner will be binding on our unitholders.
|
•
|
Under Section 17-607 of the Delaware Act, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets.
|
•
|
We may lack sufficient cash to pay distributions to our unitholders due to shortfalls in cash generated from operations attributable to a number of operational, commercial, or other factors as well as increases in our operating or general and administrative expenses, principal and interest payments on our outstanding debt, working-capital requirements, and anticipated cash needs.
|
|
|
At December 31,
|
||||||||||||||
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
||||||||
|
|
(In thousands, except per unit amounts)
|
||||||||||||||
Total revenue
|
|
$
|
260,833
|
|
|
$
|
392,924
|
|
|
$
|
548,321
|
|
|
$
|
463,559
|
|
Net income (loss)
|
|
20,188
|
|
|
(101,305
|
)
|
|
169,187
|
|
|
168,963
|
|
||||
Net income (loss) attributable to the general partner and common units and subordinated units subsequent to initial public offering
|
|
14,437
|
|
|
(108,017
|
)
|
|
*
|
|
*
|
||||||
Net income (loss) attributable to limited partners per common and subordinated unit (basic)
1
|
|
|
|
|
|
|
|
|
|
|
||||||
Per common unit (basic)
|
|
0.26
|
|
|
(0.56
|
)
|
|
*
|
|
*
|
||||||
Per subordinated unit (basic)
|
|
(0.11
|
)
|
|
(0.56
|
)
|
|
*
|
|
*
|
||||||
Net income (loss) attributable to limited partners per common and subordinated unit (diluted)
1
|
|
|
|
|
|
|
|
|
|
|||||||
Per common unit (diluted)
|
|
0.26
|
|
|
(0.56
|
)
|
|
*
|
|
*
|
||||||
Per subordinated unit (diluted)
|
|
(0.11
|
)
|
|
(0.56
|
)
|
|
*
|
|
*
|
||||||
Cash distributions declared per common and subordinated unit
|
|
|
|
|
|
|
|
|
|
|
||||||
Per common unit
|
|
1.10
|
|
|
0.42
|
|
|
*
|
|
*
|
||||||
Per subordinated unit
|
|
0.74
|
|
|
0.42
|
|
|
*
|
|
*
|
||||||
Total assets
2
|
|
1,128,827
|
|
|
1,061,436
|
|
|
1,326,782
|
|
|
1,444,413
|
|
||||
Long-term debt
|
|
316,000
|
|
|
66,000
|
|
|
394,000
|
|
|
451,000
|
|
||||
Total mezzanine equity
|
|
54,015
|
|
|
79,162
|
|
|
161,165
|
|
|
161,392
|
|
|
|
2016
|
||||||||||||||
Benchmark Prices
|
|
Fourth
Quarter
|
|
Third
Quarter
|
|
Second
Quarter
|
|
First
Quarter
|
||||||||
WTI spot oil ($/Bbl)
|
|
$
|
53.75
|
|
|
$
|
47.72
|
|
|
$
|
48.27
|
|
|
$
|
36.94
|
|
Henry Hub spot natural gas ($/MMBtu)
|
|
$
|
3.71
|
|
|
$
|
2.84
|
|
|
$
|
2.94
|
|
|
$
|
1.98
|
|
|
|
2016
|
||||||||||
U.S. Rotary Rig Count
|
|
Fourth
Quarter
|
|
Third
Quarter
|
|
Second
Quarter
|
|
First
Quarter
|
||||
Oil
|
|
525
|
|
|
425
|
|
|
330
|
|
|
372
|
|
Natural gas
|
|
132
|
|
|
96
|
|
|
90
|
|
|
92
|
|
Other
|
|
1
|
|
|
1
|
|
|
1
|
|
|
—
|
|
Total
|
|
658
|
|
|
522
|
|
|
421
|
|
|
464
|
|
|
|
2016
|
||||||||||
Region
|
|
Fourth
Quarter
|
|
Third
Quarter
|
|
Second
Quarter
|
|
First
Quarter
|
||||
|
|
(Bcf)
|
||||||||||
East
|
|
737
|
|
|
899
|
|
|
632
|
|
|
439
|
|
Midwest
|
|
921
|
|
|
1,045
|
|
|
742
|
|
|
555
|
|
Mountain
|
|
207
|
|
|
237
|
|
|
198
|
|
|
147
|
|
Pacific
|
|
275
|
|
|
318
|
|
|
315
|
|
|
262
|
|
South Central
|
|
1,171
|
|
|
1,181
|
|
|
1,253
|
|
|
1,065
|
|
Total
|
|
3,311
|
|
|
3,680
|
|
|
3,140
|
|
|
2,468
|
|
•
|
volumes of oil and natural gas produced;
|
•
|
commodity prices including the effect of hedges; and
|
•
|
EBITDA, Adjusted EBITDA, and cash available for distribution.
|
•
|
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.
|
•
|
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.
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
|
|
(In thousands)
|
||||||||||
Net income (loss)
|
|
$
|
20,188
|
|
|
$
|
(101,305
|
)
|
|
$
|
169,187
|
|
Adjustments to reconcile to Adjusted EBITDA:
|
|
|
|
|
|
|
|
|
||||
Add:
|
|
|
|
|
|
|
|
|
||||
Depreciation, depletion and amortization
|
|
102,487
|
|
|
104,298
|
|
|
111,962
|
|
|||
Interest expense
|
|
7,547
|
|
|
6,418
|
|
|
13,509
|
|
|||
EBITDA
|
|
130,222
|
|
|
9,411
|
|
|
294,658
|
|
|||
Add:
|
|
|
|
|
|
|
|
|
|
|||
Impairment of oil and natural gas properties
|
|
6,775
|
|
|
249,569
|
|
|
117,930
|
|
|||
Accretion of asset retirement obligations
|
|
892
|
|
|
1,075
|
|
|
1,060
|
|
|||
Equity-based compensation
1
|
|
43,138
|
|
|
18,000
|
|
|
11,340
|
|
|||
Unrealized loss on commodity derivative instruments
|
|
81,253
|
|
|
—
|
|
|
—
|
|
|||
Less:
|
|
|
|
|
|
|
|
|
||||
Unrealized gain on commodity derivative instruments
|
|
—
|
|
|
(27,063
|
)
|
|
(39,283
|
)
|
|||
Adjusted EBITDA
|
|
262,280
|
|
|
250,992
|
|
|
385,705
|
|
|||
Adjustments to reconcile to cash generated from operations:
|
|
|
|
|
|
|
|
|
|
|||
Add:
|
|
|
|
|
|
|
|
|
|
|||
Restructuring charges
|
|
—
|
|
|
4,208
|
|
|
—
|
|
|||
Incremental general and administrative related to initial public offering
|
|
—
|
|
|
1,303
|
|
|
—
|
|
|||
Loss on sales of assets, net
|
|
—
|
|
|
—
|
|
|
32
|
|
|||
Less:
|
|
|
|
|
|
|
|
|
||||
Deferred revenue
|
|
(870
|
)
|
|
(660
|
)
|
|
(2,589
|
)
|
|||
Cash interest expense
|
|
(6,676
|
)
|
|
(5,483
|
)
|
|
(12,544
|
)
|
|||
Gain on sales of assets, net
|
|
(4,793
|
)
|
|
(4,873
|
)
|
|
—
|
|
|||
Estimated replacement capital expenditures
2
|
|
(11,250
|
)
|
|
—
|
|
|
—
|
|
|||
Cash generated from operations
|
|
238,691
|
|
|
245,487
|
|
|
370,604
|
|
|||
Less:
|
|
|
|
|
|
|
|
|
|
|||
Cash paid to noncontrolling interests
|
|
(111
|
)
|
|
(208
|
)
|
|
(307
|
)
|
|||
Redeemable preferred unit distributions
|
|
(5,763
|
)
|
|
(11,562
|
)
|
|
(15,720
|
)
|
|||
Cash generated from operations available for
distribution on common and subordinated
units and reinvestment in our business
|
|
$
|
232,817
|
|
|
$
|
233,717
|
|
|
$
|
354,577
|
|
|
|
|
Year Ended December 31,
|
|||||||||||||
|
|
2016
|
|
2015
|
|
Variance
|
|||||||||
|
|
(Dollars in thousands, except for realized prices and per BOE data)
|
|||||||||||||
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Oil and condensate (MBbls)
1
|
|
3,680
|
|
|
3,565
|
|
|
115
|
|
|
3.2
|
%
|
|||
Natural gas (MMcf)
1
|
|
47,498
|
|
|
41,389
|
|
|
6,109
|
|
|
14.8
|
%
|
|||
Equivalents (MBoe)
|
|
11,596
|
|
|
10,463
|
|
|
$
|
1,133
|
|
|
10.8
|
%
|
||
Revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Oil and condensate sales
|
|
$
|
142,382
|
|
|
$
|
163,538
|
|
|
$
|
(21,156
|
)
|
|
(12.9
|
)%
|
Natural gas and natural gas liquids sales
|
|
122,836
|
|
|
116,018
|
|
|
6,818
|
|
|
5.9
|
%
|
|||
Gain (loss) on commodity derivative instruments
|
|
(36,464
|
)
|
|
90,288
|
|
|
(126,752
|
)
|
|
(140.4
|
)%
|
|||
Lease bonus and other income
|
|
32,079
|
|
|
23,080
|
|
|
8,999
|
|
|
39.0
|
%
|
|||
Total revenue
|
|
$
|
260,833
|
|
|
$
|
392,924
|
|
|
$
|
(132,091
|
)
|
|
(33.6
|
)%
|
Realized prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Oil and condensate ($/Bbl)
|
|
$
|
38.69
|
|
|
$
|
45.87
|
|
|
$
|
(7.18
|
)
|
|
(15.7
|
)%
|
Natural gas ($/Mcf)
1
|
|
$
|
2.59
|
|
|
$
|
2.80
|
|
|
$
|
(0.21
|
)
|
|
(7.5
|
)%
|
Equivalents ($/Boe)
|
|
$
|
22.87
|
|
|
$
|
26.72
|
|
|
$
|
(3.85
|
)
|
|
(14.4
|
)%
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Lease operating expense
|
|
$
|
18,755
|
|
|
$
|
21,583
|
|
|
$
|
(2,828
|
)
|
|
(13.1
|
)%
|
Production costs and ad valorem taxes
|
|
35,464
|
|
|
35,767
|
|
|
(303
|
)
|
|
(0.8
|
)%
|
|||
Exploration expense
|
|
645
|
|
|
2,592
|
|
|
(1,947
|
)
|
|
(75.1
|
)%
|
|||
Depreciation, depletion, and amortization
|
|
102,487
|
|
|
104,298
|
|
|
(1,811
|
)
|
|
(1.7
|
)%
|
|||
Impairment of oil and natural gas properties
|
|
6,775
|
|
|
249,569
|
|
|
(242,794
|
)
|
|
(97.3
|
)%
|
|||
General and administrative
|
|
73,139
|
|
|
77,175
|
|
|
(4,036
|
)
|
|
(5.2
|
)%
|
|
|
Year Ended December 31,
|
|||||||||||||
|
|
2015
|
|
2014
|
|
Variance
|
|||||||||
|
|
(Dollars in thousands, except for realized prices and per BOE data)
|
|||||||||||||
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Oil and condensate (MBbls)
1
|
|
3,565
|
|
|
3,005
|
|
|
560
|
|
|
18.6
|
%
|
|||
Natural gas (MMcf)
1
|
|
41,389
|
|
|
42,273
|
|
|
(884
|
)
|
|
(2.1
|
)%
|
|||
Equivalents (MBoe)
|
|
10,463
|
|
|
10,051
|
|
|
$
|
412
|
|
|
4.1
|
%
|
||
Revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Oil and condensate sales
|
|
$
|
163,538
|
|
|
$
|
257,390
|
|
|
$
|
(93,852
|
)
|
|
(36.5
|
)%
|
Natural gas and natural gas liquids sales
|
|
116,018
|
|
|
207,456
|
|
|
(91,438
|
)
|
|
(44.1
|
)%
|
|||
Gain (loss) on commodity derivative instruments
|
|
90,288
|
|
|
37,336
|
|
|
52,952
|
|
|
141.8
|
%
|
|||
Lease bonus and other income
|
|
23,080
|
|
|
46,139
|
|
|
(23,059
|
)
|
|
(50.0
|
)%
|
|||
Total revenue
|
|
$
|
392,924
|
|
|
$
|
548,321
|
|
|
$
|
(155,397
|
)
|
|
(28.3
|
)%
|
Realized prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Oil and condensate ($/Bbl)
|
|
$
|
45.87
|
|
|
$
|
85.65
|
|
|
$
|
(39.78
|
)
|
|
(46.4
|
)%
|
Natural gas ($/Mcf)
1
|
|
$
|
2.80
|
|
|
$
|
4.91
|
|
|
$
|
(2.11
|
)
|
|
(43.0
|
)%
|
Equivalents ($/Boe)
|
|
$
|
26.72
|
|
|
$
|
46.25
|
|
|
$
|
(19.53
|
)
|
|
(42.2
|
)%
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Lease operating expense
|
|
$
|
21,583
|
|
|
$
|
21,233
|
|
|
$
|
350
|
|
|
1.6
|
%
|
Production costs and ad valorem taxes
|
|
35,767
|
|
|
49,575
|
|
|
(13,808
|
)
|
|
(27.9
|
)%
|
|||
Exploration expense
|
|
2,592
|
|
|
631
|
|
|
1,961
|
|
|
310.8
|
%
|
|||
Depreciation, depletion, and amortization
|
|
104,298
|
|
|
111,962
|
|
|
(7,664
|
)
|
|
(6.8
|
)%
|
|||
Impairment of oil and natural gas properties
|
|
249,569
|
|
|
117,930
|
|
|
131,639
|
|
|
111.6
|
%
|
|||
General and administrative
|
|
77,175
|
|
|
62,765
|
|
|
14,410
|
|
|
23.0
|
%
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
|
|
(In thousands)
|
||||||||||
Cash flows provided by operating activities
|
|
$
|
196,656
|
|
|
$
|
284,735
|
|
|
$
|
396,125
|
|
Cash flows used in investing activities
|
|
(221,542
|
)
|
|
(90,998
|
)
|
|
(101,110
|
)
|
|||
Cash flows provided by (used in) financing activities
|
|
21,425
|
|
|
(195,307
|
)
|
|
(310,335
|
)
|
|
|
Payments due by period
|
||||||||||||||||||
|
|
Total
|
|
Less Than 1 Year
|
|
1-3 Years
|
|
3-5 Years
|
|
More Than 5 Years
|
||||||||||
Credit facility
|
|
$
|
316,000
|
|
|
$
|
—
|
|
|
$
|
316,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Operating lease obligations
|
|
3,296
|
|
|
1,603
|
|
|
1,693
|
|
|
—
|
|
|
—
|
|
|||||
Purchase commitments
|
|
967
|
|
|
967
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Total
|
|
$
|
320,263
|
|
|
$
|
2,570
|
|
|
$
|
317,693
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Exhibit Number
|
|
Description
|
|
|
|
3.1
|
|
Certificate of Limited Partnership of Black Stone Minerals, L.P. (incorporated herein by reference to Exhibit 3.1 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on March 19, 2015 (SEC File No. 333-202875)).
|
|
|
|
3.2
|
|
Certificate of Amendment to Certificate of Limited Partnership of Black Stone Minerals, L.P. (incorporated herein by reference to Exhibit 3.2 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on March 19, 2015 (SEC File No. 333-202875)).
|
|
|
|
3.3
|
|
First Amended and Restated Agreement of Limited Partnership of Black Stone Minerals, L.P., dated May 6, 2015, by and among Black Stone Minerals GP, L.L.C. and Black Stone Minerals Company, L.P., as amended (incorporated herein by reference to Exhibit 3.2 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on April 19, 2016 (SEC File No. 001-37362)).
|
|
|
|
10.1^
|
|
Black Stone Minerals, L.P. Long-Term Incentive Plan, dated May 6, 2015, by Black Stone Minerals GP, L.L.C. (incorporated herein by reference to Exhibit 10.1 Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on May 6, 2015 (SEC File No. 001-37362)).
|
|
|
|
10.2
|
|
First Amendment to Third Amended and Restated Credit Agreement, dated as of October 28, 2015, among Black Stone Minerals Company, L.P., as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, Black Stone Minerals, L.P., as Parent MLP, and a syndicate of lenders (incorporated herein by reference to Exhibit 10.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on October 28, 2015 (SEC File No. 001-37362)).
|
|
|
|
10.3*
|
|
Second Amendment to Third Amended and Restated Credit Agreement, dated as of October 31, 2016, among Black Stone Minerals Company, L.P., as Borrower, Black Stone Minerals, L.P., as Parent MLP, Wells Fargo Bank, National Association, as Administrative Agent, and a syndicate of lenders.
|
|
|
|
10.4
|
|
Third Amended and Restated Credit Agreement among Black Stone Minerals Company, L.P., as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, Bank of America, N.A. and Compass Bank, as Co-Syndication Agents, Wells Fargo Bank, N.A. and Amegy Bank National Association, as Co-Documentation Agents, and a syndicate of lenders dated as of January 23, 2015 (incorporated herein by reference to Exhibit 10.2 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on March 19, 2015 (SEC File No. 333-202875)).
|
|
|
|
10.5^
|
|
Employment Agreement by and between Black Stone Minerals Company, L.P. and Thomas L. Carter, Jr. effective as of April 1, 2009 (incorporated herein by reference to Exhibit 10.3 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on March 19, 2015 (SEC File No. 333-202875)).
|
|
|
|
10.6^
|
|
First Amendment to Employment Agreement by and between Black Stone Minerals Company, L.P. and Thomas L. Carter, Jr. effective as of June 25, 2014 (incorporated herein by reference to Exhibit 10.4 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on March 19, 2015 (SEC File No. 333-202875)).
|
|
|
|
10.7^
|
|
Black Stone Minerals Company, L.P. 2012 Executive Incentive Plan (incorporated herein by reference to Exhibit 10.5 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on March 19, 2015 (SEC File No. 333-202875)).
|
|
|
|
10.8^
|
|
Restricted Unit Award Agreement by and between Black Stone Minerals Company, L.P. and Thomas L. Carter, Jr. effective as of January 1, 2012 (incorporated herein by reference to Exhibit 10.6 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on March 19, 2015 (SEC File No. 333-202875)).
|
|
|
|
10.9^
|
|
Restricted Unit Award Agreement by and between Black Stone Minerals Company, L.P. and Marc Carroll effective as of January 1, 2012 (incorporated herein by reference to Exhibit 10.7 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on March 19, 2015 (SEC File No. 333-202875)).
|
|
|
|
10.10^
|
|
Restricted Unit Award Agreement by and between Black Stone Minerals Company, L.P. and Holbrook F. Dorn effective as of January 1, 2012 (incorporated herein by reference to Exhibit 10.8 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on March 19, 2015 (SEC File No. 333-202875)).
|
10.11^
|
|
Form of IPO Award Grant Notice and Award Agreement for Senior Management (Restricted Units) (incorporated herein by reference to Exhibit 10.9 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on April 13, 2015 (SEC File No. 333-202875)).
|
|
|
|
10.12^
|
|
Form of IPO Award Grant Notice and Award Agreement for Senior Management (Performance Units) (incorporated herein by reference to Exhibit 10.10 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on April 13, 2015 (SEC File No. 333-202875)).
|
|
|
|
10.13^
|
|
Form of Non-Employee Director Unit Grant Notice and Award Agreement (incorporated herein by reference to Exhibit 10.11 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on April 13, 2015 (SEC File No. 333-202875)).
|
|
|
|
10.14^
|
|
Form of Severance Agreement for Thomas L. Carter, Jr. (incorporated herein by reference to Exhibit 10.12 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on April 13, 2015 (SEC File No. 333-202875)).
|
|
|
|
10.15^
|
|
Form of Severance Agreement for Senior Vice Presidents (incorporated herein by reference to Exhibit 10.13 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on April 13, 2015 (SEC File No. 333-202875)).
|
|
|
|
10.16^
|
|
Form of STI Award Grant Notice and STI Award Agreement (Leadership) under the Black Stone Minerals, L.P. Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.1 to Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on February 2, 2016 (SEC File No. 001-37362).
|
|
|
|
10.17^
|
|
Form of LTI Award Grant Notice and LTI Award Agreement (Leadership) under the Black Stone Minerals, L.P. Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.2 to Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on February 2, 2016 (SEC File No. 001-37362).
|
|
|
|
10.18^
|
|
Form of STI Award Grant Notice and STI Award Agreement (Leadership) under the Black Stone Minerals, L.P. Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.1 Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on February 19, 2016 (SEC File No. 001-37362)).
|
|
|
|
10.19^
|
|
Form of LTI Award Grant Notice and LTI Award Agreement (Leadership) under the Black Stone Minerals, L.P. Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.2 Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on February 19, 2016 (SEC File No. 001-37362)).
|
|
|
|
10.20^
|
|
Separation and Consulting Agreement and General Release of Claims, dated as of November 21, 2016, by and among Marc Carroll, Black Stone Natural Resources Management Company, and Black Stone Minerals GP, L.L.C. (incorporated herein by reference to Exhibit 10.1 Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on November 28, 2016 (SEC File No. 001-37362)).
|
|
|
|
21.1*
|
|
List of Subsidiaries of Black Stone Minerals, L.P.
|
|
|
|
23.1*
|
|
Consent of Ernst & Young LLP
|
|
|
|
23.2*
|
|
Consent of BDO USA, LLP
|
|
|
|
23.3*
|
|
Consent of Netherland, Sewell & Associates, Inc.
|
|
|
|
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
|
|
|
|
99.1*
|
|
Report of Netherland, Sewell & Associates, Inc.
|
|
|
|
101.INS*
|
|
XBRL Instance Document.
|
|
|
|
101.SCH*
|
|
XBRL Taxonomy Schema Document.
|
|
|
|
101.CAL*
|
|
XBRL Taxonomy Calculation Linkbase Document.
|
|
|
|
101.DEF*
|
|
XBRL Taxonomy Definition Linkbase Document.
|
|
|
|
101.LAB*
|
|
XBRL Taxonomy Label Linkbase Document.
|
|
|
|
101.PRE*
|
|
XBRL Taxonomy Presentation Linkbase Document.
|
*
|
Filed herewith.
|
^
|
Management contract or compensatory plan or arrangement.
|
|
|
|
|
BLACK STONE MINERALS, L.P.
|
|
|
|
|
|
|
|
|
|
|
|
By:
|
|
Black Stone Minerals GP, L.L.C.,
its general partner
|
|
|
|
|
|
|
|
|
|
March 1, 2017
|
|
By:
|
|
|
/s/ Thomas L. Carter, Jr.
|
|
|
|
|
|
|
Thomas L. Carter, Jr.
|
|
|
|
|
|
|
President, Chief Executive Officer, and Chairman
|
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
/s/ Thomas L. Carter, Jr.
|
|
President, Chief Executive Officer, and Chairman
|
|
March 1, 2017
|
Thomas L. Carter, Jr.
|
|
(Principal Executive Officer)
|
|
|
|
|
|
|
|
/s/ Jeffrey P. Wood
|
|
Senior Vice President and Chief Financial Officer
|
|
March 1, 2017
|
Jeffrey P. Wood
|
|
(Principal Financial Officer)
|
|
|
|
|
|
|
|
/s/ Dawn K. Smajstrla
|
|
Vice President and Chief Accounting Officer
|
|
March 1, 2017
|
Dawn K. Smajstrla
|
|
(Principal Accounting Officer)
|
|
|
|
|
|
|
|
/s/ William G. Bardel
|
|
Director
|
|
March 1, 2017
|
William G. Bardel
|
|
|
|
|
|
|
|
|
|
/s/ Carin M. Barth
|
|
Director
|
|
March 1, 2017
|
Carin M. Barth
|
|
|
|
|
|
|
|
|
|
/s/ D. Mark DeWalch
|
|
Director
|
|
March 1, 2017
|
D. Mark DeWalch
|
|
|
|
|
|
|
|
|
|
/s/ Ricky J. Haeflinger
|
|
Director
|
|
March 1, 2017
|
Ricky J. Haeflinger
|
|
|
|
|
|
|
|
|
|
/s/ Jerry V. Kyle, Jr.
|
|
Director
|
|
March 1, 2017
|
Jerry V. Kyle, Jr.
|
|
|
|
|
|
|
|
|
|
/s/ Michael C. Linn
|
|
Director
|
|
March 1, 2017
|
Michael C. Linn
|
|
|
|
|
|
|
|
|
|
/s/ John H. Longmaid
|
|
Director
|
|
March 1, 2017
|
John H. Longmaid
|
|
|
|
|
|
|
|
|
|
/s/ William N. Mathis
|
|
Director
|
|
March 1, 2017
|
William N. Mathis
|
|
|
|
|
|
|
|
|
|
/s/ Alexander D. Stuart
|
|
Director
|
|
March 1, 2017
|
Alexander D. Stuart
|
|
|
|
|
|
|
|
|
|
/s/ Allison K. Thacker
|
|
Director
|
|
March 1, 2017
|
Allison K. Thacker
|
|
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
|
As of December 31,
|
||||||
|
2016
|
|
2015
|
||||
ASSETS
|
|
|
|
|
|
||
CURRENT ASSETS
|
|
|
|
|
|
||
Cash and cash equivalents
|
$
|
9,772
|
|
|
$
|
13,233
|
|
Accounts receivable
|
68,181
|
|
|
41,246
|
|
||
Commodity derivative assets
|
—
|
|
|
48,260
|
|
||
Prepaid expenses and other current assets
|
1,036
|
|
|
856
|
|
||
TOTAL CURRENT ASSETS
|
78,989
|
|
|
103,595
|
|
||
PROPERTY AND EQUIPMENT
|
|
|
|
|
|
||
Oil and natural gas properties, at cost, using the successful efforts method of accounting, includes unproved properties of $605,736 and $524,563 at December 31, 2016 and 2015, respectively
|
2,697,073
|
|
|
2,482,211
|
|
||
Accumulated depreciation, depletion, amortization, and impairment
|
(1,652,930
|
)
|
|
(1,543,796
|
)
|
||
Oil and natural gas properties, net
|
1,044,143
|
|
|
938,415
|
|
||
Other property and equipment, net of accumulated depreciation of $14,327 and $14,660 at December 31, 2016 and 2015, respectively
|
528
|
|
|
179
|
|
||
NET PROPERTY AND EQUIPMENT
|
1,044,671
|
|
|
938,594
|
|
||
DEFERRED CHARGES AND OTHER LONG-TERM ASSETS
|
5,167
|
|
|
19,247
|
|
||
TOTAL ASSETS
|
$
|
1,128,827
|
|
|
$
|
1,061,436
|
|
LIABILITIES, MEZZANINE EQUITY AND EQUITY
|
|
|
|
|
|
||
CURRENT LIABILITIES
|
|
|
|
|
|
||
Accounts payable
|
$
|
4,142
|
|
|
$
|
5,036
|
|
Accrued liabilities
|
50,952
|
|
|
58,003
|
|
||
Commodity derivative liabilities
|
16,237
|
|
|
—
|
|
||
TOTAL CURRENT LIABILITIES
|
71,331
|
|
|
63,039
|
|
||
LONG-TERM LIABILITIES
|
|
|
|
|
|
||
Credit facility
|
316,000
|
|
|
66,000
|
|
||
Accrued incentive compensation
|
1,485
|
|
|
7,902
|
|
||
Commodity derivative liabilities
|
482
|
|
|
—
|
|
||
Deferred revenue
|
518
|
|
|
3,257
|
|
||
Asset retirement obligations
|
13,350
|
|
|
10,585
|
|
||
TOTAL LIABILITIES
|
403,166
|
|
|
150,783
|
|
||
COMMITMENTS AND CONTINGENCIES (Note 12)
|
|
|
|
|
|
||
MEZZANINE EQUITY
|
|
|
|
|
|
||
Partners' equity - redeemable preferred units, 53 and 77 units outstanding at December 31, 2016 and 2015, respectively
|
54,015
|
|
|
79,162
|
|
||
EQUITY
|
|
|
|
|
|
||
Partners' equity - general partner interest
|
—
|
|
|
—
|
|
||
Partners' equity - common units, 95,721 and 96,162 units outstanding at December 31, 2016 and 2015, respectively
|
489,023
|
|
|
574,648
|
|
||
Partners' equity - subordinated units, 95,164 and 95,057 units outstanding at December 31, 2016 and 2015, respectively
|
181,602
|
|
|
255,699
|
|
||
Noncontrolling interests
|
1,021
|
|
|
1,144
|
|
||
TOTAL EQUITY
|
671,646
|
|
|
831,491
|
|
||
TOTAL LIABILITIES, MEZZANINE EQUITY AND EQUITY
|
$
|
1,128,827
|
|
|
$
|
1,061,436
|
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
REVENUE
|
|
|
|
|
|
|
|
|
|||
Oil and condensate sales
|
$
|
142,382
|
|
|
$
|
163,538
|
|
|
$
|
257,390
|
|
Natural gas and natural gas liquids sales
|
122,836
|
|
|
116,018
|
|
|
207,456
|
|
|||
Gain (loss) on commodity derivative instruments
|
(36,464
|
)
|
|
90,288
|
|
|
37,336
|
|
|||
Lease bonus and other income
|
32,079
|
|
|
23,080
|
|
|
46,139
|
|
|||
TOTAL REVENUE
|
260,833
|
|
|
392,924
|
|
|
548,321
|
|
|||
OPERATING (INCOME) EXPENSE
|
|
|
|
|
|
|
|
|
|||
Lease operating expense
|
18,755
|
|
|
21,583
|
|
|
21,233
|
|
|||
Production costs and ad valorem taxes
|
35,464
|
|
|
35,767
|
|
|
49,575
|
|
|||
Exploration expense
|
645
|
|
|
2,592
|
|
|
631
|
|
|||
Depreciation, depletion and amortization
|
102,487
|
|
|
104,298
|
|
|
111,962
|
|
|||
Impairment of oil and natural gas properties
|
6,775
|
|
|
249,569
|
|
|
117,930
|
|
|||
General and administrative
|
73,139
|
|
|
77,175
|
|
|
62,765
|
|
|||
Accretion of asset retirement obligations
|
892
|
|
|
1,075
|
|
|
1,060
|
|
|||
(Gain) loss on sale of assets, net
|
(4,793
|
)
|
|
(4,873
|
)
|
|
32
|
|
|||
Other expense
|
—
|
|
|
1,593
|
|
|
1,424
|
|
|||
TOTAL OPERATING EXPENSE
|
233,364
|
|
|
488,779
|
|
|
366,612
|
|
|||
INCOME (LOSS) FROM OPERATIONS
|
27,469
|
|
|
(95,855
|
)
|
|
181,709
|
|
|||
OTHER INCOME (EXPENSE)
|
|
|
|
|
|
|
|
|
|||
Interest and investment income
|
656
|
|
|
58
|
|
|
28
|
|
|||
Interest expense
|
(7,547
|
)
|
|
(6,418
|
)
|
|
(13,509
|
)
|
|||
Other income (expense)
|
(390
|
)
|
|
910
|
|
|
959
|
|
|||
TOTAL OTHER EXPENSE
|
(7,281
|
)
|
|
(5,450
|
)
|
|
(12,522
|
)
|
|||
NET INCOME (LOSS)
|
20,188
|
|
|
(101,305
|
)
|
|
169,187
|
|
|||
NET INCOME (LOSS) ATTRIBUTABLE TO PREDECESSOR
|
—
|
|
|
(450
|
)
|
|
(169,187
|
)
|
|||
NET INCOME (LOSS) ATTRIBUTABLE TO NONCONTROLLING INTERESTS SUBSEQUENT TO INITIAL PUBLIC OFFERING
|
12
|
|
|
1,260
|
|
|
—
|
|
|||
DISTRIBUTIONS ON REDEEMABLE PREFERRED UNITS SUBSEQUENT TO INITIAL PUBLIC OFFERING
|
(5,763
|
)
|
|
(7,522
|
)
|
|
—
|
|
|||
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS SUBSEQUENT TO INITIAL PUBLIC OFFERING
|
$
|
14,437
|
|
|
$
|
(108,017
|
)
|
|
$
|
—
|
|
ALLOCATION OF INCOME (LOSS) SUBSEQUENT TO INITIAL PUBLIC OFFERING ATTRIBUTABLE TO:
|
|
|
|
|
|
|
|
|
|||
General partner interest
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
Common units
|
24,669
|
|
|
(54,326
|
)
|
|
|
|
|||
Subordinated units
|
(10,232
|
)
|
|
(53,691
|
)
|
|
|
|
|||
|
$
|
14,437
|
|
|
$
|
(108,017
|
)
|
|
|
|
|
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:
|
|
|
|
|
|
|
|
|
|||
Per common unit (basic)
|
$
|
0.26
|
|
|
$
|
(0.56
|
)
|
|
|
|
|
Weighted average common units outstanding (basic)
|
96,073
|
|
|
96,182
|
|
|
|
|
|||
Per subordinated unit (basic)
|
$
|
(0.11
|
)
|
|
$
|
(0.56
|
)
|
|
|
|
|
Weighted average subordinated units outstanding (basic)
|
95,138
|
|
|
95,057
|
|
|
|
|
|||
Per common unit (diluted)
|
$
|
0.26
|
|
|
$
|
(0.56
|
)
|
|
|
||
Weighted average common units outstanding (diluted)
|
96,243
|
|
|
96,182
|
|
|
|
||||
Per subordinated unit (diluted)
|
$
|
(0.11
|
)
|
|
$
|
(0.56
|
)
|
|
|
||
Weighted average subordinated units outstanding (diluted)
|
95,138
|
|
|
95,057
|
|
|
|
||||
DISTRIBUTIONS DECLARED AND PAID SUBSEQUENT TO INITIAL PUBLIC OFFERING:
|
|
|
|
|
|
|
|
|
|||
Per common unit
|
$
|
1.10
|
|
|
$
|
0.424
|
|
|
|
|
|
Per subordinated unit
|
$
|
0.74
|
|
|
$
|
0.424
|
|
|
|
|
|
Predecessor
|
|
Black Stone Minerals, L.P.
|
|||||||||||||||||||||||||
|
Predecessor
units
|
|
Partners'
equity
|
|
Common
units
|
|
Subordinated
units
|
|
Partners'
equity—
common
units
|
|
Partners'
equity—
subordinated
units
|
|
Noncontrolling
interests
|
|
Total
equity
|
|||||||||||||
BALANCE AT DECEMBER 31, 2013
|
164,133
|
|
|
$
|
716,403
|
|
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
716,403
|
|
Conversion of Predecessor redeemable preferred units
|
15
|
|
|
221
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
221
|
|
|||||
Issuance of Predecessor units for acquisition of oil and natural gas properties
|
104
|
|
|
2,258
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,258
|
|
|||||
Repurchase of Predecessor units
|
(239
|
)
|
|
(5,199
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(5,199
|
)
|
|||||
Restricted Predecessor units granted, net of forfeitures
|
471
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Equity-based compensation
|
—
|
|
|
11,340
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
11,340
|
|
|||||
Distributions to Predecessor unitholders and non-controlling interests
|
—
|
|
|
(225,273
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(225,273
|
)
|
|||||
Net income attributable to Predecessor
|
—
|
|
|
169,187
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
169,187
|
|
|||||
Distributions on Predecessor redeemable preferred units
|
—
|
|
|
(15,720
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(15,720
|
)
|
|||||
BALANCE AT DECEMBER 31, 2014
|
164,484
|
|
|
653,217
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
653,217
|
|
|||||
Conversion of Predecessor redeemable preferred units
|
2,750
|
|
|
39,240
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
39,240
|
|
|||||
Restricted Predecessor units granted
|
562
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Repurchases of Predecessor units
|
(164
|
)
|
|
(3,015
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,015
|
)
|
|||||
Distributions to Predecessor unitholders and noncontrolling interests
|
—
|
|
|
(73,205
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(73,205
|
)
|
|||||
Distributions on Predecessor redeemable preferred units
|
—
|
|
|
(4,040
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4,040
|
)
|
|||||
Net income attributable to Predecessor
|
—
|
|
|
450
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
450
|
|
|||||
Allocation of Predecessor units and equity
|
(167,632
|
)
|
|
(612,647
|
)
|
|
72,575
|
|
|
95,057
|
|
|
264,235
|
|
|
345,875
|
|
|
2,537
|
|
|
—
|
|
|||||
Issuance of common units for initial public offering, net of offering costs
|
—
|
|
|
—
|
|
|
22,500
|
|
|
—
|
|
|
391,500
|
|
|
—
|
|
|
—
|
|
|
391,500
|
|
|||||
Restricted common units granted, net of forfeitures
|
—
|
|
|
—
|
|
|
1,087
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Equity-based compensation
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
14,181
|
|
|
3,819
|
|
|
—
|
|
|
18,000
|
|
|||||
Distributions
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(40,783
|
)
|
|
(40,304
|
)
|
|
(133
|
)
|
|
(81,220
|
)
|
|||||
Charges to partners' equity for accrued distribution equivalent rights
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(159
|
)
|
|
—
|
|
|
—
|
|
|
(159
|
)
|
|||||
Net loss subsequent to initial public offering
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(50,543
|
)
|
|
(49,952
|
)
|
|
(1,260
|
)
|
|
(101,755
|
)
|
|||||
Distributions on redeemable preferred units
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,783
|
)
|
|
(3,739
|
)
|
|
—
|
|
|
(7,522
|
)
|
|||||
BALANCE AT DECEMBER 31, 2015
|
—
|
|
|
—
|
|
|
96,162
|
|
|
95,057
|
|
|
574,648
|
|
|
255,699
|
|
|
1,144
|
|
|
831,491
|
|
|||||
Restricted units granted, net of forfeitures
|
—
|
|
|
—
|
|
|
993
|
|
|
(56
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Equity-based compensation
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
21,022
|
|
|
2,823
|
|
|
—
|
|
|
23,845
|
|
|||||
Conversion of redeemable preferred units
|
—
|
|
|
—
|
|
|
184
|
|
|
241
|
|
|
2,625
|
|
|
3,439
|
|
|
—
|
|
|
6,064
|
|
|||||
Repurchases of common and subordinated units
|
—
|
|
|
—
|
|
|
(1,618
|
)
|
|
(78
|
)
|
|
(27,436
|
)
|
|
—
|
|
|
—
|
|
|
(27,436
|
)
|
|||||
Distributions
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(105,817
|
)
|
|
(70,127
|
)
|
|
(111
|
)
|
|
(176,055
|
)
|
|||||
Charges to partners' equity for accrued distribution equivalent rights
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(688
|
)
|
|
—
|
|
|
—
|
|
|
(688
|
)
|
|||||
Net income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
27,565
|
|
|
(7,365
|
)
|
|
(12
|
)
|
|
20,188
|
|
|||||
Distributions on redeemable preferred units
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,896
|
)
|
|
(2,867
|
)
|
|
—
|
|
|
(5,763
|
)
|
|||||
BALANCE AT DECEMBER 31, 2016
|
—
|
|
|
$
|
—
|
|
|
95,721
|
|
|
95,164
|
|
|
$
|
489,023
|
|
|
$
|
181,602
|
|
|
$
|
1,021
|
|
|
$
|
671,646
|
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
CASH FLOWS FROM OPERATING ACTIVITIES
|
|
|
|
|
|
|
|
|
|||
Net income (loss)
|
$
|
20,188
|
|
|
$
|
(101,305
|
)
|
|
$
|
169,187
|
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
|
|
|
|
|||
Depreciation, depletion, and amortization
|
102,487
|
|
|
104,298
|
|
|
111,962
|
|
|||
Impairment of oil and natural gas properties
|
6,775
|
|
|
249,569
|
|
|
117,930
|
|
|||
Accretion of asset retirement obligations
|
892
|
|
|
1,075
|
|
|
1,060
|
|
|||
Amortization of deferred charges
|
871
|
|
|
935
|
|
|
965
|
|
|||
(Gain) loss on commodity derivative instruments
|
36,464
|
|
|
(90,288
|
)
|
|
(37,336
|
)
|
|||
Net cash received (paid) on settlement of commodity derivative instruments
|
44,789
|
|
|
63,225
|
|
|
(1,947
|
)
|
|||
Equity-based compensation
|
43,138
|
|
|
18,000
|
|
|
11,340
|
|
|||
(Gain) loss on sale of assets, net
|
(4,793
|
)
|
|
(4,873
|
)
|
|
32
|
|
|||
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
|||
Accounts receivable
|
(29,759
|
)
|
|
33,586
|
|
|
17,210
|
|
|||
Prepaid expenses and other current assets
|
(180
|
)
|
|
95
|
|
|
453
|
|
|||
Accounts payable and accrued liabilities
|
(23,029
|
)
|
|
11,221
|
|
|
8,003
|
|
|||
Deferred revenue
|
(870
|
)
|
|
(660
|
)
|
|
(2,589
|
)
|
|||
Settlement of asset retirement obligations
|
(317
|
)
|
|
(143
|
)
|
|
(145
|
)
|
|||
NET CASH PROVIDED BY OPERATING ACTIVITIES
|
196,656
|
|
|
284,735
|
|
|
396,125
|
|
|||
CASH FLOWS FROM INVESTING ACTIVITIES
|
|
|
|
|
|
|
|
|
|||
Additions to oil and natural gas properties
|
(80,179
|
)
|
|
(54,244
|
)
|
|
(74,201
|
)
|
|||
Purchase of other property and equipment
|
(425
|
)
|
|
(181
|
)
|
|
(827
|
)
|
|||
Proceeds from the sale of oil and natural gas properties
|
198
|
|
|
25,705
|
|
|
19,470
|
|
|||
Acquisitions of oil and natural gas properties
|
(141,136
|
)
|
|
(62,278
|
)
|
|
(45,552
|
)
|
|||
NET CASH USED IN INVESTING ACTIVITIES
|
(221,542
|
)
|
|
(90,998
|
)
|
|
(101,110
|
)
|
|||
CASH FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
|
|
|
|
|
|||
Proceeds from issuance of common units of Black Stone Minerals, L.P., net of
offering costs
|
—
|
|
|
399,087
|
|
|
(7,587
|
)
|
|||
Borrowings under senior line of credit
|
349,000
|
|
|
245,600
|
|
|
230,000
|
|
|||
Repayments under senior line of credit
|
(99,000
|
)
|
|
(573,600
|
)
|
|
(287,000
|
)
|
|||
Distributions to Predecessor unitholders
|
—
|
|
|
(126,383
|
)
|
|
(224,926
|
)
|
|||
Distributions to Black Stone Minerals, L.P. common and subordinated unitholders
|
(175,943
|
)
|
|
(81,087
|
)
|
|
—
|
|
|||
Distributions to preferred unitholders
|
(6,385
|
)
|
|
(13,578
|
)
|
|
(15,724
|
)
|
|||
Distributions to noncontrolling interests
|
(111
|
)
|
|
(208
|
)
|
|
—
|
|
|||
Redemption of redeemable preferred units
|
(18,461
|
)
|
|
(40,747
|
)
|
|
—
|
|
|||
Repurchases of Predecessor units
|
—
|
|
|
(3,015
|
)
|
|
(5,199
|
)
|
|||
Debt issuance costs
|
(239
|
)
|
|
(1,376
|
)
|
|
—
|
|
|||
Note receivable-officers
|
—
|
|
|
—
|
|
|
101
|
|
|||
Repurchase of common and subordinate units
|
(27,436
|
)
|
|
—
|
|
|
—
|
|
|||
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES
|
21,425
|
|
|
(195,307
|
)
|
|
(310,335
|
)
|
|||
NET CHANGE IN CASH AND CASH EQUIVALENTS
|
(3,461
|
)
|
|
(1,570
|
)
|
|
(15,320
|
)
|
|||
CASH AND CASH EQUIVALENTS - beginning of the year
|
13,233
|
|
|
14,803
|
|
|
30,123
|
|
|||
CASH AND CASH EQUIVALENTS - end of the year
|
$
|
9,772
|
|
|
$
|
13,233
|
|
|
$
|
14,803
|
|
SUPPLEMENTAL DISCLOSURE
|
|
|
|
|
|
||||||
Interest paid
|
$
|
6,535
|
|
|
$
|
5,478
|
|
|
$
|
12,754
|
|
NON-CASH ACTIVITIES
|
|
|
|
|
|
||||||
Accrued Predecessor distributions payable
|
$
|
—
|
|
|
$
|
(53,248
|
)
|
|
$
|
347
|
|
Conversion of redeemable preferred units
|
$
|
(6,064
|
)
|
|
$
|
(39,240
|
)
|
|
$
|
(221
|
)
|
Accrued distributions payable for redeemable preferred units
|
$
|
(1,324
|
)
|
|
$
|
(2,016
|
)
|
|
$
|
(4
|
)
|
Property additions and acquisitions financed through accounts payable and accrued liabilities
|
$
|
26,553
|
|
|
$
|
21,496
|
|
|
$
|
14,130
|
|
Public offering costs capitalized and offset against proceeds from initial public offering
|
$
|
—
|
|
|
$
|
7,587
|
|
|
$
|
—
|
|
Asset retirement obligations incurred
|
$
|
2,009
|
|
|
$
|
272
|
|
|
$
|
2,505
|
|
Accrued distribution equivalent rights
|
$
|
847
|
|
|
$
|
159
|
|
|
$
|
—
|
|
Liabilities assumed as consideration for oil and natural gas properties acquired
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
7,000
|
|
Acquisition of oil and natural gas properties financed through issuance of Predecessor units
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2,258
|
|
Deferred revenue (settled) assumed through acquisition of oil and natural gas properties
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(2,657
|
)
|
|
As of December 31,
|
||||||
|
2016
|
|
2015
|
||||
Accrued liabilities:
|
|
|
|
|
|
||
Accrued capital expenditures
|
$
|
17,775
|
|
|
$
|
20,494
|
|
Accrued incentive compensation
|
20,898
|
|
|
16,554
|
|
||
Accrued legal
|
—
|
|
|
7,000
|
|
||
Accrued severance
|
—
|
|
|
3,889
|
|
||
Accrued property taxes
|
3,175
|
|
|
3,699
|
|
||
Accrued other
|
9,104
|
|
|
6,367
|
|
||
TOTAL ACCRUED LIABILITIES
|
$
|
50,952
|
|
|
$
|
58,003
|
|
|
|
|
|
|
For the year ended December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(In thousands)
|
||||||
Beginning asset retirement obligations
|
$
|
10,585
|
|
|
$
|
9,381
|
|
Liabilities incurred
|
2,009
|
|
|
272
|
|
||
Liabilities settled
|
(317
|
)
|
|
(143
|
)
|
||
Accretion expense
|
892
|
|
|
1,075
|
|
||
Revisions in estimated costs
|
181
|
|
|
—
|
|
||
Ending asset retirement obligations
|
$
|
13,350
|
|
|
$
|
10,585
|
|
|
(In thousands)
|
||
Proved oil and natural gas properties
|
$
|
18,948
|
|
Unproved oil and natural gas properties
|
14,082
|
|
|
Net working capital
|
1,038
|
|
|
Asset retirement obligations
|
(50
|
)
|
|
Total fair value
|
$
|
34,018
|
|
|
(In thousands)
|
||
Proved oil and natural gas properties
|
$
|
20,787
|
|
Unproved oil and natural gas properties
|
65,745
|
|
|
Net working capital
|
1,026
|
|
|
Total fair value
|
$
|
87,558
|
|
As at December 31, 2016
|
||||||||||||||
Classification
|
|
Balance Sheet Location
|
|
Gross Fair
Value
|
|
Effect of
Counterparty
Netting
|
|
Net Carrying
Value on
Balance Sheet
|
||||||
|
|
|
|
|
|
|
(In thousands)
|
|
|
|||||
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|||
Current asset
|
|
Commodity derivative assets
|
|
$
|
3,879
|
|
|
$
|
3,879
|
|
|
$
|
—
|
|
Long-term asset
|
|
Deferred charges and other
long-term assets
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
Total assets
|
|
|
|
$
|
3,879
|
|
|
$
|
3,879
|
|
|
$
|
—
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|||
Current liability
|
|
Commodity derivative liabilities
|
|
$
|
20,116
|
|
|
$
|
3,879
|
|
|
$
|
16,237
|
|
Long-term liability
|
|
Commodity derivative liabilities
|
|
482
|
|
|
—
|
|
|
482
|
|
|||
Total liabilities
|
|
|
|
$
|
20,598
|
|
|
$
|
3,879
|
|
|
$
|
16,719
|
|
As of December 31, 2015
|
||||||||||||||
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
|
|
$
|
48,260
|
|
|
$
|
—
|
|
|
$
|
48,260
|
|
Long-term asset
|
|
Deferred charges and other
long-term assets
|
|
16,274
|
|
|
—
|
|
|
16,274
|
|
|||
Total assets
|
|
|
|
$
|
64,534
|
|
|
$
|
—
|
|
|
$
|
64,534
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|||
Current liability
|
|
Commodity derivative liabilities
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Long-term liability
|
|
Commodity derivative liabilities
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
Total liabilities
|
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
For the year ended December 31,
|
||||||||||
Derivatives not designated as hedging instruments
|
|
2016
|
|
2015
|
|
2014
|
||||||
|
|
(In thousands)
|
||||||||||
Beginning fair value of commodity derivative instruments
|
|
$
|
64,534
|
|
|
$
|
37,471
|
|
|
$
|
(1,812
|
)
|
Gain (loss) on oil derivative instruments
|
|
(15,998
|
)
|
|
57,681
|
|
|
27,548
|
|
|||
Gain (loss) on natural gas derivative instruments
|
|
(20,466
|
)
|
|
32,607
|
|
|
9,788
|
|
|||
Net cash received on settlements of oil derivative
instruments
|
|
(27,450
|
)
|
|
(41,786
|
)
|
|
(46
|
)
|
|||
Net cash (received) paid on settlements of natural gas
derivative instruments
|
|
(17,339
|
)
|
|
(21,439
|
)
|
|
1,993
|
|
|||
Net change in fair value of commodity derivative
instruments
|
|
(81,253
|
)
|
|
27,063
|
|
|
39,283
|
|
|||
Ending fair value of commodity derivative instruments
|
|
$
|
(16,719
|
)
|
|
$
|
64,534
|
|
|
$
|
37,471
|
|
|
|
Volume
|
|
Weighted Average
|
|
Range (Per Bbl)
|
|||||||||
Period and Type of Contract
|
|
(Bbl)
|
|
(Per Bbl)
|
|
Low
|
|
High
|
|||||||
Oil Swap Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
2017
|
|
|
|
|
|
|
|
|
|||||||
First quarter
|
|
394,000
|
|
|
$
|
61.78
|
|
|
$
|
50.34
|
|
|
$
|
63.65
|
|
Second quarter
|
|
405,000
|
|
|
53.63
|
|
|
51.45
|
|
|
54.38
|
|
|||
Third quarter
|
|
396,000
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Fourth quarter
|
|
396,000
|
|
|
53.12
|
|
|
52.57
|
|
|
53.67
|
|
|
|
Volume
|
|
Weighted Average
|
|
Range (Per MMBtu)
|
|||||||||
Period and Type of Contract
|
|
(MMBtu)
|
|
(Per MMBtu)
|
|
Low
|
|
High
|
|||||||
Natural Gas Swap Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
2017
|
|
|
|
|
|
|
|
|
|||||||
First quarter
|
|
8,850,000
|
|
|
$
|
3.40
|
|
|
$
|
3.08
|
|
|
$
|
3.52
|
|
Second quarter
|
|
8,300,000
|
|
|
3.09
|
|
|
2.85
|
|
|
3.18
|
|
|||
Third quarter
|
|
7,730,000
|
|
|
2.97
|
|
|
2.90
|
|
|
3.12
|
|
|||
Fourth quarter
|
|
7,040,000
|
|
|
3.08
|
|
|
2.92
|
|
|
3.29
|
|
|
|
Volume
|
|
Weighted Average
|
|
Range (Per Bbl)
|
|||||||||
Period and Type of Contract
|
|
(Bbl)
|
|
(Per Bbl)
|
|
Low
|
|
High
|
|||||||
Oil Swap Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
2017
|
|
|
|
|
|
|
|
|
|||||||
First quarter
|
|
90,000
|
|
|
$
|
54.80
|
|
|
$
|
54.28
|
|
|
$
|
55.23
|
|
Second quarter
|
|
210,000
|
|
|
54.90
|
|
|
54.65
|
|
|
55.23
|
|
|||
Third quarter
|
|
160,000
|
|
|
54.94
|
|
|
54.65
|
|
|
55.23
|
|
|||
Fourth quarter
|
|
120,000
|
|
|
55.00
|
|
|
54.65
|
|
|
55.23
|
|
|||
2018
|
|
|
|
|
|
|
|
|
|||||||
First quarter
|
|
475,000
|
|
|
$
|
54.74
|
|
|
$
|
54.50
|
|
|
$
|
55.05
|
|
Second quarter
|
|
445,000
|
|
|
54.73
|
|
|
54.50
|
|
|
54.90
|
|
|||
Third quarter
|
|
425,000
|
|
|
54.72
|
|
|
54.50
|
|
|
54.90
|
|
|||
Fourth quarter
|
|
405,000
|
|
|
54.72
|
|
|
54.50
|
|
|
54.90
|
|
|
|
Volume
|
|
Weighted Average
|
|
Range (Per MMBtu)
|
|||||||||
Period and Type of Contract
|
|
(MMBtu)
|
|
(Per MMBtu)
|
|
Low
|
|
High
|
|||||||
Natural Gas Swap Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
2017
|
|
|
|
|
|
|
|
|
|||||||
First quarter
|
|
1,740,000
|
|
|
$
|
3.19
|
|
|
$
|
2.95
|
|
|
$
|
3.40
|
|
Second quarter
|
|
4,080,000
|
|
|
3.16
|
|
|
2.95
|
|
|
3.40
|
|
|||
Third quarter
|
|
3,480,000
|
|
|
3.21
|
|
|
3.13
|
|
|
3.41
|
|
|||
Fourth quarter
|
|
3,480,000
|
|
|
3.22
|
|
|
3.13
|
|
|
3.57
|
|
|||
2018
|
|
|
|
|
|
|
|
|
|||||||
First quarter
|
|
4,800,000
|
|
|
$
|
3.01
|
|
|
$
|
2.99
|
|
|
$
|
3.02
|
|
Second quarter
|
|
4,800,000
|
|
|
3.01
|
|
|
2.99
|
|
|
3.02
|
|
|||
Third quarter
|
|
4,800,000
|
|
|
3.01
|
|
|
2.99
|
|
|
3.02
|
|
|||
Fourth quarter
|
|
4,500,000
|
|
|
3.01
|
|
|
2.99
|
|
|
3.02
|
|
|
|
Fair Value Measurements Using
|
|
Effect of
Counterparty
|
|
|
||||||||||||||
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Netting
|
|
Total
|
||||||||||
|
|
(In thousands)
|
||||||||||||||||||
As of December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Financial Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Commodity derivative instruments
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Financial Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Commodity derivative instruments
|
|
—
|
|
|
16,719
|
|
|
—
|
|
|
—
|
|
|
16,719
|
|
|||||
As of December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Financial Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Commodity derivative instruments
|
|
$
|
—
|
|
|
$
|
64,534
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
64,534
|
|
Financial Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Commodity derivative instruments
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
Fair Value Measurements Using
|
|
Net Book
|
|
|
||||||||||||||
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Value
1
|
|
Impairment
|
||||||||||
|
|
(In thousands)
|
||||||||||||||||||
Year Ended December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Impaired oil and natural gas properties
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3,042
|
|
|
$
|
9,817
|
|
|
$
|
6,775
|
|
Year Ended December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Impaired oil and natural gas properties
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
156,689
|
|
|
$
|
406,258
|
|
|
$
|
249,569
|
|
Year Ended December 31, 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Impaired oil and natural gas properties
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
81,864
|
|
|
$
|
199,794
|
|
|
$
|
117,930
|
|
|
|
Units
|
|
Weighted-Average Grant-Date Fair
Value per Unit
|
||||||||||
Units
|
|
Common
|
|
Subordinated
|
|
Common
|
|
Subordinated
|
||||||
Unvested at December 31, 2015
|
|
1,362,091
|
|
|
442,778
|
|
|
$
|
19.08
|
|
|
$
|
19.36
|
|
Granted
|
|
985,239
|
|
|
—
|
|
|
10.58
|
|
|
—
|
|
||
Vested
|
|
(716,753
|
)
|
|
(224,090
|
)
|
|
15.10
|
|
|
19.80
|
|
||
Converted
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||
Forfeited
|
|
(359,362
|
)
|
|
(55,647
|
)
|
|
17.09
|
|
|
18.77
|
|
||
Unvested at December 31, 2016
|
|
1,271,215
|
|
|
163,041
|
|
|
15.29
|
|
|
18.97
|
|
Performance units
|
|
Units
|
|
Weighted-
Average Grant-
Date Fair Value
per Unit
|
|||
Unvested at December 31, 2015
|
|
947,142
|
|
|
$
|
19.00
|
|
Granted
|
|
730,632
|
|
|
11.36
|
|
|
Vested
|
|
(216,177
|
)
|
|
17.90
|
|
|
Forfeited
|
|
(305,178
|
)
|
|
16.88
|
|
|
Unvested at December 31, 2016
|
|
1,156,419
|
|
|
14.94
|
|
|
|
Year Ended December 31,
|
||||||||||
Incentive compensation expense
|
|
2016
|
|
2015
|
|
2014
|
||||||
|
|
(In thousands)
|
||||||||||
Cash—long-term incentive plan
|
|
$
|
2,725
|
|
|
$
|
15,064
|
|
|
$
|
13,927
|
|
Equity-based compensation—restricted common and subordinated units
|
|
13,408
|
|
|
10,137
|
|
|
7,194
|
|
|||
Equity-based compensation—restricted performance units
|
|
18,518
|
|
|
4,743
|
|
|
—
|
|
|||
Board of Directors incentive plan
|
|
2,012
|
|
|
3,120
|
|
|
4,146
|
|
|||
Total incentive compensation expense
|
|
$
|
36,663
|
|
|
$
|
33,064
|
|
|
$
|
25,267
|
|
Year Ending December 31,
|
(In thousands)
|
||
2017
|
$
|
1,603
|
|
2018
|
1,647
|
|
|
2019
|
35
|
|
|
2020
|
12
|
|
|
2021
|
—
|
|
|
Total
|
$
|
3,297
|
|
|
|
For the Year Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
|
|
(In thousands, except per unit amounts)
|
||||||||||
NET INCOME (LOSS)
|
|
$
|
20,188
|
|
|
$
|
(101,305
|
)
|
|
$
|
169,187
|
|
NET (INCOME) LOSS ATTRIBUTABLE TO PREDECESSOR
|
|
—
|
|
|
(450
|
)
|
|
(169,187
|
)
|
|||
NET (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS SUBSEQUENT TO INITIAL PUBLIC OFFERING
|
|
12
|
|
|
1,260
|
|
|
—
|
|
|||
DISTRIBUTIONS ON REDEEMABLE PREFERRED UNITS SUBSEQUENT TO INITIAL PUBLIC OFFERING
|
|
(5,763
|
)
|
|
(7,522
|
)
|
|
—
|
|
|||
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS SUBSEQUENT TO INITIAL PUBLIC OFFERING
|
|
$
|
14,437
|
|
|
$
|
(108,017
|
)
|
|
$
|
—
|
|
ALLOCATION OF NET INCOME (LOSS) SUBSEQUENT TO INITIAL PUBLIC OFFERING ATTRIBUTABLE TO:
|
|
|
|
|
|
|
|
|
|
|||
General partner interest
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
Common units
|
|
24,669
|
|
|
(54,326
|
)
|
|
|
|
|||
Subordinated units
|
|
(10,232
|
)
|
|
(53,691
|
)
|
|
|
|
|||
|
|
$
|
14,437
|
|
|
$
|
(108,017
|
)
|
|
|
|
|
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:
|
|
|
|
|
|
|
|
|
|
|||
Per common unit (basic)
|
|
$
|
0.26
|
|
|
$
|
(0.56
|
)
|
|
|
|
|
Weighted average common units outstanding (basic)
|
|
96,073
|
|
|
96,182
|
|
|
|
||||
Per subordinated unit (basic)
|
|
$
|
(0.11
|
)
|
|
$
|
(0.56
|
)
|
|
|
||
Weighted average subordinated units outstanding (basic)
|
|
95,138
|
|
|
95,057
|
|
|
|
||||
Per common unit (diluted)
|
|
$
|
0.26
|
|
|
$
|
(0.56
|
)
|
|
|
||
Weighted average common units outstanding (diluted)
|
|
96,243
|
|
|
96,182
|
|
|
|
||||
Per subordinated unit (diluted)
|
|
$
|
(0.11
|
)
|
|
$
|
(0.56
|
)
|
|
|
||
Weighted average subordinated units outstanding (diluted)
|
|
95,138
|
|
|
95,057
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
|
|
(In thousands)
|
||||||||||
Acquisition Costs of Properties:
1
|
|
|
|
|
|
|
||||||
Proved
|
|
$
|
40,242
|
|
|
$
|
2,302
|
|
|
$
|
13,215
|
|
Unproved
|
|
100,888
|
|
|
60,994
|
|
|
35,706
|
|
|||
Exploration Costs
|
|
645
|
|
|
2,592
|
|
|
631
|
|
|||
Development Costs
|
|
73,316
|
|
|
60,056
|
|
|
50,595
|
|
|||
Total
|
|
$
|
215,091
|
|
|
$
|
125,944
|
|
|
$
|
100,147
|
|
1.
|
See Note 4 – Acquisitions for further discussion. Unproved properties also include purchases of leasehold prospects.
|
|
|
As of December 31,
|
||||||
|
|
2016
|
|
2015
|
||||
|
|
(In thousands)
|
||||||
Proved properties
|
|
$
|
2,091,337
|
|
|
$
|
1,957,648
|
|
Unproved properties
|
|
605,736
|
|
|
524,563
|
|
||
Total
|
|
2,697,073
|
|
|
2,482,211
|
|
||
Accumulated depreciation, depletion, amortization, and impairment
|
|
(1,652,930
|
)
|
|
(1,543,796
|
)
|
||
Oil and natural gas properties, net
|
|
$
|
1,044,143
|
|
|
$
|
938,415
|
|
|
|
Crude Oil
(MBbl)
|
|
Natural Gas
(MMcf)
|
|
Total
(MBoe)
|
|||
Net proved reserves at December 31, 2013
|
|
18,949
|
|
|
239,960
|
|
|
58,942
|
|
Revisions of previous estimates
1
|
|
(1,904
|
)
|
|
(20,764
|
)
|
|
(5,365
|
)
|
Purchases of minerals in place
2
|
|
89
|
|
|
7,439
|
|
|
1,329
|
|
Extensions, discoveries and other additions
3
|
|
2,938
|
|
|
19,894
|
|
|
6,254
|
|
Production
|
|
(3,005
|
)
|
|
(42,273
|
)
|
|
(10,051
|
)
|
Net proved reserves at December 31, 2014
|
|
17,067
|
|
|
204,256
|
|
|
51,109
|
|
Revisions of previous estimates
1
|
|
(197
|
)
|
|
(17,043
|
)
|
|
(3,037
|
)
|
Purchases of minerals in place
4
|
|
8
|
|
|
367
|
|
|
69
|
|
Extensions, discoveries and other additions
5
|
|
2,529
|
|
|
57,484
|
|
|
12,110
|
|
Production
|
|
(3,565
|
)
|
|
(41,389
|
)
|
|
(10,463
|
)
|
Net proved reserves at December 31, 2015
|
|
15,842
|
|
|
203,675
|
|
|
49,788
|
|
Revisions of previous estimates
1
|
|
3,007
|
|
|
29,024
|
|
|
7,844
|
|
Purchases of minerals in place
6
|
|
1,322
|
|
|
5,683
|
|
|
2,269
|
|
Extensions, discoveries and other additions
7
|
|
1,877
|
|
|
79,455
|
|
|
15,120
|
|
Production
|
|
(3,680
|
)
|
|
(47,498
|
)
|
|
(11,596
|
)
|
Net proved reserves at December 31, 2016
|
|
18,368
|
|
|
270,339
|
|
|
63,425
|
|
Net Proved Developed Reserves
8
|
|
|
|
|
|
|
|
|
|
December 31, 2014
|
|
16,700
|
|
|
202,888
|
|
|
50,514
|
|
December 31, 2015
|
|
15,497
|
|
|
174,555
|
|
|
44,590
|
|
December 31, 2016
|
|
18,150
|
|
|
223,057
|
|
|
55,327
|
|
Net Proved Undeveloped Reserves
9
|
|
|
|
|
|
|
|
|
|
December 31, 2014
|
|
367
|
|
|
1,368
|
|
|
595
|
|
December 31, 2015
|
|
345
|
|
|
29,120
|
|
|
5,198
|
|
December 31, 2016
|
|
218
|
|
|
47,282
|
|
|
8,098
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
|
|
(In thousands)
|
||||||||||
Future cash inflows
|
|
$
|
1,267,179
|
|
|
$
|
1,211,290
|
|
|
$
|
2,493,294
|
|
Future production costs
|
|
(193,749
|
)
|
|
(205,861
|
)
|
|
(405,833
|
)
|
|||
Future development costs
|
|
(36,509
|
)
|
|
(84,746
|
)
|
|
(64,968
|
)
|
|||
Future income tax expense
|
|
(3,516
|
)
|
|
—
|
|
|
—
|
|
|||
Future net cash flows (undiscounted)
|
|
1,033,405
|
|
|
920,683
|
|
|
2,022,493
|
|
|||
Annual discount 10% for estimated timing
|
|
(430,390
|
)
|
|
(365,711
|
)
|
|
(879,399
|
)
|
|||
Total
1
|
|
$
|
603,015
|
|
|
$
|
554,972
|
|
|
$
|
1,143,094
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
|
|
(In thousands)
|
||||||||||
Standardized measure, beginning of year
|
|
$
|
554,972
|
|
|
$
|
1,143,094
|
|
|
$
|
1,185,257
|
|
Sales, net of production costs
|
|
(210,354
|
)
|
|
(222,206
|
)
|
|
(391,983
|
)
|
|||
Net changes in prices and production costs related to future production
|
|
(81,456
|
)
|
|
(621,065
|
)
|
|
75,284
|
|
|||
Extensions, discoveries and improved recovery, net of future production and development costs
|
|
86,606
|
|
|
165,020
|
|
|
209,651
|
|
|||
Previously estimated development costs incurred during the period
|
|
28,909
|
|
|
7,084
|
|
|
12,162
|
|
|||
Revisions of estimated future development costs
|
|
—
|
|
|
669
|
|
|
7,854
|
|
|||
Revisions of previous quantity estimates, net of related costs
|
|
147,507
|
|
|
(67,911
|
)
|
|
(110,431
|
)
|
|||
Accretion of discount
|
|
55,662
|
|
|
114,309
|
|
|
118,526
|
|
|||
Purchases of reserves in place, less related costs
|
|
34,751
|
|
|
584
|
|
|
24,210
|
|
|||
Other
|
|
(13,582
|
)
|
|
35,394
|
|
|
12,564
|
|
|||
Net increase (decrease) in standardized measures
|
|
48,043
|
|
|
(588,122
|
)
|
|
(42,163
|
)
|
|||
Standardized measure, end of year
|
|
$
|
603,015
|
|
|
$
|
554,972
|
|
|
$
|
1,143,094
|
|
|
|
First Quarter
|
|
Second Quarter
|
|
Third Quarter
|
|
Fourth Quarter
2
|
||||||||
|
|
(In thousands, except for per unit data)
|
||||||||||||||
2016
|
|
|
|
|
|
|
|
|
||||||||
Total revenue
|
|
$
|
64,381
|
|
|
$
|
40,569
|
|
|
$
|
99,171
|
|
|
$
|
56,712
|
|
Income (loss) from operations
|
|
11,610
|
|
|
(19,478
|
)
|
|
39,316
|
|
|
(3,979
|
)
|
||||
Net income (loss)
|
|
10,749
|
|
|
(20,810
|
)
|
|
37,535
|
|
|
(7,286
|
)
|
||||
Net income (loss) attributable to the general partner and common and subordinated units
|
|
8,943
|
|
|
(22,111
|
)
|
|
36,219
|
|
|
(8,614
|
)
|
||||
Net income (loss) attributable to common and subordinated units per unit (basic)
1
|
|
|
|
|
|
|
|
|
|
|||||||
Per common unit (basic)
|
|
.09
|
|
|
(0.08
|
)
|
|
0.24
|
|
|
0.01
|
|
||||
Per subordinated unit (basic)
|
|
.01
|
|
|
(0.15
|
)
|
|
0.14
|
|
|
(0.11
|
)
|
||||
Net income (loss) attributable to common and subordinated units per unit (diluted)
1
|
|
|
|
|
|
|
|
|
|
|||||||
Per common unit (diluted)
|
|
.09
|
|
|
(0.08
|
)
|
|
0.24
|
|
|
0.01
|
|
||||
Per subordinated unit (diluted)
|
|
.01
|
|
|
(0.15
|
)
|
|
0.14
|
|
|
(0.11
|
)
|
||||
Cash distributions declared and paid per limited partner unit
|
|
|
|
|
|
|
|
|
|
|
||||||
Per common unit
|
|
0.2625
|
|
|
0.2625
|
|
|
0.2875
|
|
|
0.2875
|
|
||||
Per subordinated unit
|
|
0.1838
|
|
|
0.1838
|
|
|
0.1838
|
|
|
0.1838
|
|
||||
Total assets
|
|
$
|
1,045,843
|
|
|
$
|
1,126,830
|
|
|
$
|
1,137,232
|
|
|
$
|
1,128,827
|
|
Long-term debt
|
|
116,000
|
|
|
285,000
|
|
|
299,000
|
|
|
316,000
|
|
||||
Total mezzanine equity
|
|
54,001
|
|
|
54,001
|
|
|
54,015
|
|
|
54,015
|
|
||||
2015
|
|
|
|
|
|
|
|
|
||||||||
Total revenue
|
|
$
|
91,061
|
|
|
$
|
64,803
|
|
|
$
|
137,020
|
|
|
$
|
100,040
|
|
Net income (loss)
|
|
17,299
|
|
|
(122,766
|
)
|
|
53,892
|
|
|
(49,730
|
)
|
||||
Net income (loss) attributable to the general partner and common and subordinated units
|
|
*
|
|
(107,587
|
)
|
|
50,916
|
|
|
(51,346
|
)
|
|||||
Net income (loss) attributable to common and subordinated units per unit (basic)
1
|
|
|
|
|
|
|
|
|
||||||||
Per common unit (basic)
|
|
*
|
|
(0.56
|
)
|
|
0.27
|
|
|
(0.27
|
)
|
|||||
Per subordinated unit (basic)
|
|
*
|
|
(0.56
|
)
|
|
0.27
|
|
|
(0.27
|
)
|
|||||
Net income (loss) attributable to common and subordinated units per unit (diluted)
1
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Per common unit (diluted)
|
|
*
|
|
(0.56
|
)
|
|
0.27
|
|
|
(0.27
|
)
|
|||||
Per subordinated unit (diluted)
|
|
*
|
|
(0.56
|
)
|
|
0.27
|
|
|
(0.27
|
)
|
|||||
Cash distributions declared per limited partner unit
|
|
|
|
|
|
|
|
|
||||||||
Per common unit
|
|
*
|
|
*
|
|
0.1615
|
|
|
0.2625
|
|
||||||
Per subordinated unit
|
|
*
|
|
*
|
|
0.1615
|
|
|
0.2625
|
|
||||||
Total assets
|
|
$
|
1,274,291
|
|
|
$
|
1,118,569
|
|
|
$
|
1,161,446
|
|
|
$
|
1,061,436
|
|
Long-term debt
|
|
389,000
|
|
|
6,000
|
|
|
43,000
|
|
|
66,000
|
|
||||
Total mezzanine equity
|
|
120,889
|
|
|
120,904
|
|
|
120,936
|
|
|
79,162
|
|
1 Year Black Stone Minerals Chart |
1 Month Black Stone Minerals Chart |
It looks like you are not logged in. Click the button below to log in and keep track of your recent history.
Support: +44 (0) 203 8794 460 | support@advfn.com
By accessing the services available at ADVFN you are agreeing to be bound by ADVFN's Terms & Conditions