x
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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o
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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Delaware
|
38-3531640
|
(State or other jurisdiction of
incorporation or organization)
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(I.R.S. Employer
Identification No.)
|
|
|
1331 Lamar Street, Suite 650
|
|
Houston, Texas
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77010
|
(Address of principal executive offices)
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(Zip Code)
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Yes
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ý
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No
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o
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Yes
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ý
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No
|
o
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Large accelerated filer
|
o
|
Accelerated filer
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ý
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Non-accelerated filer
|
o
(Do not check if a smaller reporting company)
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Smaller reporting company
|
o
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Yes
|
o
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No
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ý
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Page
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Item 1.
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Item 2.
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Item 3.
|
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Item 4.
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Item 1.
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Item 1A.
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Item 2.
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Item 3.
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Item 4.
|
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Item 5.
|
||
Item 6.
|
||
AMI
|
|
Area of mutual interest, an agreed designated geographic area where joint venturers or other industry partners have a right of participation in acquisitions and operations
|
|
|
|
Bbl
|
|
Barrel of oil, condensate or NGLs
|
|
|
|
Bbl/d
|
|
Barrels of oil, condensate or NGLs per day
|
|
|
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Bcf
|
|
One billion cubic feet of natural gas
|
|
|
|
Bcfe
|
|
One billion cubic feet of natural gas equivalent, calculated by converting liquids volumes on the basis of 1/6th of a barrel of oil, condensate or NGLs per Mcf
|
|
|
|
Boe
|
|
One barrel of oil equivalent determined using the ratio of six thousand cubic feet of natural gas to one barrel of oil, condensate or NGLs
|
|
|
|
Boe/d
|
|
Barrels of oil equivalent per day
|
|
|
|
Btu
|
|
British thermal unit, typically used in measuring natural gas energy content
|
|
|
|
CRP
|
|
Central receipt point
|
|
|
|
FASB
|
|
Financial Accounting Standards Board
|
|
|
|
Gross acres
|
|
Refers to acres in which we own a working interest
|
|
|
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Gross wells
|
|
Refers to wells in which we have a working interest
|
|
|
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MBbl
|
|
One thousand barrels of oil, condensate or NGLs
|
|
|
|
MBbl/d
|
|
One thousand barrels of oil, condensate or NGLs per day
|
|
|
|
MBoe
|
|
One thousand barrels of oil equivalent, calculated by converting natural gas volumes on the basis of 6 Mcf of natural gas per barrel
|
|
|
|
MBoe/d
|
|
One thousand barrels of oil equivalent per day
|
|
|
|
Mcf
|
|
One thousand cubic feet of natural gas
|
|
|
|
Mcf/d
|
|
One thousand cubic feet of natural gas per day
|
|
|
|
Mcfe
|
|
One thousand cubic feet of natural gas equivalent, calculated by converting liquids volumes on the basis of 1/6th of a barrel of oil, condensate or NGLs per Mcf
|
|
|
|
MMBtu/d
|
|
One million British thermal units per day
|
|
|
|
MMcf
|
|
One million cubic feet of natural gas
|
|
|
|
MMcf/d
|
|
One million cubic feet of natural gas per day
|
|
|
|
MMcfe
|
|
One million cubic feet of natural gas equivalent, calculated by converting liquids volumes on the basis of 1/6th of a barrel of oil, condensate or NGLs per Mcf
|
|
|
|
MMcfe/d
|
|
One million cubic feet of natural gas equivalent per day
|
|
|
|
Net acres
|
|
Refers to our proportionate interest in acreage resulting from our ownership in gross acreage
|
|
|
|
Net wells
|
|
Refers to gross wells multiplied by our working interest in such wells
|
|
|
|
NGLs
|
|
Natural gas liquids
|
|
|
|
NYMEX
|
|
New York Mercantile Exchange
|
|
|
|
PBU
|
|
Performance based unit comprising one of our compensation plan awards
|
|
|
|
psi
|
|
Pounds per square inch
|
|
|
|
U.S.
|
|
United States of America
|
|
|
|
U.S. GAAP
|
|
Accounting principles generally accepted in the United States of America
|
|
June 30,
2015 |
|
December 31,
2014 |
||||
|
(Unaudited)
|
|
|
||||
|
(in thousands, except share data)
|
||||||
ASSETS
|
|
|
|
||||
CURRENT ASSETS:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
9,378
|
|
|
$
|
11,008
|
|
Accounts receivable, net of allowance for doubtful accounts of $0, respectively
|
16,431
|
|
|
30,841
|
|
||
Commodity derivative contracts
|
13,159
|
|
|
19,687
|
|
||
Prepaid expenses
|
686
|
|
|
2,083
|
|
||
Total current assets
|
39,654
|
|
|
63,619
|
|
||
PROPERTY, PLANT AND EQUIPMENT:
|
|
|
|
||||
Oil and natural gas properties, full cost method of accounting:
|
|
|
|
||||
Unproved properties, excluded from amortization
|
123,162
|
|
|
128,274
|
|
||
Proved properties
|
1,208,229
|
|
|
1,124,367
|
|
||
Total oil and natural gas properties
|
1,331,391
|
|
|
1,252,641
|
|
||
Furniture and equipment
|
3,055
|
|
|
3,010
|
|
||
Total property, plant and equipment
|
1,334,446
|
|
|
1,255,651
|
|
||
Accumulated depreciation, depletion and amortization
|
(694,054
|
)
|
|
(563,351
|
)
|
||
Total property, plant and equipment, net
|
640,392
|
|
|
692,300
|
|
||
OTHER ASSETS:
|
|
|
|
||||
Commodity derivative contracts
|
9,996
|
|
|
7,815
|
|
||
Deferred charges, net
|
2,889
|
|
|
2,586
|
|
||
Advances to operators and other assets
|
795
|
|
|
9,474
|
|
||
Total other assets
|
13,680
|
|
|
19,875
|
|
||
TOTAL ASSETS
|
$
|
693,726
|
|
|
$
|
775,794
|
|
LIABILITIES AND STOCKHOLDERS' EQUITY
|
|
|
|
||||
CURRENT LIABILITIES:
|
|
|
|
||||
Accounts payable
|
$
|
13,333
|
|
|
$
|
28,843
|
|
Revenue payable
|
6,770
|
|
|
9,122
|
|
||
Accrued interest
|
3,553
|
|
|
3,528
|
|
||
Accrued drilling and operating costs
|
6,351
|
|
|
5,977
|
|
||
Advances from non-operators
|
—
|
|
|
1,820
|
|
||
Commodity derivative contracts
|
166
|
|
|
—
|
|
||
Commodity derivative premium payable
|
1,515
|
|
|
2,481
|
|
||
Asset retirement obligation
|
86
|
|
|
82
|
|
||
Other accrued liabilities
|
9,251
|
|
|
3,175
|
|
||
Total current liabilities
|
41,025
|
|
|
55,028
|
|
||
LONG-TERM LIABILITIES:
|
|
|
|
||||
Long-term debt
|
411,545
|
|
|
360,303
|
|
||
Commodity derivative contracts
|
616
|
|
|
—
|
|
||
Commodity derivative premium payable
|
4,051
|
|
|
4,702
|
|
||
Asset retirement obligation
|
5,873
|
|
|
5,475
|
|
||
Total long-term liabilities
|
422,085
|
|
|
370,480
|
|
||
Commitments and contingencies (Note 11)
|
|
|
|
||||
STOCKHOLDERS’ EQUITY:
|
|
|
|
||||
Preferred stock, 40,000,000 shares authorized
|
|
|
|
||||
Series A Preferred stock, par value $0.01 per share; 10,000,000 shares designated; 4,045,000 shares issued and outstanding at June 30, 2015 and December 31, 2014, respectively, with liquidation preference of $25.00 per share
|
41
|
|
|
41
|
|
||
Series B Preferred stock, par value $0.01 per share; 10,000,000 shares designated; 2,140,000 shares issued and outstanding at June 30, 2015 and December 31, 2014, respectively, with liquidation preference of $25.00 per share
|
21
|
|
|
21
|
|
||
Common stock, par value $0.001 per share; 275,000,000 shares authorized; 80,144,934 and 78,632,810 shares issued and outstanding at June 30, 2015 and December 31, 2014, respectively
|
78
|
|
|
78
|
|
||
Additional paid-in capital
|
569,788
|
|
|
568,440
|
|
||
Accumulated deficit
|
(339,312
|
)
|
|
(218,294
|
)
|
||
Total stockholders’ equity
|
230,616
|
|
|
350,286
|
|
||
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
|
$
|
693,726
|
|
|
$
|
775,794
|
|
|
For the Three Months Ended June 30,
|
|
For the Six Months Ended June 30,
|
||||||||||||
|
2015
|
|
2014
|
|
2015
|
|
2014
|
||||||||
|
(in thousands, except share and per share data)
|
||||||||||||||
REVENUES:
|
|
|
|
|
|
|
|
||||||||
Oil and condensate
|
$
|
17,584
|
|
|
$
|
22,342
|
|
|
$
|
32,937
|
|
|
$
|
39,120
|
|
Natural gas
|
3,950
|
|
|
17,559
|
|
|
10,650
|
|
|
32,978
|
|
||||
NGLs
|
2,184
|
|
|
4,906
|
|
|
4,280
|
|
|
11,550
|
|
||||
Total oil, condensate, natural gas and NGLs revenues
|
23,718
|
|
|
44,807
|
|
|
47,867
|
|
|
83,648
|
|
||||
(Loss) gain on commodity derivatives contracts
|
(1,790
|
)
|
|
(8,910
|
)
|
|
8,433
|
|
|
(15,424
|
)
|
||||
Total revenues
|
21,928
|
|
|
35,897
|
|
|
56,300
|
|
|
68,224
|
|
||||
EXPENSES:
|
|
|
|
|
|
|
|
||||||||
Production taxes
|
822
|
|
|
2,037
|
|
|
1,662
|
|
|
3,931
|
|
||||
Lease operating expenses
|
7,242
|
|
|
4,877
|
|
|
13,261
|
|
|
8,921
|
|
||||
Transportation, treating and gathering
|
542
|
|
|
2,146
|
|
|
1,039
|
|
|
2,771
|
|
||||
Depreciation, depletion and amortization
|
16,080
|
|
|
10,280
|
|
|
30,551
|
|
|
22,662
|
|
||||
Impairment of oil and natural gas properties
|
100,152
|
|
|
—
|
|
|
100,152
|
|
|
—
|
|
||||
Accretion of asset retirement obligation
|
131
|
|
|
125
|
|
|
256
|
|
|
247
|
|
||||
General and administrative expense
|
4,421
|
|
|
3,893
|
|
|
8,669
|
|
|
8,656
|
|
||||
Total expenses
|
129,390
|
|
|
23,358
|
|
|
155,590
|
|
|
47,188
|
|
||||
(LOSS) INCOME FROM OPERATIONS
|
(107,462
|
)
|
|
12,539
|
|
|
(99,290
|
)
|
|
21,036
|
|
||||
OTHER INCOME (EXPENSE):
|
|
|
|
|
|
|
|
||||||||
Interest expense
|
(6,936
|
)
|
|
(6,912
|
)
|
|
(14,497
|
)
|
|
(13,803
|
)
|
||||
Investment income and other
|
3
|
|
|
4
|
|
|
6
|
|
|
11
|
|
||||
Foreign transaction loss
|
—
|
|
|
(4
|
)
|
|
—
|
|
|
(6
|
)
|
||||
(LOSS) INCOME BEFORE PROVISION FOR INCOME TAXES
|
(114,395
|
)
|
|
5,627
|
|
|
(113,781
|
)
|
|
7,238
|
|
||||
Provision for income taxes
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
NET (LOSS) INCOME
|
(114,395
|
)
|
|
5,627
|
|
|
(113,781
|
)
|
|
7,238
|
|
||||
Dividends on preferred stock
|
(3,619
|
)
|
|
(3,611
|
)
|
|
(7,237
|
)
|
|
(7,187
|
)
|
||||
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS
|
$
|
(118,014
|
)
|
|
$
|
2,016
|
|
|
$
|
(121,018
|
)
|
|
$
|
51
|
|
NET (LOSS) INCOME PER SHARE OF COMMON STOCK ATTRIBUTABLE TO COMMON STOCKHOLDERS:
|
|
|
|
|
|
|
|
||||||||
Basic
|
$
|
(1.52
|
)
|
|
$
|
0.03
|
|
|
$
|
(1.56
|
)
|
|
$
|
—
|
|
Diluted
|
$
|
(1.52
|
)
|
|
$
|
0.03
|
|
|
$
|
(1.56
|
)
|
|
$
|
—
|
|
WEIGHTED AVERAGE SHARES OF COMMON STOCK OUTSTANDING:
|
|
|
|
|
|
|
|
||||||||
Basic
|
77,611,167
|
|
|
58,702,982
|
|
|
77,364,368
|
|
|
58,462,124
|
|
||||
Diluted
|
77,611,167
|
|
|
61,922,874
|
|
|
77,364,368
|
|
|
61,674,267
|
|
|
For the Six Months Ended June 30,
|
||||||
|
2015
|
|
2014
|
||||
|
(in thousands)
|
||||||
CASH FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
||||
Net (loss) income
|
$
|
(113,781
|
)
|
|
$
|
7,238
|
|
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
|
|
|
|
||||
Depreciation, depletion and amortization
|
30,551
|
|
|
22,662
|
|
||
Impairment of oil and natural gas properties
|
100,152
|
|
|
—
|
|
||
Stock-based compensation
|
2,773
|
|
|
2,532
|
|
||
Mark to market of commodity derivatives contracts:
|
|
|
|
||||
Total (gain) loss on commodity derivatives contracts
|
(8,433
|
)
|
|
15,424
|
|
||
Cash settlements of matured commodity derivatives contracts, net
|
11,408
|
|
|
(6,061
|
)
|
||
Cash premiums paid for commodity derivatives contracts
|
(45
|
)
|
|
(155
|
)
|
||
Amortization of deferred financing costs
|
1,736
|
|
|
1,491
|
|
||
Accretion of asset retirement obligation
|
256
|
|
|
247
|
|
||
Settlement of asset retirement obligation
|
(80
|
)
|
|
(546
|
)
|
||
Changes in operating assets and liabilities:
|
|
|
|
||||
Accounts receivable
|
15,887
|
|
|
(2,827
|
)
|
||
Prepaid expenses
|
1,397
|
|
|
112
|
|
||
Accounts payable and accrued liabilities
|
(4,806
|
)
|
|
9,649
|
|
||
Net cash provided by operating activities
|
37,015
|
|
|
49,766
|
|
||
CASH FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
||||
Development and purchase of oil and natural gas properties
|
(84,724
|
)
|
|
(55,295
|
)
|
||
Advances to operators
|
(1,225
|
)
|
|
(20,657
|
)
|
||
Acquisition of oil and natural gas properties - refund
|
—
|
|
|
4,209
|
|
||
Proceeds from sale of oil and natural gas properties
|
2,008
|
|
|
3,077
|
|
||
Deposit for sale of oil and natural gas properties
|
6,620
|
|
|
—
|
|
||
(Payments to) proceeds from non-operators
|
(1,820
|
)
|
|
526
|
|
||
Purchase of furniture and equipment
|
(45
|
)
|
|
(158
|
)
|
||
Net cash used in investing activities
|
(79,186
|
)
|
|
(68,298
|
)
|
||
CASH FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
||||
Proceeds from revolving credit facility
|
55,000
|
|
|
35,000
|
|
||
Repayment of revolving credit facility
|
(5,000
|
)
|
|
(15,000
|
)
|
||
Proceeds from issuance of preferred stock, net of issuance costs
|
—
|
|
|
2,064
|
|
||
Dividends on preferred stock
|
(7,237
|
)
|
|
(7,187
|
)
|
||
Deferred financing charges
|
(797
|
)
|
|
(319
|
)
|
||
Tax withholding related to restricted stock and performance based unit award vestings
|
(1,425
|
)
|
|
(3,656
|
)
|
||
Net cash provided by financing activities
|
40,541
|
|
|
10,902
|
|
||
NET DECREASE IN CASH AND CASH EQUIVALENTS
|
(1,630
|
)
|
|
(7,630
|
)
|
||
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD
|
11,008
|
|
|
32,393
|
|
||
CASH AND CASH EQUIVALENTS, END OF PERIOD
|
$
|
9,378
|
|
|
$
|
24,763
|
|
1.
|
Description of Business
|
2.
|
Summary of Significant Accounting Policies
|
3.
|
Property, Plant and Equipment
|
|
June 30, 2015
|
|
December 31, 2014
|
||||
|
(in thousands)
|
||||||
Unproved properties, excluded from amortization:
|
|
|
|
||||
Drilling in progress costs
|
$
|
14,895
|
|
|
$
|
29,193
|
|
Acreage acquisition costs
|
98,278
|
|
|
91,362
|
|
||
Capitalized interest
|
9,989
|
|
|
7,719
|
|
||
Total unproved properties excluded from amortization
|
$
|
123,162
|
|
|
$
|
128,274
|
|
|
2015
|
||||||||||
|
Total Impairment
|
|
June 30
|
|
March 31
|
||||||
Henry Hub natural gas price (per MMBtu)
(1)
|
|
|
$
|
3.39
|
|
|
$
|
3.88
|
|
||
West Texas Intermediate oil price (per Bbl)
(1)
|
|
|
$
|
71.68
|
|
|
$
|
82.72
|
|
||
Impairment recorded (pre-tax) (in thousands)
|
$
|
100,152
|
|
|
$
|
100,152
|
|
|
$
|
—
|
|
|
2014
|
||||||||||
|
Total Impairment
|
|
June 30
|
|
March 31
|
||||||
Henry Hub natural gas price (per MMBtu)
(1)
|
|
|
$
|
4.10
|
|
|
$
|
3.99
|
|
||
West Texas Intermediate oil price (per Bbl)
(1)
|
|
|
$
|
100.11
|
|
|
$
|
98.30
|
|
||
Impairment recorded (pre-tax) (in thousands)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
(1)
|
For the respective periods, oil and natural gas prices are calculated using the trailing 12-month unweighted arithmetic average of the first-day-of-the-month prices based on Henry Hub spot natural gas prices and West Texas Intermediate spot oil prices.
|
4.
|
Long-Term Debt
|
•
|
Restrictions on liens, incurrence of other indebtedness without lenders' consent and common stock dividends and other restricted payments;
|
•
|
Maintenance of a minimum consolidated current ratio as of the end of each quarter of not less than
1.0
to
1.0
, as adjusted;
|
•
|
Maintenance of a maximum ratio of net indebtedness to EBITDA of not greater than
4.0
to
1.0
, subject to the modifications in Amendment No. 5 set forth below; and
|
•
|
Maintenance of an interest coverage ratio on a rolling four quarters basis, as adjusted, of EBITDA to interest expense, as of the end of each quarter, to be less than
2.5
to
1.0
, subject to the modifications in Amendment No. 5 set forth below.
|
•
|
Failure to make payments;
|
•
|
Non-performance of covenants and obligations continuing beyond any applicable grace period; and
|
•
|
The occurrence of a change in control of the Company, as defined under the Revolving Credit Facility.
|
•
|
Transfer or sell assets or use asset sale proceeds;
|
•
|
Pay dividends or make distributions, redeem subordinated debt or make other restricted payments;
|
•
|
Make certain investments; incur or guarantee additional debt or issue preferred equity securities;
|
•
|
Create or incur certain liens on the Company's assets;
|
•
|
Incur dividend or other payment restrictions affecting future restricted subsidiaries;
|
•
|
Merge, consolidate or transfer all or substantially all of the Company's assets;
|
•
|
Enter into certain transactions with affiliates; and
|
•
|
Enter into certain sale and leaseback transactions.
|
5.
|
Fair Value Measurements
|
•
|
Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities. The Company’s cash equivalents consist of short-term, highly liquid investments, which have maturities of 90 days or less, including sweep investments and money market funds.
|
•
|
Level 2 inputs are quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration, for substantially the full term of the financial instrument.
|
•
|
Level 3 inputs are measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources. These inputs may be used with internally developed methodologies or third party broker quotes that result in management’s best estimate of fair value. The Company’s valuation models consider various inputs including (a) quoted forward prices for commodities, (b) time value, (c) volatility factors and (d) current market and contractual prices for the underlying instruments. Significant increases or decreases in any of these inputs in isolation would result in a significantly higher or lower fair value measurement. Level 3 instruments are commodity costless collars, index swaps, basis and fixed price swaps and put and call options to hedge natural gas, oil and NGLs price risk. At each balance sheet date, the Company performs an analysis of all applicable instruments and includes in Level 3 all of those whose fair value is based on significant unobservable inputs. The fair values derived from counterparties and third-party brokers are verified by the Company using publicly available values for relevant NYMEX futures contracts and exchange traded contracts for each derivative settlement location. Although such counterparty and third-party broker quotes are used to assess the fair value of its commodity derivative instruments, the Company does not have access to the specific assumptions used in its counterparties valuation models. Consequently, additional disclosures regarding significant Level 3 unobservable inputs were not provided and the Company does not currently have sufficient corroborating market evidence to support classifying these contracts as Level 2 instruments.
|
|
Fair value as of June 30, 2015
|
||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
|
(in thousands)
|
||||||||||||||
Assets:
|
|
|
|
|
|
|
|
||||||||
Cash and cash equivalents
|
$
|
9,378
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
9,378
|
|
Commodity derivative contracts
|
—
|
|
|
—
|
|
|
23,155
|
|
|
23,155
|
|
||||
Liabilities:
|
|
|
|
|
|
|
|
||||||||
Commodity derivative contracts
|
—
|
|
|
—
|
|
|
(782
|
)
|
|
(782
|
)
|
||||
Total
|
$
|
9,378
|
|
|
$
|
—
|
|
|
$
|
22,373
|
|
|
$
|
31,751
|
|
|
|
|
|
|
|
|
|
||||||||
|
|
|
|
|
|
|
|
||||||||
|
|
|
|
|
|
|
|
||||||||
|
Fair value as of December 31, 2014
|
||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
|
(in thousands)
|
||||||||||||||
Assets:
|
|
|
|
|
|
|
|
||||||||
Cash and cash equivalents
|
$
|
11,008
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
11,008
|
|
Commodity derivative contracts
|
—
|
|
|
—
|
|
|
27,502
|
|
|
27,502
|
|
||||
Liabilities:
|
|
|
|
|
|
|
|
||||||||
Commodity derivative contracts
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Total
|
$
|
11,008
|
|
|
$
|
—
|
|
|
$
|
27,502
|
|
|
$
|
38,510
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||||||
|
2015
|
|
2014
|
|
2015
|
|
2014
|
||||||||
|
(in thousands)
|
||||||||||||||
Balance at beginning of period
|
$
|
31,823
|
|
|
$
|
620
|
|
|
$
|
27,502
|
|
|
$
|
3,764
|
|
Total (losses) gains included in earnings
|
(1,790
|
)
|
|
(8,910
|
)
|
|
8,433
|
|
|
(15,424
|
)
|
||||
Purchases
|
45
|
|
|
268
|
|
|
911
|
|
|
339
|
|
||||
Issuances
|
(1,127
|
)
|
|
—
|
|
|
(1,313
|
)
|
|
—
|
|
||||
Settlements
(1)
|
(6,578
|
)
|
|
3,394
|
|
|
(13,160
|
)
|
|
6,693
|
|
||||
Balance at end of period
|
$
|
22,373
|
|
|
$
|
(4,628
|
)
|
|
$
|
22,373
|
|
|
$
|
(4,628
|
)
|
The amount of total losses for the period included in earnings attributable to the change in mark to market of commodity derivatives contracts still held at June 30, 2015 and 2014
|
$
|
(7,777
|
)
|
|
$
|
(5,418
|
)
|
|
$
|
(3,525
|
)
|
|
$
|
(8,573
|
)
|
(1)
|
Included in gain (loss) on commodity derivatives contracts on the condensed consolidated statements of operations.
|
6.
|
Derivative Instruments and Hedging Activity
|
Settlement Period
|
|
Derivative Instrument
|
|
Average
Daily
Volume
(1)
|
|
Total of
Notional
Volume
|
|
Floor
(Long)
|
|
Short
Put
|
|
Ceiling
(Short)
|
||||||||
|
|
|
|
(in Bbls)
|
|
|
|
|
|
|
||||||||||
2015
|
|
Costless three-way collar
|
|
400
|
|
|
73,600
|
|
|
$
|
85.00
|
|
|
$
|
70.00
|
|
|
$
|
96.50
|
|
2015
|
|
Costless three-way collar
|
|
325
|
|
|
59,800
|
|
|
$
|
85.00
|
|
|
$
|
65.00
|
|
|
$
|
97.80
|
|
2015
|
|
Costless three-way collar
|
|
50
|
|
|
9,200
|
|
|
$
|
85.00
|
|
|
$
|
65.00
|
|
|
$
|
96.25
|
|
2015
|
|
Costless collar
|
|
750
|
|
|
130,000
|
|
|
$
|
52.50
|
|
|
$
|
—
|
|
|
$
|
62.05
|
|
2015
|
|
Costless collar
|
|
300
|
|
|
55,200
|
|
|
$
|
52.50
|
|
|
$
|
—
|
|
|
$
|
68.10
|
|
2015
|
|
Fixed price swap
|
|
600
|
|
|
110,400
|
|
|
$
|
72.54
|
|
|
$
|
—
|
|
|
$
|
—
|
|
2015
|
|
Fixed price swap
|
|
250
|
|
|
46,000
|
|
|
$
|
74.20
|
|
|
$
|
—
|
|
|
$
|
—
|
|
2016
|
|
Costless three-way collar
|
|
275
|
|
|
100,600
|
|
|
$
|
85.00
|
|
|
$
|
65.00
|
|
|
$
|
95.10
|
|
2016
|
|
Costless three-way collar
|
|
330
|
|
|
120,780
|
|
|
$
|
80.00
|
|
|
$
|
65.00
|
|
|
$
|
97.35
|
|
2016
|
|
Costless three-way collar
|
|
450
|
|
|
164,700
|
|
|
$
|
57.50
|
|
|
$
|
42.50
|
|
|
$
|
80.00
|
|
2016
|
|
Put spread
|
|
550
|
|
|
201,300
|
|
|
$
|
85.00
|
|
|
$
|
65.00
|
|
|
$
|
—
|
|
2016
|
|
Put spread
|
|
300
|
|
|
109,800
|
|
|
$
|
85.50
|
|
|
$
|
65.50
|
|
|
$
|
—
|
|
2017
|
|
Costless three-way collar
|
|
280
|
|
|
102,200
|
|
|
$
|
80.00
|
|
|
$
|
65.00
|
|
|
$
|
97.25
|
|
2017
|
|
Costless three-way collar
|
|
242
|
|
|
88,150
|
|
|
$
|
80.00
|
|
|
$
|
60.00
|
|
|
$
|
98.70
|
|
2017
|
|
Costless three-way collar
|
|
200
|
|
|
73,000
|
|
|
$
|
60.00
|
|
|
$
|
42.50
|
|
|
$
|
85.00
|
|
2017
|
|
Put spread
|
|
500
|
|
|
182,500
|
|
|
$
|
82.00
|
|
|
$
|
62.00
|
|
|
$
|
—
|
|
2017
|
|
Costless three-way collar
|
|
200
|
|
|
73,000
|
|
|
$
|
57.50
|
|
|
$
|
42.50
|
|
|
$
|
76.13
|
|
2018
(2)
|
|
Put spread
|
|
425
|
|
|
103,275
|
|
|
$
|
80.00
|
|
|
$
|
60.00
|
|
|
$
|
—
|
|
(1)
|
Crude volumes hedged include oil, condensate and certain components of our NGLs production.
|
(2)
|
For the period January to August 2018.
|
Settlement Period
|
|
Derivative Instrument
|
|
Average
Daily
Volume
|
|
Total of
Notional
Volume
|
|
Base
Fixed
Price
|
|
Floor
(Long)
|
|
Short
Put
|
|
Call
(Long)
|
|
Ceiling
(Short)
|
||||||||||||
|
|
|
|
(in MMBtus)
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
2015
|
|
Fixed price swap
|
|
400
|
|
|
73,600
|
|
|
$
|
4.00
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
2015
|
|
Fixed price swap
|
|
2,500
|
|
|
460,000
|
|
|
$
|
4.06
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
2015
|
|
Protective spread
|
|
2,600
|
|
|
478,400
|
|
|
$
|
4.00
|
|
|
$
|
—
|
|
|
$
|
3.25
|
|
|
$
|
—
|
|
|
$
|
—
|
|
2015
|
|
Fixed price swap
|
|
5,000
|
|
|
920,000
|
|
|
$
|
3.49
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
2015
|
|
Fixed price swap
|
|
2,000
|
|
|
368,000
|
|
|
$
|
3.53
|
|
|
$
|
—
|
|
|
$
|
3.25
|
|
|
$
|
—
|
|
|
$
|
—
|
|
2015
|
|
Producer three-way collar
|
|
2,500
|
|
|
460,000
|
|
|
$
|
—
|
|
|
$
|
3.70
|
|
|
$
|
3.00
|
|
|
$
|
—
|
|
|
$
|
4.09
|
|
2015
|
|
Producer three-way collar
|
|
5,000
|
|
|
920,000
|
|
|
$
|
—
|
|
|
$
|
3.77
|
|
|
$
|
3.00
|
|
|
$
|
—
|
|
|
$
|
4.11
|
|
2015
(1)
|
|
Producer three-way collar
|
|
2,000
|
|
|
246,000
|
|
|
$
|
—
|
|
|
$
|
3.00
|
|
|
$
|
2.25
|
|
|
$
|
—
|
|
|
$
|
3.34
|
|
2015
(1)
|
|
Fixed price swap
|
|
10,000
|
|
|
1,230,000
|
|
|
$
|
2.94
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
2015
(2)
|
|
Producer three-way collar
|
|
2,500
|
|
|
152,500
|
|
|
$
|
—
|
|
|
$
|
3.00
|
|
|
$
|
2.25
|
|
|
$
|
—
|
|
|
$
|
3.65
|
|
2015
|
|
Basis swap(3)
|
|
2,500
|
|
|
460,000
|
|
|
$
|
(1.12
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
2015
|
|
Basis swap(3)
|
|
2,500
|
|
|
460,000
|
|
|
$
|
(1.11
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
2015
|
|
Basis swap(3)
|
|
2,500
|
|
|
460,000
|
|
|
$
|
(1.14
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
2016
(4)
|
|
Producer three-way collar
|
|
2,500
|
|
|
762,500
|
|
|
$
|
—
|
|
|
$
|
3.00
|
|
|
$
|
2.25
|
|
|
$
|
—
|
|
|
$
|
3.65
|
|
2016
|
|
Protective spread
|
|
2,000
|
|
|
732,000
|
|
|
$
|
4.11
|
|
|
$
|
—
|
|
|
$
|
3.25
|
|
|
$
|
—
|
|
|
$
|
—
|
|
2016
|
|
Producer three-way collar
|
|
2,000
|
|
|
732,000
|
|
|
$
|
—
|
|
|
$
|
4.00
|
|
|
$
|
3.25
|
|
|
$
|
—
|
|
|
$
|
4.58
|
|
2016
|
|
Producer three-way collar
|
|
5,000
|
|
|
1,830,000
|
|
|
$
|
—
|
|
|
$
|
3.40
|
|
|
$
|
2.65
|
|
|
$
|
—
|
|
|
$
|
4.10
|
|
2016
|
|
Basis swap(5)
|
|
2,500
|
|
|
915,000
|
|
|
$
|
(1.10
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
2017
|
|
Short call
|
|
10,000
|
|
|
3,650,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
4.75
|
|
(1)
|
For the period July to October 2015.
|
(2)
|
For the period November to December 2015.
|
(3)
|
Represents basis swaps at the sales point of Dominion South.
|
(4)
|
For the period January to October 2016.
|
(5)
|
Represents basis swaps at the sales point of TetcoM2.
|
Settlement Period
|
|
Derivative Instrument
|
|
Average
Daily
Volume
|
|
Total of
Notional
Volume
|
|
Base
Fixed
Price
|
|||
|
|
|
|
(in Bbls)
|
|
|
|||||
2015
|
|
Fixed price swap
|
|
250
|
|
46,000
|
|
|
$
|
45.61
|
|
2015
|
|
Fixed price swap
|
|
500
|
|
92,000
|
|
|
$
|
20.79
|
|
2016
|
|
Fixed price swap
|
|
500
|
|
183,000
|
|
|
$
|
20.79
|
|
|
June 30, 2015
|
|
December 31, 2014
|
||||
|
(in thousands)
|
||||||
Current commodity derivative put premium payable
|
$
|
1,515
|
|
|
$
|
2,481
|
|
Long-term commodity derivative put premium payable
|
4,051
|
|
|
4,702
|
|
||
Total unamortized put premium liabilities
|
$
|
5,566
|
|
|
$
|
7,183
|
|
|
For the Three Months Ended June 30, 2015
|
|
For the Six Months Ended June 30, 2015
|
||||
|
(in thousands)
|
||||||
Put premium liabilities, beginning balance
|
$
|
7,281
|
|
|
$
|
7,183
|
|
Amortization of put premium liabilities
|
(1,715
|
)
|
|
(2,297
|
)
|
||
Additional put premium liabilities
|
—
|
|
|
680
|
|
||
Put premium liabilities, ending balance
|
$
|
5,566
|
|
|
$
|
5,566
|
|
|
Amortization
|
||
|
(in thousands)
|
||
January to December 2016
|
$
|
3,050
|
|
January to December 2017
|
1,684
|
|
|
January to August 2018
|
832
|
|
|
Total unamortized put premium liabilities
|
$
|
5,566
|
|
|
Fair Values of Derivative Instruments
Derivative Assets (Liabilities)
|
||||||||
|
|
|
Fair Value
|
||||||
|
Balance Sheet Location
|
|
June 30, 2015
|
|
December 31, 2014
|
||||
|
|
|
(in thousands)
|
||||||
Derivatives not designated as hedging instruments
|
|
|
|
|
|
||||
Commodity derivative contracts
|
Current assets
|
|
$
|
13,159
|
|
|
$
|
19,687
|
|
Commodity derivative contracts
|
Other assets
|
|
9,996
|
|
|
7,815
|
|
||
Commodity derivative contracts
|
Current liabilities
|
|
(166
|
)
|
|
—
|
|
||
Commodity derivative contracts
|
Long-term liabilities
|
|
(616
|
)
|
|
—
|
|
||
Total derivatives not designated as hedging instruments
|
|
|
$
|
22,373
|
|
|
$
|
27,502
|
|
|
|
|
Amount of Gain (Loss)
Recognized in Income on Derivatives For the Three Months Ended June 30, |
||||||
|
Location of Gain (Loss) Recognized in Income on Derivatives
|
|
2015
|
|
2014
|
||||
|
|
|
(in thousands)
|
||||||
Derivatives not designated as hedging instruments
|
|
|
|
|
|
||||
Commodity derivative contracts
|
Loss on commodity derivatives contracts
|
|
$
|
(1,790
|
)
|
|
$
|
(8,910
|
)
|
Total
|
|
|
$
|
(1,790
|
)
|
|
$
|
(8,910
|
)
|
|
|
|
|
|
|
||||
|
|
|
|
|
|
||||
|
|
|
|
|
|
||||
|
|
|
Amount of Loss
Recognized in Income on Derivatives For the Six Months Ended June 30, |
||||||
|
Location of (Gain) Loss Recognized in Income on Derivatives
|
|
2015
|
|
2014
|
||||
|
|
|
(in thousands)
|
||||||
Derivatives not designated as hedging instruments
|
|
|
|
|
|
||||
Commodity derivative contracts
|
Gain (loss) on commodity derivatives contracts
|
|
$
|
8,433
|
|
|
$
|
(15,424
|
)
|
Total
|
|
|
$
|
8,433
|
|
|
$
|
(15,424
|
)
|
|
|
|
|
|
|
7.
|
Capital Stock
|
|
For the Three Months Ended June 30, 2015
|
|
For the Six Months Ended June 30, 2015
|
||
Other share issuances:
|
|
|
|
||
Shares of restricted common stock granted
|
—
|
|
|
1,421,224
|
|
Shares of restricted common stock vested
|
—
|
|
|
1,274,872
|
|
Shares of common stock issued pursuant to PBUs vested, net of forfeitures
|
—
|
|
|
497,636
|
|
Shares of restricted common stock surrendered upon vesting/exercise
(1)
|
—
|
|
|
382,238
|
|
Shares of restricted common stock forfeited
|
841
|
|
|
24,498
|
|
(1)
|
Represents shares of common stock forfeited in connection with the payment of estimated withholding taxes on shares of restricted common stock that vested during the period.
|
8.
|
Interest Expense
|
|
For the Three Months Ended June 30,
|
|
For the Six Months Ended June 30,
|
||||||||||||
|
2015
|
|
2014
|
|
2015
|
|
2014
|
||||||||
|
(in thousands)
|
||||||||||||||
Interest expense:
|
|
|
|
|
|
|
|
||||||||
Cash and accrued
|
$
|
7,241
|
|
|
$
|
7,208
|
|
|
$
|
15,169
|
|
|
$
|
14,342
|
|
Amortization of deferred financing costs
(1)
|
915
|
|
|
758
|
|
|
1,736
|
|
|
1,491
|
|
||||
Capitalized interest
|
(1,220
|
)
|
|
(1,054
|
)
|
|
(2,408
|
)
|
|
(2,030
|
)
|
||||
Total interest expense
|
$
|
6,936
|
|
|
$
|
6,912
|
|
|
$
|
14,497
|
|
|
$
|
13,803
|
|
(1)
|
The three months ended
June 30, 2015
and
2014
includes
$629,000
and
$570,000
, respectively, of debt discount accretion related to the Notes. The six months ended
June 30, 2015
and
2014
includes
$1.2 million
and
$1.1 million
, respectively, of debt discount accretion related to the Notes.
|
9.
|
Income Taxes
|
10.
|
Earnings per Share
|
|
For the Three Months Ended June 30,
|
|
For the Six Months Ended June 30,
|
||||||||||||
|
2015
|
|
2014
|
|
2015
|
|
2014
|
||||||||
|
(in thousands, except per share and share data)
|
||||||||||||||
Net (loss) income attributable to common stockholders
|
$
|
(118,014
|
)
|
|
$
|
2,016
|
|
|
$
|
(121,018
|
)
|
|
$
|
51
|
|
|
|
|
|
|
|
|
|
||||||||
Weighted average common shares outstanding - basic
|
77,611,167
|
|
|
58,702,982
|
|
|
77,364,368
|
|
|
58,462,124
|
|
||||
Incremental shares from unvested restricted shares
|
—
|
|
|
2,514,542
|
|
|
—
|
|
|
2,563,673
|
|
||||
Incremental shares from outstanding stock options
|
—
|
|
|
112,232
|
|
|
—
|
|
|
106,499
|
|
||||
Incremental shares from outstanding PBUs
|
—
|
|
|
593,118
|
|
|
—
|
|
|
541,971
|
|
||||
Weighted average common shares outstanding - diluted
|
77,611,167
|
|
|
61,922,874
|
|
|
77,364,368
|
|
|
61,674,267
|
|
||||
|
|
|
|
|
|
|
|
||||||||
Net (loss) income per share of common stock attributable to common stockholders:
|
|
|
|
|
|
|
|
||||||||
Basic
|
$
|
(1.52
|
)
|
|
$
|
0.03
|
|
|
$
|
(1.56
|
)
|
|
$
|
—
|
|
Diluted
|
$
|
(1.52
|
)
|
|
$
|
0.03
|
|
|
$
|
(1.56
|
)
|
|
$
|
—
|
|
Common shares excluded from denominator as anti-dilutive:
|
|
|
|
|
|
|
|
||||||||
Unvested restricted shares
|
8,970
|
|
|
—
|
|
|
93,733
|
|
|
—
|
|
||||
Stock options
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Unvested PBUs
|
44,213
|
|
|
—
|
|
|
94,488
|
|
|
—
|
|
||||
Total
|
53,183
|
|
|
—
|
|
|
188,221
|
|
|
—
|
|
11.
|
Commitments and Contingencies
|
12.
|
Statement of Cash Flows – Supplemental Information
|
|
For the Six Months Ended June 30,
|
||||||
|
2015
|
|
2014
|
||||
|
(in thousands)
|
||||||
Cash paid for interest, net of capitalized amounts
|
$
|
12,735
|
|
|
$
|
14,469
|
|
|
|
|
|
||||
Non-cash transactions:
|
|
|
|
||||
Capital expenditures excluded from accounts payable and accrued drilling costs
|
$
|
(7,477
|
)
|
|
$
|
655
|
|
Capital expenditures included in accounts receivable
|
$
|
—
|
|
|
$
|
4,077
|
|
Capital expenditures excluded from prepaid expenses
|
$
|
—
|
|
|
$
|
51
|
|
Asset retirement obligation included in oil and natural gas properties
|
$
|
227
|
|
|
$
|
45
|
|
Application of advances to operators
|
$
|
9,904
|
|
|
$
|
19,926
|
|
Other
|
$
|
—
|
|
|
$
|
(3
|
)
|
•
|
financial position;
|
•
|
business strategy and budgets;
|
•
|
capital expenditures;
|
•
|
drilling of wells, including the anticipated scheduling and results of such operations;
|
•
|
oil, natural gas and NGLs reserves;
|
•
|
timing and amount of future production of oil, condensate, natural gas and NGLs;
|
•
|
operating costs and other expenses;
|
•
|
cash flow and liquidity;
|
•
|
compliance with covenants under our indenture and credit agreements;
|
•
|
availability of capital;
|
•
|
prospect development; and
|
•
|
property acquisitions and sales.
|
•
|
the supply and demand for oil, condensate, natural gas and NGLs;
|
•
|
continued low or further declining prices for oil, condensate, natural gas and NGLs;
|
•
|
worldwide political and economic conditions and conditions in the energy market;
|
•
|
the extent to which we are able to realize the anticipated benefits from acquired assets;
|
•
|
our ability to raise capital to fund capital expenditures or repay or refinance debt upon maturity;
|
•
|
our ability to meet financial covenants under our indenture or credit agreements or the ability to obtain amendments or waivers to effect such compliance;
|
•
|
the ability and willingness of our current or potential counterparties, third-party operators or vendors to enter into transactions with us and/or to fulfill their obligations to us;
|
•
|
failure of our joint interest partners to fund any or all of their portion of any capital program;
|
•
|
the ability to find, acquire, market, develop and produce new oil and natural gas properties;
|
•
|
uncertainties about the estimated quantities of oil and natural gas reserves and in the projection of future rates of production and timing of development expenditures of proved reserves;
|
•
|
strength and financial resources of competitors;
|
•
|
availability and cost of material and equipment, such as drilling rigs and transportation pipelines;
|
•
|
availability and cost of processing and transportation;
|
•
|
changes or advances in technology;
|
•
|
the risks associated with exploration, including cost overruns and the drilling of non-economic wells or dry wells, operating hazards inherent to the oil and natural gas business and down hole drilling and completion risks that are generally not recoverable from third parties or insurance;
|
•
|
potential mechanical failure or under-performance of significant wells or pipeline mishaps;
|
•
|
environmental risks;
|
•
|
possible new legislative initiatives and regulatory changes potentially adversely impacting our business and industry, including, but not limited to, national healthcare, hydraulic fracturing, state and federal corporate income taxes, retroactive royalty or production tax regimes, changes in environmental regulations, environmental risks and liability under federal, state and local environmental laws and regulations;
|
•
|
effects of the application of applicable laws and regulations, including changes in such regulations or the interpretation thereof;
|
•
|
potential losses from pending or possible future claims, litigation or enforcement actions;
|
•
|
potential defects in title to our properties or lease termination due to lack of activity or other disputes with mineral lease and royalty owners, whether regarding calculation and payment of royalties or otherwise;
|
•
|
the weather, including the occurrence of any adverse weather conditions and/or natural disasters affecting our business;
|
•
|
our ability to find and retain skilled personnel; and
|
•
|
any other factors that impact or could impact the exploration of natural gas or oil resources, including, but not limited to, the geology of a resource, the total amount and costs to develop recoverable reserves, legal title, regulatory, natural gas administration, marketing and operational factors relating to the extraction of oil and natural gas.
|
|
|
|
|
|
|
|
|
Cumulative Production Averages
(2)
|
|
|
|
|
||
Well Name
|
|
Current Working Interest
|
|
Approximate Lateral Length (in feet)
|
|
Peak Production Rates
(1)
(Boe/d)
|
|
Boe/d
|
|
% Oil
|
|
Date of First Production or Status
|
|
Approximate Gross Costs to Drill & Complete ($ millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LB 1-1H
|
|
47.6%
|
|
4,400
|
|
791
|
|
242
|
|
65%
|
|
January 23, 2015
|
|
$4.4
|
Hubbard 1-23H
(3)
|
|
57.0%
|
|
4,600
|
|
N/A
|
|
22
|
|
95%
|
|
February 19, 2015
|
|
$6.1
|
Boss Hogg 1-14H
|
|
50.0%
|
|
4,400
|
|
129
|
|
61
|
|
68%
|
|
February 21, 2015
|
|
$7.4
|
Bo 1-23H
|
|
43.8%
|
|
4,900
|
|
547
|
|
307
|
|
47%
|
|
February 28, 2015
|
|
$5.0
|
The River 1-22H
|
|
39.7%
|
|
4,400
|
|
1,250
|
|
943
|
|
34%
|
|
March 14, 2015
|
|
$4.6
|
Bigfoot 1-9H
|
|
47.4%
|
|
4,800
|
|
161
|
|
112
|
|
58%
|
|
March 17, 2015
|
|
$5.1
|
Falcon 1-5H
|
|
51.5%
|
|
4,700
|
|
1,202
|
|
547
|
|
84%
|
|
April 1, 2015
|
|
$4.5
|
Dorothy 1-12H
|
|
49.5%
|
|
5,000
|
|
N/A
|
|
17
|
|
78%
|
|
April 10, 2015
|
|
$4.5
|
Polar Bear 1-20H
|
|
47.7%
|
|
4,400
|
|
403
|
|
180
|
|
87%
|
|
May 5, 2015
|
|
$5.0
|
Unruh 1-34H
(4)
|
|
49.0%
|
|
4,900
|
|
N/A
|
|
N/A
|
|
N/A
|
|
Awaiting completion
|
|
$7.1
|
(1)
|
Represents highest daily gross Boe rate.
|
(2)
|
Represents gross cumulative production divided by actual producing days through July 19, 2015.
|
(3)
|
After payout working interest is 49.9%.
|
(4)
|
Approximate gross costs to drill and complete includes costs to re-drill the well due to an initial horizontal casing collapse.
|
|
|
|
|
|
|
|
|
Cumulative Production Averages
(2)
|
|
|
|
|
||
Well Name
|
|
Current Working Interest
|
|
Approximate Lateral Length (in feet)
|
|
Peak Production Rates
(1)
(BOE/d)
|
|
BOE/d
|
|
% Oil
|
|
Date of First Production or Status
|
|
Approximate Gross Costs to Drill & Complete ($ millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wolf 1-9H
|
|
16.7%
|
|
3,600
|
|
391
|
|
216
|
|
58%
|
|
January 3, 2015
|
|
$5.5
|
(1)
|
Represents highest daily gross Boe rate.
|
(2)
|
Represents gross cumulative production divided by actual producing days through July 19, 2015.
|
|
|
|
|
|
|
|
|
Cumulative Production Averages
(2)
|
|
|
|
|
||
Well Name
|
|
Current Working Interest
|
|
Approximate Lateral Length (in feet)
|
|
Peak Production Rates
(1)
(BOE/d)
|
|
BOE/d
|
|
% Oil
|
|
Date of First Production or Status
|
|
Approximate Gross Costs to Drill & Complete ($ millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Upper Hunton Completions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Warsaw 33-2H
|
|
98.3%
|
|
4,900
|
|
615
|
|
260
|
|
63%
|
|
February 13, 2015
|
|
$4.0
|
Blair Farms 31-1H
|
|
98.3%
|
|
6,500
|
|
509
|
|
353
|
|
83%
|
|
May 7, 2015
|
|
$5.0
|
Easton 22-4H
|
|
98.3%
|
|
6,500
|
|
604
|
|
357
|
|
89%
|
|
May 20, 2015
|
|
$3.1
|
Jetson 8-2H
|
|
98.3%
|
|
5,900
|
|
N/A
|
|
N/A
|
|
N/A
|
|
Awaiting completion
|
|
$3.5
|
Arcadia Farms 15-2H
|
|
98.3%
|
|
6,800
|
|
N/A
|
|
N/A
|
|
N/A
|
|
Drilling
|
|
$3.4
|
O' Donnell 5-1H
|
|
98.3%
|
|
6,800
|
|
N/A
|
|
N/A
|
|
N/A
|
|
Drilling
|
|
$3.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lower Hunton Completions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Warsaw 33-3H
|
|
98.3%
|
|
5,800
|
|
663
|
|
250
|
|
62%
|
|
February 14, 2015
|
|
$6.4
|
Easton 22-3H
|
|
98.3%
|
|
6,500
|
|
N/A
|
|
335
|
|
83%
|
|
May 24, 2015
|
|
$5.0
|
Davis 9-2H
|
|
98.3%
|
|
6,800
|
|
N/A
|
|
N/A
|
|
N/A
|
|
Awaiting flowback
|
|
$4.5
|
Davis 9-4H
|
|
98.3%
|
|
7,400
|
|
N/A
|
|
N/A
|
|
N/A
|
|
Awaiting flowback
|
|
$4.6
|
Jetson 8-1H
|
|
98.3%
|
|
5,000
|
|
N/A
|
|
N/A
|
|
N/A
|
|
Awaiting completion
|
|
$5.6
|
Arcadia Farms 15-1CH
|
|
98.3%
|
|
6,800
|
|
N/A
|
|
N/A
|
|
N/A
|
|
Drilling
|
|
$5.0
|
O'Donnell 5-2CH
|
|
98.3%
|
|
7,500
|
|
N/A
|
|
N/A
|
|
N/A
|
|
Drilling
|
|
$5.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Warsaw 33-1(3)
|
|
98.3%
|
|
N/A
|
|
59
|
|
27
|
|
47%
|
|
March 13, 2015
|
|
$3.8
|
(1)
|
Represents highest daily gross Boe rate.
|
(2)
|
Represents gross cumulative production divided by actual producing days through July 19, 2015.
|
(3)
|
The Warsaw 33-1 is a commingled vertical pilot well completed in the upper, middle and lower Hunton zones.
|
|
For the Three Months Ended June 30,
|
|
For the Six Months Ended June 30,
|
||||||||||||
Mid-Continent
|
2015
|
|
2014
|
|
2015
|
|
2014
|
||||||||
Net Production:
|
|
|
|
|
|
|
|
||||||||
Oil and condensate (MBbl)
|
304
|
|
|
167
|
|
|
601
|
|
|
303
|
|
||||
Natural gas (MMcf)
|
889
|
|
|
631
|
|
|
1,686
|
|
|
1,289
|
|
||||
NGLs (MBbl)
|
113
|
|
|
103
|
|
|
209
|
|
|
150
|
|
||||
Total net production (MBoe)
|
565
|
|
|
374
|
|
|
1,091
|
|
|
667
|
|
||||
Net Daily Production:
|
|
|
|
|
|
|
|
||||||||
Oil and condensate (MBbl/d)
|
3.3
|
|
|
1.8
|
|
|
3.3
|
|
|
1.7
|
|
||||
Natural gas (MMcf/d)
|
9.8
|
|
|
6.9
|
|
|
9.3
|
|
|
7.1
|
|
||||
NGLs (MBbl/d)
|
1.2
|
|
|
1.1
|
|
|
1.2
|
|
|
0.8
|
|
||||
Total net daily production (MBoe/d)
|
6.2
|
|
|
4.1
|
|
|
6.0
|
|
|
3.7
|
|
||||
Average sales price per unit
(1)
:
|
|
|
|
|
|
|
|
||||||||
Oil and condensate (per Bbl)
|
$
|
53.86
|
|
|
$
|
101.81
|
|
|
$
|
50.40
|
|
|
$
|
100.11
|
|
Natural gas (per Mcf)
|
$
|
2.47
|
|
|
$
|
3.85
|
|
|
$
|
2.81
|
|
|
$
|
4.78
|
|
NGLs (per Bbl)
|
$
|
14.98
|
|
|
$
|
34.01
|
|
|
$
|
14.69
|
|
|
$
|
37.26
|
|
Average sales price per Boe
(1)
|
$
|
35.86
|
|
|
$
|
61.13
|
|
|
$
|
34.92
|
|
|
$
|
63.00
|
|
|
|
|
|
|
|
|
|
||||||||
Selected operating expenses (in thousands):
|
|
|
|
|
|
|
|
||||||||
Production taxes
|
$
|
489
|
|
|
$
|
745
|
|
|
$
|
840
|
|
|
$
|
1,360
|
|
Lease operating expenses
(2)
|
$
|
5,666
|
|
|
$
|
3,793
|
|
|
$
|
10,692
|
|
|
$
|
6,632
|
|
Transportation, treating and gathering
|
$
|
3
|
|
|
$
|
12
|
|
|
$
|
7
|
|
|
$
|
22
|
|
Selected operating expenses per Boe:
|
|
|
|
|
|
|
|
||||||||
Production taxes
|
$
|
0.87
|
|
|
$
|
1.99
|
|
|
$
|
0.77
|
|
|
$
|
2.04
|
|
Lease operating expenses
(2)
|
$
|
10.04
|
|
|
$
|
10.13
|
|
|
$
|
9.80
|
|
|
$
|
9.94
|
|
Transportation, treating and gathering
|
$
|
0.01
|
|
|
$
|
0.03
|
|
|
$
|
0.01
|
|
|
$
|
0.03
|
|
Production costs
(3)
|
$
|
10.04
|
|
|
$
|
10.17
|
|
|
$
|
9.80
|
|
|
$
|
9.97
|
|
(1)
|
Excludes the impact of hedging activities.
|
(2)
|
Lease operating expenses for the three and six months ended June 30, 2015 include $1.4 million and $2.8 million, respectively, of workover expense for one-time production enhancing workovers completed on certain WEHLU wells. Excluding workover expense, lease operating expense per Boe for the three and six months ended June 30, 2015 would have been $7.59 per Boe and $7.27 per Boe, respectively, compared to $10.00 per Boe and $9.87 per Boe for the three and six months ended June 30, 2014, respectively.
|
(3)
|
Production costs include lease operating expense, insurance, gathering and workover expense and excludes ad valorem and severance taxes.
|
|
For the Three Months Ended June 30,
|
|
For the Six Months Ended June 30,
|
||||||||||||
Marcellus Shale
|
2015
|
|
2014
|
|
2015
|
|
2014
|
||||||||
Net Production:
|
|
|
|
|
|
|
|
||||||||
Oil and condensate (MBbl)
|
65
|
|
|
40
|
|
|
135
|
|
|
107
|
|
||||
Natural gas (MMcf)
|
2,071
|
|
|
2,049
|
|
|
4,228
|
|
|
4,463
|
|
||||
NGLs (MBbl)
|
185
|
|
|
105
|
|
|
307
|
|
|
213
|
|
||||
Total net production (MBoe)
|
595
|
|
|
487
|
|
|
1,147
|
|
|
1,064
|
|
||||
Net Daily Production:
|
|
|
|
|
|
|
|
||||||||
Oil and condensate (MBbl/d)
|
0.7
|
|
|
0.4
|
|
|
0.7
|
|
|
0.6
|
|
||||
Natural gas (MMcf/d)
|
22.8
|
|
|
22.5
|
|
|
23.4
|
|
|
24.7
|
|
||||
NGLs (MBbl/d)
|
2.0
|
|
|
1.2
|
|
|
1.7
|
|
|
1.2
|
|
||||
Total net daily production (MBoe/d)
|
6.5
|
|
|
5.4
|
|
|
6.3
|
|
|
5.9
|
|
||||
Average sales price per unit
(1)(2)
:
|
|
|
|
|
|
|
|
||||||||
Oil and condensate (per Bbl)
|
$
|
18.82
|
|
|
$
|
134.02
|
|
|
$
|
19.57
|
|
|
$
|
82.31
|
|
Natural gas (per Mcf)
|
$
|
0.64
|
|
|
$
|
7.38
|
|
|
$
|
1.18
|
|
|
$
|
6.01
|
|
NGLs (per Bbl)
|
$
|
2.69
|
|
|
$
|
13.49
|
|
|
$
|
3.93
|
|
|
$
|
28.00
|
|
Average sales price per Boe
(1)(2)
|
$
|
5.12
|
|
|
$
|
45.04
|
|
|
$
|
7.69
|
|
|
$
|
39.10
|
|
Selected operating expenses (in thousands):
|
|
|
|
|
|
|
|
||||||||
Production taxes
(3)
|
$
|
275
|
|
|
$
|
1,293
|
|
|
$
|
717
|
|
|
$
|
2,571
|
|
Lease operating expenses
(3)
|
$
|
1,550
|
|
|
$
|
1,084
|
|
|
$
|
2,539
|
|
|
$
|
2,288
|
|
Transportation, treating and gathering
(3)
|
$
|
450
|
|
|
$
|
2,134
|
|
|
$
|
910
|
|
|
$
|
2,749
|
|
Selected operating expenses per Boe:
|
|
|
|
|
|
|
|
||||||||
Production taxes
(3)
|
$
|
0.46
|
|
|
$
|
2.66
|
|
|
$
|
0.63
|
|
|
$
|
2.42
|
|
Lease operating expenses
(3)
|
$
|
2.61
|
|
|
$
|
2.23
|
|
|
$
|
2.21
|
|
|
$
|
2.15
|
|
Transportation, treating and gathering
(3)
|
$
|
0.76
|
|
|
$
|
4.38
|
|
|
$
|
0.79
|
|
|
$
|
2.58
|
|
Production costs
(4)
|
$
|
2.73
|
|
|
$
|
6.20
|
|
|
$
|
2.36
|
|
|
$
|
4.33
|
|
(1)
|
Excludes the impact of hedging activities.
|
(2)
|
The three and six months ended June 30, 2014 include the benefit of a one-time revenue adjustment related to an arbitration settlement. Excluding the arbitration settlement adjustment impact, average sales prices would have been as follows:
|
|
For the Three Months Ended June 30, 2014
|
|
For the Six Months Ended June 30, 2014
|
||||
Marcellus Shale
|
|
|
|
||||
Average sales price per unit:
|
|
|
|
||||
Oil and condensate (per Bbl)
|
$
|
55.59
|
|
|
$
|
52.97
|
|
Natural gas (per Mcf)
|
$
|
3.42
|
|
|
$
|
4.19
|
|
NGLs (per Bbl)
|
$
|
19.93
|
|
|
$
|
31.17
|
|
Average sales price per Boe
|
$
|
23.26
|
|
|
$
|
29.14
|
|
(3)
|
The three and six months ended June 30, 2014 include a one-time adjustment to production taxes, lease operating expenses and transportation, treating and gathering related to an arbitration settlement. Excluding the arbitration settlement adjustment impact, production taxes, lease operating expenses and transportation, treating and gathering per Boe would have been as follows:
|
|
For the Three Months Ended June 30, 2014
|
|
For the Six Months Ended June 30, 2014
|
||||
Marcellus Shale
|
|
|
|
||||
Selected operating expenses per Boe:
|
|
|
|
||||
Production taxes
|
$
|
1.46
|
|
|
$
|
1.87
|
|
Lease operating expenses
|
$
|
2.61
|
|
|
$
|
2.32
|
|
Transportation, treating and gathering
|
$
|
1.13
|
|
|
$
|
1.09
|
|
(4)
|
Production costs include lease operating expenses, insurance, gathering and workover expense and excludes ad valorem and severance taxes. Excluding the arbitration settlement adjustment impact, production costs for the three and six months ended June 30, 2014 would have been as follows:
|
|
For the Three Months Ended June 30, 2014
|
|
For the Six Months Ended June 30, 2014
|
||||
Marcellus Shale
|
|
|
|
||||
Selected operating expenses per Boe:
|
|
|
|
||||
Production costs
|
$
|
3.33
|
|
|
$
|
3.02
|
|
|
For the Three Months Ended June 30,
|
|
For the Six Months Ended June 30,
|
||||||||||||
Utica Shale
|
2015
|
|
2014
|
|
2015
|
|
2014
|
||||||||
Net Production:
|
|
|
|
|
|
|
|
||||||||
Natural gas (MMcf)
|
615
|
|
|
—
|
|
|
955
|
|
|
—
|
|
||||
Total net production (MBoe)
|
102
|
|
|
—
|
|
|
159
|
|
|
—
|
|
||||
Net Daily Production:
|
|
|
|
|
|
|
|
||||||||
Natural gas (MMcf/d)
|
6.8
|
|
|
—
|
|
|
5.3
|
|
|
—
|
|
||||
Total net daily production (MBoe/d)
|
1.1
|
|
|
—
|
|
|
0.9
|
|
|
—
|
|
||||
Average sales price per unit
(1)
:
|
|
|
|
|
|
|
|
||||||||
Natural gas (per Mcf)
|
$
|
0.69
|
|
|
$
|
—
|
|
|
$
|
0.99
|
|
|
$
|
—
|
|
Average sales price per Boe
(1)
|
$
|
4.14
|
|
|
$
|
—
|
|
|
$
|
5.93
|
|
|
$
|
—
|
|
Selected operating expenses (in thousands):
|
|
|
|
|
|
|
|
||||||||
Production taxes
|
$
|
58
|
|
|
$
|
—
|
|
|
$
|
104
|
|
|
$
|
—
|
|
Lease operating expenses
|
$
|
26
|
|
|
$
|
—
|
|
|
$
|
31
|
|
|
$
|
—
|
|
Transportation, treating and gathering
|
$
|
89
|
|
|
$
|
—
|
|
|
$
|
123
|
|
|
$
|
—
|
|
Selected operating expenses per Boe:
|
|
|
|
|
|
|
|
||||||||
Production taxes
|
$
|
0.57
|
|
|
$
|
—
|
|
|
$
|
0.65
|
|
|
$
|
—
|
|
Lease operating expenses
|
$
|
0.25
|
|
|
$
|
—
|
|
|
$
|
0.20
|
|
|
$
|
—
|
|
Transportation, treating and gathering
|
$
|
0.87
|
|
|
$
|
—
|
|
|
$
|
0.78
|
|
|
$
|
—
|
|
Production costs
(2)
|
$
|
1.12
|
|
|
$
|
—
|
|
|
$
|
0.97
|
|
|
$
|
—
|
|
(1)
|
Excludes the impact of hedging activities.
|
(2)
|
Production costs include lease operating expenses, insurance, gathering and workover expense and excludes ad valorem and severance taxes.
|
|
For the Three Months Ended June 30,
|
|
For the Six Months Ended June 30,
|
||||||||||||
|
2015
|
|
2014
|
|
2015
|
|
2014
|
||||||||
|
(In thousands, except per unit amounts)
|
||||||||||||||
Net Production:
|
|
|
|
|
|
|
|
||||||||
Oil and condensate (MBbl)
|
369
|
|
|
207
|
|
|
736
|
|
|
410
|
|
||||
Natural gas (MMcf)
|
3,575
|
|
|
2,680
|
|
|
6,870
|
|
|
5,752
|
|
||||
NGLs (MBbl)
|
297
|
|
|
208
|
|
|
516
|
|
|
363
|
|
||||
Total net production (MBoe)
|
1,262
|
|
|
861
|
|
|
2,397
|
|
|
1,732
|
|
||||
Net Daily production:
|
|
|
|
|
|
|
|
||||||||
Oil and condensate (MBbl/d)
|
4.1
|
|
|
2.3
|
|
|
4.1
|
|
|
2.3
|
|
||||
Natural gas (MMcf/d)
|
39.3
|
|
|
29.5
|
|
|
38.0
|
|
|
31.8
|
|
||||
NGLs (MBbl/d)
|
3.3
|
|
|
2.3
|
|
|
2.9
|
|
|
2.0
|
|
||||
Total net daily production (MBoe/d)
|
13.9
|
|
|
9.5
|
|
|
13.2
|
|
|
9.6
|
|
||||
Average sales price per unit
(1)
:
|
|
|
|
|
|
|
|
||||||||
Oil and condensate per Bbl, excluding impact of hedging activities
|
$
|
47.68
|
|
|
$
|
108.06
|
|
|
$
|
44.76
|
|
|
$
|
95.45
|
|
Oil and condensate per Bbl, including impact of hedging activities
(2)
|
$
|
52.20
|
|
|
$
|
102.52
|
|
|
$
|
49.86
|
|
|
$
|
91.15
|
|
Natural gas per Mcf, excluding impact of hedging activities
|
$
|
1.10
|
|
|
$
|
6.55
|
|
|
$
|
1.55
|
|
|
$
|
5.73
|
|
Natural gas per Mcf, including impact of hedging activities
(2)
|
$
|
1.68
|
|
|
$
|
6.06
|
|
|
$
|
2.11
|
|
|
$
|
5.14
|
|
NGLs per Bbl, excluding impact of hedging activities
|
$
|
7.34
|
|
|
$
|
23.62
|
|
|
$
|
8.29
|
|
|
$
|
31.82
|
|
NGLs per Bbl, including impact of hedging activities
(2)
|
$
|
14.97
|
|
|
$
|
18.66
|
|
|
$
|
16.72
|
|
|
$
|
27.20
|
|
Average sales price per Boe, excluding impact of hedging activities
|
$
|
18.79
|
|
|
$
|
52.03
|
|
|
$
|
19.97
|
|
|
$
|
48.31
|
|
Average sales price per Boe, including impact of hedging activities
(2)
|
$
|
23.54
|
|
|
$
|
47.98
|
|
|
$
|
24.96
|
|
|
$
|
44.35
|
|
Selected operating expenses:
|
|
|
|
|
|
|
|
||||||||
Production taxes
(3)
|
$
|
822
|
|
|
$
|
2,037
|
|
|
$
|
1,662
|
|
|
$
|
3,931
|
|
Lease operating expenses
(3)
|
$
|
7,242
|
|
|
$
|
4,877
|
|
|
$
|
13,261
|
|
|
$
|
8,921
|
|
Transportation, treating and gathering
(3)
|
$
|
542
|
|
|
$
|
2,146
|
|
|
$
|
1,039
|
|
|
$
|
2,771
|
|
Depreciation, depletion and amortization
|
$
|
16,080
|
|
|
$
|
10,280
|
|
|
$
|
30,551
|
|
|
$
|
22,662
|
|
Impairment of natural gas and oil properties
|
$
|
100,152
|
|
|
$
|
—
|
|
|
$
|
100,152
|
|
|
—
|
|
|
General and administrative expense
|
$
|
4,421
|
|
|
$
|
3,893
|
|
|
$
|
8,669
|
|
|
$
|
8,656
|
|
Selected operating expenses per Boe:
|
|
|
|
|
|
|
|
||||||||
Production taxes
(3)
|
$
|
0.65
|
|
|
$
|
2.37
|
|
|
$
|
0.69
|
|
|
$
|
2.27
|
|
Lease operating expenses
(3)(4)
|
$
|
5.74
|
|
|
$
|
5.66
|
|
|
$
|
5.53
|
|
|
$
|
5.15
|
|
Transportation, treating and gathering
(3)
|
$
|
0.43
|
|
|
$
|
2.49
|
|
|
$
|
0.43
|
|
|
$
|
1.60
|
|
Depreciation, depletion and amortization
|
$
|
12.74
|
|
|
$
|
11.94
|
|
|
$
|
12.75
|
|
|
$
|
13.09
|
|
General and administrative expense
|
$
|
3.50
|
|
|
$
|
4.52
|
|
|
$
|
3.62
|
|
|
$
|
5.00
|
|
Production costs
(5)
|
$
|
5.87
|
|
|
$
|
7.92
|
|
|
$
|
5.66
|
|
|
$
|
6.51
|
|
|
For the Three Months Ended June 30, 2014
|
|
For the Six Months Ended June 30, 2014
|
||||
Average sales price per unit:
|
|
|
|
||||
Oil and condensate per Bbl, excluding impact of hedging activities
|
$
|
92.84
|
|
|
$
|
87.77
|
|
Oil and condensate per Bbl, including impact of hedging activities
(2)
|
$
|
87.30
|
|
|
$
|
83.47
|
|
Natural gas per Mcf, excluding impact of hedging activities
|
$
|
3.52
|
|
|
$
|
4.32
|
|
Natural gas per Mcf, including impact of hedging activities
(2)
|
$
|
3.03
|
|
|
$
|
3.73
|
|
NGLs per Bbl, excluding impact of hedging activities
|
$
|
26.88
|
|
|
$
|
33.69
|
|
NGLs per Bbl, including impact of hedging activities
(2)
|
$
|
21.92
|
|
|
$
|
29.07
|
|
Average sales price per Boe, excluding impact of hedging activities
|
$
|
39.72
|
|
|
$
|
42.19
|
|
Average sales price per Boe, including impact of hedging activities
(2)
|
$
|
35.67
|
|
|
$
|
38.23
|
|
(2)
|
The impact of hedging includes the gain (loss) on commodity derivative contracts settled during the periods presented.
|
|
For the Three Months Ended June 30, 2014
|
|
For the Six Months Ended June 30, 2014
|
||||
Selected operating expenses per Boe:
|
|
|
|
||||
Production taxes
|
$
|
1.69
|
|
|
$
|
1.93
|
|
Lease operating expenses
|
$
|
5.88
|
|
|
$
|
5.26
|
|
Transportation, treating and gathering
|
$
|
0.65
|
|
|
$
|
0.69
|
|
(4)
|
Lease operating expenses for the three and six months ended June 30, 2015 include $1.4 million and $2.8 million, respectively, of workover expense for one-time production enhancing workovers completed on certain WEHLU wells. Excluding workover expense, lease operating expense per Boe for the three and six months ended June 30, 2015 would have been $4.64 per Boe and $4.38 per Boe, respectively, compared to $5.60 per Boe and $5.12 per Boe for the three and six months ended June 30, 2014, respectively.
|
|
For the Three Months Ended June 30, 2014
|
|
For the Six Months Ended June 30, 2014
|
||||
Selected operating expenses per Boe:
|
|
|
|
||||
Production costs
|
$
|
6.30
|
|
|
$
|
5.70
|
|
•
|
It requires assumptions to be made that were uncertain at the time the estimate was made; and
|
•
|
Changes in the estimate or different estimates could have a material impact on our consolidated results of operations or financial condition.
|
|
|
GASTAR EXPLORATION INC.
|
|
|
|
|
|
Date:
|
August 6, 2015
|
By:
|
/
S
/ J. RUSSELL PORTER
|
|
|
|
J. Russell Porter
|
|
|
|
President and Chief Executive Officer
|
|
|
|
(Duly authorized officer and principal executive
officer)
|
Date:
|
August 6, 2015
|
By:
|
/
S
/ MICHAEL A. GERLICH
|
|
|
|
Michael A. Gerlich
|
|
|
|
Senior Vice President and Chief Financial Officer
|
|
|
|
(Duly authorized officer and principal financial and
accounting officer)
|
Exhibit Number
|
|
Description
|
2.1
|
|
Amended and Restated Plan of Arrangement Under Section 193 of the Business Corporations Act (Alberta), effective as of November 14, 2013 (incorporated by reference to Exhibit 2.1 of the Current Report on Form 8-K filed with the SEC on November 15, 2013. File No. 001-32714).
|
|
|
|
2.2
|
|
Agreement and Plan of Merger, dated as of January 31, 2014, among Gastar Exploration, Inc. and Gastar Exploration USA, Inc. (incorporated by reference to Exhibit 2.1 of the Current Report on Form 8-K filed with the SEC on January 31, 2014. File No. 000-55138).
|
|
|
|
2.3**
|
|
Purchase and Sale Agreement, dated May 1, 2015, by and between Gastar Exploration Inc. and Oklahoma Energy Acquisitions, LP. (incorporated by reference to Exhibit 2.3 of the Quarterly Report on Form 10-Q filed with the SEC on May 7, 2015).
|
|
|
|
2.4†
|
|
First Amendment of Purchase and Sale Agreement, dated June 22, 2015, by and between Gastar Exploration Inc. and Oklahoma Energy Acquisitions, LP.
|
|
|
|
3.1
|
|
Amended and Restated Certificate of Incorporation of Gastar Exploration Inc. (formerly known as Gastar Exploration USA, Inc.) (incorporated by reference to Exhibit 3.1 of the Current Report on Form 8-K filed with the SEC on October 28, 2013. File No. 001-35211).
|
|
|
|
3.2
|
|
Second Amended and Restated Bylaws of Gastar Exploration Inc. (formerly known as Gastar Exploration USA, Inc.) (incorporated by reference to Exhibit 3.2 of the Current Report on Form 8-K filed with the SEC on October 28, 2013. File No. 001-35211).
|
|
|
|
3.3
|
|
Certificate of Merger of Gastar Exploration, Inc. into Gastar Exploration USA, Inc. (incorporated by reference to Exhibit 3.1 of the Current Report on Form 8-K filed with the SEC on January 31, 2014. File No. 000-55138).
|
|
|
|
3.4
|
|
Certificate of Designation of Rights and Preferences of 8.625% Series A Cumulative Preferred Stock (incorporated by reference to Exhibit 3.3 of Gastar Exploration USA, Inc.'s Form 8-A filed on June 20, 2011. File No. 001-35211).
|
|
|
|
3.5
|
|
Certificate of Designation of Rights and Preferences of 10.75% Series B Cumulative Preferred Stock (incorporated by reference to Exhibit 3.4 of the Form 8-A filed with the SEC on November 1, 2013. File No. 001-35211).
|
|
|
|
31.1†
|
|
Certification of Principal Executive Officer of Gastar Exploration Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
|
|
31.2†
|
|
Certification of Principal Financial Officer of Gastar Exploration Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
|
|
32.1††
|
|
Certification of Principal Executive Officer and Principal Financial Officer of Gastar Exploration Inc. pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
|
|
101.INS†
|
|
XBRL Instance Document
|
|
|
|
101.SCH†
|
|
XBRL Taxonomy Extension Schema Document
|
|
|
|
101.CAL†
|
|
XBRL Taxonomy Extension Calculation Linkbase Document
|
|
|
|
101.DEF†
|
|
XBRL Taxonomy Extension Definition Linkbase Document
|
|
|
|
101.LAB†
|
|
XBRL Taxonomy Extension Label Linkbase Document
|
|
|
|
101.PRE†
|
|
XBRL Taxonomy Extension Presentation Linkbase Document
|
†
|
Filed herewith.
|
††
|
By SEC rules and regulations, deemed not filed for purposes of Section 18 of the Exchange Act, or otherwise subject to the liability of that section, nor shall it be deemed incorporated by reference into any filing under the Securities Act, or the Exchange Act.
|
*
|
Management plan or compensatory plan or arrangement.
|
**
|
Pursuant to Item 601(b)(2) of Regulation S-K, the schedules and similar attachments to Exhibit 2.3 have not been filed herewith. The registrant agrees to furnish supplementally a copy of any omitted schedule to the Securities and Exchange Commission upon request.
|
1.
|
Amendment to PSA.
|
(a)
|
Section 1.01 of the PSA is hereby amended by deleting and replacing the reference to “Section 3.02(a)” with “Section 3.02(c)” in the definition of “
Deposit
”.
|
(b)
|
Section 3.02 of the PSA is hereby amended by deleting the section in its entirety and replacing it with the following language:
|
(a)
|
Section 9.01 of the PSA is hereby amended by deleting the words “June 22, 2015” and replacing them with the words “July 6, 2015”.
|
(b)
|
Section 9.05 of the PSA is hereby amended by deleting the section in its entirety.
|
(c)
|
Section 11.01(b) of the PSA is hereby amended by deleting the words “June 30, 2015” and replacing them with the words “July 7, 2015”.
|
(d)
|
Section 11.02 of the PSA is hereby amended by deleting the words “Section 3.02(b)” and replacing it with the words “Section 3.02(d)”.
|
2.
|
Confirmation.
Except as otherwise provided herein, the provisions of the PSA shall remain in full force and effect in accordance with their respective terms following the execution of this Amendment.
|
3.
|
Amendment
. This Amendment may be amended only by an instrument in writing executed by all Parties.
|
4.
|
Entire Agreement.
This Amendment, the PSA, the Confidentiality Agreement, and the documents to be executed pursuant hereto and thereto, and the exhibits and schedules attached hereto and thereto, constitute the entire agreement between the Parties pertaining to the subject matter hereof and supersede all prior agreements, understandings, negotiations and discussions, whether oral or written, of the Parties pertaining to the subject matter hereof. No supplement, amendment, alteration, modification, waiver or termination of this Amendment or the PSA shall be binding unless executed in writing by the Parties and specifically referencing this Amendment and the PSA as being supplemented, amended, altered, modified, waived or terminated.
|
5.
|
Miscellaneous
: Capitalized terms used, but not defined herein, shall have the meanings given to those terms in the PSA. As amended above, the PSA shall continue in full force and effect. Sections 15.05 (No Third Party Beneficiaries), 15.06 (Assignment), 15.07 (Governing Law), 15.08 (Notices), 15.10 (Severability), 15.11 (Counterparts) of the PSA shall apply to this Amendment as if set forth in full in this Amendment,
mutatis mutandis
. Unless otherwise provided, all references to “Section” are references to sections in the PSA.
|
By:
|
GASTAR EXPLORATION INC.
|
By:
|
OKLAHOMA ENERGY ACQUISITIONS, LP
|
1.
|
I have reviewed this Quarterly Report on Form 10-Q of Gastar Exploration Inc. (the “Registrant”);
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this report;
|
4.
|
The Registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Registrant and have:
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
Evaluated the effectiveness of the Registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
Disclosed in this report any change in the Registrant's internal control over financial reporting that occurred during the Registrant's most recent fiscal quarter (the Registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the Registrant's internal control over financial reporting; and
|
5.
|
The Registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrant's auditors and the audit committee of the Registrant's board of directors (or persons performing the equivalent functions):
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant's ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant's internal control over financial reporting.
|
/
S
/ J. RUSSELL PORTER
|
J. Russell Porter
|
Principal Executive Officer
|
1.
|
I have reviewed this Quarterly Report on Form 10-Q of Gastar Exploration Inc. (the “Registrant”);
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this report;
|
4.
|
The Registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Registrant and have:
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
Evaluated the effectiveness of the Registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
Disclosed in this report any change in the Registrant's internal control over financial reporting that occurred during the Registrant's most recent fiscal quarter (the Registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the Registrant's internal control over financial reporting; and
|
5.
|
The Registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrant's auditors and the audit committee of the Registrant's board of directors (or persons performing the equivalent functions):
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant's ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant's internal control over financial reporting.
|
/
S
/ MICHAEL A. GERLICH
|
Michael A. Gerlich
|
Principal Financial Officer
|
/S/ J. RUSSELL PORTER
|
J. Russell Porter
|
Principal Executive Officer
|
|
/S/ MICHAEL A. GERLICH
|
Michael A. Gerlich
|
Principal Financial Officer
|