Item 1. Financial Statements
ALTA MESA RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(in thousands, except shares outstanding and per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
Three Months Ended
June 30, 2019
|
|
Three Months Ended
June 30, 2018
|
|
|
Six Months Ended
June 30, 2019
|
|
February 9, 2018
Through
June 30, 2018
|
|
|
January 1, 2018
Through
February 8, 2018
|
Revenue
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
$
|
90,668
|
|
|
$
|
75,291
|
|
|
|
$
|
177,031
|
|
|
$
|
115,569
|
|
|
|
$
|
30,972
|
|
Natural gas
|
12,384
|
|
|
7,980
|
|
|
|
30,834
|
|
|
13,190
|
|
|
|
4,276
|
|
Natural gas liquids
|
10,251
|
|
|
10,241
|
|
|
|
21,467
|
|
|
14,955
|
|
|
|
4,000
|
|
Sales of gathered production
|
10,439
|
|
|
8,924
|
|
|
|
19,999
|
|
|
12,797
|
|
|
|
—
|
|
Midstream revenue
|
6,549
|
|
|
6,817
|
|
|
|
13,704
|
|
|
10,077
|
|
|
|
—
|
|
Other
|
3,014
|
|
|
2,229
|
|
|
|
6,099
|
|
|
2,784
|
|
|
|
888
|
|
Operating revenue
|
133,305
|
|
|
111,482
|
|
|
|
269,134
|
|
|
169,372
|
|
|
|
40,136
|
|
Gain (loss) on sale of assets
|
—
|
|
|
(63
|
)
|
|
|
1,483
|
|
|
5,076
|
|
|
|
840
|
|
Gain (loss) on derivatives
|
12,412
|
|
|
(29,219
|
)
|
|
|
(11,365
|
)
|
|
(51,230
|
)
|
|
|
6,663
|
|
Total revenue
|
145,717
|
|
|
82,200
|
|
|
|
259,252
|
|
|
123,218
|
|
|
|
47,639
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
15,114
|
|
|
12,679
|
|
|
|
35,058
|
|
|
20,996
|
|
|
|
4,408
|
|
Transportation, processing and marketing
|
6,837
|
|
|
5,396
|
|
|
|
11,440
|
|
|
8,755
|
|
|
|
3,725
|
|
Midstream operating
|
6,520
|
|
|
3,313
|
|
|
|
12,671
|
|
|
3,900
|
|
|
|
—
|
|
Cost of sales for purchased gathered production
|
8,720
|
|
|
8,902
|
|
|
|
18,415
|
|
|
12,711
|
|
|
|
—
|
|
Production taxes
|
5,117
|
|
|
2,606
|
|
|
|
10,600
|
|
|
4,021
|
|
|
|
953
|
|
Workovers
|
807
|
|
|
333
|
|
|
|
1,120
|
|
|
1,578
|
|
|
|
423
|
|
Exploration
|
3,289
|
|
|
8,083
|
|
|
|
5,343
|
|
|
9,668
|
|
|
|
7,003
|
|
Depreciation, depletion and amortization
|
38,009
|
|
|
33,934
|
|
|
|
75,908
|
|
|
49,613
|
|
|
|
11,670
|
|
Impairment of assets
|
6,500
|
|
|
—
|
|
|
|
6,500
|
|
|
—
|
|
|
|
—
|
|
General and administrative
|
27,172
|
|
|
22,456
|
|
|
|
56,690
|
|
|
60,208
|
|
|
|
21,234
|
|
Total operating expenses
|
118,085
|
|
|
97,702
|
|
|
|
233,745
|
|
|
171,450
|
|
|
|
49,416
|
|
Operating income
|
27,632
|
|
|
(15,502
|
)
|
|
|
25,507
|
|
|
(48,232
|
)
|
|
|
(1,777
|
)
|
Other income (expense)
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
(16,755
|
)
|
|
(11,779
|
)
|
|
|
(32,215
|
)
|
|
(17,223
|
)
|
|
|
(5,511
|
)
|
Interest income
|
79
|
|
|
824
|
|
|
|
130
|
|
|
1,370
|
|
|
|
172
|
|
Equity in earnings of unconsolidated subsidiaries
|
643
|
|
|
—
|
|
|
|
742
|
|
|
—
|
|
|
|
—
|
|
Total other income (expense), net
|
(16,033
|
)
|
|
(10,955
|
)
|
|
|
(31,343
|
)
|
|
(15,853
|
)
|
|
|
(5,339
|
)
|
Income (loss) from continuing operations before income taxes
|
11,599
|
|
|
(26,457
|
)
|
|
|
(5,836
|
)
|
|
(64,085
|
)
|
|
|
(7,116
|
)
|
Income tax provision (benefit)
|
—
|
|
|
(3,791
|
)
|
|
|
—
|
|
|
(7,665
|
)
|
|
|
—
|
|
Income (loss) from continuing operations
|
11,599
|
|
|
(22,666
|
)
|
|
|
(5,836
|
)
|
|
(56,420
|
)
|
|
|
(7,116
|
)
|
Loss from discontinued operations, net of tax
|
—
|
|
|
—
|
|
|
|
—
|
|
|
—
|
|
|
|
(7,746
|
)
|
Net income (loss)
|
11,599
|
|
|
(22,666
|
)
|
|
|
(5,836
|
)
|
|
(56,420
|
)
|
|
|
$
|
(14,862
|
)
|
Net income (loss) attributable to noncontrolling interests
|
9,354
|
|
|
(16,066
|
)
|
|
|
326
|
|
|
(36,490
|
)
|
|
|
|
Net income (loss) attributable to Alta Mesa Resources, Inc. stockholders
|
$
|
2,245
|
|
|
$
|
(6,600
|
)
|
|
|
$
|
(6,162
|
)
|
|
$
|
(19,930
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Attributable to Alta Mesa Resources, Inc. stockholders:
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) per share - basic and diluted
|
$
|
0.01
|
|
|
$
|
(0.04
|
)
|
|
|
$
|
(0.03
|
)
|
|
$
|
(0.12
|
)
|
|
|
|
Weighted average shares outstanding - basic
|
180,742,049
|
|
|
173,345,982
|
|
|
|
180,505,318
|
|
|
171,908,486
|
|
|
|
|
Weighted average shares outstanding - diluted
|
180,742,049
|
|
|
207,965,929
|
|
|
|
180,505,318
|
|
|
208,112,707
|
|
|
|
|
The accompanying notes are an integral part of these financial statements.
ALTA MESA RESOURCES, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)
(in thousands, except shares and per share data)
|
|
|
|
|
|
|
|
|
|
June 30, 2019
|
|
December 31, 2018
|
ASSETS
|
|
|
|
Current assets
|
|
|
|
Cash and cash equivalents
|
$
|
91,111
|
|
|
$
|
26,854
|
|
Restricted cash
|
890
|
|
|
1,001
|
|
Accounts receivable, net
|
73,776
|
|
|
87,842
|
|
Other receivables
|
3,635
|
|
|
6,331
|
|
Related party receivables, net
|
2,310
|
|
|
3,341
|
|
Prepaid expenses and other
|
5,575
|
|
|
1,125
|
|
Derivatives
|
4,727
|
|
|
16,423
|
|
Total current assets
|
182,024
|
|
|
142,917
|
|
Property and equipment, net
|
|
|
|
Oil and gas properties, successful efforts method
|
784,079
|
|
|
763,337
|
|
Other property and equipment
|
470,547
|
|
|
444,269
|
|
Total property and equipment, net
|
1,254,626
|
|
|
1,207,606
|
|
Other assets
|
|
|
|
Operating lease right-of-use assets, net
|
8,180
|
|
|
—
|
|
Equity method investment
|
1,842
|
|
|
1,100
|
|
Deferred financing costs, net
|
2,836
|
|
|
3,195
|
|
Deposits and other long-term assets
|
41
|
|
|
65
|
|
Derivatives
|
2,508
|
|
|
2,947
|
|
Total other assets
|
15,407
|
|
|
7,307
|
|
Total assets
|
$
|
1,452,057
|
|
|
$
|
1,357,830
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2019
|
|
December 31, 2018
|
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
|
|
|
Current liabilities
|
|
|
|
Current portion of debt
|
$
|
1,089,162
|
|
|
$
|
690,123
|
|
Accounts payable and accrued liabilities
|
109,901
|
|
|
247,439
|
|
Advances from non-operators
|
1,755
|
|
|
5,193
|
|
Advances from related party
|
4,003
|
|
|
9,839
|
|
Asset retirement obligations, current portion
|
44
|
|
|
2,079
|
|
Current operating lease liability
|
1,018
|
|
|
—
|
|
Derivatives
|
840
|
|
|
1,710
|
|
Total current liabilities
|
1,206,723
|
|
|
956,383
|
|
Long-term liabilities
|
|
|
|
Asset retirement obligations, net of current portion
|
12,442
|
|
|
9,473
|
|
Long-term debt, net
|
—
|
|
|
174,000
|
|
Other long-term liabilities
|
5,096
|
|
|
1,667
|
|
Operating lease liabilities, net of current portion
|
13,962
|
|
|
—
|
|
Derivatives
|
189
|
|
|
180
|
|
Total long-term liabilities
|
31,689
|
|
|
185,320
|
|
Total liabilities
|
1,238,412
|
|
|
1,141,703
|
|
Preferred Stock, $0.0001 par value
|
|
|
|
|
|
Class A: 1,000,000 shares authorized; 3 shares issued; 2 outstanding
|
—
|
|
|
—
|
|
Class B: 1,000,000 shares authorized; 1 share issued and outstanding
|
—
|
|
|
—
|
|
Common stock, $0.0001 par value
|
|
|
|
Class A: 1,200,000,000 shares authorized; 182,636,433 shares issued and outstanding (180,072,227 issued and outstanding at December 31, 2018)
|
18
|
|
|
18
|
|
Class C: 280,000,000 shares authorized; 199,987,976 and 202,169,576 issued and outstanding at June 30, 2019 and December 31, 2018
|
20
|
|
|
20
|
|
Additional paid in capital
|
1,509,716
|
|
|
1,503,382
|
|
Accumulated deficit
|
(1,538,975
|
)
|
|
(1,532,813
|
)
|
Total stockholders’ equity
|
(29,221
|
)
|
|
(29,393
|
)
|
Noncontrolling interests
|
242,866
|
|
|
245,520
|
|
Total equity
|
213,645
|
|
|
216,127
|
|
Total liabilities and stockholders’ equity
|
$
|
1,452,057
|
|
|
$
|
1,357,830
|
|
The accompanying notes are an integral part of these financial statements.
ALTA MESA RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
Six Months Ended
June 30, 2019
|
|
February 9, 2018
Through
June 30, 2018
|
|
|
January 1, 2018
Through
February 8, 2018
|
Cash flows from operating activities:
|
|
|
|
|
|
|
Net loss
|
$
|
(5,836
|
)
|
|
$
|
(56,420
|
)
|
|
|
$
|
(14,862
|
)
|
Adjustments to reconcile net loss to cash from operating activities:
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
75,908
|
|
|
49,613
|
|
|
|
12,554
|
|
Non-cash lease expense
|
1,675
|
|
|
—
|
|
|
|
—
|
|
Provision for uncollectible receivables
|
1,177
|
|
|
—
|
|
|
|
—
|
|
Impairment of assets
|
6,500
|
|
|
—
|
|
|
|
5,560
|
|
Amortization of deferred financing costs
|
368
|
|
|
152
|
|
|
|
171
|
|
Amortization of debt premium
|
(2,462
|
)
|
|
(2,051
|
)
|
|
|
—
|
|
Equity-based compensation expense
|
3,519
|
|
|
7,729
|
|
|
|
—
|
|
Non-cash exploration expense
|
388
|
|
|
7,288
|
|
|
|
4,575
|
|
(Gain) loss on derivatives
|
11,365
|
|
|
51,230
|
|
|
|
(6,663
|
)
|
Cash settlements of derivatives
|
909
|
|
|
(18,334
|
)
|
|
|
(2,296
|
)
|
Premium paid on derivatives
|
(1,000
|
)
|
|
—
|
|
|
|
—
|
|
Interest converted into debt
|
—
|
|
|
—
|
|
|
|
103
|
|
Interest added to notes receivable from affiliate
|
—
|
|
|
(417
|
)
|
|
|
(85
|
)
|
Deferred tax provision (benefit)
|
—
|
|
|
(7,665
|
)
|
|
|
—
|
|
Loss on sale of fixed assets
|
114
|
|
|
63
|
|
|
|
1,923
|
|
Equity in earnings of unconsolidated subsidiaries
|
(742
|
)
|
|
—
|
|
|
|
—
|
|
Impact on cash from changes in:
|
|
|
|
|
|
|
Accounts receivable
|
13,744
|
|
|
(9,143
|
)
|
|
|
(21,184
|
)
|
Other receivables
|
2,696
|
|
|
996
|
|
|
|
(662
|
)
|
Related party receivables
|
179
|
|
|
(6,260
|
)
|
|
|
(117
|
)
|
Prepaid expenses and other assets
|
(4,426
|
)
|
|
8,116
|
|
|
|
(591
|
)
|
Advances from related party
|
(154
|
)
|
|
(10,371
|
)
|
|
|
24,116
|
|
Settlement of asset retirement obligations
|
(5,835
|
)
|
|
(806
|
)
|
|
|
(63
|
)
|
Accounts payable, accrued liabilities and other liabilities
|
(12,123
|
)
|
|
(78,542
|
)
|
|
|
23,857
|
|
Operating lease obligations
|
(1,376
|
)
|
|
—
|
|
|
|
—
|
|
Cash from operating activities
|
84,588
|
|
|
(64,822
|
)
|
|
|
26,336
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
Capital expenditures
|
(247,942
|
)
|
|
(340,631
|
)
|
|
|
(36,695
|
)
|
Acquisitions, net of cash acquired
|
—
|
|
|
(791,819
|
)
|
|
|
(1,218
|
)
|
Proceeds withdrawn from trust account
|
—
|
|
|
1,042,742
|
|
|
|
—
|
|
Investment in equity affiliate and other, net
|
—
|
|
|
(6,945
|
)
|
|
|
—
|
|
Cash from investing activities
|
(247,942
|
)
|
|
(96,653
|
)
|
|
|
(37,913
|
)
|
Cash flows from financing activities:
|
|
|
|
|
|
|
Proceeds from long-term debt borrowings
|
227,500
|
|
|
80,000
|
|
|
|
60,000
|
|
Repayments of long-term debt
|
—
|
|
|
(193,565
|
)
|
|
|
(43,000
|
)
|
Deferred financing costs paid
|
—
|
|
|
(3,670
|
)
|
|
|
—
|
|
Capital distributions
|
—
|
|
|
—
|
|
|
|
(68
|
)
|
Proceeds from issuance of Class A shares
|
—
|
|
|
400,000
|
|
|
|
—
|
|
Repayment of sponsor note
|
—
|
|
|
(2,000
|
)
|
|
|
—
|
|
Repayment of deferred underwriting compensation
|
—
|
|
|
(36,225
|
)
|
|
|
—
|
|
Redemption of Class A common shares
|
—
|
|
|
(33
|
)
|
|
|
—
|
|
Cash from financing activities
|
227,500
|
|
|
244,507
|
|
|
|
16,932
|
|
Net increase in cash, cash equivalents and restricted cash
|
64,146
|
|
|
83,032
|
|
|
|
5,355
|
|
Cash, cash equivalents and restricted cash, beginning of period
|
27,855
|
|
|
388
|
|
|
|
4,990
|
|
Cash, cash equivalents and restricted cash, end of period
|
$
|
92,001
|
|
|
$
|
83,420
|
|
|
|
$
|
10,345
|
|
The accompanying notes are an integral part of these financial statements.
ALTA MESA RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY (Successor)
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Stock
|
|
|
|
|
|
Total
|
|
|
|
|
|
Class A
|
|
Class B
|
|
Class C
|
|
Paid-In
|
|
Accumulated
|
|
Stockholders’
|
|
Noncontrolling
|
|
Total
|
|
Shares
|
|
Amount
|
|
Shares
|
|
Amount
|
|
Shares
|
|
Amount
|
|
Capital
|
|
Deficit
|
|
Equity
|
|
Interests
|
|
Equity
|
Balance at February 8, 2018
|
3,862
|
|
|
$
|
—
|
|
|
25,875
|
|
|
$
|
3
|
|
|
—
|
|
|
$
|
—
|
|
|
$
|
3,106
|
|
|
$
|
(8,114
|
)
|
|
$
|
(5,005
|
)
|
|
$
|
—
|
|
|
$
|
(5,005
|
)
|
Conversion of common shares from Class B to Class A at closing of Business Combination
|
25,875
|
|
|
3
|
|
|
(25,875
|
)
|
|
(3
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Class A common shares released from possible redemption
|
99,638
|
|
|
10
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
996,374
|
|
|
—
|
|
|
996,384
|
|
|
—
|
|
|
996,384
|
|
Class A common shares redeemed
|
(3
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(33
|
)
|
|
—
|
|
|
(33
|
)
|
|
—
|
|
|
(33
|
)
|
Sale of Class A common shares
|
40,000
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
399,996
|
|
|
—
|
|
|
400,000
|
|
|
—
|
|
|
400,000
|
|
Class C common shares issued in connection with the closing of the Business Combination
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
213,402
|
|
|
21
|
|
|
(21
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Noncontrolling interest in SRII Opco issued in the Business Combination
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,058,635
|
|
|
2,058,635
|
|
Balance at February 9, 2018
|
169,372
|
|
|
17
|
|
|
—
|
|
|
—
|
|
|
213,402
|
|
|
21
|
|
|
1,399,422
|
|
|
(8,114
|
)
|
|
1,391,346
|
|
|
2,058,635
|
|
|
3,449,981
|
|
Equity based compensation expense
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,466
|
|
|
—
|
|
|
3,466
|
|
|
—
|
|
|
3,466
|
|
Net loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(13,330
|
)
|
|
(13,330
|
)
|
|
(20,424
|
)
|
|
(33,754
|
)
|
Balance at March 31, 2018
|
169,372
|
|
|
17
|
|
|
—
|
|
|
—
|
|
|
213,402
|
|
|
21
|
|
|
1,402,888
|
|
|
(21,444
|
)
|
|
1,381,482
|
|
|
2,038,211
|
|
|
3,419,693
|
|
Additional Class C common shares issued in connection with the settlement of the purchase consideration in the business combination
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,109
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Noncontrolling interest in SRII Opco assumed in the business combination
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8,758
|
|
|
8,758
|
|
Redemption of noncontrolling interests and Class C common shares for Class A common shares
|
9,589
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
(9,589
|
)
|
|
(1
|
)
|
|
90,872
|
|
|
—
|
|
|
90,872
|
|
|
(91,309
|
)
|
|
(437
|
)
|
Restricted stock awards vested
|
98
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Equity based compensation expense
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,263
|
|
|
—
|
|
|
4,263
|
|
|
—
|
|
|
4,263
|
|
Net loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6,600
|
)
|
|
(6,600
|
)
|
|
(16,066
|
)
|
|
(22,666
|
)
|
Balance at June 30, 2018
|
179,059
|
|
|
$
|
18
|
|
|
—
|
|
|
$
|
—
|
|
|
204,922
|
|
|
$
|
20
|
|
|
$
|
1,498,023
|
|
|
$
|
(28,044
|
)
|
|
$
|
1,470,017
|
|
|
$
|
1,939,594
|
|
|
$
|
3,409,611
|
|
The accompanying notes are an integral part of these financial statements.
ALTA MESA RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY (Successor)
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Stock
|
|
|
|
|
|
Total
|
|
|
|
|
|
Class A
|
|
Class B
|
|
Class C
|
|
Paid-In
|
|
Accumulated
|
|
Stockholders’
|
|
Noncontrolling
|
|
Total
|
|
Shares
|
|
Amount
|
|
Shares
|
|
Amount
|
|
Shares
|
|
Amount
|
|
Capital
|
|
Deficit
|
|
Equity
|
|
Interests
|
|
Equity
|
Balance at January 1, 2019
|
180,072
|
|
|
$
|
18
|
|
|
—
|
|
|
$
|
—
|
|
|
202,170
|
|
|
$
|
20
|
|
|
$
|
1,503,382
|
|
|
$
|
(1,532,813
|
)
|
|
$
|
(29,393
|
)
|
|
$
|
245,520
|
|
|
$
|
216,127
|
|
Restricted stock awards vested, net of taxes
|
338
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
67
|
|
|
—
|
|
|
67
|
|
|
(209
|
)
|
|
(142
|
)
|
Equity-based compensation expense
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,679
|
|
|
—
|
|
|
2,679
|
|
|
—
|
|
|
2,679
|
|
Net loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(8,407
|
)
|
|
(8,407
|
)
|
|
(9,028
|
)
|
|
(17,435
|
)
|
Balance at March 31, 2019
|
180,410
|
|
|
18
|
|
|
—
|
|
|
—
|
|
|
202,170
|
|
|
20
|
|
|
1,506,128
|
|
|
(1,541,220
|
)
|
|
(35,054
|
)
|
|
236,283
|
|
|
201,229
|
|
Conversion of commons shares from Class C shares to Class A
|
2,182
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,182
|
)
|
|
—
|
|
|
2,756
|
|
|
—
|
|
|
2,756
|
|
|
(2,756
|
)
|
|
—
|
|
Restricted stock awards vested, net of taxes
|
44
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(8
|
)
|
|
—
|
|
|
(8
|
)
|
|
(15
|
)
|
|
(23
|
)
|
Equity-based compensation
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
840
|
|
|
—
|
|
|
840
|
|
|
—
|
|
|
840
|
|
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,245
|
|
|
2,245
|
|
|
9,354
|
|
|
11,599
|
|
Balance at June 30, 2019
|
182,636
|
|
|
$
|
18
|
|
|
—
|
|
|
$
|
—
|
|
|
199,988
|
|
|
$
|
20
|
|
|
$
|
1,509,716
|
|
|
$
|
(1,538,975
|
)
|
|
$
|
(29,221
|
)
|
|
$
|
242,866
|
|
|
$
|
213,645
|
|
The accompanying notes are an integral part of these financial statements.
ALTA MESA RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ CAPITAL (Unaudited)
(in thousands)
|
|
|
|
|
|
Predecessor
|
Balance, December 31, 2017
|
$
|
154,445
|
|
Distribution of non-STACK oil and gas assets, net of associated liabilities
|
43,482
|
|
Net loss
|
(14,862
|
)
|
Balance, February 8, 2018
|
$
|
183,065
|
|
The accompanying notes are an integral part of these financial statements.
ALTA MESA RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
NOTE 1 — DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION
Alta Mesa Resources, Inc., together with its consolidated subsidiaries (“we” or “the Company”), is an independent exploration and production company focused on the acquisition, development, exploration and production of unconventional onshore oil and natural gas reserves in the eastern portion of the Anadarko Basin in Oklahoma. We operate in two reportable business segments - Upstream and Midstream. Alta Mesa Holdings, LP (“Alta Mesa”) conducts our Upstream activities and owns our proved and unproved oil and gas properties located in an area of the Anadarko Basin commonly referred to as the STACK. We generate upstream revenue principally by the production and sale of oil, gas and NGLs. We also operate in the Midstream segment through Kingfisher Midstream, LLC (“KFM”). KFM has a gas and oil gathering network, a cryogenic gas processing plant with offtake capacity, field compression facilities and a produced water disposal system in the Anadarko Basin that generate revenue primarily through long-term, fee-based contracts. The KFM midstream assets are integral to our Upstream operations, which we conduct in the same region, and they are strategically positioned to provide similar services to other producers in the area.
We were originally incorporated in Delaware in November 2016 as a special purpose acquisition company under the name Silver Run Acquisition Corporation II for the purpose of effecting a merger, exchange, acquisition, purchase, reorganization or similar business combination involving it and one or more businesses. On February 9, 2018 we acquired interests in Alta Mesa, Alta Mesa Holdings GP, LLC (“Alta Mesa GP”) and KFM through a newly formed subsidiary, SRII Opco, LP (“SRII Opco”) in a transaction referred to as the “Business Combination”, and changed our name from “Silver Run Acquisition Corporation II” to “Alta Mesa Resources, Inc.” As a result of our failure to comply with the continued listing requirements of the NASDAQ Capital Market (“NASDAQ”), trading in our Class A Common Stock and public warrants was suspended on September 24, 2019, and they are now traded over the counter under the trading symbols “AMRQQ” and “AMRWQ,” respectively.
In connection with the closing of the Business Combination, Alta Mesa distributed its non-STACK oil and gas assets and associated liabilities to its prior owner, High Mesa Holdings, LP (“High Mesa”). The non-STACK assets and liabilities are reflected as discontinued operations in the Predecessor portion of our financial statements.
All intercompany transactions and accounts have been eliminated. These interim condensed consolidated financial statements are unaudited, but we believe these statements reflect all adjustments necessary for a fair presentation of the periods reported. All such adjustments are of a normal, recurring nature unless otherwise disclosed. These financial statements and disclosures have been prepared in accordance with the SEC’s rules for interim financial statements and do not include all the information and disclosures required by generally accepted accounting principles (“GAAP”) for complete financial statements. These financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in our 2018 10-K. The results for the three and six months ended June 30, 2019 are not necessarily indicative of the results to be expected for the full year. We have no items of other comprehensive income during any period presented. Certain prior period amounts have been reclassified to conform to the current period presentation.
NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Going Concern
We are required to evaluate our ability to continue as a going concern for a period of one year following the date of issuance of our financial statements. As part of that evaluation, we took into consideration a number of factors that were previously disclosed in our 2018 10-K. Most significantly, we have seen significant reductions to our borrowing base under the Alta Mesa RBL in 2019. On April 1, 2019, our borrowing base under the Alta Mesa RBL was reduced by $30 million to $370.0 million leaving us with no meaningful remaining capacity available thereunder at that time. In August 2019, the Alta Mesa RBL lenders exercised their ability to make an optional redetermination of our borrowing base ahead of the regular redetermination scheduled in October 2019, and via this redetermination our borrowing base was reset to $200.0 million, effective August 13, 2019. As our combined borrowings and letters of credit outstanding exceeded the new borrowing base amount by $162.4 million, we had five months, beginning September 2019, to make ratable monthly payments of $32.5 million to cause utilization to be less than or equal to the borrowing base. Our Upstream business had cash on hand at August 31, 2019 of $63.0 million.
If by September 12, 2019, we had not made the first payment of $32.5 million, we would have been in default. Despite taking various actions to decrease our indebtedness and maintain our liquidity at sufficient levels to meet our commitments, on September 11, 2019, the Company, Alta Mesa, Alta Mesa GP, OEM GP, LLC, Alta Mesa Finance Services Corp, Alta Mesa Services and Oklahoma Energy Acquisitions, LP (the “AMH Debtors” and together with the Company, the “Debtors”) filed voluntary petitions (the “Bankruptcy Petitions”) for reorganization under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). The Bankruptcy Court has granted a motion seeking joint administration of the Chapter 11 cases under the caption In re Alta Mesa Resources, Inc., et. al., Case No. 19-35133. The Debtors will continue to operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.
Certain of the Company’s other subsidiaries, including SRII Opco GP, LLC, SRII Opco, KFM and its subsidiaries Kingfisher STACK Oil Pipeline, LLC and Oklahoma Produced Water Solutions, LLC are not part of the Chapter 11 cases at this time.
On September 12, 2019, the Bankruptcy Court entered various orders requested by the Debtors in order to stabilize their businesses and operations as they entered into Chapter 11 bankruptcy proceedings, including orders authorizing the Debtors to honor certain obligations to employees, vendors, and holders of royalty interests. In addition, the AMH Debtors were authorized by the Bankruptcy Court to use cash collateral of the lenders under the Alta Mesa RBL. The cash collateral order permits the AMH Debtors to use their cash and proceeds of their collateral for an initial four week period on the terms and conditions agreed by the AMH Debtors and the lenders under the Alta Mesa RBL and set forth in the order. The terms and conditions include, without limitation, adherence to a budget with an agreed upon variance and meeting certain milestones. The ability to have continued access to the cash collateral will also be dependent upon the Bankruptcy Court’s approval of future versions of the cash collateral order and the related terms and conditions provided therein.
The Debtors have begun a marketing process to sell their assets, which may also include KFM’s midstream assets. Certain of the AMH Debtors have also filed a complaint seeking a Bankruptcy Court determination that the crude oil, gas, and water gathering agreements between Debtor Oklahoma Energy Acquisitions LP, an Alta Mesa subsidiary, and non-Debtors KFM and its subsidiaries can be rejected by the Debtors.
We have no meaningful cash available to us to meet our obligations apart from cash held by our subsidiaries. As a result of Alta Mesa’s bankruptcy and the limitations imposed under the approved cash collateral agreement, our only remaining source of liquidity is through KFM and SRII Opco. At August 31, 2019, SRII Opco had cash on hand of $5.7 million and KFM had cash on hand of $13.3 million, as well as remaining borrowing capacity of $74.0 million. Access to the remaining capacity under the KFM Credit Facility requires adherence to the terms and covenant compliance on a pro forma basis for any new borrowings. We believe that KFM will exhaust its borrowing capacity and fail to meet the maintenance covenants as early as the first quarter of 2020. On September 23, 2019, KFM received a letter from the Administrative Agent whereby the lenders under the KFM Credit Facility allege a potential event of default in respect of liens placed on KFM’s assets. Accordingly, we may not have access to the remaining borrowing capacity unless or until this matter is resolved, which could materially impact our ability to meet our financial obligations. These factors raise substantial unmitigated doubt about our ability to continue as a going concern.
Recently Issued Accounting Standards Applicable to Us
Adopted
Effective January 1, 2019, we adopted ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which requires that lessees recognize a lease liability, which is a lessee’s discounted obligation to make payments under a lease, and a right-of-use asset, arising from a lessee’s right to use an asset over the lease term. Upon adoption, we used the modified retrospective method to apply the standard as of January 1, 2019 for existing leases with terms in excess of 12 months entered into prior to January 1, 2019.
Not Yet Adopted
In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. This standard requires the use of a new “expected credit loss” impairment model rather than the “incurred loss” model we use today. With respect to our trade and notes receivables and certain other financial instruments,
we may be required to (i) maintain and use lifetime loss information rather than annual loss data and (ii) forecast future economic conditions and quantify the effect of those conditions on future expected losses. The standard, including related amendments, which will be effective for us no earlier than January 2020, also requires additional disclosures regarding the credit quality of our trade and notes receivables and other financial instruments. No determination has yet been made of the impact of this new standard on our financial position or results of operations.
In August 2018, the FASB issued ASU No. 2018-15, Intangibles - Goodwill and Other - Internal-Use Software (Topic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (“ASU 2018-15”). The amendments in this standard align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal use software (and hosting arrangements that include an internal-use software license). Under this new standard, a customer in a hosting arrangement that is a service contract is required to follow the guidance in Subtopic 350-40 to determine which implementation costs to capitalize as a prepaid asset related to the service contract and which costs to expense. The capitalized implementation costs are to be expensed over the term of the hosting arrangement and reflected in the same line in the consolidated statement of operations as the fees associated with the hosting element of the arrangement. Similarly, capitalized implementation costs are to be presented in the statement of cash flows in the same line as payments made for fees associated with the hosting element. We will adopt this new standard no earlier than January 1, 2020, although early adoption is permitted. We are currently evaluating the impact of this new standard on our consolidated financial position and results of operations and have not yet determined whether to apply the new standard retrospectively or prospectively to implementation costs incurred after the date of adoption.
In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820) Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement (“ASU 2018-13”), which modifies the disclosure requirements of fair value measurements. ASU 2018-13 is effective for us no earlier than January 2020. Certain disclosures are required to be applied on a retrospective basis and others on a prospective basis. We do not expect the adoption of this standard to impact our financial position or results of operations.
NOTE 3 — ADOPTION OF ASU NO. 2016-02, LEASES
ASU No. 2016-02 requires us to recognize a right-of-use (“ROU”) asset and a discounted lease liability on our balance sheet for all leases with a term longer than one year. We adopted ASU No. 2016-02 and related guidance using the modified retrospective method as of January 1, 2019, and this adoption had no effect on the earlier comparative periods presented. At adoption, we recognized operating lease ROU assets and operating lease liabilities totaling $15.4 million each. There was no adjustment to beginning retained earnings.
We lease office space, office equipment and field equipment, including compressors. Many of our leases include both lease and non-lease components which are primarily management services performed by the lessors for the underlying assets. All of our leases of office space and office equipment were classified as operating leases upon adoption. Our leases of field equipment had remaining terms of less than one year at the date of adoption and were not recognized as operating leases on our balance sheet due to our election of the short term lease practical expedient described below. Our leases do not contain any residual value guarantees or restrictive covenants. We do not currently sublease any of our ROU assets, although we may sublease our unused office lease space in the future.
Operating fixed lease expenses are recognized on a straight-line basis over the lease term. Variable lease payments, which cannot be determined at the lease commencement date, are not included in ROU assets or lease liabilities and are expensed as incurred.
Upon adoption, we selected the following practical expedients:
|
|
|
|
Practical expedient package
|
|
We did not reassess whether any expired or existing contracts are, or contain, leases.
|
|
|
We did not reassess the lease classification of any expired or existing leases.
|
|
|
We did not reassess initial direct costs of any expired or existing leases.
|
|
|
|
Hindsight practical expedient
|
|
We did not elect to use the hindsight practical expedient which allows for the use of hindsight when determining lease term, including option periods, and impairment of operating assets.
|
|
|
|
Easement expedient
|
|
We elected to maintain the current accounting treatment of existing contracts and not reassess whether those contracts met the definition of a lease.
|
|
|
|
Combining lease and non-lease components expedient
|
|
We elected to account for lease and non-lease components as a single component.
|
|
|
|
Short-term lease expedient
|
|
We elected the short-term lease recognition exemption for all classes of underlying assets. Expense for short-term leases is recognized on a straight-line basis over the lease term. Leases with an initial term of 12 months or less and that do not include an option to purchase the underlying asset that is reasonably certain to be recognized are not recorded on the balance sheet.
|
As most leases do not have readily determinable implicit rates, we estimated the incremental borrowing rates for our future lease payments based on prevailing financial market conditions at the later of date of adoption or lease commencement, credit analysis of comparable companies and management judgments to determine the present values of our lease payments. We also apply the portfolio approach to account for leases with similar terms. At June 30, 2019, the weighted-average remaining lease term of our operating leases was approximately 8.1 years and the weighted-average discount rate applied was 14.3%.
Lease Costs
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Three Months Ended
June 30, 2019
|
|
Six Months Ended June 30, 2019
|
Operating lease cost
|
|
$
|
828
|
|
|
$
|
1,675
|
|
Variable lease cost
|
|
478
|
|
|
849
|
|
Short-term lease cost
|
|
1,071
|
|
|
3,686
|
|
Total lease cost
|
|
$
|
2,377
|
|
|
$
|
6,210
|
|
|
|
|
|
|
Reported in:
|
|
|
|
|
Lease operating expense
|
|
$
|
1,029
|
|
|
$
|
3,675
|
|
General and administrative expense
|
|
1,348
|
|
|
2,535
|
|
Total lease cost
|
|
$
|
2,377
|
|
|
$
|
6,210
|
|
Operating Lease Liability Maturities as of June 30, 2019
|
|
|
|
|
|
Fiscal year
|
|
(in thousands)
|
Remainder of 2019
|
|
$
|
1,528
|
|
2020
|
|
3,081
|
|
2021
|
|
3,048
|
|
2022
|
|
3,108
|
|
2023
|
|
2,718
|
|
Thereafter
|
|
12,647
|
|
Total lease payments
|
|
26,130
|
|
Less: imputed interest
|
|
(11,150
|
)
|
Present value of operating lease liabilities
|
|
$
|
14,980
|
|
|
|
|
Current portion of operating lease liabilities
|
|
$
|
1,018
|
|
Operating lease liabilities, net of current portion
|
|
13,962
|
|
Present value of operating lease liabilities
|
|
$
|
14,980
|
|
As described further in our 2018 10-K, our minimum future contractual lease payments under ASC 840 at December 31, 2018 were $2.8 million for 2019, $2.9 million for 2020, $2.9 million for 2021, $3.1 million for 2022, $3.0 million for 2023 and $12.2 million thereafter.
Right-of-Use Asset Impairment
During the second quarter of 2019, we consolidated employees in existing leased office space in Houston, Texas and Oklahoma City, Oklahoma. We sought to sublease the unused office space within three buildings but we were unable to fully recover the cash due to the lessor under the existing operating lease obligations in those three buildings with proceeds from subleases. As a result, we recognized a $6.5 million impairment of our existing right-of-use lease assets in those buildings during the three months ended June 30, 2019. This impairment had no impact to our lease liability.
We also expect to attempt to reject certain of the leases pursuant to our Bankruptcy filing which could decrease our lease liability if we are successful with the rejection.
NOTE 4 - EARNINGS (LOSS) PER SHARE
The following table reflects the net income attributable to common stockholders and earnings per share for the periods indicated based on a weighted average number of common shares outstanding for the period:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30, 2019
|
|
Three Months Ended
June 30, 2018
|
|
|
Six Months Ended
June 30, 2019
|
|
February 9, 2018
Through
June 30, 2018
|
|
(in thousands, except shares and per share data)
|
Net income (loss) attributable to AMR Class A common stockholders
|
$
|
2,245
|
|
|
$
|
(6,600
|
)
|
|
|
$
|
(6,162
|
)
|
|
$
|
(19,930
|
)
|
Effect of dilutive Class C securities:
|
|
|
|
|
|
|
|
|
Net loss attributable to noncontrolling interests assumed to be redeemed for Class A Common Stock, net of tax
|
—
|
|
|
(2,157
|
)
|
|
|
—
|
|
|
(4,914
|
)
|
Net income (loss) attributable to AMR Class A common stockholders after assumed redemption
|
$
|
2,245
|
|
|
$
|
(8,757
|
)
|
|
|
$
|
(6,162
|
)
|
|
$
|
(24,844
|
)
|
|
|
|
|
|
|
|
|
|
Weighted average Class A common shares outstanding (Basic)
|
180,742,049
|
|
|
173,345,982
|
|
|
|
180,505,318
|
|
|
171,908,486
|
|
Effect of dilutive securities:
|
|
|
|
|
|
|
|
|
Class A shares assumed issued to holders of noncontrolling interests upon redemption
|
—
|
|
|
34,619,947
|
|
|
|
—
|
|
|
36,204,221
|
|
Weighted average common shares outstanding (Diluted)
|
180,742,049
|
|
|
207,965,929
|
|
|
|
180,505,318
|
|
|
208,112,707
|
|
|
|
|
|
|
|
|
|
|
Income (loss) per common share attributable to AMR common stockholders:
|
|
|
|
|
|
|
|
|
Basic
|
$
|
0.01
|
|
|
$
|
(0.04
|
)
|
|
|
$
|
(0.03
|
)
|
|
$
|
(0.12
|
)
|
Diluted
|
$
|
0.01
|
|
|
$
|
(0.04
|
)
|
|
|
$
|
(0.03
|
)
|
|
$
|
(0.12
|
)
|
NOTE 5 — SUPPLEMENTAL CASH FLOW INFORMATION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
(in thousands)
|
Six Months Ended
June 30, 2019
|
|
February 9, 2018
Through
June 30, 2018
|
|
|
January 1, 2018
Through
February 8, 2018
|
Supplemental cash flow information:
|
|
|
|
|
|
|
Cash paid for interest
|
$
|
29,513
|
|
|
$
|
22,996
|
|
|
|
$
|
1,145
|
|
Cash paid for income taxes, net of refunds
|
706
|
|
|
1,573
|
|
|
|
—
|
|
Non-cash investing and financing activities:
|
|
|
|
|
|
|
Increase in asset retirement obligations
|
634
|
|
|
877
|
|
|
|
—
|
|
Increase (decrease) in accruals or payables for capital expenditures
|
(127,875
|
)
|
|
(25,798
|
)
|
|
|
4,896
|
|
Increase in withholding tax accruals for share-based compensation
|
165
|
|
|
—
|
|
|
|
—
|
|
Distribution of non-STACK assets, net of liabilities
|
—
|
|
|
—
|
|
|
|
43,482
|
|
Equity issued in Business Combination
|
—
|
|
|
2,067,393
|
|
|
—
|
|
Release of common stock from possible redemption
|
—
|
|
|
966,384
|
|
|
—
|
|
Tax effect of redemption of noncontrolling interests in SRII Opco for Class A common shares and other
|
—
|
|
|
(437)
|
|
|
—
|
|
We aggregate cash, cash equivalents and restricted cash in the statements of cash flows.
NOTE 6 — RECEIVABLES
Accounts Receivable
|
|
|
|
|
|
|
|
|
(in thousands)
|
June 30, 2019
|
|
December 31, 2018
|
Production and processing sales and fees
|
$
|
41,844
|
|
|
$
|
51,004
|
|
Joint interest billings
|
20,836
|
|
|
18,147
|
|
Pooling interest (1)
|
11,506
|
|
|
18,786
|
|
Allowance for doubtful accounts
|
(410
|
)
|
|
(95
|
)
|
Total accounts receivable, net
|
$
|
73,776
|
|
|
$
|
87,842
|
|
_________________
|
|
(1)
|
Pooling interest relates to Oklahoma’s forced pooling process which permits mineral interest owners the option to participate in the drilling of proposed wells. The pooling interest listed above represents unbilled costs for wells where the option remains pending. Depending upon the mineral owner’s decision, these costs will be billed to them or added to oil and gas properties.
|
Related Party Receivables
|
|
|
|
|
|
|
|
|
(in thousands)
|
June 30, 2019
|
|
December 31, 2018
|
Related party receivables
|
$
|
12,197
|
|
|
$
|
12,375
|
|
Allowance for doubtful accounts
|
(9,887
|
)
|
|
(9,034
|
)
|
Related party receivables, net
|
2,310
|
|
|
3,341
|
|
|
|
|
|
Notes receivable from related parties
|
13,403
|
|
|
13,403
|
|
Allowance for doubtful accounts
|
(13,403
|
)
|
|
(13,403
|
)
|
Notes receivable from related parties, net
|
—
|
|
|
—
|
|
Related party receivables, net
|
$
|
2,310
|
|
|
$
|
3,341
|
|
Management Services Agreement with High Mesa
|
|
|
|
|
(in thousands)
|
June 30, 2019
|
High Mesa related party receivable at December 31, 2018
|
$
|
10,066
|
|
Additions
|
894
|
|
Payments
|
(1,073
|
)
|
High Mesa related party receivable at June 30, 2019
|
9,887
|
|
Allowance for uncollectibility(1)
|
(9,887
|
)
|
Balance at June 30, 2019, net
|
$
|
—
|
|
_________________
|
|
(1)
|
$9.0 million of the allowance was recognized during the 2018 Successor Period.
|
Our management services agreement with HMI (“the High Mesa Agreement”) was terminated effective January 31, 2019. Through April 1, 2019, we were obligated to take all actions that HMI reasonably requested to effect the transition of the services to a successor service provider. During the transition period, HMI agreed to pay us (i) for all services performed, (ii) an amount equal to our costs and expenses incurred in connection with providing the services as provided for in the approved budget and (iii) an amount equal to our costs and expenses reimbursable pursuant to the High Mesa Agreement. As of June 30, 2019, and December 31, 2018, approximately $9.9 million and $10.1 million, respectively, were due from HMI for reimbursement of costs and expenses which are recorded as “Related party receivables, net” in the balance sheets. HMI has disputed certain of the amounts we billed. We are pursuing remedies under applicable law in connection with repayment of this receivable. There is no guarantee that HMI will pay the amounts it owes. In addition, our ability to collect these amounts or future amounts that may become due pursuant to indemnification obligations may be adversely impacted by liquidity and solvency issues at HMI. As a result of these circumstances, we have recognized an allowance for uncollectible accounts of $9.9
million and $9.0 million as of June 30, 2019 and December 31, 2018, respectively, to fully provide for the unremitted balances. We may also be subject to future contingent liabilities for the non-STACK assets for which we should have been indemnified, including liabilities associated with litigation relating to the non-STACK assets. As of June 30, 2019 and December 31, 2018, we have established no liabilities for contingent obligations associated with non-STACK assets owned by High Mesa.
Promissory notes receivable
High Mesa Services, LLC (“HMS”), a subsidiary of HMI, defaulted under the terms of a promissory note with us when it did not pay us on February 28, 2019, and HMS has failed to cure such default. We subsequently declared all amounts owed under the note immediately due and payable and we have fully reserved the promissory note balance, including interest paid-in-kind, totaling $1.7 million as of June 30, 2019 and December 31, 2018.
In addition, we have a note receivable from HMS which matures on December 31, 2019, and bears interest at 8% per annum, which may be paid-in-kind and added to the principal amount. HMI disputes its obligations under the note. As of June 30, 2019, and December 31, 2018, the note receivable balance, including interest paid-in-kind, amounted to $11.7 million, for each respective period. This balance was fully reserved at the end of both periods.
We oppose HMI’s claims and believe HMI’s obligations under the notes to be valid assets and that the full amount is payable to us. We are pursuing remedies under applicable law in connection with repayment of the promissory notes. As a result of the potential conflict of interest from certain of AMR’s directors who are also controlling holders of HMI, AMR’s disinterested directors will address any potential conflicts of interest with respect to this matter.
NOTE 7 — PROPERTY AND EQUIPMENT
|
|
|
|
|
|
|
|
|
(in thousands)
|
June 30, 2019
|
|
December 31, 2018
|
Oil and gas properties
|
|
|
|
Unproved properties
|
$
|
76,665
|
|
|
$
|
74,217
|
|
|
|
|
|
Proved oil and gas properties
|
2,196,605
|
|
|
2,110,346
|
|
Accumulated depletion and impairment
|
(1,489,191
|
)
|
|
(1,421,226
|
)
|
Proved oil and gas properties, net
|
707,414
|
|
|
689,120
|
|
Total oil and gas properties, net
|
784,079
|
|
|
763,337
|
|
Other property and equipment
|
|
|
|
Land
|
5,600
|
|
|
5,600
|
|
Fresh water wells
|
27,373
|
|
|
27,366
|
|
Produced water disposal system
|
106,467
|
|
|
104,498
|
|
Gas processing plant and gathering lines
|
412,193
|
|
|
380,470
|
|
Office furniture, equipment and vehicles
|
3,755
|
|
|
3,703
|
|
Accumulated depreciation and impairment
|
(84,841
|
)
|
|
(77,368
|
)
|
Other property and equipment, net
|
470,547
|
|
|
444,269
|
|
Total property and equipment, net
|
$
|
1,254,626
|
|
|
$
|
1,207,606
|
|
Depletion and Depreciation Expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
(in thousands)
|
Three Months Ended
June 30, 2019
|
|
Three Months Ended
June 30, 2018
|
|
|
Six Months Ended
June 30, 2019
|
|
February 9, 2018
Through
June 30, 2018
|
|
|
January 1, 2018
Through
February 8, 2018
|
Oil and gas properties depletion
|
$
|
33,923
|
|
|
$
|
26,086
|
|
|
|
$
|
67,965
|
|
|
$
|
36,859
|
|
|
|
$
|
11,021
|
|
Midstream tangible asset depreciation
|
3,504
|
|
|
2,010
|
|
|
|
6,724
|
|
|
3,132
|
|
|
|
—
|
|
Other property and equipment depreciation
|
341
|
|
|
423
|
|
|
|
749
|
|
|
586
|
|
|
|
609
|
|
Total depletion and depreciation
|
$
|
37,768
|
|
|
$
|
28,519
|
|
|
|
$
|
75,438
|
|
|
$
|
40,577
|
|
|
|
$
|
11,630
|
|
Impairment
During the three months ended June 30, 2019, we evaluated the qualitative market conditions and other factors impacting our business and concluded that there were no indicators of impairment of our long-lived assets. Therefore, we did not conduct further analysis on the recognition of additional impairment.
NOTE 8 — DISCONTINUED OPERATIONS (Predecessor)
The results of operations of the non-STACK oil and gas assets and related liabilities distributed to High Mesa immediately prior to the Business Combination and presented as discontinued operations during the Predecessor Period were as follows:
|
|
|
|
|
|
Predecessor
|
(in thousands)
|
January 1, 2018
Through
February 8, 2018
|
Revenue
|
|
Oil
|
$
|
1,617
|
|
Natural gas
|
1,023
|
|
Natural gas liquids
|
236
|
|
Other
|
16
|
|
Operating revenue
|
2,892
|
|
Loss on sale of assets
|
(1,923
|
)
|
Total revenue
|
969
|
|
Operating expenses
|
|
Lease operating
|
1,770
|
|
Transportation and marketing
|
83
|
|
Production taxes
|
167
|
|
Workovers
|
127
|
|
Depreciation, depletion and amortization
|
884
|
|
Impairment of assets
|
5,560
|
|
General and administrative
|
21
|
|
Total operating expenses
|
8,612
|
|
Other expense
|
|
Interest expense
|
(103
|
)
|
Loss from discontinued operations, net of tax
|
$
|
(7,746
|
)
|
|
|
|
|
|
|
Predecessor
|
(in thousands)
|
January 1, 2018
Through
February 8, 2018
|
Total operating cash flows of discontinued operations
|
$
|
2,974
|
|
Total investing cash flows of discontinued operations
|
(601
|
)
|
NOTE 9 — DERIVATIVES
The following summarizes the fair value and classification of our derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2019
|
Balance sheet location
|
|
Gross
fair value
of assets
|
|
Gross liabilities
offset against assets
in the Balance Sheet
|
|
Net fair
value of assets
presented in
the Balance Sheet
|
|
|
(in thousands)
|
Derivatives, current assets
|
|
$
|
13,855
|
|
|
$
|
(9,128
|
)
|
|
$
|
4,727
|
|
Derivatives, long-term assets
|
|
11,977
|
|
|
(9,469
|
)
|
|
2,508
|
|
Total
|
|
$
|
25,832
|
|
|
$
|
(18,597
|
)
|
|
$
|
7,235
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance sheet location
|
|
Gross
fair value
of liabilities
|
|
Gross assets
offset against liabilities
in the Balance Sheet
|
|
Net fair
value of liabilities
presented in
the Balance Sheet
|
|
|
(in thousands)
|
Derivatives, current liabilities
|
|
$
|
9,968
|
|
|
$
|
(9,128
|
)
|
|
$
|
840
|
|
Derivatives, long-term liabilities
|
|
9,658
|
|
|
(9,469
|
)
|
|
189
|
|
Total
|
|
$
|
19,626
|
|
|
$
|
(18,597
|
)
|
|
$
|
1,029
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2018
|
Balance sheet location
|
|
Gross
fair value
of assets
|
|
Gross liabilities
offset against assets
in the Balance Sheet
|
|
Net fair
value of assets
presented in
the Balance Sheet
|
|
|
(in thousands)
|
Derivatives, current assets
|
|
$
|
22,512
|
|
|
$
|
(6,089
|
)
|
|
$
|
16,423
|
|
Derivatives, long-term assets
|
|
7,910
|
|
|
(4,963
|
)
|
|
2,947
|
|
Total
|
|
$
|
30,422
|
|
|
$
|
(11,052
|
)
|
|
$
|
19,370
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance sheet location
|
|
Gross
fair value
of liabilities
|
|
Gross assets
offset against liabilities
in the Balance Sheet
|
|
Net fair
value of liabilities
presented in
the Balance Sheet
|
|
|
(in thousands)
|
Derivatives, current liabilities
|
|
$
|
7,799
|
|
|
$
|
(6,089
|
)
|
|
$
|
1,710
|
|
Derivatives, long-term liabilities
|
|
5,143
|
|
|
(4,963
|
)
|
|
180
|
|
Total
|
|
$
|
12,942
|
|
|
$
|
(11,052
|
)
|
|
$
|
1,890
|
|
The following table summarizes the effect of our derivatives in the consolidated statements of operations (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
Derivatives not designated as hedges
|
Three Months Ended
June 30, 2019
|
|
Three Months Ended
June 30, 2018
|
|
|
Six Months Ended
June 30, 2019
|
|
February 9, 2018
Through
June 30, 2018
|
|
|
January 1, 2018
Through
February 8, 2018
|
Gain (loss) on derivatives -
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
$
|
5,134
|
|
|
$
|
(28,712
|
)
|
|
|
$
|
(16,535
|
)
|
|
$
|
(50,656
|
)
|
|
|
$
|
4,796
|
|
Natural gas
|
7,278
|
|
|
(507
|
)
|
|
|
5,170
|
|
|
(574
|
)
|
|
|
1,867
|
|
Total gain (loss) on derivatives
|
$
|
12,412
|
|
|
$
|
(29,219
|
)
|
|
|
$
|
(11,365
|
)
|
|
$
|
(51,230
|
)
|
|
|
$
|
6,663
|
|
Other receivables at June 30, 2019 and December 31, 2018 include $1.4 million and $1.3 million, respectively, of derivative positions scheduled to be settled in the next month.
We had the following call and put derivatives at June 30, 2019:
OIL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume
|
|
Weighted
|
|
Range
|
Settlement Period and Type of Contract
|
|
in bbls
|
|
Average
|
|
High
|
|
Low
|
2019
|
|
|
|
|
|
|
|
|
|
|
|
|
Price Swap Contracts
|
|
92,000
|
|
|
$
|
63.03
|
|
|
$
|
63.03
|
|
|
$
|
63.03
|
|
Collar Contracts
|
|
|
|
|
|
|
|
|
Short Call Options
|
|
1,361,600
|
|
|
66.31
|
|
|
75.20
|
|
|
56.50
|
|
Long Put Options
|
|
1,453,600
|
|
|
53.80
|
|
|
62.00
|
|
|
50.00
|
|
Short Put Options
|
|
1,453,600
|
|
|
42.72
|
|
|
52.00
|
|
|
37.50
|
|
2020
|
|
|
|
|
|
|
|
|
Collar Contracts
|
|
|
|
|
|
|
|
|
Short Call Options
|
|
1,017,600
|
|
|
63.95
|
|
|
73.80
|
|
|
59.55
|
|
Long Put Options
|
|
1,566,600
|
|
|
56.81
|
|
|
62.50
|
|
|
50.00
|
|
Short Put Options
|
|
1,566,600
|
|
|
42.81
|
|
|
50.00
|
|
|
37.50
|
|
2021
|
|
|
|
|
|
|
|
|
Collar Contracts
|
|
|
|
|
|
|
|
|
Short Call Options
|
|
279,750
|
|
|
63.51
|
|
|
63.75
|
|
|
63.35
|
|
Long Put Options
|
|
659,850
|
|
|
46.94
|
|
|
55.00
|
|
|
41.00
|
|
Short Put Options
|
|
279,750
|
|
|
43.00
|
|
|
43.00
|
|
|
43.00
|
|
NATURAL GAS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume
|
|
Weighted
|
|
Range
|
Settlement Period and Type of Contract
|
|
in MMBtu
|
|
Average
|
|
High
|
|
Low
|
2019
|
|
|
|
|
|
|
|
|
|
|
|
|
Price Swap Contracts
|
|
7,980,000
|
|
|
$
|
2.67
|
|
|
$
|
2.72
|
|
|
$
|
2.64
|
|
Basis Swap Contracts
|
|
9,680,000
|
|
|
(0.72
|
)
|
|
(0.49
|
)
|
|
(0.93
|
)
|
Collar Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
Short Call Options
|
|
1,525,000
|
|
|
3.19
|
|
|
3.20
|
|
|
3.17
|
|
Long Put Options
|
|
1,525,000
|
|
|
2.70
|
|
|
2.70
|
|
|
2.70
|
|
Short Put Options
|
|
1,525,000
|
|
|
2.20
|
|
|
2.20
|
|
|
2.20
|
|
2020
|
|
|
|
|
|
|
|
|
|
|
|
|
Price Swap Contracts
|
|
1,284,000
|
|
|
2.54
|
|
|
2.54
|
|
|
2.54
|
|
Basis Swap Contracts
|
|
910,000
|
|
|
(0.49
|
)
|
|
(0.49
|
)
|
|
(0.50
|
)
|
Collar Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
Short Call Options
|
|
3,874,500
|
|
|
3.19
|
|
|
3.69
|
|
|
2.77
|
|
Long Put Options
|
|
10,749,500
|
|
|
2.59
|
|
|
3.00
|
|
|
2.50
|
|
Short Put Options
|
|
9,696,000
|
|
|
2.10
|
|
|
2.50
|
|
|
2.00
|
|
2021
|
|
|
|
|
|
|
|
|
Collar Contracts
|
|
|
|
|
|
|
|
|
Short Call Options
|
|
540,000
|
|
|
3.25
|
|
|
3.25
|
|
|
3.25
|
|
Long Put Options
|
|
2,790,000
|
|
|
2.62
|
|
|
2.65
|
|
|
2.50
|
|
Short Put Options
|
|
2,250,000
|
|
|
2.15
|
|
|
2.15
|
|
|
2.15
|
|
We had the following basis swaps at June 30, 2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Gas Volumes in MMBtu(1) over
Remaining Term
|
|
Reference Price 1 (1)
|
|
Reference Price 2 (1)
|
|
Period
|
|
Weighted
Average Spread
($ per MMBtu)
|
460,000
|
|
OneOK
|
|
NYMEX Henry Hub
|
|
Jul '19
|
|
—
|
|
Dec '19
|
|
$
|
(0.93
|
)
|
7,990,000
|
|
Tex/OKL Panhandle Eastern Pipeline
|
|
NYMEX Henry Hub
|
|
Jul '19
|
|
—
|
|
Dec '19
|
|
(0.70
|
)
|
910,000
|
|
Tex/OKL Panhandle Eastern Pipeline
|
|
NYMEX Henry Hub
|
|
Jan '20
|
|
—
|
|
Mar '20
|
|
(0.49
|
)
|
1,230,000
|
|
San Juan
|
|
NYMEX Henry Hub
|
|
Jul '19
|
|
—
|
|
Oct '19
|
|
(0.81
|
)
|
________________
|
|
(1)
|
Represents short swaps that fix the basis differentials between OneOK, Tex/OKL Panhandle Eastern Pipeline (“PEPL”), San Juan and NYMEX Henry Hub.
|
During September 2019, we closed out all open derivative positions resulting in net proceeds of approximately $4 million, which we applied against our outstanding borrowings under the Alta Mesa RBL.
NOTE 10 — ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
|
|
|
|
|
|
|
|
|
(in thousands)
|
June 30, 2019
|
|
December 31, 2018
|
Accounts payable
|
$
|
12,526
|
|
|
$
|
20,422
|
|
|
|
|
|
Accruals for capital expenditures
|
22,669
|
|
|
139,904
|
|
Revenue and royalties payable
|
41,304
|
|
|
50,241
|
|
Accruals for operating expenses
|
14,853
|
|
|
21,830
|
|
Accrued interest
|
6,922
|
|
|
2,477
|
|
Derivative settlements
|
743
|
|
|
109
|
|
Other
|
10,884
|
|
|
12,456
|
|
Total accrued liabilities
|
97,375
|
|
|
227,017
|
|
Accounts payable and accrued liabilities
|
$
|
109,901
|
|
|
$
|
247,439
|
|
NOTE 11 — ASSET RETIREMENT OBLIGATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
(in thousands)
|
Six Months Ended
June 30, 2019
|
|
February 9, 2018
Through
June 30, 2018
|
|
|
January 1, 2018
Through
February 8, 2018
|
Balance, beginning of period
|
$
|
11,552
|
|
|
$
|
—
|
|
|
|
$
|
10,469
|
|
Liabilities assumed in Business Combination
|
—
|
|
|
5,998
|
|
|
|
—
|
|
Liabilities incurred
|
634
|
|
|
877
|
|
|
|
—
|
|
Liabilities settled
|
(162
|
)
|
|
(806
|
)
|
|
|
(63
|
)
|
Liabilities transferred in sale of properties
|
—
|
|
|
(20
|
)
|
|
|
—
|
|
Revisions to estimates
|
(8
|
)
|
|
665
|
|
|
|
63
|
|
Accretion expense
|
470
|
|
|
263
|
|
|
|
40
|
|
Balance, end of period
|
12,486
|
|
|
6,977
|
|
|
|
10,509
|
|
Less: current portion
|
44
|
|
|
538
|
|
|
|
33
|
|
Long-term portion
|
$
|
12,442
|
|
|
$
|
6,439
|
|
|
|
$
|
10,476
|
|
NOTE 12 — DEBT
|
|
|
|
|
|
|
|
|
(in thousands)
|
June 30, 2019
|
|
December 31, 2018
|
Alta Mesa RBL
|
$
|
344,500
|
|
|
$
|
161,000
|
|
KFM Credit Facility
|
218,000
|
|
|
174,000
|
|
2024 Notes
|
500,000
|
|
|
500,000
|
|
Unamortized premium on 2024 Notes
|
26,662
|
|
|
29,123
|
|
Total debt, net
|
1,089,162
|
|
|
864,123
|
|
Less: Current portion
|
1,089,162
|
|
|
690,123
|
|
Long-term debt, net
|
$
|
—
|
|
|
$
|
174,000
|
|
Alta Mesa RBL
In April 2019, our borrowing base under the Alta Mesa RBL was reduced from $400.0 million to $370.0 million, leaving us with no meaningful remaining capacity available thereunder at that time. In August 2019, the Alta Mesa RBL lenders exercised their ability to make an optional redetermination of our borrowing base ahead of the regular redetermination scheduled in October 2019, and via this redetermination, our borrowing base was reset to $200.0 million, effective August 13, 2019. As our combined borrowings and letters of credit outstanding exceeded the new borrowing base amount by $162.4 million, we had five months, beginning September 2019, to make ratable monthly payments of $32.5 million to cause utilization to be less than or equal to the borrowing base. As indicated in our discussion of going concern, we and the AMH Debtors filed for bankruptcy protection prior to making these payments.
The Alta Mesa RBL has two covenants that are tested quarterly:
|
|
•
|
a ratio of Alta Mesa’s current assets to current liabilities, inclusive of specified adjustments, of not less than 1.0 to 1.0; and
|
|
|
•
|
a ratio of Alta Mesa’s consolidated debt to its consolidated Adjusted EBITDAX (the “leverage ratio”) of not greater than 4.0 to 1.0.
|
Alta Mesa’s filing of the Bankruptcy Petitions constituted an event of default under the Alta Mesa RBL that accelerated Alta Mesa’s obligations thereunder. Under the Bankruptcy Code, the lenders under the Alta Mesa RBL are stayed from taking any action against the AMH Debtors as a result of an event of default.
KFM Credit Facility
The KFM Credit Facility, as amended, provides for an aggregate committed borrowing capacity of $300.0 million.
There are two maintenance covenants under the KFM Credit Facility that are tested quarterly:
|
|
•
|
a ratio of KFM’s total debt to its consolidated adjusted EBITDA of not greater than 4.5 to 1.0, (which increases to 4.75 after KFM exceeds consolidated EBITDA of $75.0 million) for any 4 quarter period; and
|
|
|
•
|
a minimum interest coverage ratio of KFM’s adjusted EBITDA to interest expense of not less than 2.5 to 1.0.
|
The KFM Credit Facility also limits KFM to holding no more than $15.0 million in cash and limits its ability to amend affiliate contracts. Our bankruptcy filing did not constitute an event of default under the KFM Credit Facility.
At August 31, 2019, remaining borrowing capacity under the KFM Credit Facility totaled $74.0 million. Access to the remaining capacity under the KFM Credit Facility requires adherence to the terms and covenant compliance on a pro forma basis for any new borrowings. We believe that KFM will exhaust its borrowing capacity and fail to meet the maintenance covenants as early as the first quarter of 2020. On September 23, 2019, KFM received a letter from the Administrative Agent whereby the lenders under the KFM Credit Facility allege a potential event of default in respect of liens placed on KFM’s assets. Accordingly, we may not have access to the remaining borrowing capacity unless or until this matter is resolved, which could materially impact our ability to meet our financial obligations.
2024 Notes
We have estimated the fair value of the 2024 Notes to be $193.8 million at June 30, 2019, which is based on their most recent trading values, which is a Level 1 determination.
Alta Mesa’s filing of the Bankruptcy Petitions constituted an event of default under the 2024 Notes that accelerated Alta Mesa’s obligations thereunder. Under the Bankruptcy Code, the holders of the 2024 Notes are stayed from taking any action against Alta Mesa as a result of an event of default including acceleration.
Scheduled Maturities of Debt
|
|
|
|
|
|
Fiscal year
|
|
(in thousands)
|
2019
|
|
$
|
—
|
|
2020
|
|
—
|
|
2021
|
|
—
|
|
2022
|
|
—
|
|
2023
|
|
562,500
|
|
Thereafter
|
|
500,000
|
|
|
|
$
|
1,062,500
|
|
Based upon our going concern conclusions and the default associated with Alta Mesa’s bankruptcy filing, we believe that our indebtedness under the Alta Mesa RBL and our 2024 Notes should be reported as current liabilities despite their scheduled maturities shown above. We have reported our Alta Mesa RBL debt and our 2024 Notes as current at June 30, 2019. In addition, based on the factors described under “KFM Credit Facility” above, we have also reported all of our Midstream debt as current at June 30, 2019 despite the scheduled maturities shown above.
NOTE 13 — COMMITMENTS AND CONTINGENCIES
There have been no material developments during the first six months of 2019 in relation to our commitments and contingencies as compared to our discussion of those matters in our 2018 10-K. The commencement of the Chapter 11 proceedings automatically stayed certain actions against the Company, including the matters discussed in our 2018 10-K.
NOTE 14 — SIGNIFICANT CONCENTRATIONS
During most of the first quarter of 2019 and throughout 2018, ARM Energy Management, LLC ("ARM") marketed our oil, gas and NGLs for a marketing fee that is deducted from sales proceeds collected by ARM from purchasers. The sales were generally made under short-term contracts with month-to-month pricing based on published regional indices, adjusted for transportation, location and quality. In March 2019, in preparation for handling oil and NGL marketing responsibilities internally, we began receiving payments for the sale of oil and NGLs directly from purchasers and separately paying the marketing fee owed to ARM. As of June 1, 2019, we terminated our oil and NGL marketing agreement with ARM and have begun marketing such products internally. We have extended the term of our gas marketing agreement with ARM through November 30, 2019.
ARM has also provided us with strategic advice, execution and reporting services with respect to our derivatives activities.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
(in thousands)
|
Three Months Ended
June 30, 2019
|
|
Three Months Ended
June 30, 2018
|
|
|
Six Months Ended
June 30, 2019
|
|
February 9, 2018
Through
June 30, 2018
|
|
|
January 1, 2018
Through
February 8, 2018
|
Revenue marketed by ARM on our behalf
|
$
|
25,833
|
|
|
$
|
90,206
|
|
|
|
$
|
119,224
|
|
|
$
|
131,422
|
|
|
|
$
|
28,757
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marketing and management fees paid to ARM
|
$
|
519
|
|
|
$
|
—
|
|
|
|
$
|
1,216
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
Fees paid to ARM for services relating to our derivatives
|
218
|
|
|
209
|
|
|
|
411
|
|
|
283
|
|
|
|
66
|
|
Total fees paid to ARM
|
$
|
737
|
|
|
$
|
209
|
|
|
|
$
|
1,627
|
|
|
$
|
283
|
|
|
|
$
|
66
|
|
Receivables from ARM for sales on our behalf were $6.6 million and $43.8 million as of June 30, 2019 and December 31, 2018, respectively, which are reflected in accounts receivable on our balance sheets.
We believe that the loss of any of our customers, or of our marketing agent ARM, would not have a material adverse effect on us because alternative purchasers and marketing firms are readily available.
NOTE 15 — EQUITY-BASED COMPENSATION (Successor)
Stock compensation expense recognized was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
(in thousands)
|
Three Months Ended
June 30, 2019
|
|
Three Months Ended
June 30, 2018
|
|
|
Six Months Ended
June 30, 2019
|
|
February 9, 2018
Through
June 30, 2018
|
|
|
January 1, 2018
Through
February 8, 2018
|
Stock options
|
$
|
660
|
|
|
$
|
1,722
|
|
|
|
$
|
1,899
|
|
|
$
|
2,787
|
|
|
|
$
|
—
|
|
Restricted stock awards
|
35
|
|
|
1,260
|
|
|
|
1,468
|
|
|
2,493
|
|
|
|
—
|
|
Performance-based restricted stock units
|
145
|
|
|
1,281
|
|
|
|
152
|
|
|
2,449
|
|
|
|
—
|
|
Total compensation expense
|
$
|
840
|
|
|
$
|
4,263
|
|
|
|
$
|
3,519
|
|
|
$
|
7,729
|
|
|
|
$
|
—
|
|
Performance-based restricted stock units (“PSUs”) issued in 2018 generally vest over three years at 20% during the first year (“2018 tranche”), 30% during the second year (“2019 tranche”), and 50% during the third year (“2020 tranche”). The number of PSUs vesting each year is based on achievement of annual company-specific performance goals and obligations applicable to each year of vesting. Based on achievement of those goals and objectives, the number of PSUs that can vest range from 0% to 200% of the target growth applicable to each vesting period. The performance goals set for the 2018 tranche were not attained and, therefore, the 2018 tranche was forfeited as of December 31, 2018, except with respect to separations involving employment agreements whereby the separated employee was eligible to receive the award granted.
The performance targets for the 2019 tranche of performance-based restricted stock units were established in March 2019 and 572,990 PSUs were deemed granted at that time. The fair value of the 2019 tranche granted was $0.27 per unit, which will be recognized as expense over the remainder of 2019, subject to continued employment.
No performance targets have yet been established for the 2020 tranche and therefore, no expense will be recognized for those awards until the specific targets have been established and probability of attainment can be measured.
NOTE 16 — RELATED PARTY TRANSACTIONS
David Murrell, our Vice President of Land and Business Development, is the principal of David Murrell & Associates, which provided land consulting services to us until termination of our contract in December 2018. The primary employee of David Murrell & Associates is his spouse, Brigid Murrell. Services were provided at a pre-negotiated hourly rate based on actual time utilized by us. Total expenditures under this arrangement were approximately $83,000 and $28,000 for the period February 9,
2018 through June 30, 2018, and the Predecessor Period, respectively. These amounts are recorded in general and administrative expenses.
David McClure, AMR’s former Vice President of Facilities and Infrastructure, and the son-in-law of our former President and Chief Executive Officer, Harlan H. Chappelle, received total compensation of $768,860, $1,017,711 and $28,874 during the six months ended June 30, 2019, the period February 9, 2018 through June 30, 2018, and the Predecessor Period, respectively. These amounts are included in general and administrative expense. Mr. McClure separated from the Company in February 2019.
David Pepper, Surface Land Manager for KFM, and the cousin of our Vice President of Land and Business Development, David Murrell, received total compensation of $117,962, $297,134, $67,322, for the six months ended June 30, 2019, the period February 9, 2018 through June 30, 2018, and the Predecessor Period, respectively. These amounts are included in general and administrative expense.
Bayou City Agreement
In January 2016, our wholly owned subsidiary Oklahoma Energy entered into a Joint Development Agreement, as amended on June 10, 2016 and December 31, 2016, (the “JDA”), with BCE, a fund advised by Bayou City, to fund a portion of our drilling operations and to allow us to accelerate development of our STACK acreage. The JDA established a development plan of 60 wells in three tranches, and provides opportunities for an additional 20 wells. Pursuant to the JDA, BCE committed to fund 100% of our working interest share up to a maximum average well cost of $3.2 million in drilling and completion costs per well for any tranche. We are responsible for any drilling and completion costs exceeding approved amounts. BCE may request refunds of certain advances from time to time if funded wells previously on the drilling schedule were subsequently removed. In exchange for funding the drilling and completion costs, BCE receives 80% of our working interest in each wellbore, which BCE interest will be reduced to 20% of our initial working interest upon BCE achieving a 15% internal rate of return on the wells within a tranche and automatically further reduced to 12.5% of our initial interest upon BCE achieving a 25% internal rate of return. Following the completion of each joint well, we and BCE will each bear our respective proportionate working interest share of all subsequent costs related to such joint well. Mr. William McMullen, one of our directors, is founder and managing partner of BCE. The approximate dollar value of the amount involved in this transaction, or Mr. McMullen’s interests in the transaction, depends on a number of factors outside his control and is not known at this time. During the Predecessor Period, BCE advanced us approximately $39.5 million to drill wells under the JDA. As of June 30, 2019, 61 joint wells have been drilled or spudded. At June 30, 2019 and December 31, 2018, $4.0 million and $9.8 million, respectively of revenue and net advances remaining from BCE for their working interest share of the drilling and development costs arising under the JDA were included as “Advances from related party” in our condensed consolidated balance sheets. At June 30, 2019, there were no funded horizontal wells in progress, and we do not expect any wells to be developed in 2019 pursuant to the JDA. On June 11, 2019, we received a letter from BCE noticing us of alleged defaults under the JDA. We dispute these allegations and intend to vigorously defend ourselves.
NOTE 17 — BUSINESS SEGMENT INFORMATION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2019
|
(in thousands)
|
Exploration &
Production
|
|
Midstream
|
|
Corporate and Eliminations
|
|
Total
|
Revenue
|
|
|
|
|
|
|
|
Oil
|
$
|
90,668
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
90,668
|
|
Natural gas
|
12,384
|
|
|
—
|
|
|
—
|
|
|
12,384
|
|
Natural gas liquids
|
10,251
|
|
|
—
|
|
|
—
|
|
|
10,251
|
|
Sales of gathered production
|
—
|
|
|
10,439
|
|
|
—
|
|
|
10,439
|
|
Midstream revenue
|
—
|
|
|
22,112
|
|
|
(15,563
|
)
|
|
6,549
|
|
Segment sales revenue
|
113,303
|
|
|
32,551
|
|
|
(15,563
|
)
|
|
130,291
|
|
Other revenue
|
330
|
|
|
6,693
|
|
|
(4,009
|
)
|
|
3,014
|
|
Operating revenue
|
113,633
|
|
|
39,244
|
|
|
(19,572
|
)
|
|
133,305
|
|
Gain on sale of assets
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Gain (loss) on derivatives
|
12,412
|
|
|
—
|
|
|
—
|
|
|
12,412
|
|
Total revenue
|
126,045
|
|
|
39,244
|
|
|
(19,572
|
)
|
|
145,717
|
|
Operating expenses
|
|
|
|
|
|
|
|
Lease operating
|
19,123
|
|
|
—
|
|
|
(4,009
|
)
|
|
15,114
|
|
Transportation, processing and marketing
|
19,614
|
|
|
2,786
|
|
|
(15,563
|
)
|
|
6,837
|
|
Midstream operating
|
—
|
|
|
6,520
|
|
|
—
|
|
|
6,520
|
|
Cost of sales for purchased gathered production
|
—
|
|
|
8,720
|
|
|
—
|
|
|
8,720
|
|
Production taxes
|
5,117
|
|
|
—
|
|
|
—
|
|
|
5,117
|
|
Workovers
|
412
|
|
|
395
|
|
|
—
|
|
|
807
|
|
Exploration
|
3,289
|
|
|
—
|
|
|
—
|
|
|
3,289
|
|
Depreciation, depletion and amortization
|
34,504
|
|
|
3,505
|
|
|
—
|
|
|
38,009
|
|
Impairment of assets
|
6,500
|
|
|
—
|
|
|
—
|
|
|
6,500
|
|
General and administrative
|
15,723
|
|
|
5,324
|
|
|
6,125
|
|
|
27,172
|
|
Total operating expenses
|
104,282
|
|
|
27,250
|
|
|
(13,447
|
)
|
|
118,085
|
|
Operating income
|
21,763
|
|
|
11,994
|
|
|
(6,125
|
)
|
|
27,632
|
|
Other income (expense)
|
|
|
|
|
|
|
|
Interest expense
|
(14,071
|
)
|
|
(2,684
|
)
|
|
—
|
|
|
(16,755
|
)
|
Interest income
|
54
|
|
|
6
|
|
|
19
|
|
|
79
|
|
Equity in earnings of unconsolidated subsidiaries
|
—
|
|
|
643
|
|
|
—
|
|
|
643
|
|
Total other income (expense)
|
(14,017
|
)
|
|
(2,035
|
)
|
|
19
|
|
|
(16,033
|
)
|
Income (loss) from continuing operations before income taxes
|
7,746
|
|
|
9,959
|
|
|
(6,106
|
)
|
|
11,599
|
|
|
|
|
|
|
|
|
|
Interest expense
|
14,071
|
|
|
2,684
|
|
|
—
|
|
|
16,755
|
|
Depreciation, depletion and amortization
|
34,504
|
|
|
3,505
|
|
|
—
|
|
|
38,009
|
|
Gain on unrealized hedges
|
(11,868
|
)
|
|
—
|
|
|
—
|
|
|
(11,868
|
)
|
Impairment of assets
|
6,500
|
|
|
—
|
|
|
—
|
|
|
6,500
|
|
Equity-based compensation
|
1,396
|
|
|
(556
|
)
|
|
—
|
|
|
840
|
|
Exploration
|
3,289
|
|
|
—
|
|
|
—
|
|
|
3,289
|
|
Severance costs
|
609
|
|
|
88
|
|
|
—
|
|
|
697
|
|
Strategic costs
|
4,061
|
|
|
—
|
|
|
—
|
|
|
4,061
|
|
Adjusted EBITDAX
|
$
|
60,308
|
|
|
$
|
15,680
|
|
|
$
|
(6,106
|
)
|
|
$
|
69,882
|
|
|
|
|
|
|
|
|
|
Equity method investment at period end
|
$
|
—
|
|
|
$
|
1,842
|
|
|
$
|
—
|
|
|
$
|
1,842
|
|
Capital expenditures
|
47,061
|
|
|
39,533
|
|
|
—
|
|
|
86,594
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2018
|
(in thousands)
|
Exploration &
Production
|
|
Midstream
|
|
Corporate and Eliminations
|
|
Total
|
Revenue
|
|
|
|
|
|
|
|
Oil
|
$
|
75,291
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
75,291
|
|
Natural gas
|
7,980
|
|
|
—
|
|
|
—
|
|
|
7,980
|
|
Natural gas liquids
|
10,241
|
|
|
—
|
|
|
—
|
|
|
10,241
|
|
Sales of gathered production
|
—
|
|
|
21,024
|
|
|
(12,100
|
)
|
|
8,924
|
|
Midstream revenue
|
—
|
|
|
15,849
|
|
|
(9,032
|
)
|
|
6,817
|
|
Segment sales revenue
|
93,512
|
|
|
36,873
|
|
|
(21,132
|
)
|
|
109,253
|
|
Other revenue
|
2,229
|
|
|
—
|
|
|
—
|
|
|
2,229
|
|
Operating revenue
|
95,741
|
|
|
36,873
|
|
|
(21,132
|
)
|
|
111,482
|
|
Gain on sale of assets
|
(63
|
)
|
|
—
|
|
|
—
|
|
|
(63
|
)
|
Gain (loss) on derivatives
|
(29,219
|
)
|
|
—
|
|
|
—
|
|
|
(29,219
|
)
|
Total revenue
|
66,459
|
|
|
36,873
|
|
|
(21,132
|
)
|
|
82,200
|
|
Operating expenses
|
|
|
|
|
|
|
|
Lease operating
|
12,679
|
|
|
—
|
|
|
—
|
|
|
12,679
|
|
Transportation, processing and marketing
|
11,205
|
|
|
3,223
|
|
|
(9,032
|
)
|
|
5,396
|
|
Midstream operating
|
—
|
|
|
3,313
|
|
|
—
|
|
|
3,313
|
|
Cost of sales for purchased gathered production
|
—
|
|
|
21,002
|
|
|
(12,100
|
)
|
|
8,902
|
|
Production taxes
|
2,606
|
|
|
—
|
|
|
—
|
|
|
2,606
|
|
Workovers
|
333
|
|
|
—
|
|
|
—
|
|
|
333
|
|
Exploration
|
8,083
|
|
|
—
|
|
|
—
|
|
|
8,083
|
|
Depreciation, depletion and amortization
|
26,670
|
|
|
7,264
|
|
|
—
|
|
|
33,934
|
|
Impairment of assets
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
General and administrative
|
17,811
|
|
|
4,140
|
|
|
505
|
|
|
22,456
|
|
Total operating expenses
|
79,387
|
|
|
38,942
|
|
|
(20,627
|
)
|
|
97,702
|
|
Operating income
|
(12,928
|
)
|
|
(2,069
|
)
|
|
(505
|
)
|
|
(15,502
|
)
|
Other income (expense)
|
|
|
|
|
|
|
|
Interest expense
|
(10,361
|
)
|
|
(1,418
|
)
|
|
—
|
|
|
(11,779
|
)
|
Interest income
|
820
|
|
|
—
|
|
|
4
|
|
|
824
|
|
Total other income (expense)
|
(9,541
|
)
|
|
(1,418
|
)
|
|
4
|
|
|
(10,955
|
)
|
Income (loss) from continuing operations before income taxes
|
(22,469
|
)
|
|
(3,487
|
)
|
|
(501
|
)
|
|
(26,457
|
)
|
|
|
|
|
|
|
|
|
Interest expense
|
10,361
|
|
|
1,418
|
|
|
—
|
|
|
11,779
|
|
Depreciation, depletion and amortization
|
26,670
|
|
|
7,264
|
|
|
—
|
|
|
33,934
|
|
Loss on unrealized hedges
|
14,860
|
|
|
—
|
|
|
—
|
|
|
14,860
|
|
Equity-based compensation
|
3,621
|
|
|
465
|
|
|
177
|
|
|
4,263
|
|
Exploration
|
8,083
|
|
|
—
|
|
|
—
|
|
|
8,083
|
|
Business Combination
|
443
|
|
|
—
|
|
|
—
|
|
|
443
|
|
Adjusted EBITDAX
|
$
|
41,569
|
|
|
$
|
5,660
|
|
|
$
|
(324
|
)
|
|
$
|
46,905
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
$
|
189,732
|
|
|
$
|
17,844
|
|
|
$
|
—
|
|
|
$
|
207,576
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2019
|
(in thousands)
|
Exploration &
Production
|
|
Midstream
|
|
Corporate and Eliminations
|
|
Total
|
Revenue
|
|
|
|
|
|
|
|
Oil
|
$
|
177,031
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
177,031
|
|
Natural gas
|
30,834
|
|
|
—
|
|
|
—
|
|
|
30,834
|
|
Natural gas liquids
|
21,467
|
|
|
—
|
|
|
—
|
|
|
21,467
|
|
Sales of gathered production
|
—
|
|
|
19,999
|
|
|
—
|
|
|
19,999
|
|
Midstream revenue
|
—
|
|
|
44,488
|
|
|
(30,784
|
)
|
|
13,704
|
|
Segment sales revenue
|
229,332
|
|
|
64,487
|
|
|
(30,784
|
)
|
|
263,035
|
|
Other revenue
|
898
|
|
|
14,374
|
|
|
(9,173
|
)
|
|
6,099
|
|
Operating revenue
|
230,230
|
|
|
78,861
|
|
|
(39,957
|
)
|
|
269,134
|
|
Gain on sale of assets
|
1,483
|
|
|
—
|
|
|
—
|
|
|
1,483
|
|
Gain (loss) on derivatives
|
(11,365
|
)
|
|
—
|
|
|
—
|
|
|
(11,365
|
)
|
Total revenue
|
220,348
|
|
|
78,861
|
|
|
(39,957
|
)
|
|
259,252
|
|
Operating expenses
|
|
|
|
|
|
|
|
Lease operating
|
44,231
|
|
|
—
|
|
|
(9,173
|
)
|
|
35,058
|
|
Transportation, processing and marketing
|
37,375
|
|
|
4,849
|
|
|
(30,784
|
)
|
|
11,440
|
|
Midstream operating
|
—
|
|
|
12,671
|
|
|
—
|
|
|
12,671
|
|
Cost of sales for purchased gathered production
|
—
|
|
|
18,415
|
|
|
—
|
|
|
18,415
|
|
Production taxes
|
10,600
|
|
|
—
|
|
|
—
|
|
|
10,600
|
|
Workovers
|
609
|
|
|
511
|
|
|
—
|
|
|
1,120
|
|
Exploration
|
5,343
|
|
|
—
|
|
|
—
|
|
|
5,343
|
|
Depreciation, depletion and amortization
|
69,179
|
|
|
6,729
|
|
|
—
|
|
|
75,908
|
|
Impairment of assets
|
6,500
|
|
|
—
|
|
|
—
|
|
|
6,500
|
|
General and administrative
|
36,670
|
|
|
13,387
|
|
|
6,633
|
|
|
56,690
|
|
Total operating expenses
|
210,507
|
|
|
56,562
|
|
|
(33,324
|
)
|
|
233,745
|
|
Operating income
|
9,841
|
|
|
22,299
|
|
|
(6,633
|
)
|
|
25,507
|
|
Other income (expense)
|
|
|
|
|
|
|
|
Interest expense
|
(26,901
|
)
|
|
(5,314
|
)
|
|
—
|
|
|
(32,215
|
)
|
Interest income
|
81
|
|
|
10
|
|
|
39
|
|
|
130
|
|
Equity in earnings of unconsolidated subsidiaries
|
—
|
|
|
742
|
|
|
—
|
|
|
742
|
|
Total other income (expense)
|
(26,820
|
)
|
|
(4,562
|
)
|
|
39
|
|
|
(31,343
|
)
|
Income (loss) from continuing operations before income taxes
|
(16,979
|
)
|
|
17,737
|
|
|
(6,594
|
)
|
|
(5,836
|
)
|
|
|
|
|
|
|
|
|
Interest expense
|
26,901
|
|
|
5,314
|
|
|
—
|
|
|
32,215
|
|
Depreciation, depletion and amortization
|
69,179
|
|
|
6,729
|
|
|
—
|
|
|
75,908
|
|
Loss on unrealized hedges
|
12,274
|
|
|
—
|
|
|
—
|
|
|
12,274
|
|
Impairment of assets
|
6,500
|
|
|
—
|
|
|
—
|
|
|
6,500
|
|
Equity-based compensation
|
3,057
|
|
|
462
|
|
|
—
|
|
|
3,519
|
|
Exploration
|
5,343
|
|
|
—
|
|
|
—
|
|
|
5,343
|
|
Severance costs
|
4,584
|
|
|
1,984
|
|
|
—
|
|
|
6,568
|
|
Strategic costs
|
4,061
|
|
|
—
|
|
|
—
|
|
|
4,061
|
|
Business Combination
|
10
|
|
|
—
|
|
|
—
|
|
|
10
|
|
Adjusted EBITDAX
|
$
|
114,930
|
|
|
$
|
32,226
|
|
|
$
|
(6,594
|
)
|
|
$
|
140,562
|
|
|
|
|
|
|
|
|
|
Equity method investment at period end
|
$
|
—
|
|
|
$
|
1,842
|
|
|
$
|
—
|
|
|
$
|
1,842
|
|
Capital expenditures
|
180,138
|
|
|
67,804
|
|
|
—
|
|
|
247,942
|
|
Total assets at period end
|
999,744
|
|
|
458,882
|
|
|
(6,569
|
)
|
|
1,452,057
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
February 9, 2018 Through June 30, 2018
|
(in thousands)
|
Exploration &
Production
|
|
Midstream
|
|
Corporate and Eliminations
|
|
Total
|
Revenue
|
|
|
|
|
|
|
|
Oil
|
$
|
115,569
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
115,569
|
|
Natural gas
|
13,190
|
|
|
—
|
|
|
—
|
|
|
13,190
|
|
Natural gas liquids
|
14,955
|
|
|
—
|
|
|
—
|
|
|
14,955
|
|
Sales of gathered production
|
—
|
|
|
31,634
|
|
|
(18,837
|
)
|
|
12,797
|
|
Midstream revenue
|
—
|
|
|
23,671
|
|
|
(13,594
|
)
|
|
10,077
|
|
Segment sales revenue
|
143,714
|
|
|
55,305
|
|
|
(32,431
|
)
|
|
166,588
|
|
Other revenue
|
2,784
|
|
|
—
|
|
|
—
|
|
|
2,784
|
|
Operating revenue
|
146,498
|
|
|
55,305
|
|
|
(32,431
|
)
|
|
169,372
|
|
Gain (loss) on sale of assets
|
5,076
|
|
|
—
|
|
|
—
|
|
|
5,076
|
|
Gain (loss) on derivatives
|
(51,230
|
)
|
|
—
|
|
|
—
|
|
|
(51,230
|
)
|
Total revenue
|
100,344
|
|
|
55,305
|
|
|
(32,431
|
)
|
|
123,218
|
|
Operating expenses
|
|
|
|
|
|
|
|
Lease operating
|
20,996
|
|
|
—
|
|
|
—
|
|
|
20,996
|
|
Transportation, processing and marketing
|
16,788
|
|
|
5,561
|
|
|
(13,594
|
)
|
|
8,755
|
|
Midstream operating
|
—
|
|
|
3,900
|
|
|
—
|
|
|
3,900
|
|
Cost of sales for purchased gathered production
|
—
|
|
|
31,548
|
|
|
(18,837
|
)
|
|
12,711
|
|
Production taxes
|
4,021
|
|
|
—
|
|
|
—
|
|
|
4,021
|
|
Workovers
|
1,578
|
|
|
—
|
|
|
—
|
|
|
1,578
|
|
Exploration
|
9,668
|
|
|
—
|
|
|
—
|
|
|
9,668
|
|
Depreciation, depletion and amortization
|
37,708
|
|
|
11,905
|
|
|
—
|
|
|
49,613
|
|
Impairment of assets
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
General and administrative
|
52,465
|
|
|
6,313
|
|
|
1,430
|
|
|
60,208
|
|
Total operating expenses
|
143,224
|
|
|
59,227
|
|
|
(31,001
|
)
|
|
171,450
|
|
Operating income
|
(42,880
|
)
|
|
(3,922
|
)
|
|
(1,430
|
)
|
|
(48,232
|
)
|
Other income (expense)
|
|
|
|
|
|
|
|
Interest expense
|
(15,557
|
)
|
|
(1,666
|
)
|
|
—
|
|
|
(17,223
|
)
|
Interest income
|
1,366
|
|
|
—
|
|
|
4
|
|
|
1,370
|
|
Total other income (expense)
|
(14,191
|
)
|
|
(1,666
|
)
|
|
4
|
|
|
(15,853
|
)
|
Income (loss) from continuing operations before income taxes
|
(57,071
|
)
|
|
(5,588
|
)
|
|
(1,426
|
)
|
|
(64,085
|
)
|
|
|
|
|
|
|
|
|
Interest expense
|
15,557
|
|
|
1,666
|
|
|
—
|
|
|
17,223
|
|
Depreciation, depletion and amortization
|
37,708
|
|
|
11,905
|
|
|
—
|
|
|
49,613
|
|
Loss on unrealized hedges
|
32,896
|
|
|
—
|
|
|
—
|
|
|
32,896
|
|
Loss on sale of fixed assets
|
63
|
|
|
—
|
|
|
—
|
|
|
63
|
|
Equity-based compensation
|
6,389
|
|
|
507
|
|
|
833
|
|
|
7,729
|
|
Exploration
|
9,668
|
|
|
—
|
|
|
—
|
|
|
9,668
|
|
Business Combination
|
23,717
|
|
|
—
|
|
|
—
|
|
|
23,717
|
|
Adjusted EBITDAX
|
$
|
68,927
|
|
|
$
|
8,490
|
|
|
$
|
(593
|
)
|
|
$
|
76,824
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
$
|
319,042
|
|
|
$
|
21,589
|
|
|
$
|
—
|
|
|
$
|
340,631
|
|
Total assets at period end
|
2,817,714
|
|
|
1,427,792
|
|
|
8,152
|
|
|
4,253,658
|
|
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with the condensed consolidated financial statements and related notes included elsewhere in this report. The following discussion and analysis contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, the impact of the Chapter 11 proceedings on our business, the volatility of oil and gas prices, production timing and volumes, our ability to continue as a going concern, estimates of proved reserves, operating costs and capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed in “Cautionary Statement Regarding Forward-Looking Statements” at the beginning of this Quarterly Report and in the sections titled “Risk Factors” in this Quarterly Report, our Q1 2019 Form 10-Q and in our 2018 10-K, all of which are difficult to predict. As a result of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.
Overview
We are an independent exploration and production company focused on the acquisition, development, exploration and production of unconventional onshore oil and natural gas reserves in the eastern portion of the Anadarko Basin in Oklahoma. We operate in two reportable business segments - Upstream and Midstream. Alta Mesa conducts our Upstream activities and owns our proved and unproved oil and gas properties located in an area of the Anadarko Basin commonly referred to as the STACK. We generate upstream revenue principally by the production and sale of oil, gas and NGLs. We also operate in the Midstream segment through KFM. KFM has a gas and oil gathering network, a cryogenic gas processing plant with offtake capacity, field compression facilities and a produced water disposal system in the Anadarko Basin that generate revenue primarily through long-term, fee-based contracts. The KFM midstream assets are integral to our Upstream operations, which we conduct in the same region, and they are strategically positioned to provide similar services to other producers in the area.
As of June 30, 2019, we have a highly contiguous position of approximately 130,000 net acres in the up-dip, naturally-fractured oil portion of the STACK primarily in eastern Kingfisher and southeastern Major counties in Oklahoma. Our drilling locations primarily target the Osage, Meramec and Oswego formations. After the Business Combination, we conducted development activities using a spacing array of 6 to 10 wells per section and running up to 9 rigs at the peak activity level. In late 2018, our production across the acreage evidenced that the well spacing was not delivering the well level production that we expected. During January 2019, we suspended our development program to allow our new management team to conduct a full operational and economic review. We restarted our development program in March 2019 with a less dense spacing pattern of up to five wells per section. In addition, we have worked to improve our economic returns by reducing well costs, general and administrative expense and other operating expense. We have operated 2 rigs since restarting the program, however, in order to preserve liquidity in anticipation of the bankruptcy filing in September 2019, we have ceased all development activities, unless or until such activities are approved by the Court or until our bankruptcy can be resolved.
We anticipate that the reduced Alta Mesa development attendant to the bankruptcy proceedings could also result in less gathering volumes for KFM, which will adversely impact KFM’s revenue, EBITDA and operating cash flows. During bankruptcy, we will be dependent on liquidity provided by our non-debtor subsidiaries, including KFM, to meet our financial obligations. Access to the remaining capacity under the KFM Credit Facility requires adherence to the terms and covenant compliance on a pro forma basis for any new borrowings. We believe that KFM will exhaust its borrowing capacity and fail to meet the maintenance covenants as early as the first quarter of 2020. On September 23, 2019, KFM received a letter from the Administrative Agent whereby the lenders under the KFM Credit Facility allege a potential event of default in respect of liens placed on KFM’s assets. Accordingly, we may not have access to the remaining borrowing capacity unless or until this matter is resolved, which could materially impact our ability to meet our financial obligations.
Pursuant to the Business Combination, we recorded the acquired assets and liabilities at their estimated fair values on the closing date. This resulted in our financial presentation being separated into two distinct periods, the period before the Business Combination (“Predecessor Period”) and the period after the Business Combination (“Successor Period”). The Company’s financial presentation reflects Alta Mesa as the “Predecessor” for the period January 1, 2018 to February 8, 2018. The Company, including the consolidated results of Alta Mesa and KFM, is the “Successor” for periods since February 9, 2018.
Accordingly, for purposes of explaining our segment results, we have presented the results of our Upstream and Midstream segments for the three months ended June 30, 2019, in comparison to the results for the three months ended June 30, 2018, and
the results for the six months ended June 30, 2019, in comparison to (i) the results of the Upstream and Midstream segments for the period February 9, 2018 through June 30, 2018, and (ii) the results of Alta Mesa for the Predecessor Period. As KFM was acquired on February 9, 2018, its results are not included in the Predecessor Period.
We distributed our non-STACK oil and gas assets and liabilities to High Mesa in connection with the closing of the Business Combination. We report the non-STACK oil and gas assets and liabilities as discontinued operations during the Predecessor Period.
Outlook, Market Conditions and Commodity Prices
Our revenue, profitability and future growth rate depend on many factors, particularly the prices of oil, gas and NGLs, which are beyond our control. The success of our business is significantly affected by the price of oil due to its weighting in our production profile.
Factors affecting oil prices include worldwide economic conditions; geopolitical activities in various regions of the world; worldwide supply and demand conditions; weather conditions; actions taken by the Organization of Petroleum Exporting Countries; and the value of the U.S. dollar in international currency markets. Commodity prices remain unpredictable and we cannot accurately predict future commodity prices and, therefore, cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our capital expenditures, production volumes or revenues. In the event that oil, gas and NGL prices significantly decrease, such decreases could have a material adverse effect on our financial condition, the carrying value of our oil and natural gas properties, our proved reserves and our ability to finance operations, including the amount of the borrowing capacity under the Alta Mesa RBL.
Key performance indicators
During 2019, our board of directors has established the following operating measures as key performance indicators for executive management compensation and the Company as a whole:
|
|
•
|
General and administrative costs (excluding strategic costs);
|
|
|
•
|
Lease operating expense;
|
|
|
•
|
Well drilling and completion costs; and
|
|
|
•
|
Adjusted EBITDA or EBITDAX.
|
We will focus on measuring our performance against baseline and prior year comparable periods during this and future filings.
The Company’s management believes Adjusted EBITDA for our Midstream segment and Adjusted EBITDAX for our Upstream segment are useful because they allow users to more effectively evaluate our operating performance, compare the results of our operations from period to period and against our peers without regard to our financing methods or capital structure and because it highlights trends in our businesses that may not otherwise be apparent when relying solely on GAAP measures. Adjusted EBITDA and Adjusted EBITDAX should not be considered as alternatives to our net income (loss), operating income (loss) or other performance measures derived in accordance with GAAP and may not be comparable to similarly titled measures in other companies’ reports.
Going concern
We are required to evaluate our ability to continue as a going concern for a period of one year following the date of issuance of our financial statements. As part of that evaluation, we took into consideration a number of factors that were previously disclosed in our 2018 10-K. Most significantly, we have seen significant reductions to our borrowing base under the Alta Mesa RBL in 2019. On April 1, 2019, our borrowing base under the Alta Mesa RBL was reduced by $30 million to $370.0 million leaving us with no meaningful remaining capacity available thereunder at that time. In August 2019, the Alta Mesa RBL lenders exercised their ability to make an optional redetermination of our borrowing base ahead of the regular redetermination scheduled in October 2019, and via this redetermination our borrowing base was reset to $200 million, effective August 13, 2019. As our combined borrowings and letters of credit outstanding exceeded the new borrowing base amount by $162.4 million, we had five months, beginning September 2019, to make ratable monthly payments of $32.5 million to cause
utilization to be less than or equal to the borrowing base. Our Upstream business had cash on hand at August 31, 2019 of $63.0 million.
If by September 12, 2019, we had not made the first payment of $32.5 million, we would have been in default. Despite taking various actions to decrease our indebtedness and maintain our liquidity at sufficient levels to meet our commitments, on September 11, 2019, the Debtors filed Bankruptcy Petitions for reorganization under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). The Bankruptcy Court has granted a motion seeking joint administration of the Chapter 11 cases under the caption In re Alta Mesa Resources, Inc., et. al., Case No. 19-35133. The Debtors will continue to operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.
Certain of the Company’s other subsidiaries, including SRII Opco GP, LLC, SRII Opco, KFM and its subsidiaries Kingfisher STACK Oil Pipeline, LLC and Oklahoma Produced Water Solutions, LLC are not part of the Chapter 11 cases at this time.
On September 12, 2019, the Bankruptcy Court entered various orders requested by the Debtors in order to stabilize their businesses and operations as they entered into Chapter 11 bankruptcy proceedings, including orders authorizing the Debtors to honor certain obligations to employees, vendors, and holders of royalty interests. In addition, the AMH Debtors were authorized by the Bankruptcy Court to use cash collateral of the lenders under the Alta Mesa RBL. The cash collateral order permits the AMH Debtors to use their cash and proceeds of their collateral for an initial four week period on the terms and conditions agreed by the AMH Debtors and the lenders under the Alta Mesa RBL and set forth in the order. The terms and conditions include, without limitation, adherence to a budget with an agreed upon variance and meeting certain milestones. The ability to have continued access to the cash collateral will also be dependent upon the Bankruptcy Court’s approval of future versions of the cash collateral order and the related terms and conditions provided therein.
The Debtors have begun a marketing process to sell their assets, which may also include KFM’s midstream assets. Certain of the AMH Debtors have also filed a complaint seeking a Bankruptcy Court determination that the crude oil, gas, and water gathering agreements between Debtor Oklahoma Energy Acquisitions LP, an Alta Mesa subsidiary, and non-Debtors KFM and its subsidiaries can be rejected by the Debtors.
We have no meaningful cash available to us to meet our obligations apart from cash held by our subsidiaries. As a result of Alta Mesa’s bankruptcy and the limitations imposed under the approved cash collateral agreement, our only remaining source of liquidity is through KFM and SRII Opco. At August 31, 2019, SRII Opco had cash on hand of $5.7 million and KFM had cash on hand of $13.3 million, as well as remaining borrowing capacity of $74.0 million. Access to the remaining capacity under the KFM Credit Facility requires adherence to the terms and covenant compliance on a pro forma basis for any new borrowings. We believe that KFM will exhaust its borrowing capacity and fail to meet the maintenance covenants as early as the first quarter of 2020. On September 23, 2019, KFM received a letter from the Administrative Agent whereby the lenders under the KFM Credit Facility allege a potential event of default in respect of liens placed on KFM’s assets. Accordingly, we may not have access to the remaining borrowing capacity unless or until this matter is resolved, which could materially impact our ability to meet our financial obligations.
Delisting from Stock Exchange
As a result of our failure to comply with the continued listing requirements of the NASDAQ, trading in our Class A Common Stock and public warrants was suspended on September 24, 2019, and they are now traded over the counter under the trading symbols “AMRQQ” and “AMRWQ,” respectively.
Derivatives
The objective of our hedging program is to produce, over time, relative revenue stability. However, both settlements and fair value changes in our derivatives can significantly impact our short-term results of operations. During September 2019, we closed out all open derivative positions resulting in net proceeds of approximately $4 million, which we applied against our outstanding borrowings under the Alta Mesa RBL.
Impairments
No long-lived asset impairments were recognized during the six months ended June 30, 2019, except for certain operating lease right-of-use assets described above. However, in late fourth quarter of 2018, the combination of depressed prevailing oil and
gas prices, changes to assumed spacing in conjunction with evolving views on the viability of multiple benches and reduced individual well expectations, along with other factors, resulted in impairment charges of $2.0 billion to our oil and gas properties and $1.2 billion to our Midstream segment goodwill, tangible and intangible assets during the quarter ended December 31, 2018. Individual well expectations were impacted by reductions in estimated reserve recovery of original oil and gas in place.
Factors affecting future performance
The primary factors affecting our production levels, which may be interrelated, are current commodity prices, capital availability, the effectiveness and efficiency of our production operations, the success of our drilling program and our inventory of drilling prospects. In addition, our wells have significant natural production declines. Our development program was established to overcome this natural decline. Sustaining our production levels or our future growth will depend on our ability to continue to develop reserves, including our ability to fund such development. We expect that our ability to add reserves through drilling and other development techniques will be significantly curtailed as a result of our bankruptcy filing, which will have an adverse effect on any revenue growth and, as a result, our cash flow from operations.
RESULTS OF OPERATIONS
For the Three Months Ended June 30, 2019 (“Second Quarter 2019”) Compared to the Three Months Ended June 30, 2018 (“Second Quarter 2018”).
Upstream Segment Results
Revenue
Our oil, gas and NGLs revenue varies as a result of changes in commodity prices and production volumes. The following table summarizes our revenue and production data for the periods presented:
|
|
|
|
|
|
|
|
|
(in thousands, except per unit data)
|
Second Quarter 2019
|
|
Second Quarter 2018
|
Net production:
|
|
|
|
Oil (Mbbls)
|
1,545
|
|
|
1,123
|
|
Natural gas (MMcf)
|
6,283
|
|
|
3,944
|
|
NGLs (Mbbls)
|
819
|
|
|
554
|
|
Total (MBoe)
|
3,411
|
|
|
2,334
|
|
|
|
|
|
Average net daily production volumes:
|
|
|
|
Oil (Mbblsd)
|
17.0
|
|
|
12.3
|
|
Natural gas (MMcfd)
|
69.0
|
|
|
43.3
|
|
NGLs (Mbblsd)
|
9.0
|
|
|
6.1
|
|
Total (MBoed)
|
37.5
|
|
|
25.6
|
|
|
|
|
|
Average sales prices:
|
|
|
|
Oil (per bbl)
|
$
|
58.67
|
|
|
$
|
67.09
|
|
Effect of realized derivatives settlements (per bbl)
|
0.12
|
|
|
(12.80
|
)
|
Oil, after hedging (per bbl)
|
$
|
58.79
|
|
|
$
|
54.29
|
|
Percentage of unhedged realized oil price to NYMEX oil price
|
98
|
%
|
|
99
|
%
|
|
|
|
|
Natural gas (per Mcf)
|
$
|
1.97
|
|
|
$
|
2.02
|
|
Effect of realized derivatives settlements (per Mcf)
|
0.06
|
|
|
—
|
|
Natural gas, after hedging (per Mcf)
|
$
|
2.03
|
|
|
$
|
2.02
|
|
|
|
|
|
NGLs (per bbl)
|
$
|
12.52
|
|
|
$
|
18.47
|
|
Effect of realized derivatives settlements (per bbl)
|
—
|
|
|
—
|
|
NGLs, after hedging (per bbl)
|
$
|
12.52
|
|
|
$
|
18.47
|
|
|
|
|
|
Revenue
|
|
|
|
Oil sales
|
$
|
90,668
|
|
|
$
|
75,291
|
|
Natural gas sales
|
12,384
|
|
|
7,980
|
|
NGL sales
|
10,251
|
|
|
10,241
|
|
Total sales revenue
|
$
|
113,303
|
|
|
$
|
93,512
|
|
Oil sales for the Second Quarter 2019 increased due to increased production, partially offset by lower average sales prices before hedging. The increase in production was due to the extensive development program conducted following the Business Combination.
Natural gas sales for the Second Quarter 2019 increased primarily due to increased production as a result of the extensive development program conducted following the Business Combination.
NGL sales for the Second Quarter 2019 increased modestly due to increased 2019 production, mostly offset by lower average prices. The increase in production volume was primarily due to the impact of our development activities after the Business Combination.
Derivatives
|
|
|
|
|
|
|
|
|
(in thousands)
|
Second Quarter 2019
|
|
Second Quarter 2018
|
Gain (loss) on derivatives:
|
|
|
|
Oil
|
$
|
191
|
|
|
$
|
(14,362
|
)
|
Natural gas
|
353
|
|
|
3
|
|
Total realized gains (losses)
|
544
|
|
|
(14,359
|
)
|
Unrealized gains (losses)
|
11,868
|
|
|
(14,860
|
)
|
Total gain (loss) on derivatives
|
$
|
12,412
|
|
|
$
|
(29,219
|
)
|
Decreases and increases in future commodity prices during each period compared to futures prices in effect at the time of execution of our outstanding derivatives resulted in the gains and losses recognized, respectively, during each quarter.
Operating Expenses
|
|
|
|
|
|
|
|
|
(in thousands, except per unit data)
|
Second Quarter 2019
|
|
Second Quarter 2018
|
Operating expenses:
|
|
|
|
Lease operating
|
$
|
19,123
|
|
|
$
|
12,679
|
|
Transportation and marketing
|
19,614
|
|
|
11,205
|
|
Production taxes
|
5,117
|
|
|
2,606
|
|
Workovers
|
412
|
|
|
333
|
|
Exploration
|
3,289
|
|
|
8,083
|
|
Depreciation, depletion and amortization
|
34,504
|
|
|
26,670
|
|
Impairment
|
6,500
|
|
|
—
|
|
General and administrative
|
15,723
|
|
|
17,811
|
|
Total operating expense
|
$
|
104,282
|
|
|
$
|
79,387
|
|
|
|
|
|
Operating expenses per BOE:
|
|
|
|
Lease operating
|
$
|
5.61
|
|
|
$
|
5.43
|
|
Transportation and marketing
|
5.75
|
|
|
4.80
|
|
Production taxes
|
1.50
|
|
|
1.12
|
|
Workovers
|
0.12
|
|
|
0.14
|
|
Depreciation, depletion and amortization
|
10.12
|
|
|
11.43
|
|
Lease operating expense for the Second Quarter 2019 increased due to higher production and the impact of additional costs associated with the sale of our produced water assets to our affiliate KFM in the fourth quarter of 2018.
Transportation and marketing expense for the Second Quarter 2019 increased due to higher volumes. The fee we pay per unit reflects the firm processing capacity at the plant, as well as firm transport for our residue gas at the tailgate of the plant. The amount for the Second Quarter 2019 also reflects a more significant expense due to an increase in committed capacity which went unused.
Production taxes for the Second Quarter 2019 increased due to the increase in oil and NGL revenue and an increase in the Oklahoma severance tax rate from 2% to 5%, effective in the third quarter of 2018, for wells in their first 3 years of production.
|
|
|
|
|
|
|
|
|
(in thousands)
|
Second Quarter 2019
|
|
Second Quarter 2018
|
Exploration expense:
|
|
|
|
Geological and geophysical costs
|
$
|
366
|
|
|
$
|
1,139
|
|
Other exploration expense, including expired leases
|
2,909
|
|
|
6,579
|
|
ARO settlements in excess of recorded liabilities
|
14
|
|
|
365
|
|
Total exploration expense
|
$
|
3,289
|
|
|
$
|
8,083
|
|
Exploration expense during the Second Quarter 2019 decreased compared to the Second Quarter 2018 largely due to $3.7 million of lower expired lease costs.
Depreciation, depletion and amortization was lower on a per BOE basis during the Second Quarter 2019 largely due to the amount of impairment taken on our oil and gas properties during the fourth quarter of 2018, which reduced the depletable base.
During the Second Quarter 2019, we recognized a $6.5 million impairment of our operating lease right-of-use assets.
|
|
|
|
|
|
|
|
|
(in thousands)
|
Second Quarter 2019
|
|
Second Quarter 2018
|
General and administrative expense:
|
|
|
|
Employee-related costs
|
$
|
6,649
|
|
|
$
|
6,126
|
|
Equity-based compensation
|
1,396
|
|
|
3,621
|
|
Professional fees
|
126
|
|
|
3,843
|
|
Strategic costs
|
4,061
|
|
|
—
|
|
Business Combination
|
—
|
|
|
443
|
|
Severance costs
|
609
|
|
|
—
|
|
Information technology
|
946
|
|
|
2,146
|
|
Operating leases
|
1,293
|
|
|
995
|
|
Provision for uncollectible receivables
|
298
|
|
|
—
|
|
Other
|
345
|
|
|
637
|
|
Total general and administrative expense
|
$
|
15,723
|
|
|
$
|
17,811
|
|
General and administrative expenses during the Second Quarter 2019 decreased due mainly to lower costs associated with equity-based compensation expense and information technology costs associated with the change in control. General and administrative expense during the Second Quarter 2019 also included costs for legal and financial advisory services associated with financial structuring activities, including negotiations with representatives of our lenders and other third parties.
Below is a reconciliation of our income (loss) from continuing operations before income taxes to our Adjusted EBITDAX:
|
|
|
|
|
|
|
|
|
(in thousands)
|
Second Quarter 2019
|
|
Second Quarter 2018
|
Income (loss) from continuing operations before income taxes
|
$
|
7,746
|
|
|
$
|
(22,469
|
)
|
|
|
|
|
Interest expense
|
14,071
|
|
|
10,361
|
|
Depreciation, depletion and amortization
|
34,504
|
|
|
26,670
|
|
Exploration
|
3,289
|
|
|
8,083
|
|
Loss (gain) on unrealized hedges
|
(11,868
|
)
|
|
14,860
|
|
Impairment of assets
|
6,500
|
|
|
—
|
|
Equity-based compensation
|
1,396
|
|
|
3,621
|
|
Severance costs
|
609
|
|
|
—
|
|
Strategic costs
|
4,061
|
|
|
—
|
|
Business Combination
|
—
|
|
|
443
|
|
Adjusted EBITDAX
|
$
|
60,308
|
|
|
$
|
41,569
|
|
Other (Income) Expense
|
|
|
|
|
|
|
|
|
(in thousands)
|
Second Quarter 2019
|
|
Second Quarter 2018
|
Alta Mesa RBL
|
$
|
5,204
|
|
|
$
|
—
|
|
2024 Notes
|
9,844
|
|
|
9,844
|
|
Bond premium amortization
|
(1,231
|
)
|
|
(1,231
|
)
|
Deferred financing cost amortization
|
94
|
|
|
80
|
|
Other
|
160
|
|
|
1,668
|
|
Total interest expense
|
14,071
|
|
|
10,361
|
|
Interest income
|
(54
|
)
|
|
(820
|
)
|
Total other (income) expense, net
|
$
|
14,017
|
|
|
$
|
9,541
|
|
Interest expense for the Second Quarter 2019 increased due primarily to increased levels of borrowings under the Alta Mesa RBL. Other interest expense includes commitment fees and interest expense related to our joint development agreement with BCE.
Midstream Segment Results
Revenue
|
|
|
|
|
|
|
|
|
(in thousands)
|
Second Quarter 2019
|
|
Second Quarter 2018
|
Sales of gathered production
|
$
|
10,439
|
|
|
$
|
21,024
|
|
Midstream revenue
|
22,112
|
|
|
15,849
|
|
Produced water disposal fees
|
6,693
|
|
|
—
|
|
Total Midstream revenue
|
$
|
39,244
|
|
|
$
|
36,873
|
|
|
|
|
|
KFM gas volumes (MMcf)
|
12,736
|
|
|
8,704
|
|
KFM crude oil volumes (Mbbls)
|
443
|
|
|
301
|
|
KFM produced water gathering volumes (Mbbls)
|
6,941
|
|
|
—
|
|
Sales of gathered production during the Second Quarter 2019 decreased compared to the Second Quarter 2018 due to a decline in volumes from third-party producers that are processed and sold back to the producers.
Midstream revenue during the Second Quarter 2019 increased compared to the Second Quarter 2018 due to increased receipt point volumes and the impact of a second cryogenic processing train being commissioned in mid 2018.
Produced water disposal fees during the Second Quarter 2019 resulted from the acquisition of produced water disposal assets from Alta Mesa during the fourth quarter of 2018.
Operating Expenses
|
|
|
|
|
|
|
|
|
(in thousands)
|
Second Quarter 2019
|
|
Second Quarter 2018
|
Midstream operating
|
$
|
6,520
|
|
|
$
|
3,313
|
|
Cost of sales for purchased gathered production
|
8,720
|
|
|
21,002
|
|
Transportation and processing
|
2,786
|
|
|
3,223
|
|
Workovers
|
395
|
|
|
—
|
|
Depreciation and amortization
|
3,505
|
|
|
7,264
|
|
General and administrative
|
5,324
|
|
|
4,140
|
|
Total operating expenses
|
$
|
27,250
|
|
|
$
|
38,942
|
|
Midstream operating expense for the Second Quarter 2019 increased compared to the Second Quarter 2018 due to additional operating expenses for the produced water disposal assets acquired from Alta Mesa during the fourth quarter of 2018 and the impact of higher volumes, which led to higher compressor-related costs.
Cost of sales of purchased gathered production decreased in the Second Quarter 2019 as compared to the Second Quarter 2018, reflective of the sales decline to third parties noted above.
Transportation and processing expense declined in the Second Quarter 2019 as compared to the Second Quarter 2018 as a result of the segment’s cost reduction efforts during the current period.
Depreciation and amortization during the Second Quarter 2018 included $5.3 million of amortization expense related to intangible customer relationship assets that were fully impaired at December 31, 2018. This impact was partially offset by an increase of $1.5 million in depreciation of tangible assets during the Second Quarter 2019 due to capital spending since June 30, 2018, including the purchase of the produced waster disposal assets from Alta Mesa in the fourth quarter of 2018.
|
|
|
|
|
|
|
|
|
(in thousands)
|
Second Quarter 2019
|
|
Second Quarter 2018
|
General and administrative expenses:
|
|
|
|
Employee-related costs
|
$
|
3,745
|
|
|
$
|
2,995
|
|
Equity-based compensation
|
(556
|
)
|
|
465
|
|
Professional fees
|
748
|
|
|
415
|
|
Strategic costs
|
648
|
|
|
5
|
|
Severance costs
|
88
|
|
|
—
|
|
Information technology
|
—
|
|
|
4
|
|
Operating leases
|
55
|
|
|
25
|
|
Other
|
596
|
|
|
231
|
|
Total general and administrative expense
|
$
|
5,324
|
|
|
$
|
4,140
|
|
General and administrative expense increased during the Second Quarter 2019 as a result of increased headcount and higher legal and financial advisory services associated with financial structuring activities. The departure of our Vice President and Chief Operating Officer - Midstream resulted in recognition during the Second Quarter 2019 of the forfeiture of certain previously expensed equity compensation awards.
Below is a reconciliation of Midstream adjusted EBITDA to income (loss) from continuing operations before income taxes:
|
|
|
|
|
|
|
|
|
(in thousands)
|
Second Quarter 2019
|
|
Second Quarter 2018
|
Income (loss) from continuing operations before income taxes
|
$
|
9,959
|
|
|
$
|
(3,487
|
)
|
|
|
|
|
Interest expense
|
2,684
|
|
|
1,418
|
|
Depreciation and amortization
|
3,505
|
|
|
7,264
|
|
Impairment of assets
|
—
|
|
|
—
|
|
Equity-based compensation
|
(556
|
)
|
|
465
|
|
Severance costs
|
88
|
|
|
—
|
|
Adjusted Midstream EBITDA
|
$
|
15,680
|
|
|
$
|
5,660
|
|
Other (Income) Expense
|
|
|
|
|
|
|
|
|
(in thousands)
|
Second Quarter 2019
|
|
Second Quarter 2018
|
KFM Credit Facility
|
$
|
2,429
|
|
|
$
|
322
|
|
Predecessor revolving credit facility
|
—
|
|
|
827
|
|
Deferred financing cost amortization
|
154
|
|
|
72
|
|
Other
|
101
|
|
|
197
|
|
Total interest expense
|
2,684
|
|
|
1,418
|
|
Interest income
|
(6
|
)
|
|
—
|
|
Equity in earnings of unconsolidated subsidiaries
|
(643
|
)
|
|
—
|
|
Total other (income) expense, net
|
$
|
2,035
|
|
|
$
|
1,418
|
|
Interest expense for the Second Quarter 2019 increased primarily due to increased levels of borrowings under the KFM Credit Facility compared to the predecessor credit facility. Deferred financing costs associated with the KFM Credit Facility are being amortized over the facility’s remaining term. Other interest primarily relates to commitment fees.
Equity in earnings of unconsolidated subsidiaries represents our share of the net income during the Second Quarter 2019 associated with our 50% ownership in the Cimarron pipeline (“Cimarron”). Our investment in Cimarron is accounted for under the equity method.
For the Six Months Ended June 30, 2019 (“2019 Period”) Compared to the Periods February 9, 2018 Through June 30, 2018 (Successor) and January 1, 2018 Through February 8, 2018 (Predecessor)
The tables included below set forth financial information for the Successor Periods and Predecessor Period, which are distinct reporting periods as a result of the Business Combination. The Predecessor Period amounts below exclude operating results related to discontinued operations. We refer to the combined Predecessor Period and Successor Period from February 9, 2018 through June 30, 2018 and January 1, 2018 through February 8, 2018 as the “2018 Period”.
Upstream Segment Results
Revenue
Our oil, gas and NGLs revenue varies as a result of changes in commodity prices and production volumes. The following table summarizes our revenue and production data for the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
(in thousands, except per unit data)
|
Six Months Ended
June 30, 2019
|
|
February 9, 2018
Through
June 30, 2018
|
|
|
January 1, 2018
Through
February 8, 2018
|
Net production:
|
|
|
|
|
|
|
Oil (Mbbl)
|
3,164
|
|
|
1,774
|
|
|
|
494
|
|
Natural gas (MMcf)
|
12,114
|
|
|
6,192
|
|
|
|
1,609
|
|
NGLs (Mbbl)
|
1,614
|
|
|
777
|
|
|
|
151
|
|
Total (MBoe)
|
6,797
|
|
|
3,583
|
|
|
|
914
|
|
|
|
|
|
|
|
|
Average net daily production volumes:
|
|
|
|
|
|
|
Oil (Mbbld)
|
17.5
|
|
|
12.5
|
|
|
|
12.7
|
|
Natural gas (MMcfd)
|
66.9
|
|
|
43.6
|
|
|
|
41.2
|
|
NGLs (Mbbld)
|
8.9
|
|
|
5.5
|
|
|
|
3.9
|
|
Total (MBoed)
|
37.6
|
|
|
25.2
|
|
|
|
23.4
|
|
|
|
|
|
|
|
|
Average sales prices:
|
|
|
|
|
|
|
Oil (per bbl)
|
$
|
55.94
|
|
|
$
|
65.16
|
|
|
|
$
|
62.68
|
|
Effect of realized derivatives settlements (per bbl)
|
0.61
|
|
|
(11.01
|
)
|
|
|
(6.44
|
)
|
Oil, after hedging (per bbl)
|
$
|
56.55
|
|
|
$
|
54.15
|
|
|
|
$
|
56.24
|
|
Percentage of unhedged realized oil price to NYMEX oil price
|
97
|
%
|
|
99
|
%
|
|
|
99
|
%
|
|
|
|
|
|
|
|
Natural gas (per Mcf)
|
$
|
2.55
|
|
|
$
|
2.13
|
|
|
|
$
|
2.66
|
|
Effect of realized derivatives settlements (per Mcf)
|
(0.08
|
)
|
|
0.09
|
|
|
|
0.94
|
|
Natural gas, after hedging (per Mcf)
|
$
|
2.47
|
|
|
$
|
2.22
|
|
|
|
$
|
3.60
|
|
|
|
|
|
|
|
|
NGLs (per bbl)
|
$
|
13.30
|
|
|
$
|
19.25
|
|
|
|
$
|
26.41
|
|
Effect of realized derivatives settlements (per bbl)
|
—
|
|
|
—
|
|
|
|
—
|
|
NGLs, after hedging (per bbl)
|
$
|
13.30
|
|
|
$
|
19.25
|
|
|
|
$
|
26.41
|
|
|
|
|
|
|
|
|
Revenue
|
|
|
|
|
|
|
Oil sales
|
$
|
177,031
|
|
|
$
|
115,569
|
|
|
|
$
|
30,972
|
|
Natural gas sales
|
30,834
|
|
|
13,190
|
|
|
|
4,276
|
|
NGL sales
|
21,467
|
|
|
14,955
|
|
|
|
4,000
|
|
Total sales
|
$
|
229,332
|
|
|
$
|
143,714
|
|
|
|
$
|
39,248
|
|
Oil sales for the 2019 Period increased due to increased production, partially offset by lower average sales prices before hedging. The increase in production was due to the extensive development program conducted following the Business Combination.
Natural gas sales for the 2019 Period increased due to both an increase in production as a result of the extensive development program conducted following the Business Combination and higher prevailing market prices.
NGL sales for the 2019 Period increased due to increased production, significantly offset by lower average prices. The increase in production volume was primarily due to the impact of our extensive 2018 development activities following the Business Combination.
Gain (loss) on sale of assets for the 2019 Period included a gain from the sale of seismic data totaling $1.5 million compared to a similar gain of $5.9 million during the 2018 Period.
Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
(in thousands)
|
Six Months Ended
June 30, 2019
|
|
February 9, 2018
Through
June 30, 2018
|
|
|
January 1, 2018
Through
February 8, 2018
|
Gain (loss) on derivatives:
|
|
|
|
|
|
|
Oil
|
$
|
1,936
|
|
|
$
|
(18,892
|
)
|
|
|
$
|
(3,819
|
)
|
Natural gas
|
(1,027
|
)
|
|
558
|
|
|
|
1,523
|
|
Total realized gains (losses)
|
909
|
|
|
(18,334
|
)
|
|
|
(2,296
|
)
|
Unrealized gains (losses)
|
(12,274
|
)
|
|
(32,896
|
)
|
|
|
8,959
|
|
Total gain (loss) on derivatives
|
$
|
(11,365
|
)
|
|
$
|
(51,230
|
)
|
|
|
$
|
6,663
|
|
Decreases and increases in future commodity prices during each period compared to futures prices in effect at the time of execution of our outstanding derivatives resulted in the gains and losses recognized, respectively, during each six month period.
Operating Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
(in thousands, except per unit data)
|
Six Months Ended
June 30, 2019
|
|
February 9, 2018
Through
June 30, 2018
|
|
|
January 1, 2018
Through
February 8, 2018
|
Operating expenses:
|
|
|
|
|
|
|
Lease operating
|
$
|
44,231
|
|
|
$
|
20,996
|
|
|
|
$
|
4,408
|
|
Transportation and marketing
|
37,375
|
|
|
16,788
|
|
|
|
3,725
|
|
Production taxes
|
10,600
|
|
|
4,021
|
|
|
|
953
|
|
Workovers
|
609
|
|
|
1,578
|
|
|
|
423
|
|
Exploration
|
5,343
|
|
|
9,668
|
|
|
|
7,003
|
|
Depreciation, depletion and amortization
|
69,179
|
|
|
37,708
|
|
|
|
11,670
|
|
Impairment of assets
|
6,500
|
|
|
—
|
|
|
|
—
|
|
General and administrative
|
36,670
|
|
|
52,465
|
|
|
|
21,234
|
|
Total operating expense
|
$
|
210,507
|
|
|
$
|
143,224
|
|
|
|
$
|
49,416
|
|
|
|
|
|
|
|
|
Operating expenses per BOE:
|
|
|
|
|
|
|
Lease operating
|
$
|
6.51
|
|
|
$
|
5.86
|
|
|
|
$
|
4.82
|
|
Transportation and marketing
|
5.50
|
|
|
4.69
|
|
|
|
4.08
|
|
Production taxes
|
1.56
|
|
|
1.12
|
|
|
|
1.04
|
|
Workovers
|
0.09
|
|
|
0.44
|
|
|
|
0.46
|
|
Depreciation, depletion and amortization
|
10.18
|
|
|
10.52
|
|
|
|
12.77
|
|
Lease operating expense for the 2019 Period increased primarily due to higher production and the impact of additional costs associated with the sale of our produced water assets to our affiliate KFM in the fourth quarter of 2018.
Transportation and marketing expense for the 2019 Period increased primarily due to higher volumes. The fee we pay per unit reflects the firm processing capacity at the plant, as well as firm transport for our residue gas at the tailgate of the plant. The 2019 period also reflects a more significant expense due to an increase in committed capacity which went unused.
Production taxes for the 2019 Period increased primarily due to the increase in oil and NGL revenue and an increase in the Oklahoma severance tax rate from 2% to 5%, effective in the third quarter of 2018, for wells in their first 3 years of production.
Workovers are associated with maintenance and other efforts to increase production. During the 2019 Period, these costs decreased due to minimal workover projects being undertaken.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
(in thousands)
|
Six Months Ended
June 30, 2019
|
|
February 9, 2018
Through
June 30, 2018
|
|
|
January 1, 2018
Through
February 8, 2018
|
Exploration expense:
|
|
|
|
|
|
|
Geological and geophysical costs
|
$
|
678
|
|
|
$
|
1,590
|
|
|
|
$
|
2,440
|
|
Other exploration expense, including expired leases
|
4,604
|
|
|
7,412
|
|
|
|
4,504
|
|
ARO settlements in excess of recorded liabilities
|
61
|
|
|
666
|
|
|
|
59
|
|
Total exploration expense
|
$
|
5,343
|
|
|
$
|
9,668
|
|
|
|
$
|
7,003
|
|
Exploration expense for the 2019 Period decreased primarily due to our cost reduction efforts, including a reduced number of employees in the geology department, and a decrease in expenses relating to expired or expiring leaseholds.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
(in thousands)
|
Six Months Ended
June 30, 2019
|
|
February 9, 2018
Through
June 30, 2018
|
|
|
January 1, 2018
Through
February 8, 2018
|
General and administrative expense:
|
|
|
|
|
|
|
Employee-related costs
|
$
|
14,957
|
|
|
$
|
12,646
|
|
|
|
$
|
1,032
|
|
Equity-based compensation
|
3,057
|
|
|
6,389
|
|
|
|
—
|
|
Professional fees
|
3,723
|
|
|
5,083
|
|
|
|
1,019
|
|
Strategic costs
|
4,061
|
|
|
—
|
|
|
|
—
|
|
Business Combination
|
10
|
|
|
23,717
|
|
|
|
17,040
|
|
Severance costs
|
4,584
|
|
|
—
|
|
|
|
—
|
|
Information technology
|
1,980
|
|
|
2,649
|
|
|
|
—
|
|
Operating leases
|
2,317
|
|
|
1,486
|
|
|
|
208
|
|
Provision for uncollectible receivables
|
1,177
|
|
|
—
|
|
|
|
—
|
|
Other
|
804
|
|
|
495
|
|
|
|
1,935
|
|
Total general and administrative expense
|
$
|
36,670
|
|
|
$
|
52,465
|
|
|
|
$
|
21,234
|
|
General and administrative expense for the 2019 Period decreased compared to the 2018 Period primarily due to nonrecurring Business Combination costs and other professional fees incurred in the 2018 Period for advisors helping to value and integrate the acquired business. General and administrative expense during the 2019 Period also included costs for legal and financial advisory services associated with financial structuring activities, including negotiations with representatives of our lenders and other third parties.
Below is a reconciliation of our income (loss) from continuing operations before income taxes to our Adjusted EBITDAX:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
(in thousands)
|
Six Months Ended
June 30, 2019
|
|
February 9, 2018
Through
June 30, 2018
|
|
|
January 1, 2018
Through
February 8, 2018
|
Income (loss) from continuing operations before income taxes
|
$
|
(16,979
|
)
|
|
$
|
(57,071
|
)
|
|
|
$
|
(7,116
|
)
|
|
|
|
|
|
|
|
Interest expense
|
26,901
|
|
|
15,557
|
|
|
|
5,511
|
|
Depreciation, depletion and amortization
|
69,179
|
|
|
37,708
|
|
|
|
11,670
|
|
Exploration
|
5,343
|
|
|
9,668
|
|
|
|
7,003
|
|
Loss (gain) on unrealized hedges
|
12,274
|
|
|
32,896
|
|
|
|
(8,959
|
)
|
Loss on sale of property and equipment
|
—
|
|
|
63
|
|
|
|
—
|
|
Impairment of assets
|
6,500
|
|
|
—
|
|
|
|
—
|
|
Equity-based compensation
|
3,057
|
|
|
6,389
|
|
|
|
—
|
|
Severance costs
|
4,584
|
|
|
—
|
|
|
|
—
|
|
Strategic costs
|
4,061
|
|
|
—
|
|
|
|
—
|
|
Business Combination
|
10
|
|
|
23,717
|
|
|
|
17,040
|
|
Adjusted EBITDAX
|
$
|
114,930
|
|
|
$
|
68,927
|
|
|
|
$
|
25,149
|
|
Other (Income) Expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
(in thousands)
|
Six Months Ended
June 30, 2019
|
|
February 9, 2018
Through
June 30, 2018
|
|
|
January 1, 2018
Through
February 8, 2018
|
Alta Mesa RBL
|
$
|
8,783
|
|
|
$
|
252
|
|
|
|
$
|
815
|
|
2024 Notes
|
19,688
|
|
|
16,406
|
|
|
|
3,281
|
|
Bond premium amortization
|
(2,462
|
)
|
|
(2,051
|
)
|
|
|
—
|
|
Deferred financing cost amortization
|
139
|
|
|
80
|
|
|
|
171
|
|
Other
|
753
|
|
|
870
|
|
|
|
1,244
|
|
Total interest expense
|
26,901
|
|
|
15,557
|
|
|
|
5,511
|
|
Interest income
|
(81
|
)
|
|
(1,366
|
)
|
|
|
(172
|
)
|
Total other (income) expense, net
|
$
|
26,820
|
|
|
$
|
14,191
|
|
|
|
$
|
5,339
|
|
Interest expense for the 2019 Period increased primarily due to increased levels of borrowing under the Alta Mesa RBL. Other interest expense includes commitment fees and interest expense related to our joint development agreement with BCE.
Midstream Segment Results
Revenue
|
|
|
|
|
|
|
|
|
(in thousands)
|
Six Months Ended June 30, 2019
|
|
February 9, 2018
Through
June 30, 2018
|
Sales of gathered production
|
$
|
19,999
|
|
|
$
|
31,634
|
|
Midstream revenue
|
44,488
|
|
|
23,671
|
|
Produced water disposal fees
|
14,374
|
|
|
—
|
|
Total Midstream revenue
|
$
|
78,861
|
|
|
$
|
55,305
|
|
|
|
|
|
KFM gas volumes (MMcf)
|
25,100
|
|
|
12,944
|
|
KFM crude oil volumes (Mbbls)
|
1,037
|
|
|
433
|
|
KFM produced water gathering volumes (Mbbls)
|
14,622
|
|
|
—
|
|
Sales of gathered production during the 2019 Period decreased compared to the 2018 Period due to a decline in volumes from third-party producers that are processed and sold back to the producers.
Midstream revenue during the 2019 Period increased compared to the 2018 Period due to increased receipt point volumes and the impact of a second cryogenic processing train being commissioned in mid 2018.
Produced water disposal fees during the 2019 Period resulted from the acquisition of produced water disposal assets from Alta Mesa during the fourth quarter of 2018.
Operating Expenses
|
|
|
|
|
|
|
|
|
(in thousands)
|
Six Months Ended June 30, 2019
|
|
February 9, 2018
Through
June 30, 2018
|
Midstream operating
|
$
|
12,671
|
|
|
$
|
3,900
|
|
Cost of sales for purchased gathered production
|
18,415
|
|
|
31,548
|
|
Transportation and processing
|
4,849
|
|
|
5,561
|
|
Workovers
|
511
|
|
|
—
|
|
Depreciation and amortization
|
6,729
|
|
|
11,905
|
|
General and administrative
|
13,387
|
|
|
6,313
|
|
Total operating expenses
|
$
|
56,562
|
|
|
$
|
59,227
|
|
Midstream operating expense for the 2019 Period increased compared to the 2018 Period due to additional operating expenses for the produced water disposal assets acquired from Alta Mesa during the fourth quarter of 2018 and the impact of higher volumes, which led to higher compressor-related costs.
Cost of sales of purchased gathered production decreased in the 2019 Period as compared to the 2018 Period, reflective of the sales decline to third parties noted above.
Transportation and processing expense declined in the 2019 Period as compared to the 2018 Period as a result of the segment’s cost reduction efforts during the current period.
Depreciation and amortization during the 2018 Period included $8.8 million of amortization expense related to intangible customer relationship assets that were fully impaired at December 31, 2018. This impact was partially offset by an increase of $3.6 million in depreciation of tangible assets during the 2019 Period due to capital spending since June 30, 2018, including the purchase of the produced waster disposal assets from Alta Mesa in the fourth quarter of 2018, and as a result of the increased number of days during the 2019 Period compared to the 2018 Period.
|
|
|
|
|
|
|
|
|
(in thousands)
|
Six Months Ended June 30, 2019
|
|
February 9, 2018
Through
June 30, 2018
|
General and administrative expenses:
|
|
|
|
Employee-related costs
|
$
|
7,723
|
|
|
$
|
4,013
|
|
Equity-based compensation
|
462
|
|
|
507
|
|
Professional fees
|
1,197
|
|
|
532
|
|
Strategic costs
|
648
|
|
|
10
|
|
Severance costs
|
1,984
|
|
|
—
|
|
Information technology
|
126
|
|
|
4
|
|
Operating leases
|
218
|
|
|
39
|
|
Other
|
1,029
|
|
|
1,208
|
|
Total general and administrative expense
|
$
|
13,387
|
|
|
$
|
6,313
|
|
General and administrative expense increased during the 2019 Period as a result of increased headcount and higher legal and financial advisory services associated with financial structuring activities. Following a reassessment of 2019 activity levels, we implemented a reduction in force program during the 2019 Period, which along with the departure of our Vice President and Chief Operating Officer - Midstream, resulted in severance costs during the period.
Below is a reconciliation of Midstream adjusted EBITDA to income (loss) from continuing operations before income taxes:
|
|
|
|
|
|
|
|
|
(in thousands)
|
Six Months Ended June 30, 2019
|
|
February 9, 2018
Through
June 30, 2018
|
Income (loss) from continuing operations before income taxes
|
$
|
17,737
|
|
|
$
|
(5,588
|
)
|
|
|
|
|
Interest expense
|
5,314
|
|
|
1,666
|
|
Depreciation and amortization
|
6,729
|
|
|
11,905
|
|
Equity-based compensation
|
462
|
|
|
507
|
|
Severance costs
|
1,984
|
|
|
—
|
|
Adjusted Midstream EBITDA
|
$
|
32,226
|
|
|
$
|
8,490
|
|
Other (Income) Expense
|
|
|
|
|
|
|
|
|
(in thousands)
|
Six Months Ended June 30, 2019
|
|
February 9, 2018
Through
June 30, 2018
|
KFM Credit Facility
|
$
|
4,811
|
|
|
$
|
322
|
|
Predecessor revolving credit facility
|
—
|
|
|
980
|
|
Deferred financing cost amortization
|
229
|
|
|
72
|
|
Other
|
274
|
|
|
292
|
|
Total interest expense
|
5,314
|
|
|
1,666
|
|
Interest income
|
(10
|
)
|
|
—
|
|
Equity in earnings of unconsolidated subsidiaries
|
(742
|
)
|
|
—
|
|
Total other (income) expense, net
|
$
|
4,562
|
|
|
$
|
1,666
|
|
Interest expense for the 2019 Period increased primarily due to increased levels of borrowings under the KFM Credit Facility compared to the predecessor credit facility. Deferred financing costs associated with the KFM Credit Facility are being amortized over the facility’s remaining term. Other interest primarily relates to commitment fees.
Equity in earnings of unconsolidated subsidiaries represents our share of the net income during the 2019 Period associated with our 50% ownership in the Cimarron pipeline (“Cimarron”). Our investment in Cimarron is accounted for under the equity method.
LIQUIDITY AND CAPITAL RESOURCES
Our principal requirements for capital during 2019 have been to fund our day-to-day operations, development activities and to satisfy our contractual obligations related to servicing our debt and hedges. During 2019, our main sources of liquidity and capital resources came from operating cash flow and borrowings under the Alta Mesa RBL.
In April 2019, our borrowing base under the Alta Mesa RBL was reduced from $400.0 million to $370.0 million leaving us with no meaningful remaining capacity available thereunder at that time. In August 2019, the Alta Mesa RBL lenders exercised their ability to make an optional redetermination of our borrowing base ahead of the regular redetermination scheduled in October 2019, and via this redetermination our borrowing base was reset to $200 million, effective August 13, 2019. As our combined borrowings and letters of credit outstanding exceeded the new borrowing base amount by $162.4 million, we had five months, beginning September 2019, to make ratable monthly payments of $32.5 million to cause utilization to be less than or equal to the borrowing base. Our Upstream business had cash on hand at August 31, 2019 of $63.0 million.
If by September 12, 2019, we had not made the first payment of $32.5 million, we would have been in default. Despite taking various actions to decrease our indebtedness and maintain our liquidity at sufficient levels to meet our commitments, on September 11, 2019, the Debtors filed Bankruptcy Petitions for reorganization under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). The Bankruptcy Court has granted a motion seeking joint administration of the Chapter 11 cases under the caption In re Alta Mesa Resources, Inc., et. al., Case No. 19-35133. The Debtors will continue to operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.
Certain of the Company’s other subsidiaries, including SRII Opco GP, LLC, SRII Opco, KFM and its subsidiaries Kingfisher STACK Oil Pipeline, LLC and Oklahoma Produced Water Solutions, LLC are not part of the Chapter 11 cases at this time.
On September 12, 2019, the Bankruptcy Court entered various orders requested by the Debtors in order to stabilize their businesses and operations as they entered into Chapter 11 bankruptcy proceedings, including orders authorizing the Debtors to honor certain obligations to employees, vendors, and holders of royalty interests. In addition, the AMH Debtors were authorized by the Bankruptcy Court to use cash collateral of the lenders under the Alta Mesa RBL. The cash collateral order permits the AMH Debtors to use their cash and proceeds of their collateral for an initial four week period on the terms and conditions agreed by the AMH Debtors and the lenders under the Alta Mesa RBL and set forth in the order. The terms and conditions include, without limitation, adherence to a budget with an agreed upon variance and meeting certain milestones. The ability to have continued access to the cash collateral will also be dependent upon the Bankruptcy Court’s approval of future versions of the cash collateral order and the related terms and conditions provided therein.
We have no meaningful cash available to us to meet our obligations apart from cash held by our subsidiaries. As a result of Alta Mesa’s bankruptcy and the limitations imposed under the approved cash collateral agreement, our only remaining source of liquidity is through KFM and SRII Opco. At August 31, 2019, SRII Opco had cash on hand of $5.7 million and KFM had cash on hand of $13.3 million, as well as remaining borrowing capacity of $74.0 million. Access to the remaining capacity under the KFM Credit Facility requires adherence to the terms and covenant compliance on a pro forma basis for any new borrowings. We believe that KFM will exhaust its borrowing capacity and fail to meet the maintenance covenants as early as the first quarter of 2020. On September 23, 2019, KFM received a letter from the Administrative Agent whereby the lenders under the KFM Credit Facility allege a potential event of default in respect of liens placed on KFM’s assets. Accordingly, we may not have access to the remaining borrowing capacity unless or until this matter is resolved, which could materially impact our ability to meet our financial obligations.
During September, we ceased all development activities, other than any that may be prospectively approved by the Court or until our bankruptcy cases can be resolved. The abandonment of planned development activities, particularly with respect to bringing new wells onto production, will likely reduce our production levels, revenue and cash flow, and may result in the expiry of certain leases.
We expect our third quarter 2019 capital incurred to be approximately $44 million, of which $40 million was attributable to the Upstream segment’s 2 rig program we conducted until the time of our bankruptcy filing. Under the terms and conditions of the cash collateral order entered by the Bankruptcy Court and corresponding budget, we are not able to operate any drilling rigs
during the fourth quarter of 2019, although we had certain capital spending to finish drilling wells that were in process at the time of our bankruptcy filing. We expect our fourth quarter 2019 capital spending to be substantially less than before the bankruptcy filing.
We anticipate that the reduced Alta Mesa development attendant to the bankruptcy proceedings could also result in less gathering volumes for KFM, which will adversely impact KFM’s revenue, EBITDA and operating cash flows. During bankruptcy, we will be dependent on liquidity provided by our non-debtor subsidiaries, including KFM, to meet our financial obligations. Access to the remaining capacity under the KFM Credit Facility requires adherence to the terms and covenant compliance on a pro forma basis for any new borrowings. We believe that KFM will exhaust its borrowing capacity and fail to meet the maintenance covenants as early as the first quarter of 2020. On September 23, 2019, KFM received a letter from the Administrative Agent whereby the lenders under the KFM Credit Facility allege a potential event of default in respect of liens placed on KFM’s assets. Accordingly, we may not have access to the remaining borrowing capacity unless or until this matter is resolved, which could materially impact our ability to meet our financial obligations.
As we execute our business strategy, we will monitor the capital resources available to meet future financial obligations and planned capital expenditures. We cannot provide assurance that operations and other needed capital will be available on acceptable terms, or at all, and our development pace may need to change based on our evolving liquidity profile.
Cash Flow Analysis
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
(in thousands)
|
Six Months Ended
June 30, 2019
|
|
February 9, 2018
Through
June 30, 2018
|
|
|
January 1, 2018
Through
February 8, 2018
|
Cash from operating activities
|
$
|
84,588
|
|
|
$
|
(64,822
|
)
|
|
|
$
|
26,336
|
|
Cash from investing activities
|
(247,942
|
)
|
|
(96,653
|
)
|
|
|
(37,913
|
)
|
Cash from financing activities
|
227,500
|
|
|
244,507
|
|
|
|
16,932
|
|
Net increase in cash, cash equivalents and restricted cash
|
$
|
64,146
|
|
|
$
|
83,032
|
|
|
|
$
|
5,355
|
|
Cash flow from operating activities
During the 2019 Period, cash-based items of net income (loss), including revenue (exclusive of unrealized commodity gains or losses), operating expenses and taxes, general and administrative expenses, and the cash portion of our interest expense totaled $91.9 million compared to $32.2 million during the 2018 Period, due largely to higher revenues associated with increased production and the lack of costs associated with the Business Combination that were incurred in 2018. Approximately $7.3 million of cash was used to increase working capital during the 2019 Period. During the 2018 Period, cash totaling $70.7 million was used to increase working capital primarily due to increases in trade receivables and amounts due from related parties for administrative services provided, including certain other transactions, and to reduce liabilities arising prior to or as a result of the Business Combination.
Cash flow from investing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
(in thousands)
|
Six Months Ended
June 30, 2019
|
|
February 9, 2018
Through
June 30, 2018
|
|
|
January 1, 2018
Through
February 8, 2018
|
Cash provided by (used for)
|
|
|
|
|
|
|
Capital expenditures
|
$
|
(247,942
|
)
|
|
$
|
(340,631
|
)
|
|
|
$
|
(36,695
|
)
|
Acquisition of acreage
|
—
|
|
|
(791,819
|
)
|
|
|
(1,218
|
)
|
Proceeds withdrawn from trust account
|
—
|
|
|
1,042,742
|
|
|
|
—
|
|
Investment in equity affiliate and other, net
|
—
|
|
|
(6,945
|
)
|
|
|
—
|
|
Cash from investing activities
|
$
|
(247,942
|
)
|
|
$
|
(96,653
|
)
|
|
|
$
|
(37,913
|
)
|
During the 2019 Period, capital expenditures included $127.9 million for additions to property and equipment that occurred prior to December 31, 2018. Capital spending during 2019 has decreased significantly from 2018 as a result of the reassessment of our current drilling plans due to the results obtained from our 2018 drilling program and our existing liquidity concerns. We ran as many as 9 rigs during the 2018 period.
Cash flow from financing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
(in thousands)
|
Six Months Ended
June 30, 2019
|
|
February 9, 2018
Through
June 30, 2018
|
|
|
January 1, 2018
Through
February 8, 2018
|
Cash provided by (used for)
|
|
|
|
|
|
|
Proceeds from long-term debt borrowings
|
$
|
227,500
|
|
|
$
|
80,000
|
|
|
|
$
|
60,000
|
|
Repayments of long-term debt
|
—
|
|
|
(193,565
|
)
|
|
|
(43,000
|
)
|
Capital contributions (distributions), net
|
—
|
|
|
—
|
|
|
|
(68
|
)
|
Proceeds from issuance of Class A shares
|
—
|
|
|
400,000
|
|
|
|
—
|
|
Repayment of sponsor note
|
—
|
|
|
(2,000
|
)
|
|
|
—
|
|
Repayment of deferred underwriting compensation
|
—
|
|
|
(36,225
|
)
|
|
|
—
|
|
Redemption of Class A common shares
|
—
|
|
|
(33
|
)
|
|
|
—
|
|
Other
|
—
|
|
|
(3,670
|
)
|
|
|
—
|
|
Cash from financing activities
|
$
|
227,500
|
|
|
$
|
244,507
|
|
|
|
$
|
16,932
|
|
During the 2019 Period, our outstanding balances owed under the Alta Mesa RBL and KFM Credit Facility increased by $227.5 million from December 31, 2018, largely related to borrowings to fund our capital expenditures, including those expenditures incurred in 2018.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
We are exposed to certain market risks that are inherent in our financial statements that arise in the normal course of business. We may enter into derivatives to manage or reduce market risk, but we do not enter into derivatives for speculative purposes. We do not designate derivatives as hedges for accounting purposes.
Commodity Price Risk and Hedges
Our major market risk exposure is to prevailing prices for oil, gas and NGLs, which have historically been volatile. As such, future results are subject to change due to changes in these prices. Realized prices are primarily driven by the prevailing worldwide price for oil and regional prices for gas. We have used derivatives to reduce our exposure to the risks of price changes. Pursuant to our risk management policy, we have engaged in hedging against low prices and price volatility.
The fair value of our oil and gas derivatives and basis swaps at June 30, 2019 was a net asset of $6.2 million. A 10% increase in oil and gas prices (with all other factors held constant) would result in a net liability of $7.7 million at June 30, 2019, and a 10% decrease in oil and gas prices (with all other factors held constant) would result in a net asset of $18.9 million at June 30, 2019. During September 2019, we closed out all open derivative positions resulting in net proceeds of approximately $4 million, which we applied against our outstanding borrowings under the Alta Mesa RBL.
Counterparty and Customer Credit Risk
Our derivatives expose us to credit risk in the event of nonperformance by counterparties. While we do not require them to post collateral, we do monitor the credit standing of such counterparties, all of which have investment grade ratings, and are lenders under the Alta Mesa RBL.
Our principal ongoing exposures to credit risk are from joint interest receivables and receivables from the sale of our oil and gas production and midstream gathering and processing activities. The inability or failure of our customers to meet their obligations
to us or their insolvency or liquidation may adversely affect our financial results. However, we believe the credit quality of our purchasers of production, midstream services and other working interest owners is high. Because Alta Mesa filed for bankruptcy protection, KFM’s ability to collect fees from Alta Mesa for midstream services could be impaired. We cannot predict the likelihood, if any, that Alta Mesa’s bankruptcy filing could have on KFM’s operating cash flow.
During most of the first quarter of 2019 and throughout 2018, ARM Energy Management, LLC ("ARM") marketed our oil, gas and NGLs for a marketing fee that is deducted from sales proceeds collected by ARM from purchasers. The sales were generally made under short-term contracts with month-to-month pricing based on published regional indices, adjusted for transportation, location and quality. In March 2019, in preparation for handling oil and NGL marketing responsibilities internally, we began receiving payments for the sale of oil and NGLs directly from purchasers and separately paying the marketing fee owed to ARM. As of June 1, 2019, we terminated our oil and NGL marketing agreement with ARM and have begun marketing such products internally. We have extended the term of our gas marketing agreement with ARM through November 30, 2019.
For the six months ended June 30, 2019, ARM marketed $119.2 million, or 44.3% of our operating revenue for the period.
Joint operations receivables arise from billings to entities that own interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we intend to drill. We have little ability to control whether these entities will participate in our wells.
Interest Rates
We are subject to interest rate risk under the Alta Mesa RBL and KFM Credit Facility. We currently have no open interest rate derivatives. A 100 basis point increase in interest rates would increase our annual interest expense for both facilities by approximately $5.6 million, based on the balances outstanding at June 30, 2019.
Inflation
Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the 2019 Period. Although the impact of inflation has been insignificant in recent years, it could cause future upward pressure on the cost of oilfield services, equipment and general and administrative expenses.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As required by Rules 13a-15 and 15d-15 of the Exchange Act, our management, with the participation of our principal executive officer and principal financial officer, performed an evaluation of our disclosure controls and procedures. Our controls and procedures are designed to ensure that information required to be disclosed by the Company in reports it files or
submits under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the SEC, and that the information required to be disclosed by the Company in reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including the principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.
As described further in our 2018 10-K, we concluded that our disclosure controls and procedures were not effective as of December 31, 2018, due to existence of material weakness in our internal control over financial reporting (“ICFR”). Apart from the controls and procedures relating to accounting for business combinations, several of the material weaknesses in our ICFR continued to exist during the 2019 Period. These material weaknesses include:
|
|
•
|
establishment of formal policies and procedures;
|
|
|
•
|
ineffective monitoring activities that span the Company to ensure that internal controls processes are functioning properly;
|
|
|
•
|
ineffective controls over the financial statement close and disclosure process; and
|
|
|
•
|
over-reliance on and ineffective controls over access to and changes involving critical worksheets.
|
As noted in our 2018 10-K, KFM was excluded from management’s assessment of internal control over financial reporting as of December 31, 2018 but will be included in our assessment for 2019.
Changes in Internal Control Over Financial Reporting (ICFR)
While we have made progress in multiple areas to improve ICFR, management is continuing to implement the remediation plan described in our 2018 10-K and continues to work to make changes in controls and procedures in a manner consistent with the size, complexity and scale of operations subsequent to the Business Combination.
During the Second Quarter 2019, we have made access changes to payroll, production accounting, and reserves systems to address material weaknesses identified during 2018. Testing to be conducted later in 2019 will determine whether these changes to system access will prove effective in remediating the underlying material weakness.