Item 1. Financial Statements
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands)
|
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
June 30, 2017
|
|
December 31, 2016
|
ASSETS
|
|
|
|
|
|
|
CURRENT ASSETS
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
7,487
|
|
|
$
|
9,772
|
|
Accounts receivable
|
|
72,255
|
|
|
68,181
|
|
Commodity derivative assets
|
|
13,329
|
|
|
—
|
|
Prepaid expenses and other current assets
|
|
1,765
|
|
|
1,036
|
|
TOTAL CURRENT ASSETS
|
|
94,836
|
|
|
78,989
|
|
PROPERTY AND EQUIPMENT
|
|
|
|
|
|
|
Oil and natural gas properties, at cost, using the successful efforts method of accounting, includes unproved properties of $730,435 and $605,736 at June 30, 2017 and December 31, 2016, respectively
|
|
2,850,183
|
|
|
2,697,073
|
|
Accumulated depreciation, depletion, amortization, and impairment
|
|
(1,707,534
|
)
|
|
(1,652,930
|
)
|
Oil and natural gas properties, net
|
|
1,142,649
|
|
|
1,044,143
|
|
Other property and equipment, net of accumulated depreciation of
$14,341
and $14,327 at June 30, 2017 and December 31, 2016, respectively
|
|
542
|
|
|
528
|
|
NET PROPERTY AND EQUIPMENT
|
|
1,143,191
|
|
|
1,044,671
|
|
Deferred charges and other long-term assets
|
|
12,059
|
|
|
5,167
|
|
TOTAL ASSETS
|
|
$
|
1,250,086
|
|
|
$
|
1,128,827
|
|
LIABILITIES, MEZZANINE EQUITY AND EQUITY
|
|
|
|
|
|
|
CURRENT LIABILITIES
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
3,533
|
|
|
$
|
4,142
|
|
Accrued liabilities
|
|
39,541
|
|
|
50,952
|
|
Commodity derivative liabilities
|
|
—
|
|
|
16,237
|
|
Other current liabilities
|
|
203
|
|
|
—
|
|
TOTAL CURRENT LIABILITIES
|
|
43,277
|
|
|
71,331
|
|
LONG-TERM LIABILITIES
|
|
|
|
|
|
|
Credit facility
|
|
393,000
|
|
|
316,000
|
|
Accrued incentive compensation
|
|
2,295
|
|
|
1,485
|
|
Commodity derivative liabilities
|
|
—
|
|
|
482
|
|
Deferred revenue
|
|
—
|
|
|
518
|
|
Asset retirement obligations
|
|
13,627
|
|
|
13,350
|
|
TOTAL LIABILITIES
|
|
452,199
|
|
|
403,166
|
|
COMMITMENTS AND CONTINGENCIES (Note 8)
|
|
|
|
|
|
|
MEZZANINE EQUITY
|
|
|
|
|
|
|
Partners' equity - convertible redeemable preferred units, 26 and 53 units outstanding at June 30, 2017 and December 31, 2016, respectively
|
|
27,085
|
|
|
54,015
|
|
EQUITY
|
|
|
|
|
|
|
Partners' equity - general partner interest
|
|
—
|
|
|
—
|
|
Partners' equity - common units, 100,559 and 95,721 units outstanding at June 30, 2017 and December 31, 2016, respectively
|
|
573,817
|
|
|
489,023
|
|
Partners' equity - subordinated units, 95,388 and 95,164 units outstanding at June 30, 2017 and December 31, 2016, respectively
|
|
196,037
|
|
|
181,602
|
|
Noncontrolling interests
|
|
948
|
|
|
1,021
|
|
TOTAL EQUITY
|
|
770,802
|
|
|
671,646
|
|
TOTAL LIABILITIES, MEZZANINE EQUITY AND EQUITY
|
|
$
|
1,250,086
|
|
|
$
|
1,128,827
|
|
The accompanying notes are an integral part of these consolidated financial statements.
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(In thousands, except per unit amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
|
June 30,
|
|
June 30,
|
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
REVENUE
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate sales
|
|
$
|
37,262
|
|
|
$
|
34,553
|
|
|
$
|
77,736
|
|
|
$
|
61,801
|
|
Natural gas and natural gas liquids sales
|
|
49,903
|
|
|
21,607
|
|
|
97,604
|
|
|
46,719
|
|
Gain (loss) on commodity derivative instruments
|
|
22,003
|
|
|
(30,733
|
)
|
|
44,728
|
|
|
(20,107
|
)
|
Lease bonus and other income
|
|
11,356
|
|
|
15,142
|
|
|
25,038
|
|
|
16,537
|
|
TOTAL REVENUE
|
|
120,524
|
|
|
40,569
|
|
|
245,106
|
|
|
104,950
|
|
OPERATING (INCOME) EXPENSE
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense
|
|
4,148
|
|
|
4,283
|
|
|
8,337
|
|
|
9,172
|
|
Production costs and ad valorem taxes
|
|
11,863
|
|
|
7,012
|
|
|
23,765
|
|
|
14,074
|
|
Exploration expense
|
|
46
|
|
|
629
|
|
|
608
|
|
|
637
|
|
Depreciation, depletion, and amortization
|
|
28,900
|
|
|
29,202
|
|
|
55,279
|
|
|
50,923
|
|
Impairment of oil and natural gas properties
|
|
—
|
|
|
679
|
|
|
—
|
|
|
6,775
|
|
General and administrative
|
|
17,481
|
|
|
18,134
|
|
|
34,693
|
|
|
35,535
|
|
Accretion of asset retirement obligations
|
|
253
|
|
|
200
|
|
|
500
|
|
|
474
|
|
(Gain) loss on sale of assets, net
|
|
(7
|
)
|
|
(92
|
)
|
|
(931
|
)
|
|
(4,772
|
)
|
TOTAL OPERATING EXPENSE
|
|
62,684
|
|
|
60,047
|
|
|
122,251
|
|
|
112,818
|
|
INCOME (LOSS) FROM OPERATIONS
|
|
57,840
|
|
|
(19,478
|
)
|
|
122,855
|
|
|
(7,868
|
)
|
OTHER INCOME (EXPENSE)
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest and investment income
|
|
33
|
|
|
38
|
|
|
39
|
|
|
191
|
|
Interest expense
|
|
(3,981
|
)
|
|
(1,443
|
)
|
|
(7,488
|
)
|
|
(2,491
|
)
|
Other income (expense)
|
|
282
|
|
|
73
|
|
|
351
|
|
|
107
|
|
TOTAL OTHER EXPENSE
|
|
(3,666
|
)
|
|
(1,332
|
)
|
|
(7,098
|
)
|
|
(2,193
|
)
|
NET INCOME (LOSS)
|
|
54,174
|
|
|
(20,810
|
)
|
|
115,757
|
|
|
(10,061
|
)
|
NET (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS
|
|
16
|
|
|
9
|
|
|
7
|
|
|
7
|
|
DISTRIBUTIONS ON REDEEMABLE PREFERRED UNITS
|
|
(672
|
)
|
|
(1,310
|
)
|
|
(1,786
|
)
|
|
(3,114
|
)
|
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS
|
|
$
|
53,518
|
|
|
$
|
(22,111
|
)
|
|
$
|
113,978
|
|
|
$
|
(13,168
|
)
|
ALLOCATION OF NET INCOME (LOSS):
|
|
|
|
|
|
|
|
|
|
|
|
|
General partner interest
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Common units
|
|
32,100
|
|
|
(7,445
|
)
|
|
67,617
|
|
|
862
|
|
Subordinated units
|
|
21,418
|
|
|
(14,666
|
)
|
|
46,361
|
|
|
(14,030
|
)
|
|
|
$
|
53,518
|
|
|
$
|
(22,111
|
)
|
|
$
|
113,978
|
|
|
$
|
(13,168
|
)
|
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:
|
|
|
|
|
|
|
|
|
|
|
|
|
Per common unit (basic)
|
|
$
|
0.33
|
|
|
$
|
(0.08
|
)
|
|
$
|
0.69
|
|
|
$
|
0.01
|
|
Weighted average common units outstanding (basic)
|
|
97,990
|
|
|
96,356
|
|
|
97,448
|
|
|
96,418
|
|
Per subordinated unit (basic)
|
|
$
|
0.22
|
|
|
$
|
(0.15
|
)
|
|
$
|
0.49
|
|
|
$
|
(0.15
|
)
|
Weighted average subordinated units outstanding (basic)
|
|
95,388
|
|
|
95,189
|
|
|
95,269
|
|
|
95,092
|
|
Per common unit (diluted)
|
|
$
|
0.33
|
|
|
$
|
(0.08
|
)
|
|
$
|
0.69
|
|
|
$
|
0.01
|
|
Weighted average common units outstanding (diluted)
|
|
97,990
|
|
|
96,418
|
|
|
97,448
|
|
|
96,481
|
|
Per subordinated unit (diluted)
|
|
$
|
0.22
|
|
|
$
|
(0.15
|
)
|
|
$
|
0.49
|
|
|
$
|
(0.15
|
)
|
Weighted average subordinated units outstanding (diluted)
|
|
95,388
|
|
|
95,092
|
|
|
95,269
|
|
|
95,092
|
|
DISTRIBUTIONS DECLARED AND PAID:
|
|
|
|
|
|
|
|
|
|
|
|
|
Per common unit
|
|
$
|
0.2875
|
|
|
$
|
0.2625
|
|
|
$
|
0.5750
|
|
|
$
|
0.5250
|
|
Per subordinated unit
|
|
$
|
0.1838
|
|
|
$
|
0.1838
|
|
|
$
|
0.3675
|
|
|
$
|
0.3675
|
|
The accompanying notes are an integral part of these consolidated financial statements.
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF EQUITY
(Unaudited)
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
units
|
|
Subordinated
units
|
|
Partners'
equity—
common
units
|
|
Partners'
equity—
subordinated
units
|
|
Noncontrolling
interests
|
|
Total
equity
|
BALANCE AT DECEMBER 31, 2016
|
|
95,721
|
|
|
95,164
|
|
|
$
|
489,023
|
|
|
$
|
181,602
|
|
|
$
|
1,021
|
|
|
$
|
671,646
|
|
Restricted units granted, net of forfeitures
|
|
1,565
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Equity-based compensation
|
|
—
|
|
|
—
|
|
|
21,045
|
|
|
(379
|
)
|
|
—
|
|
|
20,666
|
|
Conversion of redeemable preferred units
|
|
201
|
|
|
263
|
|
|
2,868
|
|
|
3,756
|
|
|
—
|
|
|
6,624
|
|
Repurchases of common and subordinated units
|
|
(427
|
)
|
|
(39
|
)
|
|
(7,553
|
)
|
|
(292
|
)
|
|
—
|
|
|
(7,845
|
)
|
Issuance of units for property acquisitions
|
|
3,434
|
|
|
—
|
|
|
56,447
|
|
|
—
|
|
|
—
|
|
|
56,447
|
|
Distributions
|
|
—
|
|
|
—
|
|
|
(56,008
|
)
|
|
(35,011
|
)
|
|
(66
|
)
|
|
(91,085
|
)
|
Charges to partners' equity for accrued distribution equivalent rights
|
|
—
|
|
|
—
|
|
|
(613
|
)
|
|
—
|
|
|
—
|
|
|
(613
|
)
|
Net income (loss)
|
|
—
|
|
|
—
|
|
|
68,520
|
|
|
47,244
|
|
|
(7
|
)
|
|
115,757
|
|
Issuance of common units, net of offering costs
|
|
65
|
|
|
—
|
|
|
991
|
|
|
—
|
|
|
—
|
|
|
991
|
|
Distributions on redeemable preferred units
|
|
—
|
|
|
—
|
|
|
(903
|
)
|
|
(883
|
)
|
|
—
|
|
|
(1,786
|
)
|
BALANCE AT JUNE 30, 2017
|
|
100,559
|
|
|
95,388
|
|
|
$
|
573,817
|
|
|
$
|
196,037
|
|
|
$
|
948
|
|
|
$
|
770,802
|
|
The accompanying notes are an integral part of these consolidated financial statements.
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
June 30,
|
|
|
2017
|
|
2016
|
CASH FLOWS FROM OPERATING ACTIVITIES
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
115,757
|
|
|
$
|
(10,061
|
)
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
|
|
Depreciation, depletion, and amortization
|
|
55,279
|
|
|
50,923
|
|
Impairment of oil and natural gas properties
|
|
—
|
|
|
6,775
|
|
Accretion of asset retirement obligations
|
|
500
|
|
|
474
|
|
Amortization of deferred charges
|
|
436
|
|
|
394
|
|
(Gain) loss on commodity derivative instruments
|
|
(44,728
|
)
|
|
20,107
|
|
Net cash received on settlement of commodity derivative instruments
|
|
7,359
|
|
|
33,918
|
|
Equity-based compensation
|
|
10,939
|
|
|
25,139
|
|
(Gain) loss on sale of assets, net
|
|
(931
|
)
|
|
(4,772
|
)
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
Accounts receivable
|
|
(4,318
|
)
|
|
(6,585
|
)
|
Prepaid expenses and other current assets
|
|
(729
|
)
|
|
(1,003
|
)
|
Accounts payable and accrued liabilities
|
|
658
|
|
|
(31,859
|
)
|
Deferred revenue
|
|
(969
|
)
|
|
221
|
|
Settlement of asset retirement obligations
|
|
(89
|
)
|
|
(127
|
)
|
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES
|
|
139,164
|
|
|
83,544
|
|
CASH FLOWS FROM INVESTING ACTIVITIES
|
|
|
|
|
|
|
Acquisitions of oil and natural gas properties
|
|
(66,501
|
)
|
|
(136,340
|
)
|
Additions to oil and natural gas properties
|
|
(33,903
|
)
|
|
(36,710
|
)
|
Purchase of other property and equipment
|
|
(96
|
)
|
|
(5
|
)
|
Proceeds from the sale of oil and natural gas properties
|
|
2,133
|
|
|
177
|
|
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES
|
|
(98,367
|
)
|
|
(172,878
|
)
|
CASH FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
|
|
|
Borrowings under senior line of credit
|
|
159,500
|
|
|
230,000
|
|
Repayments of borrowings under senior line of credit
|
|
(82,500
|
)
|
|
(11,000
|
)
|
Distributions to Black Stone Minerals, L.P. common and subordinated unitholders
|
|
(91,019
|
)
|
|
(85,866
|
)
|
Distributions to redeemable preferred unitholders
|
|
(2,452
|
)
|
|
(3,751
|
)
|
Distributions to non-controlling interests
|
|
(66
|
)
|
|
(54
|
)
|
Proceeds from issuance of common units
|
|
991
|
|
|
—
|
|
Payments for capitalized offering costs
|
|
—
|
|
|
(301
|
)
|
Redemptions of redeemable preferred units
|
|
(19,641
|
)
|
|
(18,461
|
)
|
Loan origination fees
|
|
(50
|
)
|
|
—
|
|
Repurchases of common and subordinated units
|
|
(7,845
|
)
|
|
(24,696
|
)
|
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES
|
|
(43,082
|
)
|
|
85,871
|
|
NET CHANGE IN CASH AND CASH EQUIVALENTS
|
|
(2,285
|
)
|
|
(3,463
|
)
|
CASH AND CASH EQUIVALENTS - beginning of the period
|
|
9,772
|
|
|
13,233
|
|
CASH AND CASH EQUIVALENTS - end of the period
|
|
$
|
7,487
|
|
|
$
|
9,770
|
|
SUPPLEMENTAL DISCLOSURE
|
|
|
|
|
Interest paid
|
|
$
|
7,062
|
|
|
$
|
1,928
|
|
The accompanying notes are an integral part of these consolidated financial statements.
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1—BUSINESS AND BASIS OF PRESENTATION
Description of the business
: Black Stone Minerals, L.P. (“BSM” or the “Partnership”) is a publicly traded Delaware limited partnership formed on September 16, 2014. On May 6, 2015, BSM completed its initial public offering (the “IPO”) of
22,500,000
common units representing limited partner interests at a price to the public of
$19.00
per common unit. BSM received proceeds of
$391.5 million
from the sale of its common units, net of underwriting discount, structuring fee, and offering expenses (including costs previously incurred and capitalized). BSM used the net proceeds from the IPO to repay substantially all indebtedness outstanding under its credit facility. On May 1, 2015, BSM’s common units began trading on the New York Stock Exchange under the symbol “BSM.”
Black Stone Minerals Company, L.P., a Delaware limited partnership, and its subsidiaries (collectively referred to as “BSMC” or the “Predecessor”) own oil and natural gas mineral interests in the United States. In connection with the IPO, BSMC was merged into a wholly owned subsidiary of BSM, with BSMC as the surviving entity. Pursuant to the merger, the Class A and Class B common units representing limited partner interests of the Predecessor were converted into an aggregate of
72,574,715
common units and
95,057,312
subordinated units of BSM at a conversion ratio of
12.9465
:1 for
0.4329
common units and
0.5671
subordinated units, and the preferred units of BSMC were converted into an aggregate of
117,963
preferred units of BSM at a conversion ratio of
one
to one. The merger was accounted for as a combination of entities under common control with assets and liabilities transferred at their carrying amounts in a manner similar to a pooling of interests. Unless otherwise stated or the context otherwise indicates, all references to the “Partnership” or similar expressions for time periods prior to the IPO refer to Black Stone Minerals Company, L.P. and its subsidiaries, the Predecessor, for accounting purposes. For time periods subsequent to the IPO, these terms refer to Black Stone Minerals, L.P. and its subsidiaries.
In addition to mineral interests, which make up the vast majority of the asset base, the Partnership’s assets also include nonparticipating and overriding royalty interests. These interests, which are non-cost-bearing, are collectively referred to as “mineral and royalty interests.” As of
June 30, 2017
, the Partnership’s mineral and royalty interests were located in
41
states and
64
onshore oil and natural gas producing basins of the continental United States, including all of the major onshore producing basins. The Partnership also owns non-operated working interests in certain oil and natural gas properties.
Basis of presentation
: The accompanying unaudited interim consolidated financial statements of the Partnership have been prepared in accordance with generally accepted accounting principles (“GAAP”) in the United States and pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). These unaudited interim consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q and, therefore, do not include all disclosures required for financial statements prepared in conformity with U.S. GAAP. Accordingly, the accompanying unaudited interim consolidated financial statements and related notes should be read in conjunction with the Partnership’s consolidated financial statements included in the Partnership’s 2016 Annual Report on Form 10-K. The financial statements include the consolidated results of the Partnership. All intercompany balances and transactions have been eliminated.
Certain reclassifications have been made to the prior periods presented to conform to the current period financial statement presentation. The reclassifications have no effect on the consolidated financial position, results of operations, or cash flows of the Partnership.
In the opinion of management, all material adjustments, which are of a normal and recurring nature, necessary for a fair presentation of the results for the periods presented have been reflected. The results of operations for the
six months ended June 30, 2017
are not necessarily indicative of the results to be expected for the full year.
The Partnership evaluates the significant terms of its investments to determine the method of accounting to be applied to each respective investment. Investments in which the Partnership has less than a
20%
ownership interest and does not have control or exercise significant influence are accounted for under the cost method. The Partnership’s cost method investment is included in deferred charges and other long-term assets in the consolidated balance sheets. Investments in which the Partnership exercises control are consolidated, and the noncontrolling interests of such investments, which are not attributable directly or indirectly to the Partnership, are presented as a separate component of net income and equity in the accompanying consolidated financial statements.
The consolidated financial statements include undivided interests in oil and natural gas property rights. The Partnership accounts for its share of oil and natural gas property rights by reporting its proportionate share of assets, liabilities, revenues, costs, and cash flows within the relevant lines on the accompanying consolidated balance sheets, statements of operations, and statements of cash flows.
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Segment reporting
: The Partnership operates in a single operating and reportable segment. Operating segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assess performance. The Partnership’s chief executive officer has been determined to be the chief operating decision maker and allocates resources and assesses performance based upon financial information at the consolidated level.
NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Significant accounting policies:
Significant accounting policies are disclosed in the Partnership’s Annual Report on Form 10-K for the year ended
December 31, 2016
. There have been no changes in such policies or the application of such policies during the
six months ended June 30, 2017
.
New accounting pronouncements
: In May 2014, the Financial Accounting Standards Board (the “FASB”) issued an accounting standards update on a comprehensive new revenue recognition standard that will supersede Accounting Standards Codification (“ASC”) 605,
Revenue Recognition
. The new accounting guidance creates a framework under which an entity will allocate the transaction price to separate performance obligations and recognize revenue when each performance obligation is satisfied. Under the new standard, entities will be required to use judgment and make estimates, including identifying performance obligations in a contract, estimating the amount of variable consideration to include in the transaction price, allocating the transaction price to each separate performance obligation, and determining when an entity satisfies its performance obligations. The standard allows for either “full retrospective” adoption, meaning that the standard is applied to all of the periods presented with a cumulative catch-up adjustment as of the earliest period presented, or “modified retrospective” adoption, meaning the standard is applied only to the most current period presented in the financial statements with a cumulative catch-up as of the current period. In July 2015, the FASB decided to defer the original effective date by one year to be effective for annual reporting periods beginning after December 15, 2017 instead of December 15, 2016 for public entities, with early adoption permitted. The Partnership intends to use the modified retrospective adoption approach.
The Partnership has identified all of its revenue streams and based on current evaluations to-date, the Partnership does not anticipate this new guidance will have a material impact on its consolidated financial statements. The Partnership is continuing to evaluate the disclosure requirements of this new guidance and does not plan on early adopting this guidance
.
In February 2016, the FASB issued Accounting Standard Update (“ASU”) No. 2016-02,
Leases (Topic 842)
, which requires lessees to recognize the lease assets and lease liabilities classified as operating leases on the balance sheet. The amendment will be effective for reporting periods beginning on or after December 15, 2018, and early adoption is permitted. The Partnership will use the modified retrospective adoption approach. Based on current evaluations to-date, the Partnership does not anticipate this new guidance will have a material impact on its consolidated financial statements and will not early adopt.
In August 2016, the FASB issued ASU 2016-15,
Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments
,
to address diversity in practice of how certain cash receipts and cash payments are currently presented and classified in the statement of cash flows. The ASU addresses the topic of separately identifiable cash flows and application of the predominance principle. Classification of cash receipts and payments that have aspects of more than one class of cash flows should be determined first by applying specific guidance, and then by the nature of each separately identifiable cash flow. In situations where there is an absence of specific guidance and the cash flow has aspects of more than one type of classification, the predominance principle should be applied whereby the cash flow classification should depend on the activity that is likely to be the predominant source or use of cash flows. The amendments in this ASU are effective for public business entities for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. Early adoption is permitted; however the Partnership will not adopt this guidance early. The Partnership intends to use the retrospective transition method and is evaluating the impact that the new accounting guidance will have on its consolidated financial statements and related disclosure.
In January 2017, the FASB issued ASU No. 2017-01,
Business Combinations (Topic 805)
, which clarifies the definition of a business in order to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The FASB issued this ASU in response to stakeholder feedback that the current definition of a business in ASC 805 is being applied too broadly and the application of the guidance was not resulting in consistent application in a cost-effective manner. This ASU provides a screen whereby a transaction will be accounted for as an asset purchase (or disposal) if substantially all of the fair value of the gross assets acquired (disposed) is concentrated in a single identifiable asset or a group of similar identifiable assets. If the screen is not met, the entity will evaluate whether it is a business acquisition under revised criteria. The ASU is effective for public business entities in fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. Early adoption is permitted under certain circumstances; however the Partnership will not adopt this guidance early. The amendments in this ASU should be applied prospectively as of the
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
beginning of the period of adoption. The Partnership is evaluating the impact that the new accounting guidance will have on its consolidated financial statements and related disclosures.
In May 2017, the FASB issued ASU 2017-09
Compensation-Stock Compensation (Topic 718): Scope of Modification Accounting.
The update provides guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting under Topic 718. The amendments require an entity to account for the effects of a modification unless all of the following conditions are met:
-The fair value (or intrinsic or calculated value if elected) of the modified award is the same as the value of the original award immediately before the original award was modified.
-The vesting conditions of the modified award are the same as the vesting conditions of the original award immediately before the original award is modified.
-The classification of the modified award as an equity instrument or a liability instrument is the same as the classification of the original award immediately before the original award is modified.
This ASU is effective for all entities for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted, including adoption in any interim period, for public business entities for reporting periods for which financial statements have not yet been issued. The Partnership is not planning to adopt this guidance early. The amendments in this ASU should be applied prospectively to an award modified on or after the adoption date. The Partnership is evaluating the impact that the new accounting guidance will have on its consolidated financial statements and related disclosure.
NOTE 3—ASSET RETIREMENT OBLIGATIONS
The asset retirement obligation (“ARO”) liability reflects the present value of estimated costs of dismantlement, removal, site reclamation, and similar activities associated with the Partnership’s working-interest oil and natural gas properties. The Partnership utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. The Partnership estimates the ultimate productive life of its properties, a credit-adjusted risk-free rate, and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and natural gas property balance. The following table describes changes to the Partnership’s ARO liability during the period:
|
|
|
|
|
|
For the six months ended
|
|
June 30, 2017
|
|
(In thousands)
|
Beginning asset retirement obligations
|
$
|
13,350
|
|
Liabilities incurred
|
74
|
|
Liabilities settled
|
(89
|
)
|
Accretion expense
|
500
|
|
Dispositions
|
(5
|
)
|
Revisions
|
—
|
|
Ending asset retirement obligations
|
$
|
13,830
|
|
Current asset retirement obligation
|
$
|
203
|
|
Non-current asset retirement obligation
|
$
|
13,627
|
|
NOTE 4—ACQUISITIONS AND DISPOSITIONS
Acquisitions of proved oil and natural gas properties and working interests are considered business combinations and are recorded at their estimated fair value as of the acquisition date. Acquisitions of unproved oil and natural gas properties are considered asset acquisitions and are recorded at cost.
2017 Acquisitions and Dispositions
During the second quarter of 2017, the Partnership executed the following transactions:
In June 2017, the Partnership closed a series of related mineral and royalty interests acquisitions, on properties previously owned by Angelina County Lumber Company and various other sellers, in
twelve
Texas counties, primarily Angelina and Nacogdoches counties. Consideration consisted of approximately
$4.8 million
in cash and
$45.7 million
of the Partnership’s common units, of which
$1.4 million
of the common units were recorded as a liability on the June 30, 2017
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
balance sheet due to delays in processing the units by the Partnership's transfer agent. Acquisition-related costs of
$1.0 million
were expensed and included in the general and administrative line item of the 2017 consolidated statement of operations.
|
|
|
|
|
|
(In thousands)
|
Proved oil and natural gas properties
|
$
|
5,006
|
|
Unproved oil and natural gas properties
|
45,477
|
|
Total fair value
|
$
|
50,483
|
|
The Partnership acquired additional mineral and royalty interests in Angelina County, Texas for
$12.3 million
in cash and San Augustine County Texas for
$1.0 million
in cash.
During the first quarter of 2017, the Partnership executed the following transactions:
On January 4, 2017, the Partnership acquired mineral and royalty interests in Loving County, Texas for approximately
$22.3 million
in cash.
|
|
|
|
|
|
(In thousands)
|
Proved oil and natural gas properties
|
$
|
3,331
|
|
Unproved oil and natural gas properties
|
18,802
|
|
Net working capital
|
204
|
|
Total fair value
|
$
|
22,337
|
|
On January 10, 2017, the Partnership acquired mineral and royalty interests in Loving and Winkler counties of Texas for approximately
$5.0 million
in cash and
$12.0 million
of the Partnership’s common units. In addition, acquisition related costs of
$1.2 million
were expensed and included in the general and administrative line item of the 2017 consolidated statement of operations.
|
|
|
|
|
|
(In thousands)
|
Proved oil and natural gas properties
|
$
|
1,804
|
|
Unproved oil and natural gas properties
|
15,206
|
|
Net working capital
|
59
|
|
Total fair value
|
$
|
17,069
|
|
In addition, several mineral and royalty interest acquisitions were closed in Angelina County, Texas for an aggregate amount of approximately
$16.6 million
in cash and
$0.2 million
of the Partnership’s common units. There were
two
additional mineral and royalty interest acquisitions in Loving and Winkler Counties in Texas for approximately
$3.4 million
in cash.
One
additional royalty interest purchase closed in San Augustine County, Texas for approximately
$1.0 million
. The cash portion of all acquisitions in the first half of 2017 was funded via borrowings under the Partnership's credit facility.
On February 21, 2017, the Partnership announced that it had entered into a farmout agreement with Canaan Resource Partners ("Canaan") which covers certain Haynesville and Bossier shale acreage in San Augustine County, Texas operated by XTO Energy Inc. The Partnership has an approximate
50%
working interest in the acreage and is the largest mineral owner. A total of
18
wells are anticipated to be drilled over an initial phase, beginning with wells spud after January 1, 2017. At its option, Canaan may participate in
two
additional phases with each phase continuing for the lesser of
two years
or until an additional
20
wells have been drilled. During the
three
phases of the agreement, Canaan will commit on a phase-by-phase basis and fund
80%
of the Partnership's drilling and completion costs and will be assigned
80%
of the Partnership's working interests in such wells (
40%
working interest on an 8/8ths basis). After the third phase, Canaan can earn
40%
of the Partnership’s working interest (
20%
working interest on an 8/8ths basis) in additional wells drilled in the area by continuing to fund
40%
of the Partnership's costs for those wells on a well-by-well basis. The Partnership will receive an overriding royalty interest (“ORRI”) before payout and an increased ORRI after payout on all wells drilled under the agreement. The execution of this agreement is anticipated to reduce the Partnership's future capital expenditures by approximately
$30
-
$35 million
in 2017 and
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
by an average of
$40
-
$50 million
annually, thereafter.
2016 Acquisitions
On January 8, 2016, the Partnership acquired mineral and royalty interests in the Permian Basin for
$10.0 million
in cash.
On June 15, 2016, the Partnership acquired an oil and natural gas mineral asset package primarily located in Weld County, Colorado for
$34.0 million
in cash. The following table summarizes the fair values assigned to the properties acquired:
|
|
|
|
|
|
(In thousands)
|
Proved oil and natural gas properties
|
$
|
18,948
|
|
Unproved oil and natural gas properties
|
14,082
|
|
Net working capital
|
1,038
|
|
Asset retirement obligations
|
(50
|
)
|
Total fair value
|
$
|
34,018
|
|
On June 17, 2016, the Partnership acquired a diverse oil and natural gas mineral package from Freeport-McMoRan Oil and Gas, Inc. for
$87.6 million
in cash. The following table summarizes the fair values assigned to the properties acquired:
|
|
|
|
|
|
(In thousands)
|
Proved oil and natural gas properties
|
$
|
20,787
|
|
Unproved oil and natural gas properties
|
65,745
|
|
Net working capital
|
1,026
|
|
Total fair value
|
$
|
87,558
|
|
The cash portion of all 2016 acquisition transactions was funded via borrowings under the Partnership's credit facility.
NOTE 5—DERIVATIVES AND FINANCIAL INSTRUMENTS
The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To mitigate the inherent commodity price risk associated with its operations, the Partnership uses oil and natural gas derivative instruments. From time to time, such instruments may include fixed-price-swap contracts, fixed price contracts, costless collars, and other contractual arrangements. The Partnership enters into oil and natural gas derivative contracts that contain netting arrangements with each counterparty. The Partnership does not enter into derivative instruments for speculative purposes.
As of
June 30, 2017
, the Partnership’s open derivative contracts consisted of only fixed-price-swap contracts. A fixed-price-swap contract between the Partnership and the counterparty specifies a fixed commodity price and a future settlement date. The Partnership has not designated any of its contracts as fair value or cash flow hedges. Accordingly, any changes in the fair value of the contracts are included in the consolidated statement of operations in the period of the change. All derivative gains and losses from the Partnership’s derivative contracts have been recognized in “Revenue” in the Partnership's accompanying consolidated statements of operations. Derivative instruments that have not yet been settled in cash are reflected as either derivative assets or liabilities in the Partnership’s accompanying consolidated balance sheets as of
June 30, 2017
and
December 31, 2016
. See Note 6 – Fair Value Measurement for further discussion.
The Partnership's derivative contracts expose it to credit risk in the event of nonperformance by counterparties. While the Partnership does not require its derivative contract counterparties to post collateral, the Partnership does evaluate the credit standing of such counterparties as deemed appropriate. This evaluation includes reviewing a counterparty’s credit rating and latest financial information. As of
June 30, 2017
, the Partnership had
nine
counterparties, all of which are rated Baa1 or better by Moody’s.
Seven
of the Partnership's counterparties are lenders under the Partnership's credit facility. The Partnership would have been at risk of losing a fair value amount of
$21.8 million
had the Partnership's counterparties as a group been unable to fulfill their obligations as of
June 30, 2017
.
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The table below summarizes the fair value and classification of the Partnership’s derivative instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of June 30, 2017
|
Classification
|
|
Balance Sheet Location
|
|
Gross Fair
Value
|
|
Effect of
Counterparty
Netting
|
|
Net Carrying
Value on
Balance Sheet
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
Current asset
|
|
Commodity derivative assets
|
|
$
|
14,434
|
|
|
$
|
(1,105
|
)
|
|
$
|
13,329
|
|
Long-term asset
|
|
Deferred charges and other
long-term assets
|
|
7,321
|
|
|
—
|
|
|
7,321
|
|
Total assets
|
|
|
|
$
|
21,755
|
|
|
$
|
(1,105
|
)
|
|
$
|
20,650
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
Current liability
|
|
Commodity derivative liabilities
|
|
$
|
1,105
|
|
|
$
|
(1,105
|
)
|
|
$
|
—
|
|
Long-term liability
|
|
Commodity derivative liabilities
|
|
—
|
|
|
—
|
|
|
—
|
|
Total liabilities
|
|
|
|
$
|
1,105
|
|
|
$
|
(1,105
|
)
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2016
|
Classification
|
|
Balance Sheet Location
|
|
Gross Fair
Value
|
|
Effect of
Counterparty
Netting
|
|
Net Carrying
Value on
Balance Sheet
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
Current asset
|
|
Commodity derivative assets
|
|
$
|
3,879
|
|
|
$
|
(3,879
|
)
|
|
$
|
—
|
|
Long-term asset
|
|
Deferred charges and other
long-term assets
|
|
—
|
|
|
—
|
|
|
—
|
|
Total assets
|
|
|
|
$
|
3,879
|
|
|
$
|
(3,879
|
)
|
|
$
|
—
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
Current liability
|
|
Commodity derivative liabilities
|
|
$
|
20,116
|
|
|
$
|
(3,879
|
)
|
|
$
|
16,237
|
|
Long-term liability
|
|
Commodity derivative liabilities
|
|
482
|
|
|
—
|
|
|
482
|
|
Total liabilities
|
|
|
|
$
|
20,598
|
|
|
$
|
(3,879
|
)
|
|
$
|
16,719
|
|
Changes in the fair values of the Partnership’s derivative instruments (both assets and liabilities) are presented on a net basis in the accompanying consolidated statements of operations. Changes in the fair value of the Partnership’s commodity derivative instruments (both assets and liabilities) are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
For the Six Months Ended June 30,
|
Derivatives not designated as hedging instruments
|
|
2017
|
|
2016
|
|
|
(In thousands)
|
Beginning fair value of commodity derivative instruments
|
|
$
|
(16,719
|
)
|
|
$
|
64,534
|
|
Gain (loss) on oil derivative instruments
|
|
27,799
|
|
|
(12,615
|
)
|
Gain (loss) on natural gas derivative instruments
|
|
16,929
|
|
|
(7,492
|
)
|
Net cash received on settlements of oil derivative
instruments
|
|
(6,656
|
)
|
|
(18,766
|
)
|
Net cash received on settlements of natural gas
derivative instruments
|
|
(703
|
)
|
|
(15,152
|
)
|
Net change in fair value of commodity derivative
instruments
|
|
37,369
|
|
|
(54,025
|
)
|
Ending fair value of commodity derivative instruments
|
|
$
|
20,650
|
|
|
$
|
10,509
|
|
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Partnership had the following open derivative contracts for oil as of
June 30, 2017
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Range (Per Bbl)
|
Period and Type of Contract
|
|
Volume
(Bbl)
|
|
Weighted Average
(Per Bbl)
|
|
Low
|
|
High
|
Oil Swap Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
2017
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter
|
|
195,000
|
|
|
$
|
54.19
|
|
|
$
|
51.86
|
|
|
$
|
55.23
|
|
Third Quarter
|
|
556,000
|
|
|
53.29
|
|
|
52.04
|
|
|
55.23
|
|
Fourth Quarter
|
|
516,000
|
|
|
53.56
|
|
|
52.57
|
|
|
55.23
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
475,000
|
|
|
$
|
54.74
|
|
|
$
|
54.50
|
|
|
$
|
55.05
|
|
Second Quarter
|
|
445,000
|
|
|
54.73
|
|
|
54.50
|
|
|
54.90
|
|
Third Quarter
|
|
425,000
|
|
|
54.72
|
|
|
54.50
|
|
|
54.90
|
|
Fourth Quarter
|
|
405,000
|
|
|
54.72
|
|
|
54.50
|
|
|
54.90
|
|
The Partnership had the following open derivative contracts for natural gas as of
June 30, 2017
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Range (Per MMBtu)
|
Period and Type of Contract
|
|
Volume
(MMBtu)
|
|
Weighted Average
(Per MMBtu)
|
|
Low
|
|
High
|
Natural Gas Swap Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
2017
|
|
|
|
|
|
|
|
|
|
|
|
|
Third Quarter
|
|
12,490,000
|
|
|
$
|
3.08
|
|
|
$
|
2.90
|
|
|
$
|
3.45
|
|
Fourth Quarter
|
|
11,280,000
|
|
|
3.14
|
|
|
2.92
|
|
|
3.57
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
9,870,000
|
|
|
$
|
3.05
|
|
|
$
|
2.96
|
|
|
$
|
3.45
|
|
Second Quarter
|
|
8,840,000
|
|
|
3.01
|
|
|
2.86
|
|
|
3.23
|
|
Third Quarter
|
|
7,730,000
|
|
|
3.00
|
|
|
2.90
|
|
|
3.23
|
|
Fourth Quarter
|
|
6,860,000
|
|
|
3.00
|
|
|
2.90
|
|
|
3.23
|
|
The Partnership has not entered into any additional derivative contracts for oil or natural gas subsequent to
June 30, 2017
.
NOTE 6—FAIR VALUE MEASUREMENT
Fair value is defined as the amount at which an asset (or liability) could be bought (or incurred) or sold (or settled) in an orderly transaction between market participants at the measurement date. Further, ASC 820 establishes a framework for measuring fair value, establishes a fair value hierarchy based on the quality of inputs used to measure fair value, and includes certain disclosure requirements. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk.
ASC 820 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:
Level 1
—Unadjusted quoted prices for identical assets or liabilities in active markets.
Level 2
—Quoted prices for similar assets or liabilities in non-active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term
of the financial instrument.
Level 3
—Inputs that are unobservable and significant to the fair value measurement (including the Partnership’s own assumptions in determining fair value).
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. There were
no
transfers into, or out of, the three levels of the fair value hierarchy for the
six months ended June 30, 2017
or the year ended
December 31, 2016
.
The carrying value of the Partnership's cash and cash equivalents, receivables, and payables approximate fair value due to the short-term nature of the instruments. The estimated carrying value of all debt as of
June 30, 2017
and
December 31, 2016
approximated the fair value due to variable market rates of interest. These debt fair values, which are Level 3 measurements, were estimated based on the Partnership’s incremental borrowing rates for similar types of borrowing arrangements, when quoted market prices were not available. The estimated fair values of the Partnership’s financial instruments are not necessarily indicative of the amounts that would be realized in a current market exchange.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
The Partnership estimated the fair value of derivative instruments using the market approach via a model that uses inputs that are observable in the market or can be derived from, or corroborated by, observable data. See Note 5 – Derivatives and Financial Instruments for further discussion.
The following table presents information about the Partnership’s assets and liabilities measured at fair value on a recurring basis:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using
|
|
Effect of
Counterparty
Netting
|
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
Total
|
|
|
(In thousands)
|
As of June 30, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative instruments
|
|
$
|
—
|
|
|
$
|
21,755
|
|
|
$
|
—
|
|
|
$
|
(1,105
|
)
|
|
$
|
20,650
|
|
Financial Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative instruments
|
|
$
|
—
|
|
|
$
|
1,105
|
|
|
$
|
—
|
|
|
$
|
(1,105
|
)
|
|
$
|
—
|
|
As of December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative instruments
|
|
$
|
—
|
|
|
$
|
3,879
|
|
|
$
|
—
|
|
|
$
|
(3,879
|
)
|
|
$
|
—
|
|
Financial Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative instruments
|
|
$
|
—
|
|
|
$
|
20,598
|
|
|
$
|
—
|
|
|
$
|
(3,879
|
)
|
|
$
|
16,719
|
|
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Nonfinancial assets and liabilities measured at fair value on a nonrecurring basis include certain nonfinancial assets and liabilities, as may be acquired in a business combination, and measurements of oil and natural gas property values for assessment of impairment.
The determination of the fair values of proved and unproved properties acquired in business combinations are estimated by discounting the projected cash flows. The factors used to determine fair value include estimates of economic reserves, future operating and development costs, future commodity prices, and a risk-adjusted discount rate. The Partnership has designated these measurements as Level 3. The Partnership’s fair value assessments for recent acquisitions are included in Note 4 – Acquisitions and Dispositions.
Oil and natural gas properties are measured at fair value on a nonrecurring basis using the income approach when assessing for impairment. Proved and unproved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of those properties. When assessing producing properties for impairment, the Partnership compares the expected undiscounted projected future cash flows of the producing properties to the carrying amount of the producing properties to determine recoverability. When the carrying amount exceeds its estimated undiscounted future cash flows, the carrying amount is written down to its fair value, which is measured as the present value of the projected future cash flows of such properties. The factors used to determine fair value include estimates of economic reserves, future operating and development costs, future commodity prices, and a risk-adjusted discount rate.
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Partnership’s estimates of fair value have been determined at discrete points in time based on relevant market data. These estimates involve uncertainty and cannot be determined with precision. There were no significant changes in valuation techniques or related inputs as of
June 30, 2017
or
December 31, 2016
.
The following table presents information about the Partnership’s assets measured at fair value on a nonrecurring basis:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using
|
|
Net Book
Value
1
|
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
Impairment
|
|
|
(In thousands)
|
Three months ended June 30, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impaired oil and natural gas properties
|
|
$
|
—
|
|
—
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Three months ended June 30, 2016
|
|
|
|
|
|
|
|
|
|
|
Impaired oil and natural gas properties
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
543
|
|
|
$
|
1,222
|
|
|
$
|
679
|
|
Six months ended June 30, 2017
|
|
|
|
|
|
|
|
|
|
|
Impaired oil and natural gas properties
|
|
$
|
—
|
|
—
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Six months ended June 30, 2016
|
|
|
|
|
|
|
|
|
|
|
Impaired oil and natural gas properties
|
|
$
|
—
|
|
—
|
|
$
|
—
|
|
|
$
|
3,042
|
|
|
$
|
9,817
|
|
|
$
|
6,775
|
|
1
Amount represents net book value at the date of assessment.
NOTE 7—CREDIT FACILITY
The Partnership maintains a senior secured revolving credit agreement, as amended (the “Senior Line of Credit”). The Senior Line of Credit has a maximum credit amount of
$1.0 billion
. On
October 28, 2015
, the Senior Line of Credit was amended to extend the term of the agreement from
February 3, 2017
to
February 4, 2019
. The amount of the borrowing base is derived from the value of the Partnership’s oil and natural gas properties as determined by the lender syndicate using pricing assumptions that often differ from the current market for future prices. Effective April 15, 2016, the borrowing base was
$450.0 million
. The Partnership's fall 2016 borrowing base redetermination process resulted in an increase in the borrowing base to
$500.0 million
, which became effective October 31, 2016. Effective April 25, 2017, the borrowing base redetermination resulted in an increase to
$550.0 million
. Drawings on the Senior Line of Credit are used for the acquisition of oil and natural gas properties and for other general business purposes.
Prior to October 31, 2016, borrowings under the Senior Line of Credit bore interest at LIBOR plus a margin between
1.50%
and
2.50%
, or the Prime rate plus a margin between
0.50%
and
1.50%
, with the margin depending on the borrowing base utilization percentage. The prime rate was determined to be the higher of the financial institution’s prime rate or the federal funds effective rate plus
0.50%
per annum.
Effective October 31, 2016, borrowings under the Senior Line of Credit bore interest at LIBOR plus a margin between
2.00%
and
3.00%
, or the Prime rate plus a margin between
1.00%
and
2.00%
, with the margin depending on the borrowing base utilization.
The weighted-average interest rate of the Senior Line of Credit was
3.73%
and
3.26%
as of
June 30, 2017
and
December 31, 2016
, respectively. Accrued interest is payable at the end of each calendar quarter or at the end of each interest period, unless the interest period is longer than
90 days
, in which case interest is payable at the end of every
90
-day period. In addition, a commitment fee is payable at the end of each calendar quarter based on either a rate of
0.375%
if the borrowing base utilization percentage is less than
50%
, or
0.500%
per annum if the borrowing base utilization percentage is equal to or greater than
50%
. The Senior Line of Credit is secured by substantially all of the Partnership’s producing oil and natural gas assets.
The Senior Line of Credit contains various limitations on future borrowings, leases, hedging, and sales of assets. Additionally, the Senior Line of Credit requires the Partnership to maintain a current ratio of not less than
1.0
:1.0 and a ratio of total debt to EBITDAX (Earnings before Interest, Taxes, Depreciation, Amortization, and Exploration) of not more than
3.5
:1.0. As of
June 30, 2017
, the Partnership was in compliance with all financial covenants for the Senior Line of Credit.
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The aggregate principal balance outstanding was
$393.0 million
and
$316.0 million
at
June 30, 2017
and
December 31, 2016
, respectively. The unused portion of the available borrowings under the Senior Line of Credit was
$157.0 million
and
$184.0 million
at
June 30, 2017
and
December 31, 2016
, respectively.
NOTE 8—COMMITMENTS AND CONTINGENCIES
Environmental Matters
The Partnership’s business includes activities that are subject to U.S. federal, state, and local environmental regulations with regard to air, land, and water quality and other environmental matters.
The Partnership does not consider the potential remediation costs that could result from issues identified in any environmental site assessments to be significant to the consolidated financial statements, and
no
provision for potential remediation costs has been made.
Litigation
From time to time, the Partnership is involved in legal actions and claims arising in the ordinary course of business. The Partnership believes existing claims as of
June 30, 2017
will be resolved without material adverse effect on the Partnership’s financial condition or operations.
NOTE 9—INCENTIVE COMPENSATION
On January 7, 2017, the Compensation Committee of the Board of Directors of the Partnership’s general partner (the “Board”) approved a special grant of
312,825
restricted common units to Thomas L. Carter, Jr., the President and Chief Executive Officer of the Partnership’s general partner. Such restricted common units, are subject to limitations on transferability, customary forfeiture provisions, and service-based graded vesting requirements through January 7, 2020.
On January 11, 2017, each non-employee director on the Board, other than Robert E. W. Sinclair, was granted
9,095
fully vested common units for service during 2016. Mr. Sinclair was granted
3,653
fully vested common units for services during 2016 prior to his resignation from the Board. Subsequent to June 30, 2017, Mr. William Randall, the newly elected member of the Board, was issued
6,426
fully vested common units on July 28, 2017. On February 15, 2017, the Compensation Committee of the Board approved a grant of awards to each of the Partnership’s executive officers and certain other employees. These awards consisted of
438,067
restricted common units and
438,067
restricted performance units (in the form of phantom units) with distribution equivalent rights. The restricted common units are subject to limitations on transferability, customary forfeiture provisions, and service-based graded vesting requirements through January 7, 2020.
The table below summarizes incentive compensation expense recorded in general and administrative expenses in the consolidated statements of operations for the
three and six
months ended
June 30, 2017
and
2016
, respectively:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
Incentive compensation expense
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
|
(In thousands)
|
|
(In thousands)
|
Cash—long-term incentive plan
|
|
$
|
214
|
|
|
$
|
560
|
|
|
$
|
636
|
|
|
$
|
2,410
|
|
Equity-based compensation—restricted common and subordinated units
|
|
2,940
|
|
|
3,190
|
|
|
4,748
|
|
|
5,933
|
|
Equity-based compensation—restricted performance units
|
|
2,723
|
|
|
5,426
|
|
|
5,076
|
|
|
8,039
|
|
Board of Directors incentive plan
|
|
614
|
|
|
476
|
|
|
1,114
|
|
|
957
|
|
Total incentive compensation expense
|
|
$
|
6,491
|
|
|
$
|
9,652
|
|
|
$
|
11,574
|
|
|
$
|
17,339
|
|
NOTE 10—REDEEMABLE PREFERRED UNITS
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Partnership had
26,426
and
52,691
redeemable preferred units outstanding with a carrying value of
$27.1 million
and
$54.0 million
as of
June 30, 2017
and
December 31, 2016
, respectively. The aforementioned amounts included accrued distributions of
$0.7 million
as of
June 30, 2017
and
$1.3 million
as of
December 31, 2016
. The redeemable preferred units are classified as mezzanine equity on the consolidated balance sheets since redemption is outside the control of the Partnership. The redeemable preferred units are entitled to an annual distribution of
10%
of the outstanding funded capital of the redeemable preferred units, payable on a quarterly basis in arrears.
The redeemable preferred units are convertible into common and subordinated units at any time at the option of the redeemable preferred unitholders. The redeemable preferred units have an adjusted conversion price of
$14.2683
and an adjusted conversion rate of
30.3431
common units and
39.7427
subordinated units per redeemable preferred unit, which reflects the reverse split described in Note 1 – Business and Basis of Presentation and the capital restructuring related to the IPO. The redeemable preferred unitholders can elect to have the Partnership redeem, at face value, up to
26,426
redeemable preferred units as of December 31,
2017
, plus any accrued and unpaid distributions.
The Partnership shall have the right, at its sole option, to redeem an amount of redeemable preferred units equal to the units being redeemed by an owner of preferred units as of each December 31. Any amount of a given year’s redeemable preferred units eligible for redemption not redeemed as of December 31 shall automatically convert to common and subordinated units during the first quarter of the following year.
For the
six months ended June 30, 2017
,
19,641
redeemable preferred units were redeemed for
$20.1 million
, including accrued unpaid yield. For the three months ended
June 30, 2017
,
6,899
redeemable preferred units were redeemed for
$7.1 million
, including accrued unpaid yield. For the
six months ended June 30, 2017
,
6,624
redeemable preferred units totaling
$6.6 million
were converted into
200,996
common units and
263,247
sub
ordinated units as a result of the
mandatory conversion subsequent to
December 31, 2016
. For the year ended
December 31, 2016
,
6,064
redeemable preferred units totaling
$6.1 million
were converted into the equivalent of
184,006
common units and
240,986
subordinated units on an adjusted basis.
NOTE 11—EARNINGS PER UNIT
The Partnership applies the two-class method for purposes of calculating earnings per unit (“EPU”). The holders of the Partnership’s restricted common and subordinated units have all the rights of a unitholder, including non-forfeitable distribution rights. As participating securities, the restricted common and subordinated units are included in the calculation of basic earnings per unit. For the periods presented, the amount of earnings allocated to these participating units was not material. Net income (loss) attributable to the Partnership is allocated to the Partnership’s general partner and the common and subordinated unitholders in proportion to their pro rata ownership after giving effect to distributions, if any, declared during the period. The redeemable preferred units could be converted into
0.8 million
common units and
1.0 million
subordinated units as of
June 30, 2017
. At
June 30, 2017
, if the outstanding redeemable preferred units were converted to common and subordinated units, the effect would be anti-dilutive. The Partnership’s restricted performance unit awards are contingently issuable units that are considered in the calculation of diluted EPU. The Partnership assesses the number of units that would be issuable, if any, under the terms of the arrangement if the end of the reporting period were the end of the contingency period. At
June 30, 2017
, there were no units related to the Partnership’s restricted performance unit awards included in the calculation of diluted EPU.
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table sets forth the computation of basic and diluted earnings per common and subordinated unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended
June 30,
|
|
For the Six Months Ended
June 30,
|
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
|
(In thousands, except per unit amounts)
|
|
(In thousands, except per unit amounts)
|
NET INCOME (LOSS)
|
|
$
|
54,174
|
|
|
$
|
(20,810
|
)
|
|
$
|
115,757
|
|
|
$
|
(10,061
|
)
|
NET (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS
|
|
16
|
|
|
9
|
|
|
7
|
|
|
7
|
|
DISTRIBUTIONS ON REDEEMABLE PREFERRED UNITS
|
|
(672
|
)
|
|
(1,310
|
)
|
|
(1,786
|
)
|
|
(3,114
|
)
|
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS
|
|
$
|
53,518
|
|
|
$
|
(22,111
|
)
|
|
$
|
113,978
|
|
|
$
|
(13,168
|
)
|
ALLOCATION OF NET INCOME (LOSS):
|
|
|
|
|
|
|
|
|
|
|
|
|
General partner interest
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Common units
|
|
32,100
|
|
|
(7,445
|
)
|
|
67,617
|
|
|
862
|
|
Subordinated units
|
|
21,418
|
|
|
(14,666
|
)
|
|
46,361
|
|
|
(14,030
|
)
|
|
|
$
|
53,518
|
|
|
$
|
(22,111
|
)
|
|
$
|
113,978
|
|
|
$
|
(13,168
|
)
|
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:
|
|
|
|
|
|
|
|
|
|
|
|
|
Per common unit (basic)
|
|
$
|
0.33
|
|
|
$
|
(0.08
|
)
|
|
$
|
0.69
|
|
|
$
|
0.01
|
|
Weighted average common units outstanding (basic)
|
|
97,990
|
|
|
96,356
|
|
|
97,448
|
|
|
96,418
|
|
Per subordinated unit (basic)
|
|
$
|
0.22
|
|
|
$
|
(0.15
|
)
|
|
$
|
0.49
|
|
|
$
|
(0.15
|
)
|
Weighted average subordinated units outstanding (basic)
|
|
95,388
|
|
|
95,189
|
|
|
95,269
|
|
|
95,092
|
|
Per common unit (diluted)
|
|
$
|
0.33
|
|
|
$
|
(0.08
|
)
|
|
$
|
0.69
|
|
|
$
|
0.01
|
|
Weighted average common units outstanding (diluted)
|
|
97,990
|
|
|
96,418
|
|
|
97,448
|
|
|
96,481
|
|
Per subordinated unit (diluted)
|
|
$
|
0.22
|
|
|
$
|
(0.15
|
)
|
|
$
|
0.49
|
|
|
$
|
(0.15
|
)
|
Weighted average subordinated units outstanding (diluted)
|
|
95,388
|
|
|
95,092
|
|
|
95,269
|
|
|
95,092
|
|
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 12—AT-THE-MARKET OFFERING PROGRAM
On May 26, 2017, the Partnership commenced an at-the-market offering program (the “ATM Program”) and in connection therewith entered into an Equity Distribution Agreement with Wells Fargo Securities, LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, and UBS Securities LLC, as Sales Agents (each a “Sales Agent” and collectively the “Sales Agents”). Pursuant to the terms of the ATM Program, the Partnership may sell, from time to time through the Sales Agents, the Partnership’s common units representing limited partner interests having an aggregate offering price of up to
$100,000,000
. Sales of common units, if any, may be made in negotiated transactions or transactions that are deemed to be “at the market” offerings as defined in Rule 415 under the Securities Act of 1933, as amended (the “Securities Act”), including sales made directly on the New York Stock Exchange or sales made to or through a market maker other than on an exchange.
Under the terms of the ATM Program, the Partnership may also sell common units to one or more of the Sales Agents as principal for its own account at a price to be agreed upon at the time of sale. Any sale of common units to a Sales Agent as principal would be pursuant to the terms of a separate agreement between the Partnership and such Sales Agent.
The Partnership intends to use the net proceeds from any sales pursuant to the ATM Program, after deducting the Sales Agents’ commissions and the Partnership’s offering expenses, for general partnership purposes, which may include, among other things, repayment of indebtedness outstanding under the Partnership’s credit facility.
Common units to be sold pursuant to the Equity Distribution Agreement will be offered and sold pursuant to the Partnership’s existing effective shelf-registration statement on Form S-3 (File No. 333-215857), which was declared effective by the Securities and Exchange Commission on February 8, 2017.
The Equity Distribution Agreement contains customary representations, warranties and agreements, indemnification obligations, including for liabilities under the Securities Act, other obligations of the parties and termination provisions.
Through June 30, 2017, the Partnership sold
65,003
common units under the ATM Program for net proceeds of
$1.0 million
.
NOTE 13—SUBSEQUENT EVENTS
On
August 7, 2017
, the Board approved a distribution for the three months ended
June 30, 2017
of
$0.3125
per common unit and
$0.20875
per subordinated unit. Distributions will be payable on
August 24, 2017
to unitholders of record at the close of business on
August 17, 2017
.
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
Item 2.
|
Management’s Discussion and Analysis of Financial Condition and Results of Operations
|
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our unaudited consolidated financial statements and notes thereto presented in this Quarterly Report on Form 10-Q, as well as our audited financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2016. This discussion and analysis contains forward-looking statements that involve risks, uncertainties, and assumptions. Actual results may differ materially from those anticipated in these forward-looking statements as a result of a number of factors, including those set forth under “Cautionary Note Regarding Forward-Looking Statements” and “Part II, Item 1A. Risk Factors.”
Unless the context clearly indicates otherwise, references in this Quarterly Report on Form 10-Q to “BSM,” the “Partnership,” “we,” “our,” “us,” or similar terms for time periods prior to the IPO refer to Black Stone Minerals Company, L.P. and its subsidiaries, the predecessor for accounting purposes. For time periods subsequent to the IPO, these terms refer to Black Stone Minerals, L.P. and its subsidiaries.
Cautionary Note Regarding Forward-Looking Statements
Certain statements and information in this Quarterly Report on Form 10-Q may constitute “forward-looking statements.” The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could,” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:
|
|
•
|
our ability to execute our business strategies;
|
|
|
•
|
the volatility of realized oil and natural gas prices;
|
|
|
•
|
the level of production on our properties;
|
|
|
•
|
regional supply and demand factors, delays, or interruptions of production;
|
|
|
•
|
our ability to replace our oil and natural gas reserves;
|
|
|
•
|
our ability to identify, complete, and integrate acquisitions;
|
|
|
•
|
general economic, business, or industry conditions;
|
|
|
•
|
competition in the oil and natural gas industry;
|
|
|
•
|
the ability of our operators to obtain capital or financing needed for development and exploration operations;
|
|
|
•
|
title defects in the properties in which we invest;
|
|
|
•
|
the availability or cost of rigs, equipment, raw materials, supplies, oilfield services, or personnel;
|
|
|
•
|
restrictions on the use of water;
|
|
|
•
|
the availability of transportation facilities;
|
|
|
•
|
the ability of our operators to comply with applicable governmental laws and regulations and to obtain permits and governmental approvals;
|
|
|
•
|
federal and state legislative and regulatory initiatives relating to hydraulic fracturing;
|
|
|
•
|
future operating results;
|
|
|
•
|
future cash flows and liquidity, including our ability to generate sufficient cash to pay quarterly distributions;
|
|
|
•
|
exploration and development drilling prospects, inventories, projects, and programs;
|
|
|
•
|
operating hazards faced by our operators;
|
|
|
•
|
the ability of our operators to keep pace with technological advancements; and
|
|
|
•
|
certain factors discussed elsewhere in this filing.
|
For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see “Risk Factors” in our Annual Report on Form 10-K.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events, or otherwise.
Overview
We are one of the largest owners of oil and natural gas mineral interests in the United States. Our principal business is maximizing the value of our existing portfolio of mineral and royalty assets through active management and expanding our asset base through acquisitions of additional mineral and royalty interests. We maximize value through the marketing of our mineral assets for lease, creative structuring of terms on those leases to encourage and accelerate drilling activity, and selectively participating alongside our lessees on a working-interest basis in low-risk development-drilling opportunities on our interests. Our primary business objective is to grow our reserves, production, and cash generated from operations over the long term, while paying, to the extent practicable, a growing quarterly distribution to our unitholders.
As of
June 30, 2017
, our mineral and royalty interests were located in 41 states and 64 onshore basins in the continental United States. These non-cost-bearing interests include ownership in approximately 53,000 producing wells. We also own non-operated working interests, largely on our mineral and royalty interests. We recognize oil and natural gas revenue from our mineral and royalty and non-operated working interests in producing wells when the oil and natural gas production from the associated acreage is sold. Our other sources of revenue include mineral lease bonus and delay rentals, which are recognized as revenue according to the terms of the lease agreements.
Recent Developments
Acquisitions
During the first six months of 2017, we closed numerous acquisitions consisting of various mineral and royalty interests in several Texas counties. In the first quarter of 2017, we acquired mineral and royalty interests in East Texas prospective for the Haynesville and Bossier shales for a total of $17.6 million in cash and $0.2 million in our common units, as well as mineral and royalty interests in the Delaware Basin for $30.8 million in cash and $12.0 million in common units. In the second quarter of 2017, we acquired additional mineral and royalty interests in East Texas for $18.1 million in cash and $45.7 million in our common units, primarily through the acquisition of the Angelina County Lumber Company. Additional information regarding acquisitions is contained in Note 4 - Acquisitions and Dispositions to our unaudited consolidated financial statements included herein for further discussion.
At-the-Market Offering Program
In the second quarter of 2017, we commenced an at-the-market offering (the “ATM Program”) program and in connection therewith entered into an Equity Distribution Agreement . The ATM Program permits us from time to time through our Sales Agents to sell our common units having an aggregate offering price of up to $100,000,000. We intend to use the net proceeds from any sales pursuant to the ATM Program, after deducting commissions and offering expenses, for general partnership purposes, which may include, among other things, repayment of indebtedness outstanding under our credit facility. Common units to be sold pursuant to the Equity Distribution Agreement will be offered and sold pursuant to our existing effective shelf-registration statement on Form S-3 (File No. 333-215857), which was declared effective by the Securities and Exchange Commission on February 8, 2017. Proceeds, net of commissions and expenses, of these sales in the second quarter amounted to
$1.0 million
. See Note 12 - At-the-Market-Offering Program to our unaudited consolidated financial statements included herein for further discussion.
Farmout Agreement
On February 21, 2017, we announced that we entered into a farmout agreement with Canaan Resource Partners ("Canaan"), which covers certain Haynesville and Bossier shale acreage in San Augustine County, Texas operated by XTO Energy Inc. We have an approximate 50% working interest in the acreage. A total of 18 wells are anticipated to be drilled over an initial phase, beginning with wells spud after January 1, 2017. At its option, Canaan may participate in two additional phases with each phase continuing for the lesser of two years or until 20 wells have been drilled. During the three phases of the agreement, Canaan will commit on a phase-by-phase basis and fund 80% of our drilling and completion costs and will be assigned 80% of our working interests in such wells (40% working interest on an 8/8ths basis). After the third phase, Canaan can earn 40% of our working interest (20% working interest on an 8/8ths basis) in additional wells drilled in the area by continuing to fund 40% of our costs for those wells on a well-by-well basis. We will receive a base overriding royalty interest (“ORRI”) before payout and an additional ORRI after payout on all wells drilled under the agreement. The execution of this agreement is anticipated to reduce our future capital expenditures by approximately $40-$50 million annually.
Business Environment
The information presented below is designed to give a broad overview of the oil and natural gas business environment as it affects us.
Commodity Prices
Oil and natural gas prices have been historically volatile based upon the dynamics of supply and demand. The Energy Information Agency ("EIA") estimates that global petroleum and other liquid fuels inventory builds averaged 0.3 million Bbls per day in 2016, marking the third consecutive year of inventory builds.
The EIA projects that the Organization of Petroleum Exporting Countries ("OPEC") crude oil output will rise by 0.5 MMBbls per day in 2018, driven by an increase in output in Iraq. In both 2017 and 2018, the EIA expects crude oil production to increase in Libya and Nigeria, which are countries not covered by the current supply reduction agreement.
The EIA forecasts total U.S. crude oil production to average 9.3 MMBbls per day in 2017, up 0.5 MMBbls from 2016. In 2018, crude oil production is anticipated to rise to an average of 9.9 MMBbls per day, which if achieved, would surpass the previous record of 9.6 MMBbls set in 1970. U.S. crude oil production is forecast to reach 10.1 MMBbls per day in December 2018.
The average West Texas Intermediate ("WTI") price is forecast by the EIA to be $49 per Bbl in 2017 and $50 per Bbl in 2018. Global oil inventories are forecast to be relatively unchanged in the second half of 2017 before returning to average inventory builds of 0.2 million Bbl per day in 2018. Given this expectation of relative balance in the global oil market through the forecast period, crude oil spot prices are expected to remain fairly flat in the coming months.
The EIA estimates that dry natural gas production averaged 72.5 Bcf per day in June 2017, which reflects a 0.9 Bcf per day increase from 2016. The EIA expects production to rise through 2017 and 2018 in response to anticipated price increases and large increases in liquefied natural gas ("LNG") exports. The EIA also expects dry natural gas production to rise by 1.0 Bcf per day in 2017 and by 3.1 Bcf per day in 2018. The EIA projects the United States will become a net exporter of natural
gas, on average in 2017, with net exports expected to average 0.4 Bcf per day. As LNG exports increase, 2018 net exports are forecast to average 1.3 Bcf per day. Henry Hub spot prices have been relatively flat in 2017, averaging $3.04 per MMBtu during the first half of the year, which is approximately the same price as in the fourth quarter of 2016. Prices averaged $2.98 per MMBtu in June 2017. The EIA expects closer-to-normal winter temperatures this winter, which could contribute to growth in residential and commercial consumption. Forecast Henry Hub natural gas spot prices are anticipated to average $3.10 per MMBtu in 2017 and $3.40 per MMBtu in 2018.
To manage the variability in cash flows associated with the projected sale of our oil and natural gas production, we use various derivative instruments, which have recently consisted of fixed-price swap contracts.
The following table reflects commodity prices at the end of each quarter presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017
|
|
2016
|
Benchmark Prices
|
|
|
Second
Quarter
|
|
First Quarter
|
|
|
Second
Quarter
|
|
First Quarter
|
WTI spot oil price ($/Bbl)
|
|
|
$
|
46.02
|
|
|
$
|
50.54
|
|
|
|
$
|
48.27
|
|
|
$
|
36.94
|
|
Henry Hub spot natural gas ($/MMBtu)
|
|
|
$
|
2.98
|
|
|
$
|
3.13
|
|
|
|
$
|
2.94
|
|
|
$
|
1.98
|
|
Source: EIA
Rig Count
As we are not an operator, drilling on our acreage is dependent upon the exploration and production companies that lease our acreage. In addition to drilling plans that we seek from our operators, we also monitor rig counts in an effort to identify existing and future leasing and drilling activity on our acreage.
The following table shows the rig count at the close of each quarter presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017
|
|
2016
|
U.S. Rotary Rig Count
|
|
|
Second
Quarter
|
|
First Quarter
|
|
|
Second
Quarter
|
|
First Quarter
|
Oil
|
|
|
756
|
|
|
662
|
|
|
|
330
|
|
|
372
|
|
Natural gas
|
|
|
184
|
|
|
160
|
|
|
|
90
|
|
|
92
|
|
Other
|
|
|
—
|
|
|
2
|
|
|
|
1
|
|
|
—
|
|
Total
|
|
|
940
|
|
|
824
|
|
|
|
421
|
|
|
464
|
|
Source: Baker Hughes Incorporated
Natural Gas Storage
A substantial portion of our revenue is derived from sales of oil production attributable to our interests; however, the majority of our production is natural gas. Natural gas prices are significantly influenced by storage levels throughout the year. Accordingly, we monitor the natural gas storage reports regularly in the evaluation of our business and its outlook.
Historically, natural gas supply and demand fluctuates on a seasonal basis. From April to October, when the weather is warmer and natural gas demand is lower, natural gas storage levels generally increase. From November to March, storage levels typically decline as utility companies draw natural gas from storage to meet increased heating demand due to colder weather. In order to maintain sufficient storage levels for increased seasonal demand, a portion of natural gas production during the summer months must be used for storage injection. The portion of production used for storage varies from year to year depending on the demand from the previous winter and the demand for electricity used for cooling during the summer months. According to the EIA, natural gas inventories reached a record high of 4,047 Bcf on November 11, 2016 and inventories ended the winter heating season at 2,072 Bcf in March 2017. The EIA projects that natural gas inventories will be 3,940 Bcf at the end of October 2017, which would be approximately 2% higher than the five year average but approximately 2% lower than the record high level experienced in November 2016.
The following table shows natural gas storage volumes by region at the close of each quarter presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017
|
|
2016
|
Region
|
|
|
Second
Quarter
|
|
First Quarter
|
|
|
Second
Quarter
|
|
First Quarter
|
|
|
(Bcf)
|
East
|
|
|
564
|
|
|
268
|
|
|
|
632
|
|
|
439
|
|
Midwest
|
|
|
699
|
|
|
479
|
|
|
|
742
|
|
|
555
|
|
Mountain
|
|
|
187
|
|
|
142
|
|
|
|
198
|
|
|
147
|
|
Pacific
|
|
|
287
|
|
|
216
|
|
|
|
315
|
|
|
262
|
|
South Central
|
|
|
1,151
|
|
|
946
|
|
|
|
1,253
|
|
|
1,065
|
|
Total
|
|
|
2,888
|
|
|
2,051
|
|
|
|
3,140
|
|
|
2,468
|
|
Source: EIA
How We Evaluate Our Operations
We use a variety of operational and financial measures to assess our performance. Among the measures considered by management are the following:
|
|
•
|
volumes of oil and natural gas produced;
|
|
|
•
|
commodity prices including the effect of derivative instruments; and
|
|
|
•
|
Adjusted EBITDA, distributable cash flow, and distributable cash flow after net working interest capital expenditures.
|
Volumes of Oil and Natural Gas Produced
In order to track and assess the performance of our assets, we monitor and analyze our production volumes from the various basins and plays that comprise our extensive asset base. We also regularly compare projected volumes to actual reported volumes and investigate unexpected variances.
Commodity Prices
Factors Affecting the Sales Price of Oil and Natural Gas
The prices we receive for oil, natural gas, and natural gas liquids (“NGLs”) vary by geographical area. The relative prices of these products are determined by the factors affecting global and regional supply and demand dynamics, such as economic conditions, production levels, availability of transportation, weather cycles, and other factors. In addition, realized prices are influenced by product quality and proximity to consuming and refining markets. Any differences between realized prices and NYMEX prices are referred to as differentials. All of our production is derived from properties located in the United States. As a result of our geographic diversification, we are not exposed to concentrated differential risks associated with any single play, trend, or basin.
|
|
•
|
Oil
. The substantial majority of our oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of our control. NYMEX light sweet crude oil, commonly referred to as WTI, is the prevailing domestic oil pricing index. The majority of our oil production is priced at the prevailing market price with the final realized price affected by both quality and location differentials.
|
The chemical composition of crude oil plays an important role in its refining and subsequent sale as petroleum products. As a result, variations in chemical composition relative to the benchmark crude oil, usually WTI, will result in price adjustments, which are often referred to as quality differentials. The characteristics that most significantly affect quality differentials include the density of the oil, as characterized by its American Petroleum Institute (“API”) gravity, and the presence and concentration of impurities, such as sulfur.
Location differentials generally result from transportation costs based on the produced oil’s proximity to consuming and refining markets and major trading points.
|
|
•
|
Natural Gas.
The NYMEX price quoted at Henry Hub is a widely used benchmark for the pricing of natural gas in the United States. The actual volumetric prices realized from the sale of natural gas differ from the quoted NYMEX price as a result of quality and location differentials.
|
Quality differentials result from the heating value of natural gas measured in Btus and the presence of impurities, such as hydrogen sulfide, carbon dioxide, and nitrogen. Natural gas containing ethane and heavier hydrocarbons has a higher Btu value and will realize a higher volumetric price than natural gas which is predominantly methane, which has a lower Btu value. Natural gas with a higher concentration of impurities will realize a lower volumetric price due to the presence of the impurities in the natural gas when sold or the cost of treating the natural gas to meet pipeline quality specifications.
Natural gas, which currently has a limited global transportation system, is subject to price variances based on local supply and demand conditions and the cost to transport natural gas to end user markets.
Hedging
We enter into derivative instruments to partially mitigate the impact of commodity price volatility on our cash generated from operations. From time to time, such instruments may include fixed-price swaps, fixed-price contracts, costless collars, and other contractual arrangements. We generally employ a “rolling hedge” strategy whereby we hedge a significant portion of our proved developed producing reserves 12 to 24 months into the future. The impact of these derivative instruments could affect the amount of revenue we ultimately realize. Since 2015, we have only entered into fixed-price swap contracts. Under fixed-price swap contracts, a counterparty is required to make a payment to us if the settlement price is less than the swap strike price. Conversely, we are required to make a payment to the counterparty if the settlement price is greater than the swap strike price. We may employ contractual arrangements other than fixed-price swap contracts in the future to mitigate the impact of price fluctuations. If commodity prices decline in the future, our hedging contracts will partially mitigate the effect of lower prices on our future revenue.
Our open oil and natural gas derivative contracts as of
June 30, 2017
, and as of the date of this filing, are detailed in Note 5 – Derivatives and Financial Instruments to our unaudited consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q. Our credit agreement limits the extent to which we can hedge our future production. Under the terms of our credit agreement, we are able to hedge all of our estimated production from our proved developed producing reserves based on the most recent reserve information provided to our lenders. We do not enter into derivative instruments for speculative purposes. We have hedged 95.5% and 95.5% of our available oil and condensate hedge volumes, respectively and 99.7% and 99.4% of our available natural gas hedge volumes for the remainder of 2017 and 2018, respectively.
Non-GAAP Financial Measures
Adjusted EBITDA, distributable cash flow, and distributable cash flow after net working interest capital expenditures are supplemental non-GAAP financial measures used by our management and external users of our financial statements such as investors, research analysts, and others, to assess the financial performance of our assets and our ability to sustain distributions over the long term without regard to financing methods, capital structure, or historical cost basis.
We define Adjusted EBITDA as net income (loss) before interest expense, income taxes and depreciation, depletion, and amortization adjusted for impairment of oil and natural gas properties, accretion of asset retirement obligations, unrealized gains and losses on commodity derivative instruments, and non-cash equity-based compensation. We define distributable cash flow as Adjusted EBITDA plus or minus amounts for certain non-cash operating activities, estimated replacement capital expenditures, cash interest expense, and distributions to noncontrolling interests and preferred unitholders. We define distributable cash flow after net working interest capital expenditures as distributable cash flow less net working interest capital expenditures. Net working interest capital expenditures consists of all capital expenditures related to working interest wells less the recoupment of working interest expenditures under our farmout agreement.
Adjusted EBITDA, distributable cash flow, and distributable cash flow after net working interest capital expenditures should not be considered an alternative to, or more meaningful than, net income (loss), income (loss) from operations, cash flows from operating activities, or any other measure of financial performance presented in accordance with generally accepted accounting principles (“GAAP”) in the United States as measures of our financial performance.
Adjusted EBITDA, distributable cash flow, and distributable cash flow after net working interest capital expenditures have important limitations as analytical tools because they exclude some but not all items that affect net income (loss), the most
directly comparable GAAP financial measure. Our computation of Adjusted EBITDA, distributable cash flow, and distributable cash flow after net working interest capital expenditures may differ from computations of similarly titled measures of other companies.
The following table presents a reconciliation of Adjusted EBITDA, distributable cash flow and distributable cash flow after net working interest capital expenditures to net income (loss), the most directly comparable GAAP financial measure, for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
|
(Unaudited)
(In thousands)
|
Net income (loss)
|
|
$
|
54,174
|
|
|
$
|
(20,810
|
)
|
|
$
|
115,757
|
|
|
$
|
(10,061
|
)
|
Adjustments to reconcile to Adjusted EBITDA:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
28,900
|
|
|
29,202
|
|
|
55,279
|
|
|
50,923
|
|
Interest expense
|
|
3,981
|
|
|
1,443
|
|
|
7,488
|
|
|
2,491
|
|
Impairment of oil and natural gas properties
|
|
—
|
|
|
679
|
|
|
—
|
|
|
6,775
|
|
Accretion of asset retirement obligations
|
|
253
|
|
|
200
|
|
|
500
|
|
|
474
|
|
Equity-based compensation
2
|
|
6,278
|
|
|
19,239
|
|
|
10,939
|
|
|
25,139
|
|
Unrealized (gain) loss on commodity derivative instruments
|
|
(18,921
|
)
|
|
44,070
|
|
|
(37,368
|
)
|
|
54,025
|
|
Adjusted EBITDA
|
|
74,665
|
|
|
74,023
|
|
|
152,595
|
|
|
129,766
|
|
Adjustments to reconcile to distributable cash flow:
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in deferred revenue
|
|
(643
|
)
|
|
424
|
|
|
(969
|
)
|
|
221
|
|
Cash interest expense
|
|
(3,760
|
)
|
|
(1,246
|
)
|
|
(7,053
|
)
|
|
(2,097
|
)
|
(Gain) loss on sales of assets, net
|
|
(7
|
)
|
|
(92
|
)
|
|
(931
|
)
|
|
(4,772
|
)
|
Estimated replacement capital expenditures
1
|
|
(3,250
|
)
|
|
(3,750
|
)
|
|
(7,000
|
)
|
|
(3,750
|
)
|
Cash paid to noncontrolling interests
|
|
(41
|
)
|
|
(21
|
)
|
|
(66
|
)
|
|
(54
|
)
|
Redeemable preferred unit distributions
|
|
(672
|
)
|
|
(1,310
|
)
|
|
(1,786
|
)
|
|
(3,114
|
)
|
Distributable Cash Flow
|
|
66,292
|
|
|
68,028
|
|
|
134,790
|
|
|
116,200
|
|
Net working interest capital expenditures
|
|
(15,330
|
)
|
|
(11,600
|
)
|
|
(32,295
|
)
|
|
(36,710
|
)
|
Distributable cash flow after net working interest capital expenditures
|
|
$
|
50,962
|
|
|
$
|
56,428
|
|
|
$
|
102,495
|
|
|
$
|
79,490
|
|
1
On August 3, 2016, the Board of Directors of our general partner (the “Board”)
established a replacement capital expenditure estimate of $15.0 million for the period of April 1, 2016 to March 31, 2017. There was no established estimate of replacement capital expenditures prior to this period. On June 8, 2017, the Board established a replacement capital expenditure estimate of $13.0 million for the period of April 1, 2017 to March 31, 2018.
2
On April 25, 2016, the Compensation Committee of the Board approved a resolution to change the settlement feature of certain employee long-term incentive
compensation plans from cash to equity. As a result of the modification, $10.1 million of cash-settled liabilities were reclassified to equity-settled liabilities
during the second quarter of 2016.
Results of Operations
Three Months Ended June 30, 2017
Compared to
Three Months Ended June 30, 2016
The following table shows our production, revenues, pricing, and expenses for the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
|
2017
|
|
2016
|
|
Variance
|
|
|
(Unaudited)
(Dollars in thousands, except for realized prices)
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate (MBbls)
|
|
824
|
|
|
947
|
|
|
(123
|
)
|
|
(13.0
|
)%
|
Natural gas (MMcf)
1
|
|
15,425
|
|
|
11,558
|
|
|
3,867
|
|
|
33.5
|
%
|
Equivalents (MBoe)
|
|
3,395
|
|
|
2,873
|
|
|
522
|
|
|
18.2
|
%
|
Revenue:
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate sales
|
|
$
|
37,262
|
|
|
$
|
34,553
|
|
|
$
|
2,709
|
|
|
7.8
|
%
|
Natural gas and natural gas liquids sales
|
|
49,903
|
|
|
21,607
|
|
|
28,296
|
|
|
131.0
|
%
|
Gain (loss) on commodity derivative instruments
|
|
22,003
|
|
|
(30,733
|
)
|
|
52,736
|
|
|
(171.6
|
)%
|
Lease bonus and other income
|
|
11,356
|
|
|
15,142
|
|
|
(3,786
|
)
|
|
(25.0
|
)%
|
Total revenue
|
|
$
|
120,524
|
|
|
$
|
40,569
|
|
|
$
|
79,955
|
|
|
197.1
|
%
|
Realized prices:
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate ($/Bbl)
|
|
$
|
45.22
|
|
|
$
|
36.49
|
|
|
$
|
8.73
|
|
|
23.9
|
%
|
Natural gas ($/Mcf)
1
|
|
3.24
|
|
|
1.87
|
|
|
1.37
|
|
|
73.3
|
%
|
Equivalents ($/Boe)
|
|
$
|
25.67
|
|
|
$
|
19.55
|
|
|
$
|
6.12
|
|
|
31.3
|
%
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense
|
|
$
|
4,148
|
|
|
$
|
4,283
|
|
|
$
|
(135
|
)
|
|
(3.2
|
)%
|
Production costs and ad valorem taxes
|
|
11,863
|
|
|
7,012
|
|
|
4,851
|
|
|
69.2
|
%
|
Exploration expense
|
|
46
|
|
|
629
|
|
|
(583
|
)
|
|
(92.7
|
)%
|
Depreciation, depletion, and amortization
|
|
28,900
|
|
|
29,202
|
|
|
(302
|
)
|
|
(1.0
|
)%
|
Impairment of oil and natural gas properties
|
|
—
|
|
|
679
|
|
|
(679
|
)
|
|
(100.0
|
)%
|
General and administrative
|
|
17,481
|
|
|
18,134
|
|
|
(653
|
)
|
|
(3.6
|
)%
|
|
|
1
|
As a mineral-and-royalty-interest owner, we are often provided insufficient and inconsistent data on NGL volumes by our operators. As a result, we are unable to reliably determine the total volumes of NGLs associated with the production of natural gas on our acreage. Accordingly, no NGL volumes are included in our reported production; however, revenue attributable to NGLs is included in our natural gas revenue and our calculation of realized prices for natural gas.
|
Revenue
Total revenue for the quarter ended
June 30, 2017
increased compared to the quarter ended
June 30, 2016
. Production for the quarter ended
June 30, 2017
averaged 37.3 MBoe per day, an increase of 5.7 MBoe per day compared to the corresponding period in
2016
. The increase in total revenue is primarily due to higher commodity prices, increased production, and gains from commodity derivative instruments, as compared to the corresponding period in
2016
.
Oil and condensate sales.
Oil and condensate sales during the period were higher than the
second
quarter of
2016
due to higher realized prices. Our total oil and condensate production was lower than the
second
quarter of 2016. Our mineral-and-royalty-interest oil and condensate volumes accounted
for 86.8%
and
79.3%
of total oil and condensate volumes for the
quarters ended
June 30, 2017
and
2016
, respectively.
Our
mineral-and-royalty-interest oil
and condensate
volumes decreased
4.7%
in
the
second
quarter of
2017
relative to
the
corresponding period in
2016
,
primarily
driven
by lower production in our Eagle Ford Shale assets.
Natural gas and natural gas liquids sales.
Natural gas and NGL sales increased for the quarter ended
June 30, 2017
as compared to the same period for
2016
. Higher commodity prices and higher production volumes, largely driven by new wells
in the Haynesville play, were primarily responsible for the increase in our natural gas and NGL revenues. Mineral-and-royalty-interest production accounted for 47.1% and 62.5% of our natural gas volumes for the quarters ended
June 30, 2017
and
2016
, respectively.
Gain (loss) on commodity derivative instruments.
During the
second
quarter of
2017
, we recognized $13.5 million of gains from oil commodity contracts, which included cash received of $3.8 million, compared to recognized losses of $15.5 million in the same period of
2016
. During the
second
quarter of
2017
, we recognized $8.5 million of gains from natural gas commodity contracts, which included cash paid of $0.8 million, compared to recognized losses of $15.2 million in the same period of
2016
.
Lease bonus and other income.
When we lease our mineral interests, we generally receive an upfront cash payment, or a lease bonus. Leasing activity in the Bakken/Three Forks and the Wolfcamp trends made up the majority of leases written in the second quarter of 2017.
Operating and Other Expenses
Lease operating expense
. Lease operating expense includes normally recurring expenses associated with our non-operated working interests necessary to produce hydrocarbons from our oil and natural gas wells, as well as certain nonrecurring expenses, such as well repairs. Lease operating expense decreased for the quarter ended
June 30, 2017
as compared to the same period in
2016
, primarily due to fewer producing wells and fewer remedial projects initiated by our operators.
Production costs and ad valorem taxes
. Production taxes include statutory amounts deducted from our production revenues by various state taxing entities. Depending on the regulations of the states where the production originates, these taxes may be based on a percentage of the realized value or a fixed amount per production unit. This category also includes the costs to process and transport our production to applicable sales points. Ad valorem taxes are jurisdictional taxes levied on the value of oil and natural gas minerals and reserves. Rates, methods of calculating property values, and timing of payments vary between taxing authorities. For the quarter ended
June 30, 2017
, production costs and ad valorem taxes increased from the quarter ended
June 30, 2016
, generally as a result of higher commodity prices and natural gas production volumes.
Exploration expense
. Exploration expense typically consists of dry-hole expenses and geological and geophysical costs, including seismic costs, and is expensed as incurred under the successful efforts method of accounting. Exploration expense decreased for the three months ended June 30, 2017 as compared to the same period in
2016
. The 2017 and 2016 expense represents costs incurred to acquire 3-D seismic information, related to our mineral and royalty interests, from a third-party service provider.
Depreciation, depletion, and amortization
. Depletion is an estimate of the amount of cost basis of oil and natural gas properties attributable to the volume of hydrocarbons extracted during a period, calculated on a units-of-production basis. Estimates of proved developed producing reserves are a major component of the calculation of depletion. We adjust our depletion rates semi-annually based upon mid-year and year-end reserve reports, except when circumstances indicate that there has been a significant change in reserves or costs. Depreciation, depletion, and amortization decreased for the quarter ended
June 30, 2017
as compared to the same period in
2016
, primarily due to the impact of lower depletion rates partially offset by higher production.
Impairment of oil and natural gas properties
. Individual categories of oil and natural gas properties are assessed periodically to determine if the net book value for these properties has been impaired. Management periodically conducts an in-depth evaluation of the carrying amounts of property acquisitions, successful exploratory wells, development activity, undeveloped leasehold, and mineral interests to identify impairments. There were no impairments for the quarter ended
June 30, 2017
. Impairments totaled $0.7 million for the quarter ended June 30, 2016 primarily due to drilling costs in the Mississippian play exceeding our expected realizable net cash flow.
General and administrative
. General and administrative expenses are costs not directly associated with the production of oil and natural gas and include the cost of
employee salaries
and related benefits, office expenses, and fees for professional services. For the
quarter ended
June 30, 2017
, general and administrative expenses
decreased
as compared to the same period in
2016
. In
2017
,
costs
attributable
to our long-term incentive plans
were lower
than in the
corresponding
period
in
2016
.
Interest expense
. Interest expense was higher in the second quarter of 2017 due to increased borrowings under our credit facility. Average outstanding borrowings during the
second
quarter of
2017
were higher than the
second
quarter of
2016
due to
funding of acquisitions in 2017 and 2016, common unit repurchases in 2016, and redemptions associated with our preferred units.
Six Months Ended June 30, 2017
Compared to
Six Months Ended June 30, 2016
The following table shows our production, revenues, pricing, and expenses for the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
|
2017
|
|
2016
|
|
Variance
|
|
|
(Dollars in thousands, except for realized prices and per Boe data)
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate (MBbls)
|
|
1,685
|
|
|
1,833
|
|
|
(148
|
)
|
|
(8.1
|
)%
|
Natural gas (MMcf)
1
|
|
29,485
|
|
|
22,807
|
|
|
6,678
|
|
|
29.3
|
%
|
Equivalents (MBoe)
|
|
6,599
|
|
|
5,634
|
|
|
965
|
|
|
17.1
|
%
|
Revenue:
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate sales
|
|
$
|
77,736
|
|
|
$
|
61,801
|
|
|
$
|
15,935
|
|
|
25.8
|
%
|
Natural gas and natural gas liquids sales
|
|
97,604
|
|
|
46,719
|
|
|
50,885
|
|
|
108.9
|
%
|
Gain (loss) on commodity derivative instruments
|
|
44,728
|
|
|
(20,107
|
)
|
|
64,835
|
|
|
(322.4
|
)%
|
Lease bonus and other income
|
|
25,038
|
|
|
16,537
|
|
|
8,501
|
|
|
51.4
|
%
|
Total revenue
|
|
$
|
245,106
|
|
|
$
|
104,950
|
|
|
$
|
140,156
|
|
|
133.5
|
%
|
Realized prices:
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate ($/Bbl)
|
|
$
|
46.13
|
|
|
$
|
33.72
|
|
|
$
|
12.41
|
|
|
36.8
|
%
|
Natural gas ($/Mcf)
1
|
|
3.31
|
|
|
2.05
|
|
|
1.26
|
|
|
61.5
|
%
|
Equivalents ($/Boe)
|
|
$
|
26.57
|
|
|
$
|
19.26
|
|
|
$
|
7.31
|
|
|
38.0
|
%
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense
|
|
$
|
8,337
|
|
|
$
|
9,172
|
|
|
$
|
(835
|
)
|
|
(9.1
|
)%
|
Production costs and ad valorem taxes
|
|
23,765
|
|
|
14,074
|
|
|
9,691
|
|
|
68.9
|
%
|
Exploration expense
|
|
608
|
|
|
637
|
|
|
(29
|
)
|
|
(4.6
|
)%
|
Depreciation, depletion, and amortization
|
|
55,279
|
|
|
50,923
|
|
|
4,356
|
|
|
8.6
|
%
|
Impairment of oil and natural gas properties
|
|
—
|
|
|
6,775
|
|
|
(6,775
|
)
|
|
(100.0
|
)%
|
General and administrative
|
|
34,693
|
|
|
35,535
|
|
|
(842
|
)
|
|
(2.4
|
)%
|
|
|
1
|
As a mineral-and-royalty-interest owner, we are often provided insufficient and inconsistent data on NGL volumes by our operators. As a result, we are unable to reliably determine the total volumes of NGLs associated with the production of natural gas on our acreage. Accordingly, no NGL volumes are included in our reported production; however, revenue attributable to NGLs is included in our natural gas revenue and our calculation of realized prices for natural gas.
|
Revenue
Total revenues for the
six months ended June 30, 2017
increased compared to the
six months ended June 30, 2016
. Production for the
six months ended June 30, 2017
averaged 36.5 MBoe per day, an increase of 5.5 MBoe per day, compared to the corresponding period in
2016
. The increase in total revenue from the corresponding prior period is primarily due to a $64.8 million increase in revenue from our commodity derivative instruments; higher realized commodity prices, the impact of which totaled $58.1 million, an $8.7 million increase in net production volumes; and $8.5 million higher lease bonus and other income.
Oil and condensate sales.
Oil and condensate sales during the
six months ended June 30, 2017
were higher than the corresponding period in
2016
primarily due to higher realized prices. Oil and condensate production for the
six months ended June 30, 2017
was lower than in the
six months ended June 30, 2016
, but the decreased production was more than offset by an increase in realized prices. Our mineral-and-royalty-interest oil and condensate volumes accounted for 83.1% and 78.9% of total oil and condensate volumes for the
six months ended June 30, 2017
and
2016
, respectively. Our mineral-and-royalty-interest oil and condensate volumes decreased 3.2% for the
six months ended June 30, 2017
relative to the corresponding period in
2016
, primarily driven by production decreases in the Eagle Ford play. Our working-interest oil and condensate volumes decreased by 26.4% to 1.6 MBbls per day during the
six months ended June 30, 2017
as compared to the same period in
2016
primarily due to decreased activity in the Bakken play.
Natural gas and natural gas liquids sales.
Natural gas and NGL sales increased for the
six months ended June 30, 2017
as compared to the same period for
2016
. An increase in production volumes, primarily from new wells in the Haynesville/Bossier and Wilcox plays, and an increase in the realized natural gas and NGL prices for the
six months ended June 30, 2017
compared to the corresponding period in
2016
was primarily responsible for the increase in our natural gas and NGL revenues. Mineral-and-royalty-interest production accounted for 49.3% and 62.0% of our natural gas volumes for the
six months ended June 30, 2017
and
2016
, respectively.
Gain (loss) on commodity derivative instruments.
During the
six months ended June 30, 2017
, we recognized a $27.8 million gain on our oil commodity contracts, which included $6.7 million in cash received, compared to a recognized loss of $12.6 million in the same period of
2016
. During the first six months of
2017
, we recognized $16.9 million of gains from natural gas commodity contracts, which included $0.7 million of cash received, compared to a recognized loss of $7.5 million in the same period of
2016
.
Lease bonus and other income.
Lease bonus and other income increased for the
six months ended June 30, 2017
as compared to the same period in
2016
. In the first six months of
2017
, we successfully closed several significant lease transactions in San Augustine, Midland, Potter and Ward counties of Texas, in Red River parish of Louisiana and Dunn and McKenzie counties of North Dakota.
Operating and Other Expenses
Lease operating expense
. Lease operating expense decreased for the
six months ended June 30, 2017
as compared to the same period in
2016
, primarily due to fewer producing wells and fewer remedial projects initiated by our operators.
Production costs and ad valorem taxes
. For the
six months ended June 30, 2017
, production costs and ad valorem taxes increased from the
six months ended June 30, 2016
, generally as a result of higher commodity prices and natural gas production volumes.
Exploration expense
. Exploration expense decreased for the
six months ended June 30, 2017
as compared to the same period in
2016
. Exploration expense for the six months ended June 30, 2017 and 2016 represents costs incurred to acquire 3-D seismic information, related to our mineral and royalty interests, from a third-party service provider.
Depreciation, depletion, and amortization
. Depreciation, depletion, and amortization increased for the
six months ended June 30, 2017
as compared to the same period in
2016
, primarily due to higher production partially offset by lower depletion rates.
Impairment of oil and natural gas properties
. Impairments totaled
$6.8
million for the six months ended June 30, 2016 primarily due to changes in reserve values resulting from declines in future expected realized net cash flows.
General and administrative
. For the
six months ended June 30, 2017
, general and administrative expenses decreased as compared to the same period in
2016
due to lower costs attributable to our long-term incentive plans.
Interest expense
. Interest expense increased due to higher average outstanding borrowings under our credit facility. Average outstanding borrowings during the first
six
months of
2017
were higher than the
six months ended June 30, 2016
, primarily due to funding of acquisitions, common unit repurchases in 2016, and redemptions associated with our preferred units in 2017.
Liquidity and Capital Resources
Overview
Our primary sources of liquidity are cash generated from operations, borrowings under our credit facility, and proceeds from the issuance of equity and debt. Our primary uses of cash are for distributions to our unitholders and for investing in our business, specifically the acquisition of mineral and royalty interests and our selective participation on a non-operated working-interest basis in the development of our oil and natural gas properties.
We intend to finance our future acquisitions with cash generated from operations, borrowings from our credit facility, and proceeds from any future issuances of equity and debt. Over the long-term, we intend to finance our working-interest capital needs with internally-generated cash flows, although at times we may fund a portion of these expenditures through
external financing sources such as borrowings under our credit facility. Replacement capital expenditures are expenditures necessary to replace our existing oil and natural gas reserves or otherwise maintain our asset base over the long-term. Like a number of other master limited partnerships, we are required by our partnership agreement to retain cash from our operations in an amount equal to our estimated replacement capital requirements. The Board of Directors of our general partner (the “Board”) established a replacement capital expenditure estimate of $15.0 million for the period of April 1, 2016 to March 31, 2017. On June 8, 2017, the Board established a replacement capital expenditure estimate of $13.0 million for the period of April 1, 2017 to March 31, 2018.
Cash Flows
The following table shows our cash flows for the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
June 30,
|
|
|
2017
|
|
2016
|
|
|
(Unaudited)
(In thousands)
|
Cash flows provided by (used in) operating activities
|
|
$
|
139,164
|
|
|
$
|
83,544
|
|
Cash flows provided by (used in) investing activities
|
|
(98,367
|
)
|
|
(172,878
|
)
|
Cash flows provided by (used in) financing activities
|
|
(43,082
|
)
|
|
85,871
|
|
Six Months Ended June 30, 2017
Compared to
Six Months Ended June 30, 2016
Operating Activities
. Our operating cash flows are dependent, in large part, on our production, realized commodity prices, derivative settlements, lease bonus revenue, and operating expenses. Our cash flows from operations increased from $83.5 million for the
six months ended June 30, 2016
to $139.2 million for the
six months ended June 30, 2017
. The increase was primarily due to higher cash collections of $76.4 million related to higher oil and natural gas sales and other changes in working capital as compared to the corresponding period in
2016
.
Investing Activities
. Net cash used in investing activities decreased by $74.5 million in the first
six
months of
2017
as compared to the corresponding period in
2016
primarily due to mineral and property acquisitions being higher during the first
six
months of
2016
. Lower capital expenditures for our working interest properties added to the overall decrease in investing activities.
Financing Activities
. Cash flows from financing activities decreased in the first six months of 2017 as compared to the corresponding period in 2016. Net cash used in financing activities for the six months ended June 30, 2017 consisted of distributions to our common and subordinated unit holders, redemptions of redeemable preferred units and repurchases of common and subordinated units. These cash outflows were partially offset by net borrowings under our credit facility and proceeds from the issuance of common units under the ATM Program. Net cash provided by financing activities for the six months ended June 30, 2016 consisted of net borrowings under our credit facility partially offset by distributions to our common and subordinated unit holders, redemptions of redeemable preferred units and repurchases of common and subordinated units.
Capital Expenditures
Our
2017
drilling expenditures are expected to be between $40 million to $50 million down from our previous estimate of $50 million to $60 million. Approximately 90% of our drilling capital budget will be spent in the Haynesville/Bossier play with the remainder expected to be spent in various plays including the Bakken/Three Forks and Wolfcamp plays. On February 16, 2017, we entered into a farmout agreement which will reduce our future capital requirements and will generate additional royalty income. The farmout covers our working interests within an approximate 34,000-acre block in San Augustine County, Texas.
During the
six months ended June 30, 2017
, we incurred $30.8 million related to drilling and completion costs, primarily in the Haynesville/Bossier play. During the six months ended June 30, 2017, we also completed mineral and royalty interests acquisitions for $124.4 million in cash and equity. See Note 4 – Acquisitions and Dispositions to our unaudited consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for further discussion.
Credit Facility
On January 23, 2015, we amended and restated our $1.0 billion senior secured revolving credit agreement. Under this third amended and restated credit facility, the commitment of the lenders equals the lesser of the aggregate maximum credit amounts of the lenders and the borrowing base, which is determined based on the lenders’ estimated value of our oil and natural gas properties. On October 28, 2015, the third amended and restated credit facility was further amended to extend the term of the agreement from February 3, 2017 to February 4, 2019. Borrowings under the third amended and restated credit facility may be used for the acquisition of properties, cash distributions, and other general corporate purposes. Our regular, semi-annual borrowing base redetermination process resulted in a decrease of the borrowing base from $550.0 million to $450.0 million, effective April 15, 2016. Our fall 2016 borrowing base redetermination process resulted in an increase in the borrowing base to $500.0 million, which became effective October 31, 2016. Effective April 25, 2017, the borrowing base redetermination resulted in an increase to $550.0 million. As of
June 30, 2017
, we had outstanding borrowings of $393.0 million at a weighted-average interest rate of 3.73%.
The borrowing base under the third amended and restated credit agreement is redetermined semi-annually, typically in April and October of each year, by the administrative agent, taking into consideration the estimated loan value of our oil and natural gas properties consistent with the administrative agent’s normal lending criteria. The administrative agent’s proposed redetermined borrowing base must be approved by all lenders to increase our existing borrowing base, and by two-thirds of the lenders to maintain or decrease our existing borrowing base. In addition, we and the lenders (at the election of two-thirds of the lenders) each have discretion to have the borrowing base redetermined once between scheduled redeterminations.
Outstanding borrowings under the third amended and restated credit facility bear interest at a floating rate elected by us equal to an alternative base rate (which is equal to the greatest of the Prime rate, the Federal Funds effective rate plus 0.50%, or 1-month LIBOR plus 1.00%) or LIBOR, in each case, plus the applicable margin. Through October 2016, the applicable margin ranged from 0.50% to 1.50% in the case of the alternative base rate and from 1.50% to 2.50% in the case of LIBOR, in each case depending on the amount of borrowings outstanding in relation to the borrowing base. Subsequent to the closing of our fall redetermination on October 31, 2016, the applicable margin ranges from 1.00% to 2.00% in the case of the alternative base rate and from 2.00% to 3.00% in the case of LIBOR, depending on the borrowings outstanding in relation to the borrowing base.
We are obligated to pay a quarterly commitment fee ranging from a 0.375% to 0.500% annualized rate on the unused portion of the borrowing base, depending on the amount of the borrowings outstanding in relation to the borrowing base. Principal may be optionally repaid from time to time without premium or penalty, other than customary LIBOR breakage, and is required to be paid (a) if the amount outstanding exceeds the borrowing base, whether due to a borrowing base redetermination or otherwise, in some cases subject to a cure period, or (b) at the maturity date. The third amended and restated credit facility is secured by liens on substantially all of our producing properties.
The third amended and restated credit agreement contains various affirmative, negative, and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates, and entering into certain swap agreements, as well as require the maintenance of certain financial ratios. The third amended and restated credit agreement contains two financial covenants: total debt to EBITDAX of 3.5:1.0 or less and a modified current ratio of 1.0:1.0 or greater as defined in the credit agreement. Distributions are not permitted if there is a default under the third amended and restated credit agreement (including due to a failure to satisfy one of the financial covenants) or during any time that our borrowing base is lower than the loans outstanding under the third amended and restated credit facility. The lenders have the right to accelerate all of the indebtedness under the third amended and restated credit facility upon the occurrence and during the continuance of any event of default, and the third amended and restated credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy, and change of control. There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods. As of
June 30, 2017
, we were in compliance with all debt covenants.
Contractual Obligations
As of
June 30, 2017
, there have been no material changes to our contractual obligations previously disclosed in our
2016
Annual Report on Form 10-K.
Off-Balance Sheet Arrangements
As of
June 30, 2017
, we did not have any material off-balance sheet arrangements.
Critical Accounting Policies and Related Estimates
As of
June 30, 2017
, there have been no significant changes to our critical accounting policies and related estimates previously disclosed in our
2016
Annual Report on Form 10-K.
New and Revised Financial Accounting Standards
The effects of new accounting pronouncements are discussed in the notes to our unaudited consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q.