Item 1. Financial Statements
STONE ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEET
(In thousands of dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
2016
|
|
December 31,
2015
|
|
|
(Unaudited)
|
|
(Note 1)
|
|
Assets
|
|
|
|
|
Current assets:
|
|
|
|
|
Cash and cash equivalents
|
$
|
169,194
|
|
|
$
|
10,759
|
|
|
Accounts receivable
|
38,276
|
|
|
48,031
|
|
|
Fair value of derivative contracts
|
11,887
|
|
|
38,576
|
|
|
Current income tax receivable
|
46,174
|
|
|
46,174
|
|
|
Other current assets
|
12,080
|
|
|
6,881
|
|
|
Total current assets
|
277,611
|
|
|
150,421
|
|
|
Oil and gas properties, full cost method of accounting:
|
|
|
|
|
Proved
|
9,518,245
|
|
|
9,375,898
|
|
|
Less: accumulated depreciation, depletion and amortization
|
(8,960,440
|
)
|
|
(8,603,955
|
)
|
|
Net proved oil and gas properties
|
557,805
|
|
|
771,943
|
|
|
Unevaluated
|
425,204
|
|
|
440,043
|
|
|
Other property and equipment, net
|
27,968
|
|
|
29,289
|
|
|
Other assets, net
|
28,183
|
|
|
18,473
|
|
|
Total assets
|
$
|
1,316,771
|
|
|
$
|
1,410,169
|
|
|
Liabilities and Stockholders’ Equity
|
|
|
|
|
Current liabilities:
|
|
|
|
|
Accounts payable to vendors
|
$
|
28,914
|
|
|
$
|
82,207
|
|
|
Undistributed oil and gas proceeds
|
5,071
|
|
|
5,992
|
|
|
Accrued interest
|
9,773
|
|
|
9,022
|
|
|
Fair value of derivative contracts
|
37
|
|
|
—
|
|
|
Asset retirement obligations
|
33,695
|
|
|
21,291
|
|
|
Current portion of long-term debt
|
288,336
|
|
|
—
|
|
|
Other current liabilities
|
34,793
|
|
|
40,712
|
|
|
Total current liabilities
|
400,619
|
|
|
159,224
|
|
|
Long-term debt
|
1,122,901
|
|
|
1,060,955
|
|
|
Asset retirement obligations
|
203,661
|
|
|
204,575
|
|
|
Other long-term liabilities
|
18,446
|
|
|
25,204
|
|
|
Total liabilities
|
1,745,627
|
|
|
1,449,958
|
|
|
Commitments and contingencies
|
|
|
|
|
Stockholders’ equity:
|
|
|
|
|
Common stock, $.01 par value; authorized 30,000,000 shares; issued 5,592,641 and 5,530,232 shares, respectively
|
56
|
|
|
55
|
|
|
Treasury stock (1,658 shares, at cost)
|
(860
|
)
|
|
(860
|
)
|
|
Additional paid-in capital
|
1,654,731
|
|
|
1,648,687
|
|
|
Accumulated deficit
|
(2,090,168
|
)
|
|
(1,705,623
|
)
|
|
Accumulated other comprehensive income
|
7,385
|
|
|
17,952
|
|
|
Total stockholders’ equity
|
(428,856
|
)
|
|
(39,789
|
)
|
|
Total liabilities and stockholders’ equity
|
$
|
1,316,771
|
|
|
$
|
1,410,169
|
|
The accompanying notes are an integral part of this balance sheet.
STONE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
(In thousands, except per share amounts)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
Operating revenue:
|
|
|
|
|
|
|
|
|
Oil production
|
$
|
72,711
|
|
|
$
|
111,585
|
|
|
$
|
132,986
|
|
|
$
|
219,092
|
|
|
Natural gas production
|
12,553
|
|
|
26,907
|
|
|
27,726
|
|
|
55,244
|
|
|
Natural gas liquids production
|
3,718
|
|
|
11,033
|
|
|
8,453
|
|
|
23,399
|
|
|
Other operational income
|
337
|
|
|
—
|
|
|
693
|
|
|
1,792
|
|
|
Derivative income, net
|
—
|
|
|
—
|
|
|
—
|
|
|
2,427
|
|
|
Total operating revenue
|
89,319
|
|
|
149,525
|
|
|
169,858
|
|
|
301,954
|
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
18,826
|
|
|
27,429
|
|
|
38,373
|
|
|
55,006
|
|
|
Transportation, processing and gathering expenses
|
7,183
|
|
|
19,940
|
|
|
8,024
|
|
|
37,643
|
|
|
Production taxes
|
578
|
|
|
1,827
|
|
|
1,059
|
|
|
4,342
|
|
|
Depreciation, depletion and amortization
|
46,231
|
|
|
77,951
|
|
|
107,789
|
|
|
164,373
|
|
|
Write-down of oil and gas properties
|
118,649
|
|
|
224,294
|
|
|
247,853
|
|
|
715,706
|
|
|
Accretion expense
|
10,082
|
|
|
6,408
|
|
|
20,065
|
|
|
12,817
|
|
|
Salaries, general and administrative expenses
|
20,014
|
|
|
16,418
|
|
|
32,768
|
|
|
33,425
|
|
|
Incentive compensation expense
|
4,670
|
|
|
1,264
|
|
|
9,649
|
|
|
2,827
|
|
|
Restructuring fees
|
9,436
|
|
|
—
|
|
|
10,389
|
|
|
—
|
|
|
Other operational expenses
|
27,680
|
|
|
1,454
|
|
|
40,207
|
|
|
1,170
|
|
|
Derivative expense, net
|
626
|
|
|
701
|
|
|
488
|
|
|
—
|
|
|
Total operating expenses
|
263,975
|
|
|
377,686
|
|
|
516,664
|
|
|
1,027,309
|
|
|
Loss from operations
|
(174,656
|
)
|
|
(228,161
|
)
|
|
(346,806
|
)
|
|
(725,355
|
)
|
|
Other (income) expenses:
|
|
|
|
|
|
|
|
|
Interest expense
|
17,599
|
|
|
10,472
|
|
|
32,840
|
|
|
20,837
|
|
|
Interest income
|
(302
|
)
|
|
(66
|
)
|
|
(416
|
)
|
|
(188
|
)
|
|
Other income
|
(270
|
)
|
|
(613
|
)
|
|
(568
|
)
|
|
(756
|
)
|
|
Other expense
|
9
|
|
|
—
|
|
|
11
|
|
|
—
|
|
|
Total other expenses
|
17,036
|
|
|
9,793
|
|
|
31,867
|
|
|
19,893
|
|
|
Loss before income taxes
|
(191,692
|
)
|
|
(237,954
|
)
|
|
(378,673
|
)
|
|
(745,248
|
)
|
|
Provision (benefit) for income taxes:
|
|
|
|
|
|
|
|
|
Current
|
(2,113
|
)
|
|
—
|
|
|
(3,187
|
)
|
|
—
|
|
|
Deferred
|
6,182
|
|
|
(85,048
|
)
|
|
9,059
|
|
|
(264,954
|
)
|
|
Total income taxes
|
4,069
|
|
|
(85,048
|
)
|
|
5,872
|
|
|
(264,954
|
)
|
|
Net loss
|
$
|
(195,761
|
)
|
|
$
|
(152,906
|
)
|
|
$
|
(384,545
|
)
|
|
$
|
(480,294
|
)
|
|
Basic loss per share
|
$
|
(35.05
|
)
|
|
$
|
(27.68
|
)
|
|
$
|
(68.94
|
)
|
|
$
|
(86.99
|
)
|
|
Diluted loss per share
|
$
|
(35.05
|
)
|
|
$
|
(27.68
|
)
|
|
$
|
(68.94
|
)
|
|
$
|
(86.99
|
)
|
|
Average shares outstanding
|
5,585
|
|
|
5,525
|
|
|
5,578
|
|
|
5,521
|
|
|
Average shares outstanding assuming dilution
|
5,585
|
|
|
5,525
|
|
|
5,578
|
|
|
5,521
|
|
The accompanying notes are an integral part of this statement.
STONE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (LOSS)
(In thousands)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
Net loss
|
$
|
(195,761
|
)
|
|
$
|
(152,906
|
)
|
|
$
|
(384,545
|
)
|
|
$
|
(480,294
|
)
|
|
Other comprehensive income (loss), net of tax effect:
|
|
|
|
|
|
|
|
|
Derivatives
|
(11,356
|
)
|
|
(31,480
|
)
|
|
(16,640
|
)
|
|
(40,338
|
)
|
|
Foreign currency translation
|
—
|
|
|
1,324
|
|
|
6,073
|
|
|
(2,321
|
)
|
|
Comprehensive loss
|
$
|
(207,117
|
)
|
|
$
|
(183,062
|
)
|
|
$
|
(395,112
|
)
|
|
$
|
(522,953
|
)
|
The accompanying notes are an integral part of this statement.
STONE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
(In thousands)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
June 30,
|
|
|
2016
|
|
2015
|
|
Cash flows from operating activities:
|
|
|
|
|
Net loss
|
$
|
(384,545
|
)
|
|
$
|
(480,294
|
)
|
|
Adjustments to reconcile net loss to net cash provided by operating activities:
|
|
|
|
|
Depreciation, depletion and amortization
|
107,789
|
|
|
164,373
|
|
|
Write-down of oil and gas properties
|
247,853
|
|
|
715,706
|
|
|
Accretion expense
|
20,065
|
|
|
12,817
|
|
|
Deferred income tax provision (benefit)
|
9,059
|
|
|
(264,954
|
)
|
|
Settlement of asset retirement obligations
|
(10,706
|
)
|
|
(35,923
|
)
|
|
Non-cash stock compensation expense
|
4,682
|
|
|
6,028
|
|
|
Non-cash derivative expense
|
1,025
|
|
|
7,931
|
|
|
Non-cash interest expense
|
9,403
|
|
|
8,737
|
|
|
Other non-cash expense
|
6,081
|
|
|
—
|
|
|
Change in current income taxes
|
(3,187
|
)
|
|
7,206
|
|
|
Decrease in accounts receivable
|
9,755
|
|
|
23,047
|
|
|
Increase in other current assets
|
(5,283
|
)
|
|
(1,959
|
)
|
|
Decrease in accounts payable
|
(321
|
)
|
|
(7,826
|
)
|
|
Decrease in other current liabilities
|
(5,920
|
)
|
|
(8,720
|
)
|
|
Other
|
(7,880
|
)
|
|
(504
|
)
|
|
Net cash (used in) provided by operating activities
|
(2,130
|
)
|
|
145,665
|
|
|
Cash flows from investing activities:
|
|
|
|
|
Investment in oil and gas properties
|
(179,311
|
)
|
|
(264,355
|
)
|
|
Proceeds from sale of oil and gas properties, net of expenses
|
—
|
|
|
10,100
|
|
|
Investment in fixed and other assets
|
(898
|
)
|
|
(727
|
)
|
|
Change in restricted funds
|
1,045
|
|
|
179,475
|
|
|
Net cash used in investing activities
|
(179,164
|
)
|
|
(75,507
|
)
|
|
Cash flows from financing activities:
|
|
|
|
|
Proceeds from bank borrowings
|
477,000
|
|
|
5,000
|
|
|
Repayments of bank borrowings
|
(135,500
|
)
|
|
(5,000
|
)
|
|
Repayments of building loan
|
(189
|
)
|
|
—
|
|
|
Deferred financing costs
|
(900
|
)
|
|
—
|
|
|
Net payments for share-based compensation
|
(673
|
)
|
|
(3,069
|
)
|
|
Net cash provided by (used in) financing activities
|
339,738
|
|
|
(3,069
|
)
|
|
Effect of exchange rate changes on cash
|
(9
|
)
|
|
78
|
|
|
Net change in cash and cash equivalents
|
158,435
|
|
|
67,167
|
|
|
Cash and cash equivalents, beginning of period
|
10,759
|
|
|
74,488
|
|
|
Cash and cash equivalents, end of period
|
$
|
169,194
|
|
|
$
|
141,655
|
|
The accompanying notes are an integral part of this statement.
STONE ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1 – Interim Financial Statements
The condensed consolidated financial statements of Stone Energy Corporation (“Stone” or the "Company") and its subsidiaries as of
June 30, 2016
and for the three and
six
month periods ended
June 30, 2016
and
2015
are unaudited and reflect all adjustments (consisting only of normal recurring adjustments), which are, in the opinion of management, necessary for a fair presentation of the financial position and operating results for the interim periods. The condensed consolidated balance sheet as of
December 31, 2015
has been derived from the audited financial statements as of that date contained in our Annual Report on Form 10-K for the year ended
December 31, 2015
(our “
2015
Annual Report on Form 10-K”). The condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto, together with management’s discussion and analysis of financial condition and results of operations, contained in our
2015
Annual Report on Form 10-K. The results of operations for the three and
six
month periods ended
June 30, 2016
are not necessarily indicative of future financial results. Certain prior period amounts have been reclassified to conform to current period presentation.
On May 27, 2016, the board of directors of the Company approved a 1-for-10 reverse stock split of the Company's issued and outstanding shares of common stock. The reverse stock split was effective upon the filing and effectiveness of a certificate of amendment to the Company's certificate of incorporation after the market closed on June 10, 2016, and the common stock began trading on a split-adjusted basis when the market opened on June 13, 2016. The effect of the reverse stock split was to combine each 10 shares of outstanding common stock prior to the reverse split into one new share subsequent to the reverse split. The Company's authorized shares of common stock were proportionately decreased in connection with the reverse stock split. Additionally, the overall and per share limitations in the Company’s 2009 Amended and Restated Stock Incentive Plan, as amended from time to time, and outstanding awards thereunder were also proportionately adjusted. The Company retained the current par value of
$.01
per share for all shares of common stock.
All references in the financial statements and notes thereto to number of shares, per share data, restricted stock and stock option data have been retroactively adjusted to give effect to the 1-for-10 reverse stock split. Stockholders' equity reflects the reverse stock split by reclassifying from common stock to additional paid-in capital an amount equal to the par value of the reduction in the number of shares as a result of the reverse split.
Note 2 – Going Concern
The accompanying condensed consolidated financial statements have been prepared assuming the Company will continue as a going concern, which contemplates continuity of operations, realization of assets and the satisfaction of liabilities in the normal course of business for the twelve month period following the date of these condensed consolidated financial statements. As such, the accompanying condensed consolidated financial statements do not include any adjustments relating to the recoverability and classification of assets and their carrying amounts, or the amount and classification of liabilities that may result should the Company be unable to continue as a going concern.
The level of our indebtedness of
$1,428 million
as of June 30, 2016 and the current commodity price environment have presented challenges as they relate to our ability to comply with the covenants in the agreements governing our indebtedness, particularly the maximum Consolidated Funded Debt to consolidated EBITDA (“Consolidated Funded Leverage”) financial covenant set forth in our bank credit agreement. If we exceed the maximum Consolidated Funded Leverage financial covenant, we would be required to seek a waiver or amendment from our bank lenders. If we are unable to reach an agreement with our banks or find acceptable alternative financing, it may lead to an event of default under our bank credit facility. If following an event of default, the banks were to accelerate repayment under the bank credit facility, it would result in an event of default and may result in the acceleration of our other debt instruments.
On June 14, 2016, we entered into an amendment to the bank credit facility (see
Note 5 – Debt
) which, among other things, requires that we maintain minimum liquidity of
$125.0 million
through January 15, 2017 and revised the maximum Consolidated Funded Leverage financial covenant from
3.75
to 1 to
5.25
to 1 for the fiscal quarter ended June 30, 2016,
6.50
to 1 for the fiscal quarter ending September 30, 2016,
9.50
to 1 for the fiscal quarter ending December 31, 2016 and
3.75
to 1 thereafter. We were in compliance with all covenants under the bank credit facility as of June 30, 2016, however, the minimum liquidity requirement and other restrictions under the credit facility may prevent us from being able to meet our interest payment obligation on the 7½% Senior Notes due in 2022 (the “2022 Notes”) in the fourth quarter of 2016 as well as the subsequent maturity of our 1¾% Senior Convertible Notes due in March 2017 (the “2017 Convertible Notes”). Additionally, we anticipate that we could exceed the Consolidated Funded Leverage financial covenant of
3.75
to 1 at the end of the first quarter of 2017 unless a material portion of our debt is repaid, reduced or exchanged into equity. These conditions raise substantial doubt about our ability to continue as a going concern.
We are in the process of analyzing various strategic alternatives to address our liquidity and capital structure, including strategic and refinancing alternatives through a private restructuring, asset sales and a prepackaged or prearranged bankruptcy filing. We cannot provide any assurances that we will be able to complete a private restructuring or asset sales on satisfactory terms to provide the liquidity to restructure or pay down our senior indebtedness.
Note 3 – Earnings Per Share
The following table sets forth the calculation of basic and diluted weighted average shares outstanding and earnings per share for the indicated periods:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
|
(In thousands, except per share data)
|
|
Income (numerator):
|
|
|
|
|
|
|
|
|
Basic:
|
|
|
|
|
|
|
|
|
Net loss
|
$
|
(195,761
|
)
|
|
$
|
(152,906
|
)
|
|
$
|
(384,545
|
)
|
|
$
|
(480,294
|
)
|
|
Net income attributable to participating securities
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Net loss attributable to common stock - basic
|
$
|
(195,761
|
)
|
|
$
|
(152,906
|
)
|
|
$
|
(384,545
|
)
|
|
$
|
(480,294
|
)
|
|
Diluted:
|
|
|
|
|
|
|
|
|
Net loss
|
$
|
(195,761
|
)
|
|
$
|
(152,906
|
)
|
|
$
|
(384,545
|
)
|
|
$
|
(480,294
|
)
|
|
Net income attributable to participating securities
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Net loss attributable to common stock - diluted
|
$
|
(195,761
|
)
|
|
$
|
(152,906
|
)
|
|
$
|
(384,545
|
)
|
|
$
|
(480,294
|
)
|
|
Weighted average shares (denominator):
|
|
|
|
|
|
|
|
|
Weighted average shares - basic
|
5,585
|
|
|
5,525
|
|
|
5,578
|
|
|
5,521
|
|
|
Dilutive effect of stock options
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Dilutive effect of convertible notes
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Weighted average shares - diluted
|
5,585
|
|
|
5,525
|
|
|
5,578
|
|
|
5,521
|
|
|
Basic loss per share
|
$
|
(35.05
|
)
|
|
$
|
(27.68
|
)
|
|
$
|
(68.94
|
)
|
|
$
|
(86.99
|
)
|
|
Diluted loss per share
|
$
|
(35.05
|
)
|
|
$
|
(27.68
|
)
|
|
$
|
(68.94
|
)
|
|
$
|
(86.99
|
)
|
All outstanding stock options were considered antidilutive during the three and
six
months ended
June 30, 2016
(approximately
12,900
shares) and during the three and
six
months ended
June 30, 2015
(approximately
17,400
shares) because we had net losses for such periods.
During the three months ended
June 30, 2016
and
2015
, approximately
12,100
shares and
2,900
shares of our common stock, respectively, were issued from authorized shares upon the lapsing of forfeiture restrictions of restricted stock for employees and nonemployee directors. During the
six
months ended
June 30, 2016
and
2015
, approximately
62,200
shares and
39,900
shares of our common stock, respectively, were issued from authorized shares upon the lapsing of forfeiture restrictions of restricted stock for employees and nonemployee directors.
For the three and
six
months ended
June 30, 2016
and
2015
, the 2017 Convertible Notes had no dilutive effect on the diluted earnings per share computation as we had net losses for such periods. For the three and
six
months ended
June 30, 2016
and
2015
, the average price of our common stock was less than the strike price of the Sold Warrants (as defined in
Note 5 – Debt
) and therefore, such warrants were not dilutive for such periods. Based on the terms of the Purchased Call Options (as defined in
Note 5 – Debt
), such call options are antidilutive and therefore were not included in the calculation of diluted earnings per share.
Note 4 – Derivative Instruments and Hedging Activities
Our hedging strategy is designed to protect our near and intermediate term cash flows from future declines in oil and natural gas prices. This protection is essential to capital budget planning, which is sensitive to expenditures that must be committed to in advance, such as rig contracts and the purchase of tubular goods. We enter into derivative transactions to secure a commodity price for a portion of our expected future production that is acceptable at the time of the transaction. These derivatives are generally designated as cash flow hedges upon entering into the contracts. We do not enter into derivative transactions for trading purposes. We have no fair value hedges.
The nature of a derivative instrument must be evaluated to determine if it qualifies as a hedging instrument. If the instrument qualifies as a hedging instrument, it is recorded as either an asset or liability measured at fair value and subsequent changes in the
derivative’s fair value are recognized in stockholders’ equity through other comprehensive income (loss), net of related taxes, to the extent the hedge is considered effective. Monthly settlements of effective hedges are reflected in revenue from oil and natural gas production and cash flows from operating activities. Instruments not qualifying as hedging instruments are recorded in our balance sheet at fair value and subsequent changes in fair value are recognized in earnings through derivative expense (income). Monthly settlements of ineffective hedges and derivative instruments not qualifying as hedging instruments are recognized in earnings through derivative expense (income) and cash flows from operating activities.
We have entered into fixed-price swaps and collars with various counterparties for a portion of our expected 2016 oil and natural gas production from the Gulf Coast Basin. Our fixed-price oil swap settlements and oil collar settlements are based on an average of the New York Mercantile Exchange (“NYMEX”) closing price for West Texas Intermediate crude oil during the entire calendar month. Our fixed-price gas swap settlements are based on the NYMEX price for the last day of a respective contract month. Swaps typically provide for monthly payments by us if prices rise above the swap price or monthly payments to us if prices fall below the swap price. Collar contracts typically require payments by us if the NYMEX average closing price is above the ceiling price or payments to us if the NYMEX average closing price is below the floor price. Our fixed-price swap contracts are with The Toronto-Dominion Bank, The Bank of Nova Scotia and Natixis. Our oil collar contract is with The Bank of Nova Scotia.
All of our derivative transactions have been carried out in the over-the-counter market and are not typically subject to margin-deposit requirements. The use of derivative instruments involves the risk that the counterparties will be unable to meet the financial terms of such transactions. The counterparties to all of our derivative instruments have an "investment grade" credit rating. We monitor the credit ratings of our derivative counterparties on an ongoing basis. Although we have entered into derivative contracts with multiple counterparties to mitigate our exposure to any individual counterparty, if any of our counterparties were to default on its obligations to us under the derivative contracts or seek bankruptcy protection, we may not realize the benefit of some of our derivative instruments and incur a loss. At
August 2, 2016
,
two
counterparties accounted for approximately
86%
of our contracted volumes. All of our derivative instruments are with lenders under our bank credit facility.
The following tables illustrate our derivative positions for calendar year 2016 as of
August 2, 2016
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed-Price Swaps (NYMEX)
|
|
|
Natural Gas
|
|
Oil
|
|
|
Daily Volume
(MMBtus/d)
|
|
Swap Price
($)
|
|
Daily Volume
(Bbls/d)
|
|
Swap Price
($)
|
|
2016
|
10,000
|
|
|
4.110
|
|
|
1,000
|
|
|
49.75
|
|
|
2016
|
10,000
|
|
|
4.120
|
|
|
1,000
|
|
|
52.78
|
|
|
2016
|
|
|
|
|
|
|
1,000
|
|
|
90.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Collar (NYMEX)
|
|
|
Oil
|
|
|
Daily Volume
(Bbls/d)
|
|
Floor Price ($)
|
|
Ceiling Price ($)
|
|
2016
|
1,000
|
|
|
45.00
|
|
|
54.75
|
|
We previously discontinued hedge accounting for certain 2015 natural gas contracts, as it became no longer probable that our Gulf of Mexico ("GOM") natural gas production would be sufficient to cover the GOM volumes hedged. Additionally, a small portion of our cash flow hedges are typically determined to be ineffective because oil and natural gas price changes in the markets in which we sell our products are not
100%
correlative to changes in the underlying price basis indicative in the derivative contract. At
June 30, 2016
, we had accumulated other comprehensive income of
$7.4 million
, net of tax, related to the fair value of our effective cash flow hedges that were outstanding as of
June 30, 2016
. The
$7.4 million
of accumulated other comprehensive income will be reclassified into earnings in the next 12 months.
Derivatives qualifying as hedging instruments:
The following tables disclose the location and fair value amounts of derivatives qualifying as hedging instruments, as reported in our balance sheet, at
June 30, 2016
and
December 31, 2015
. We had an immaterial collar contract qualifying as a hedging instrument, with a fair value of approximately
$37,000
, classified as a current liability in our balance sheet at June 30, 2016.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Derivatives Qualifying as Hedging Instruments at
|
|
June 30, 2016
|
|
(In millions)
|
|
|
Asset Derivatives
|
|
Liability Derivatives
|
|
Description
|
Balance Sheet Location
|
|
Fair
Value
|
|
Balance Sheet Location
|
|
Fair
Value
|
|
Commodity contracts
|
Current assets: Fair value of
derivative contracts
|
|
$
|
11.9
|
|
|
Current liabilities: Fair value
of derivative contracts
|
|
$
|
—
|
|
|
|
Long-term assets: Fair value
of derivative contracts
|
|
—
|
|
|
Long-term liabilities: Fair
value of derivative contracts
|
|
—
|
|
|
|
|
|
$
|
11.9
|
|
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Derivatives Qualifying as Hedging Instruments at
|
|
December 31, 2015
|
|
(In millions)
|
|
|
Asset Derivatives
|
|
Liability Derivatives
|
|
Description
|
Balance Sheet Location
|
|
Fair
Value
|
|
Balance Sheet Location
|
|
Fair
Value
|
|
Commodity contracts
|
Current assets: Fair value of
derivative contracts
|
|
$
|
38.6
|
|
|
Current liabilities: Fair value
of derivative contracts
|
|
$
|
—
|
|
|
|
Long-term assets: Fair value
of derivative contracts
|
|
—
|
|
|
Long-term liabilities: Fair
value of derivative contracts
|
|
—
|
|
|
|
|
|
$
|
38.6
|
|
|
|
|
$
|
—
|
|
The following tables disclose the before tax effect of derivatives qualifying as hedging instruments, as reported in the statement of operations, for the three and
six
month periods ended
June 30, 2016
and
2015
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of Derivatives Qualifying as Hedging Instruments on the Statement of Operations
|
|
for the Three Months Ended June 30, 2016 and 2015
|
|
(In millions)
|
|
Derivatives in
Cash Flow Hedging
Relationships
|
|
Amount of Gain
(Loss) Recognized
in Other
Comprehensive
Income on
Derivatives
|
|
Gain (Loss) Reclassified from
Accumulated Other Comprehensive
Income into Income
(Effective Portion) (a)
|
|
Gain (Loss) Recognized in Income
on Derivatives
(Ineffective Portion)
|
|
|
|
2016
|
|
2015
|
|
Location
|
|
2016
|
|
2015
|
|
Location
|
|
2016
|
|
2015
|
|
Commodity contracts
|
|
$
|
(8.6
|
)
|
|
$
|
(18.8
|
)
|
|
Operating revenue -
oil/natural gas production
|
|
$
|
8.9
|
|
|
$
|
30.4
|
|
|
Derivative income
(expense), net
|
|
$
|
(0.6
|
)
|
|
$
|
(0.4
|
)
|
|
Total
|
|
$
|
(8.6
|
)
|
|
$
|
(18.8
|
)
|
|
|
|
$
|
8.9
|
|
|
$
|
30.4
|
|
|
|
|
$
|
(0.6
|
)
|
|
$
|
(0.4
|
)
|
|
|
|
|
(a)
|
For the three months ended
June 30, 2016
, effective hedging contracts increased oil revenue by
$5.1 million
and increased natural gas revenue by
$3.8 million
. For the three months ended
June 30, 2015
, effective hedging contracts increased oil revenue by
$26.4 million
and increased natural gas revenue by
$4.0 million
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of Derivatives Qualifying as Hedging Instruments on the Statement of Operations
|
|
for the Six Months Ended June 30, 2016 and 2015
|
|
(In millions)
|
|
Derivatives in
Cash Flow Hedging
Relationships
|
|
Amount of Gain
(Loss) Recognized
in Other
Comprehensive
Income on
Derivatives
|
|
Gain (Loss) Reclassified from
Accumulated Other Comprehensive
Income into Income
(Effective Portion) (a)
|
|
Gain (Loss) Recognized in Income
on Derivatives
(Ineffective Portion)
|
|
|
|
2016
|
|
2015
|
|
Location
|
|
2016
|
|
2015
|
|
Location
|
|
2016
|
|
2015
|
|
Commodity contracts
|
|
$
|
(4.0
|
)
|
|
$
|
4.1
|
|
|
Operating revenue -
oil/natural gas production
|
|
$
|
21.7
|
|
|
$
|
67.2
|
|
|
Derivative income
(expense), net
|
|
$
|
(0.5
|
)
|
|
$
|
0.5
|
|
|
Total
|
|
$
|
(4.0
|
)
|
|
$
|
4.1
|
|
|
|
|
$
|
21.7
|
|
|
$
|
67.2
|
|
|
|
|
$
|
(0.5
|
)
|
|
$
|
0.5
|
|
|
|
|
|
(a)
|
For the
six
months ended
June 30, 2016
, effective hedging contracts increased oil revenue by
$14.4 million
and increased natural gas revenue by
$7.3 million
. For the
six
months ended
June 30, 2015
, effective hedging contracts increased oil revenue by
$60.4 million
and increased natural gas revenue by
$6.8 million
.
|
Derivatives not qualifying as hedging instruments:
Gains or losses related to changes in fair value and cash settlements for derivatives not qualifying as hedging instruments are recorded as derivative income (expense) in the statement of operations. The following table discloses the before tax effect of our derivatives not qualifying as hedging instruments on the statement of operations, for the three and
six
month periods ended
June 30, 2016
and
2015
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (Loss) Recognized in Derivative Income (Expense)
(In millions)
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
Description
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
Commodity contracts:
|
|
|
|
|
|
|
|
|
Cash settlements
|
$
|
—
|
|
|
$
|
4.1
|
|
|
$
|
—
|
|
|
$
|
7.2
|
|
|
Change in fair value
|
—
|
|
|
(4.4
|
)
|
|
—
|
|
|
(5.3
|
)
|
|
Total gains (losses) on non-qualifying hedges
|
$
|
—
|
|
|
$
|
(0.3
|
)
|
|
$
|
—
|
|
|
$
|
1.9
|
|
Offsetting of derivative assets and liabilities:
Our derivative contracts are subject to netting arrangements. It is our policy to not offset our derivative contracts in presenting the fair value of these contracts as assets and liabilities in our balance sheet. As of
June 30, 2016
, all of our derivative contracts, other than our collar contract, were in an asset position. The potential impact of the rights of offset of our collar contract was immaterial at June 30, 2016. As of
December 31, 2015
, all of our derivative contracts were in an asset position and therefore, there was no potential impact of the rights of offset.
Note 5 – Debt
Our debt balances (net of related unamortized discounts and debt issuance costs) as of
June 30, 2016
and December 31, 2015 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
2016
|
|
December 31,
2015
|
|
|
(In millions)
|
|
1
3
⁄
4
% Senior Convertible Notes due 2017
|
$
|
287.9
|
|
|
$
|
279.3
|
|
|
7
1
⁄
2
% Senior Notes due 2022
|
770.3
|
|
|
770.0
|
|
|
Revolving credit facility
|
341.5
|
|
|
—
|
|
|
4.20% Building Loan
|
11.5
|
|
|
11.7
|
|
|
Total debt
|
1,411.2
|
|
|
1,061.0
|
|
|
Less: current portion of long-term debt
|
(288.3
|
)
|
|
—
|
|
|
Long-term debt
|
$
|
1,122.9
|
|
|
$
|
1,061.0
|
|
Current Portion of Long-Term Debt.
As of
June 30, 2016
, the current portion of long-term debt of
$288.3 million
consisted of
$287.9 million
of 2017 Convertible Notes and
$0.4 million
of principal payments due within one year on the Building Loan.
Revolving Credit Facility.
On
June 24, 2014
, we entered into a revolving credit facility (the Fourth Amended and Restated Credit Agreement dated as of June 24, 2014) with commitments totaling
$900 million
(subject to borrowing base limitations) through a syndicated bank group, with an initial borrowing base of
$500 million
. The bank credit facility matures on
July 1, 2019
. On
April 13, 2016
, our borrowing base under the bank credit facility was reduced from
$500 million
to
$300 million
. On that date, we had
$457 million
of outstanding borrowings and
$18.3 million
of outstanding letters of credit, or
$175.3 million
in excess of the redetermined borrowing base (referred to as a borrowing base deficiency). Our agreement with the banks provides that within 30 days after notification of a borrowing base deficiency, we must elect to cure the borrowing base deficiency through any combination of the following actions: (1) repay amounts outstanding sufficient to cure the deficiency within
10 days
after our written election to do so; (2) add additional oil and gas properties acceptable to the banks to the borrowing base and take such actions necessary to grant the banks a mortgage in the properties within
30 days
after our written election to do so; and/or (3) arrange to pay the deficiency in six equal monthly installments. We elected to pay the
deficiency in six equal monthly installments, making the first payment of
$29.2 million
on May 13, 2016 and the second payment of
$29.2 million
on June 13, 2016.
On June 14, 2016, we entered into Amendment No. 3 (the "Amendment") to the bank credit facility to (i) increase the borrowing base to
$360 million
from
$300 million
, (ii) provide for no redetermination of the borrowing base by the lenders until January 15, 2017, other than an automatic reduction upon the sale of certain of our properties, (iii) permit second lien indebtedness to refinance the existing 2017 Convertible Notes and 2022 Notes, (iv) revise the maximum Consolidated Funded Leverage financial covenant to be
5.25
to 1 for the fiscal quarter ended June 30, 2016,
6.50
to 1 for the fiscal quarter ending September 30, 2016,
9.50
to 1 for the fiscal quarter ending December 31, 2016 and
3.75
to 1 thereafter, (v) require minimum liquidity (as defined in the Amendment) of at least
$125.0 million
until January 15, 2017, (vi) impose limitations on capital expenditures of
$60 million
for the period of June 1, 2016 through December 31, 2016, but allowing for an additional
$25 million
to be expended for Appalachian drilled but uncompleted wells, (vii) grant the lenders a perfected security interest in all deposit accounts and (viii) provide for anti-hoarding cash provisions for amounts in excess of
$50.0 million
to apply after December 10, 2016. Upon execution of the Amendment, we repaid
$56.8 million
in borrowings under the credit facility, which eliminated the borrowing base deficiency and brought the total borrowings and letters of credit outstanding under the bank credit facility in conformity with the borrowing base limitation.
On June 30 and August 2, 2016, we had
$341.5 million
of outstanding borrowings and
$18.3 million
of outstanding letters of credit, leaving
$0.2 million
of availability under the bank credit facility. The weighted average interest rate under the bank credit facility was approximately
4.3%
at
June 30, 2016
. Subject to certain exceptions, the bank credit facility is required to be guaranteed by all of our material domestic direct and indirect subsidiaries. As of
June 30, 2016
, the bank credit facility was guaranteed by Stone Energy Offshore, L.L.C. (“Stone Offshore”), SEO A LLC and SEO B LLC (collectively, the “Guarantor Subsidiaries”).
The borrowing base under the bank credit facility is redetermined semi-annually, typically in May and November, by the lenders, taking into consideration the estimated loan value of our oil and gas properties and those of our subsidiaries that guarantee the bank credit facility in accordance with the lenders’ customary practices for oil and gas loans. In addition, we and the lenders each have discretion at any time, but not more than two additional times in any calendar year, to have the borrowing base redetermined. However, the Amendment provides for no redetermination of the borrowing base by the lenders until January 15, 2017, other than an automatic reduction upon the sale of certain of our properties. The bank credit facility is collateralized by substantially all of our assets and the assets of our material subsidiaries. We are required to mortgage, and grant a security interest in, our oil and natural gas reserves representing at least
86%
of the discounted present value of the future net cash flows from our proved oil and natural gas reserves reviewed in determining the borrowing base. Interest on loans under the bank credit facility is calculated using the London Interbank Offering (“LIBOR”) rate or the base rate, at our election. The margin for loans at the LIBOR rate is determined based on borrowing base utilization and ranges from
1.500%
to
2.500%
.
In addition to the covenants discussed above, the bank credit facility provides that we must maintain a ratio of consolidated EBITDA to consolidated Net Interest Expense, as defined in the credit agreement, for the preceding four quarterly periods of not less than
2.5
to 1. The bank credit facility also includes certain customary restrictions or requirements with respect to disposition of properties, incurrence of additional debt, change of control and reporting responsibilities. These covenants may limit or prohibit us from paying cash dividends but do allow for limited stock repurchases. These covenants also restrict our ability to prepay other indebtedness under certain circumstances. We were in compliance with all covenants as of June 30, 2016.
2017 Convertible Notes.
On March 6, 2012, we issued in a private offering
$300 million
in aggregate principal amount of the 2017 Convertible Notes to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, as amended (the “Securities Act”). The 2017 Convertible Notes are convertible into cash, shares of our common stock or a combination of cash and shares of our common stock, based on an initial conversion rate of
23.4449
shares of our common stock per
$1,000
principal amount of 2017 Convertible Notes, which corresponded to an initial conversion price of approximately
$42.65
per share of our common stock at the time of the issuance of the 2017 Convertible Notes. The conversion rate, and thus the conversion price, may be adjusted under certain circumstances as described in the indenture related to the 2017 Convertible Notes. Upon conversion, we will be obligated to pay or deliver, as the case may be, cash, shares of our common stock or a combination of cash and shares of our common stock. Prior to December 1, 2016, the 2017 Convertible Notes will be convertible only upon the occurrence of certain events and during certain periods, and thereafter, at any time until the second scheduled trading day immediately preceding the maturity date. On June 10, 2016, we completed a 1-for-10 reverse stock split with respect to our common stock (see
Note 1 – Interim Financial Statements
). Proportional adjustments were made to the conversion price and shares as they relate to the 2017 Convertible Notes, resulting in a conversion rate of 2.34449 shares of our common stock with a corresponding conversion price of
$426.50
per share. On
June 30, 2016
, our closing share price was
$12.06
per share.
The 2017 Convertible Notes will be due on March 1, 2017, unless earlier converted or repurchased by us at the option of the holder(s), and interest is payable on the 2017 Convertible Notes each March 1and September 1. On the maturity date, each holder will be entitled to receive
$1,000
in cash for each $1,000 in principal amount of 2017 Convertible Notes, together with any accrued and unpaid interest to, but excluding, the maturity date.
In connection with the offering, we entered into convertible note hedge transactions with respect to our common stock (the “Purchased Call Options”) with Barclays Capital Inc., acting as agent for Barclays Bank PLC and Bank of America, N.A. (the “Dealers”). We paid an aggregate amount of approximately
$70.8 million
to the Dealers for the Purchased Call Options. The Purchased Call Options cover, subject to customary antidilution adjustments, approximately
703,347
shares of our common stock at a strike price that corresponds to the initial conversion price of the 2017 Convertible Notes (after the effectiveness of the reverse stock split of 1-for-10), also subject to adjustment, and are exercisable upon conversion of the 2017 Convertible Notes.
We also entered into separate warrant transactions whereby, in reliance upon the exemption from registration provided by Section 4(a)(2) of the Securities Act, we sold to the Dealers warrants to acquire, subject to customary antidilution adjustments, approximately
703,347
shares of our common stock (the “Sold Warrants”) at a strike price of
$559.10
per share of our common stock (after the effectiveness of the reverse stock split of 1-for-10). We received aggregate proceeds of approximately
$40.1 million
from the sale of the Sold Warrants to the Dealers. If, upon expiration of the Sold Warrants, the price per share of our common stock, as measured under the Sold Warrants, is greater than the strike price of the Sold Warrants, we will be required to issue, without further consideration, under each Sold Warrant a number of shares of our common stock with a value equal to the amount of such difference.
As of
June 30, 2016
, the carrying amount of the liability component of the 2017 Convertible Notes of
$287.9 million
was classified as a current liability. During the three and
six
months ended
June 30, 2016
, we recognized
$4.0 million
and
$7.9 million
, respectively, of interest expense for the amortization of the discount and
$0.4 million
and
$0.8 million
, respectively, of interest expense for the amortization of deferred financing costs related to the 2017 Convertible Notes. During the three and
six
months ended
June 30, 2015
, we recognized
$3.7 million
and
$7.4 million
, respectively, of interest expense for the amortization of the discount and
$0.4 million
and
$0.7 million
, respectively, of interest expense for the amortization of deferred financing costs related to the 2017 Convertible Notes. During the three and
six
month periods ended
June 30, 2016
, we recognized
$1.3 million
and
$2.6 million
, respectively, of interest expense related to the contractual interest coupon on the 2017 Convertible Notes. During the three and
six
month periods ended
June 30, 2015
, we recognized
$1.3 million
and
$2.6 million
, respectively, of interest expense related to the contractual interest coupon on the 2017 Convertible Notes.
Note 6 – Asset Retirement Obligations
The change in our asset retirement obligations during the
six
months ended
June 30, 2016
is set forth below:
|
|
|
|
|
|
|
|
|
Six Months Ended
June 30, 2016
|
|
|
(In millions)
|
|
Asset retirement obligations as of the beginning of the period, including current portion
|
$
|
225.9
|
|
|
Liabilities incurred
|
2.1
|
|
|
Liabilities settled
|
(10.7
|
)
|
|
Accretion expense
|
20.1
|
|
|
Asset retirement obligations as of the end of the period, including current portion
|
$
|
237.4
|
|
Note 7 – Income Taxes
As a result of the significant declines in commodity prices and the resulting ceiling test write-downs and net losses incurred, we determined during 2015 that it was more likely than not that a portion of our deferred tax assets will not be realized in the future. Accordingly, we established a valuation allowance against a portion of our deferred tax assets. As of June 30, 2016, our valuation allowance totaled
$322.8
million. Our effective tax rate for the
six
months ended
June 30, 2016
was
2.1%
. This percentage differed from the federal statutory rate of
35.0%
primarily due to the establishment of the valuation allowance against deferred tax assets. Our assessment of the realizability of our deferred tax assets is based on the weight of all available evidence, both positive and negative, including future reversals of deferred tax liabilities. We had a current income tax receivable of
$46.2 million
at June 30, 2016, which relates to expected tax refunds from the carryback of net operating losses to previous tax years. Additionally, we had
$3.2 million
of non-current income tax receivables at June 30, 2016 reflected in Other Assets, as they aren’t expected to be received within twelve months.
Note 8 – Fair Value Measurements
U.S. Generally Accepted Accounting Principles establish a fair value hierarchy that has three levels based on the reliability of the inputs used to determine the fair value. These levels include: Level 1, defined as inputs such as unadjusted quoted prices in active markets for identical assets or liabilities; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly
observable; and Level 3, defined as unobservable inputs for use when little or no market data exists, therefore requiring an entity to develop its own assumptions.
As of
June 30, 2016
and
December 31, 2015
, we held certain financial assets that are required to be measured at fair value on a recurring basis, including our commodity derivative instruments and our investments in marketable securities. We utilize the services of an independent third party to assist us in valuing our derivative instruments. We used the income approach in determining the fair value of our derivative instruments utilizing a proprietary pricing model. The model accounts for our credit risk and the credit risk of our counterparties in the discount rate applied to estimated future cash inflows and outflows. Our swap contracts are included within the Level 2 fair value hierarchy, and our collar contracts are included within the Level 3 fair value hierarchy. Significant unobservable inputs used in establishing fair value for the collars were the volatility impacts in the pricing model as it relates to the call portion of the collar. For a more detailed description of our derivative instruments, see
Note 4 – Derivative Instruments and Hedging Activities
. We used the market approach in determining the fair value of our investments in marketable securities, which are included within the Level 1 fair value hierarchy.
We had no liabilities measured at fair value on a recurring basis at December 31, 2015. At June 30, 2016, we had an immaterial collar contract in a liability position, measured at fair value on a recurring basis. The following tables present our assets that are measured at fair value on a recurring basis at June 30, 2016 and December 31, 2015.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at
|
|
|
June 30, 2016
|
|
Assets
|
Total
|
|
Quoted Prices
in Active
Markets for
Identical Assets
(Level 1)
|
|
Significant
Other
Observable
Inputs
(Level 2)
|
|
Significant
Unobservable
Inputs
(Level 3)
|
|
|
(In millions)
|
|
Marketable securities (Other assets)
|
$
|
8.6
|
|
|
$
|
8.6
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Derivative contracts
|
11.9
|
|
|
—
|
|
|
11.9
|
|
|
—
|
|
|
Total
|
$
|
20.5
|
|
|
$
|
8.6
|
|
|
$
|
11.9
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at
|
|
|
December 31, 2015
|
|
Assets
|
Total
|
|
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
|
|
Significant
Other
Observable
Inputs
(Level 2)
|
|
Significant
Unobservable
Inputs
(Level 3)
|
|
|
(In millions)
|
|
Marketable securities (Other assets)
|
$
|
8.5
|
|
|
$
|
8.5
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Derivative contracts
|
38.6
|
|
|
—
|
|
|
36.6
|
|
|
2.0
|
|
|
Total
|
$
|
47.1
|
|
|
$
|
8.5
|
|
|
$
|
36.6
|
|
|
$
|
2.0
|
|
The table below presents a reconciliation for assets measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the six months ended
June 30, 2016
.
|
|
|
|
|
|
|
|
|
|
|
Hedging Contracts, net
|
|
|
|
(In millions)
|
|
Balance as of January 1, 2016
|
|
$
|
2.0
|
|
|
Total gains/(losses) (realized or unrealized):
|
|
|
|
Included in earnings
|
|
1.1
|
|
|
Included in other comprehensive income
|
|
(1.9
|
)
|
|
Purchases, sales, issuances and settlements
|
|
(1.2
|
)
|
|
Transfers in and out of Level 3
|
|
—
|
|
|
Balance as of June 30, 2016
|
|
$
|
—
|
|
|
The amount of total gains/(losses) for the period included in earnings (derivative income) attributable to the change in unrealized gain/(losses) relating to derivatives still held at June 30, 2016
|
|
$
|
—
|
|
The fair value of cash and cash equivalents approximated book value at
June 30, 2016
and
December 31, 2015
. As of
June 30, 2016
and
December 31, 2015
, the fair value of the liability component of the 2017 Convertible Notes was approximately
$258.5 million
and
$217.1 million
, respectively. As of
June 30, 2016
and
December 31, 2015
, the fair value of the 2022 Notes was approximately
$348.8 million
and
$271.3 million
, respectively.
The fair value of the 2022 Notes was determined based on quotes obtained from brokers, which represent Level 1 inputs. We applied fair value concepts in determining the liability component of the 2017 Convertible Notes (see
Note 5 – Debt
) at inception,
June 30, 2016
and
December 31, 2015
. The fair value of the liability was estimated using an income approach. The significant inputs in these determinations were market interest rates based on quotes obtained from brokers and represent Level 2 inputs.
Note 9 – Accumulated Other Comprehensive Income (Loss)
Changes in accumulated other comprehensive income (loss) by component for the three and
six
months ended
June 30, 2016
, were as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow
Hedges
|
|
Foreign
Currency
Items
|
|
Total
|
|
Three Months Ended June 30, 2016
|
|
|
|
|
|
|
Beginning balance, net of tax
|
$
|
18.7
|
|
|
$
|
—
|
|
|
$
|
18.7
|
|
|
Other comprehensive income (loss) before reclassifications:
|
|
|
|
|
|
|
Change in fair value of derivatives
|
(8.6
|
)
|
|
—
|
|
|
(8.6
|
)
|
|
Income tax effect
|
3.1
|
|
|
—
|
|
|
3.1
|
|
|
Net of tax
|
(5.5
|
)
|
|
—
|
|
|
(5.5
|
)
|
|
Amounts reclassified from accumulated other comprehensive income:
|
|
|
|
|
|
|
Operating revenue: oil/natural gas production
|
8.9
|
|
|
—
|
|
|
8.9
|
|
|
Income tax effect
|
(3.1
|
)
|
|
—
|
|
|
(3.1
|
)
|
|
Net of tax
|
5.8
|
|
|
—
|
|
|
5.8
|
|
|
Other comprehensive loss, net of tax
|
(11.3
|
)
|
|
—
|
|
|
(11.3
|
)
|
|
Ending balance, net of tax
|
$
|
7.4
|
|
|
$
|
—
|
|
|
$
|
7.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow
Hedges
|
|
Foreign
Currency
Items
|
|
Total
|
|
Six Months Ended June 30, 2016
|
|
|
|
|
|
|
Beginning balance, net of tax
|
$
|
24.0
|
|
|
$
|
(6.0
|
)
|
|
$
|
18.0
|
|
|
Other comprehensive income (loss) before reclassifications:
|
|
|
|
|
|
|
Change in fair value of derivatives
|
(4.0
|
)
|
|
—
|
|
|
(4.0
|
)
|
|
Income tax effect
|
1.4
|
|
|
—
|
|
|
1.4
|
|
|
Net of tax
|
(2.6
|
)
|
|
—
|
|
|
(2.6
|
)
|
|
Amounts reclassified from accumulated other comprehensive income:
|
|
|
|
|
|
|
Operating revenue: oil/natural gas production
|
21.7
|
|
|
—
|
|
|
21.7
|
|
|
Other operational expenses
|
—
|
|
|
(6.0
|
)
|
|
(6.0
|
)
|
|
Income tax effect
|
(7.7
|
)
|
|
—
|
|
|
(7.7
|
)
|
|
Net of tax
|
14.0
|
|
|
(6.0
|
)
|
|
8.0
|
|
|
Other comprehensive income (loss), net of tax
|
(16.6
|
)
|
|
6.0
|
|
|
(10.6
|
)
|
|
Ending balance, net of tax
|
$
|
7.4
|
|
|
$
|
—
|
|
|
$
|
7.4
|
|
Changes in accumulated other comprehensive income (loss) by component for the three and
six
months ended
June 30, 2015
, were as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow
Hedges
|
|
Foreign
Currency
Items
|
|
Total
|
|
Three Months Ended June 30, 2015
|
|
|
|
|
|
|
Beginning balance, net of tax
|
$
|
77.9
|
|
|
$
|
(7.1
|
)
|
|
$
|
70.8
|
|
|
Other comprehensive income (loss) before reclassifications:
|
|
|
|
|
|
|
Change in fair value of derivatives
|
(18.8
|
)
|
|
—
|
|
|
(18.8
|
)
|
|
Foreign currency translations
|
—
|
|
|
1.3
|
|
|
1.3
|
|
|
Income tax effect
|
6.9
|
|
|
—
|
|
|
6.9
|
|
|
Net of tax
|
(11.9
|
)
|
|
1.3
|
|
|
(10.6
|
)
|
|
Amounts reclassified from accumulated other comprehensive income:
|
|
|
|
|
|
|
Operating revenue: oil/natural gas production
|
30.4
|
|
|
—
|
|
|
30.4
|
|
|
Income tax effect
|
(10.9
|
)
|
|
—
|
|
|
(10.9
|
)
|
|
Net of tax
|
19.5
|
|
|
—
|
|
|
19.5
|
|
|
Other comprehensive income (loss), net of tax
|
(31.4
|
)
|
|
1.3
|
|
|
(30.1
|
)
|
|
Ending balance, net of tax
|
$
|
46.5
|
|
|
$
|
(5.8
|
)
|
|
$
|
40.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow
Hedges
|
|
Foreign
Currency
Items
|
|
Total
|
|
Six Months Ended June 30, 2015
|
|
|
|
|
|
|
Beginning balance, net of tax
|
$
|
86.8
|
|
|
$
|
(3.5
|
)
|
|
$
|
83.3
|
|
|
Other comprehensive income (loss) before reclassifications:
|
|
|
|
|
|
|
Change in fair value of derivatives
|
4.1
|
|
|
—
|
|
|
4.1
|
|
|
Foreign currency translations
|
—
|
|
|
(2.3
|
)
|
|
(2.3
|
)
|
|
Income tax effect
|
(1.3
|
)
|
|
—
|
|
|
(1.3
|
)
|
|
Net of tax
|
2.8
|
|
|
(2.3
|
)
|
|
0.5
|
|
|
Amounts reclassified from accumulated other comprehensive income:
|
|
|
|
|
|
|
Operating revenue: oil/natural gas production
|
67.2
|
|
|
—
|
|
|
67.2
|
|
|
Income tax effect
|
(24.1
|
)
|
|
—
|
|
|
(24.1
|
)
|
|
Net of tax
|
43.1
|
|
|
—
|
|
|
43.1
|
|
|
Other comprehensive loss, net of tax
|
(40.3
|
)
|
|
(2.3
|
)
|
|
(42.6
|
)
|
|
Ending balance, net of tax
|
$
|
46.5
|
|
|
$
|
(5.8
|
)
|
|
$
|
40.7
|
|
During the six months ended
June 30, 2016
, we reclassified approximately
$6.0 million
of losses related to cumulative foreign currency translation adjustments from accumulated other comprehensive income into other operational expenses upon the substantial liquidation of our foreign subsidiary, Stone Energy Canada ULC.
Note 10 – Investment in Oil and Gas Properties
Under the full cost method of accounting, we compare, at the end of each financial reporting period, the present value of estimated future net cash flows from proved reserves (adjusted for hedges and excluding cash flows related to estimated abandonment costs) to the net capitalized costs of proved oil and gas properties, net of related deferred taxes. We refer to this comparison as a ceiling test. If the net capitalized costs of proved oil and gas properties exceed the estimated discounted future net cash flows from proved reserves, we are required to write down the value of our oil and gas properties to the value of the discounted cash flows. At June 30, 2016, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of
$118.6 million
based on twelve-month average prices, net of applicable differentials, of
$43.49
per Bbl of oil,
$1.93
per Mcf of natural gas and
$9.33
per Bbl of natural gas liquids ("NGLs"). The write-down at June 30, 2016 was decreased by
$18.1 million
as a result of hedges. At March 31, 2016, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of
$128.9 million
based on twelve-month average prices, net of applicable differentials, of
$46.72
per Bbl of oil,
$2.01
per Mcf of natural gas and
$13.65
per Bbl of NGLs, as compared to December 31, 2015 twelve-month average prices, net of applicable differentials, of
$51.16
per Bbl of oil,
$2.19
per Mcf of natural gas and
$16.40
per Bbl of NGLs. At March 31, 2016, the write-down of oil and gas properties also included
$0.3 million
related to our Canadian oil and gas properties, which were deemed to be fully impaired at the end of 2015. The write-down at March 31, 2016 was decreased by
$23 million
as a result of hedges.
Note 11 – Other Operational Expenses
Included in other operational expenses for the six months ended June 30, 2016 is a
$6.0
million loss on the substantial liquidation of our foreign subsidiary, Stone Energy Canada ULC, representing cumulative foreign currency translation adjustments, which were reclassified from accumulated other comprehensive income. See
Note 9 – Accumulated Other Comprehensive Income (Loss)
. Also included in other operational expenses for the six months ended June 30, 2016 are approximately
$13.6
million of rig subsidy and stacking charges related to the ENSCO 8503 deep water drilling rig, the Saxon Appalachian rig and the platform rig at Pompano and a
$20 million
charge related to the termination of our deep water drilling rig contract with Ensco.
Note 12 – Restructuring Fees
In March 2016, we retained Lazard as our financial advisor and Latham & Watkins LLP as our legal advisor to assist the Company in analyzing and considering financial, transactional and strategic alternatives. We also retained Alvarez & Marsal to assist the Company through this process. In April 2016, the independent directors of our board of directors named current board member David T. Lawrence a Special Liaison of the Independent Directors to work together with the management team of the Company to help with assessing strategic and restructuring alternatives. Andrews Kurth LLP has also been hired as special counsel to the independent directors. Additionally, we are engaged in negotiations with financial advisors for certain holders of the 2017 Convertible Notes and 2022 Notes regarding the restructuring of the notes and in June 2016, we secured an amendment to our existing credit facility with our bank group. The legal and financial advisory costs associated with these restructuring efforts are included in the statement of operations as restructuring fees and totaled
$9.4 million
and
$10.4 million
for the three and six months ended June 30, 2016, respectively.
Note 13 – Commitments and Contingencies
On March 21, 2016, we received notice letters from the Bureau of Ocean Energy Management ("BOEM") stating that BOEM had determined that we no longer qualified for a supplemental bonding waiver under the financial criteria specified in BOEM’s guidance to lessees at such time. BOEM's notice letters indicated the amount of Stone's supplemental bonding needs could be as much as
$565 million
. In late March 2016, we proposed a tailored plan to BOEM for financial assurances relating to our abandonment obligations, which provides for posting some incremental financial assurances in favor of BOEM. On May 13, 2016, we received notice letters from BOEM rescinding its demand for supplemental bonding with the understanding that we will continue to make progress with BOEM in finalizing and implementing our long-term tailored plan. Currently, we have posted an aggregate of approximately
$230 million
in surety bonds in favor of BOEM, third party bonds and letters of credit, all relating to our offshore abandonment obligations. We have submitted our tailored plan to BOEM and are awaiting its review and approval. Our proposed plan would require approximately
$16 million
of incremental financial assurance or bonding for 2016, a majority of which may require cash collateral. Under the submitted plan, additional financial assurance would be required for subsequent years. There is no assurance this tailored plan will be approved by BOEM. Additionally, on July 14, 2016, BOEM issued a Notice to Lessees (“NTL”) that augments requirements for the posting of additional financial assurances by offshore lessees. We are reviewing the new NTL and its potential impact to Stone.
Note 14 – Recently Issued Accounting Standards
In February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2016-02, "
Leases (Topic 842)
" to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The standard is effective for public entities for fiscal years beginning after December 15, 2018, and for interim periods within those fiscal years, with earlier application permitted. Upon adoption the lessee will apply the new standard retrospectively to all periods presented or retrospectively using a cumulative effect adjustment in the year of adoption. We are currently evaluating the effect that this new standard may have on our financial statements.
In March 2016, the FASB issued ASU 2016-09, "
Compensation – Stock Compensation (Topic 718)
" to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and forfeitures, as well as classification in the statement of cash flows. The standard is effective for public entities for fiscal years beginning after December 15, 2016, and for interim periods within those fiscal years. Early adoption is permitted for any entity in any interim or annual period. An entity that elects early adoption must adopt all of the amendments in ASU 2016-09 in the same period. We are currently evaluating the effect that this new standard may have on our financial statements, but we do not anticipate the implementation of this new standard will have a material effect.
Note 15 – New York Stock Exchange Compliance
On April 29, 2016, we were notified by the New York Stock Exchange (“NYSE”) that we were not in compliance with the NYSE's continued listing requirements, as the average closing price of our shares of common stock had fallen below
$1.00
per share over a period of
30
consecutive trading days, which is the minimum average share price for continued listing on the NYSE under Section 802.01C of the NYSE Listed Company Manual. On May 17, 2016, we were notified by the NYSE that our average global market capitalization had been less than
$50 million
over a consecutive 30 trading-day period at the same time that our stockholders' equity was less than
$50 million
, which is non-compliant with Section 802.01B of the NYSE Listed Company Manual.
At the close of business on June 10, 2016, we effected a 1-for-10 reverse stock split (see
Note 1 – Interim Financial Statements
) in order to increase the market price per share of our common stock in order to regain compliance with the NYSE's minimum share price requirement. We were notified on July 1, 2016 that we cured the minimum share price deficiency and that we were no longer considered non-compliant with the
$1.00
per share average closing price requirement, although we remain non-compliant with the
$50 million
market capitalization and stockholders' equity requirements. On June 30, 2016, we submitted our 18-month business plan for curing the average market capitalization and stockholders' equity deficiencies to the NYSE. After our submission of the business plan, the NYSE has 45 calendar days to review the plan to determine whether we have made reasonable demonstration of our ability to come into conformity with the relevant standards within the 18-month period. The NYSE will either accept the plan, at which time we would be subject to ongoing monitoring for compliance with the plan, or not accept the plan, at which time we would be subject to suspension and delisting proceedings. If the NYSE accepts the plan, during the 18-month cure period, our shares of common stock would continue to be listed and traded on the NYSE. As of
August 2, 2016
, our market capitalization has been above
$50 million
for 25 consecutive trading days.
Note 16 – Guarantor Financial Statements
Our Guarantor Subsidiaries, including Stone Offshore, SEO A LLC and SEO B LLC, are unconditional guarantors of the 2017 Convertible Notes and the 2022 Notes. Our other subsidiaries (the “Non-Guarantor Subsidiaries”) have not provided guarantees. The following presents unaudited condensed consolidating financial information as of
June 30, 2016
and
December 31, 2015
and for the three and
six
month periods ended
June 30, 2016
and
2015
on an issuer (parent company), Guarantor Subsidiaries, Non-Guarantor Subsidiaries and consolidated basis. Elimination entries presented are necessary to combine the entities.
CONDENSED CONSOLIDATING BALANCE SHEET
JUNE 30, 2016
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
Guarantor
Subsidiaries
|
|
Non-
Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
$
|
169,193
|
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
169,194
|
|
|
Accounts receivable
|
25,410
|
|
|
31,171
|
|
|
883
|
|
|
(19,188
|
)
|
|
38,276
|
|
|
Fair value of derivative contracts
|
—
|
|
|
11,887
|
|
|
—
|
|
|
—
|
|
|
11,887
|
|
|
Current income tax receivable
|
46,174
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
46,174
|
|
|
Other current assets
|
12,080
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
12,080
|
|
|
Total current assets
|
252,857
|
|
|
43,059
|
|
|
883
|
|
|
(19,188
|
)
|
|
277,611
|
|
|
Oil and gas properties, full cost method:
|
|
|
|
|
|
|
|
|
|
|
Proved
|
1,907,347
|
|
|
7,565,003
|
|
|
45,895
|
|
|
—
|
|
|
9,518,245
|
|
|
Less: accumulated DD&A
|
(1,907,326
|
)
|
|
(7,007,219
|
)
|
|
(45,895
|
)
|
|
—
|
|
|
(8,960,440
|
)
|
|
Net proved oil and gas properties
|
21
|
|
|
557,784
|
|
|
—
|
|
|
—
|
|
|
557,805
|
|
|
Unevaluated
|
261,971
|
|
|
163,233
|
|
|
—
|
|
|
—
|
|
|
425,204
|
|
|
Other property and equipment, net
|
27,968
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
27,968
|
|
|
Other assets, net
|
27,445
|
|
|
738
|
|
|
—
|
|
|
—
|
|
|
28,183
|
|
|
Investment in subsidiary
|
503,738
|
|
|
—
|
|
|
—
|
|
|
(503,738
|
)
|
|
—
|
|
|
Total assets
|
$
|
1,074,000
|
|
|
$
|
764,814
|
|
|
$
|
883
|
|
|
$
|
(522,926
|
)
|
|
$
|
1,316,771
|
|
|
Liabilities and Stockholders’ Equity
|
|
|
|
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
|
|
|
|
Accounts payable to vendors
|
$
|
23,153
|
|
|
$
|
24,950
|
|
|
$
|
—
|
|
|
$
|
(19,189
|
)
|
|
$
|
28,914
|
|
|
Undistributed oil and gas proceeds
|
4,379
|
|
|
692
|
|
|
—
|
|
|
—
|
|
|
5,071
|
|
|
Accrued interest
|
9,773
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9,773
|
|
|
Fair value of derivative contracts
|
—
|
|
|
37
|
|
|
—
|
|
|
—
|
|
|
37
|
|
|
Asset retirement obligations
|
—
|
|
|
33,695
|
|
|
—
|
|
|
—
|
|
|
33,695
|
|
|
Current portion of long-term debt
|
288,336
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
288,336
|
|
|
Other current liabilities
|
34,513
|
|
|
280
|
|
|
—
|
|
|
—
|
|
|
34,793
|
|
|
Total current liabilities
|
360,154
|
|
|
59,654
|
|
|
—
|
|
|
(19,189
|
)
|
|
400,619
|
|
|
Long-term debt
|
1,122,901
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,122,901
|
|
|
Asset retirement obligations
|
1,355
|
|
|
202,306
|
|
|
—
|
|
|
—
|
|
|
203,661
|
|
|
Other long-term liabilities
|
18,446
|
|
|
|
|
|
—
|
|
|
—
|
|
|
18,446
|
|
|
Total liabilities
|
1,502,856
|
|
|
261,960
|
|
|
—
|
|
|
(19,189
|
)
|
|
1,745,627
|
|
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
|
|
Stockholders’ equity:
|
|
|
|
|
|
|
|
|
|
|
Common stock
|
56
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
56
|
|
|
Treasury stock
|
(860
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(860
|
)
|
|
Additional paid-in capital
|
1,654,731
|
|
|
1,344,577
|
|
|
109,078
|
|
|
(1,453,655
|
)
|
|
1,654,731
|
|
|
Accumulated deficit
|
(2,090,168
|
)
|
|
(849,108
|
)
|
|
(108,195
|
)
|
|
957,303
|
|
|
(2,090,168
|
)
|
|
Accumulated other comprehensive income
|
7,385
|
|
|
7,385
|
|
|
—
|
|
|
(7,385
|
)
|
|
7,385
|
|
|
Total stockholders’ equity
|
(428,856
|
)
|
|
502,854
|
|
|
883
|
|
|
(503,737
|
)
|
|
(428,856
|
)
|
|
Total liabilities and stockholders’ equity
|
$
|
1,074,000
|
|
|
$
|
764,814
|
|
|
$
|
883
|
|
|
$
|
(522,926
|
)
|
|
$
|
1,316,771
|
|
CONDENSED CONSOLIDATING BALANCE SHEET
DECEMBER 31, 2015
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
Guarantor
Subsidiaries
|
|
Non-
Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
$
|
9,681
|
|
|
$
|
2
|
|
|
$
|
1,076
|
|
|
$
|
—
|
|
|
$
|
10,759
|
|
|
Accounts receivable
|
10,597
|
|
|
39,190
|
|
|
—
|
|
|
(1,756
|
)
|
|
48,031
|
|
|
Fair value of derivative contracts
|
—
|
|
|
38,576
|
|
|
—
|
|
|
—
|
|
|
38,576
|
|
|
Current income tax receivable
|
46,174
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
46,174
|
|
|
Other current assets
|
6,848
|
|
|
—
|
|
|
33
|
|
|
—
|
|
|
6,881
|
|
|
Total current assets
|
73,300
|
|
|
77,768
|
|
|
1,109
|
|
|
(1,756
|
)
|
|
150,421
|
|
|
Oil and gas properties, full cost method:
|
|
|
|
|
|
|
|
|
|
|
Proved
|
1,875,152
|
|
|
7,458,262
|
|
|
42,484
|
|
|
—
|
|
|
9,375,898
|
|
|
Less: accumulated DD&A
|
(1,874,622
|
)
|
|
(6,686,849
|
)
|
|
(42,484
|
)
|
|
—
|
|
|
(8,603,955
|
)
|
|
Net proved oil and gas properties
|
530
|
|
|
771,413
|
|
|
—
|
|
|
—
|
|
|
771,943
|
|
|
Unevaluated
|
253,308
|
|
|
186,735
|
|
|
—
|
|
|
—
|
|
|
440,043
|
|
|
Other property and equipment, net
|
29,289
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
29,289
|
|
|
Other assets, net
|
16,612
|
|
|
826
|
|
|
1,035
|
|
|
—
|
|
|
18,473
|
|
|
Investment in subsidiary
|
745,033
|
|
|
—
|
|
|
1,088
|
|
|
(746,121
|
)
|
|
—
|
|
|
Total assets
|
$
|
1,118,072
|
|
|
$
|
1,036,742
|
|
|
$
|
3,232
|
|
|
$
|
(747,877
|
)
|
|
$
|
1,410,169
|
|
|
Liabilities and Stockholders’ Equity
|
|
|
|
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
|
|
|
|
Accounts payable to vendors
|
$
|
16,063
|
|
|
$
|
67,901
|
|
|
$
|
—
|
|
|
$
|
(1,757
|
)
|
|
$
|
82,207
|
|
|
Undistributed oil and gas proceeds
|
5,216
|
|
|
776
|
|
|
—
|
|
|
—
|
|
|
5,992
|
|
|
Accrued interest
|
9,022
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9,022
|
|
|
Asset retirement obligations
|
—
|
|
|
20,400
|
|
|
891
|
|
|
—
|
|
|
21,291
|
|
|
Other current liabilities
|
40,161
|
|
|
551
|
|
|
—
|
|
|
—
|
|
|
40,712
|
|
|
Total current liabilities
|
70,462
|
|
|
89,628
|
|
|
891
|
|
|
(1,757
|
)
|
|
159,224
|
|
|
Long-term debt
|
1,060,955
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,060,955
|
|
|
Asset retirement obligations
|
1,240
|
|
|
203,335
|
|
|
—
|
|
|
—
|
|
|
204,575
|
|
|
Other long-term liabilities
|
25,204
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
25,204
|
|
|
Total liabilities
|
1,157,861
|
|
|
292,963
|
|
|
891
|
|
|
(1,757
|
)
|
|
1,449,958
|
|
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
|
|
Stockholders’ equity:
|
|
|
|
|
|
|
|
|
|
|
Common stock
|
55
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
55
|
|
|
Treasury stock
|
(860
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(860
|
)
|
|
Additional paid-in capital
|
1,648,687
|
|
|
1,344,577
|
|
|
109,795
|
|
|
(1,454,372
|
)
|
|
1,648,687
|
|
|
Accumulated deficit
|
(1,705,623
|
)
|
|
(624,824
|
)
|
|
(95,306
|
)
|
|
720,130
|
|
|
(1,705,623
|
)
|
|
Accumulated other comprehensive income (loss)
|
17,952
|
|
|
24,026
|
|
|
(12,148
|
)
|
|
(11,878
|
)
|
|
17,952
|
|
|
Total stockholders’ equity
|
(39,789
|
)
|
|
743,779
|
|
|
2,341
|
|
|
(746,120
|
)
|
|
(39,789
|
)
|
|
Total liabilities and stockholders’ equity
|
$
|
1,118,072
|
|
|
$
|
1,036,742
|
|
|
$
|
3,232
|
|
|
$
|
(747,877
|
)
|
|
$
|
1,410,169
|
|
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
THREE MONTHS ENDED JUNE 30, 2016
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
Guarantor
Subsidiaries
|
|
Non-
Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
|
Operating revenue:
|
|
|
|
|
|
|
|
|
|
|
Oil production
|
$
|
1,323
|
|
|
$
|
71,388
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
72,711
|
|
|
Natural gas production
|
3,959
|
|
|
8,594
|
|
|
—
|
|
|
—
|
|
|
12,553
|
|
|
Natural gas liquids production
|
2,375
|
|
|
1,343
|
|
|
—
|
|
|
—
|
|
|
3,718
|
|
|
Other operational income
|
337
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
337
|
|
|
Total operating revenue
|
7,994
|
|
|
81,325
|
|
|
—
|
|
|
—
|
|
|
89,319
|
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
3,814
|
|
|
15,012
|
|
|
—
|
|
|
—
|
|
|
18,826
|
|
|
Transportation, processing and gathering expenses
|
6,021
|
|
|
1,162
|
|
|
—
|
|
|
—
|
|
|
7,183
|
|
|
Production taxes
|
383
|
|
|
195
|
|
|
—
|
|
|
—
|
|
|
578
|
|
|
Depreciation, depletion and amortization
|
10,470
|
|
|
35,761
|
|
|
—
|
|
|
—
|
|
|
46,231
|
|
|
Write-down of oil and gas properties
|
6,534
|
|
|
112,114
|
|
|
1
|
|
|
—
|
|
|
118,649
|
|
|
Accretion expense
|
58
|
|
|
10,024
|
|
|
—
|
|
|
—
|
|
|
10,082
|
|
|
Salaries, general and administrative expenses
|
20,013
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
20,014
|
|
|
Incentive compensation expense
|
4,670
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,670
|
|
|
Restructuring fees
|
9,436
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9,436
|
|
|
Other operational expenses
|
27,736
|
|
|
(57
|
)
|
|
1
|
|
|
—
|
|
|
27,680
|
|
|
Derivative expense, net
|
—
|
|
|
626
|
|
|
—
|
|
|
—
|
|
|
626
|
|
|
Total operating expenses
|
89,135
|
|
|
174,838
|
|
|
2
|
|
|
—
|
|
|
263,975
|
|
|
Loss from operations
|
(81,141
|
)
|
|
(93,513
|
)
|
|
(2
|
)
|
|
—
|
|
|
(174,656
|
)
|
|
Other (income) expenses:
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
17,599
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
17,599
|
|
|
Interest income
|
(302
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(302
|
)
|
|
Other income
|
(20
|
)
|
|
(250
|
)
|
|
—
|
|
|
—
|
|
|
(270
|
)
|
|
Other expense
|
9
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9
|
|
|
Loss from investment in subsidiaries
|
99,447
|
|
|
—
|
|
|
1
|
|
|
(99,448
|
)
|
|
—
|
|
|
Total other (income) expenses
|
116,733
|
|
|
(250
|
)
|
|
1
|
|
|
(99,448
|
)
|
|
17,036
|
|
|
Loss before taxes
|
(197,874
|
)
|
|
(93,263
|
)
|
|
(3
|
)
|
|
99,448
|
|
|
(191,692
|
)
|
|
Provision (benefit) for income taxes:
|
|
|
|
|
|
|
|
|
|
|
Current
|
(2,113
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,113
|
)
|
|
Deferred
|
—
|
|
|
6,182
|
|
|
—
|
|
|
—
|
|
|
6,182
|
|
|
Total income taxes
|
(2,113
|
)
|
|
6,182
|
|
|
—
|
|
|
—
|
|
|
4,069
|
|
|
Net loss
|
$
|
(195,761
|
)
|
|
$
|
(99,445
|
)
|
|
$
|
(3
|
)
|
|
$
|
99,448
|
|
|
$
|
(195,761
|
)
|
|
Comprehensive loss
|
$
|
(207,117
|
)
|
|
$
|
(99,445
|
)
|
|
$
|
(3
|
)
|
|
$
|
99,448
|
|
|
$
|
(207,117
|
)
|
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
THREE MONTHS ENDED JUNE 30, 2015
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
Guarantor
Subsidiaries
|
|
Non-
Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
|
Operating revenue:
|
|
|
|
|
|
|
|
|
|
|
Oil production
|
$
|
6,504
|
|
|
$
|
105,081
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
111,585
|
|
|
Natural gas production
|
15,647
|
|
|
11,260
|
|
|
—
|
|
|
—
|
|
|
26,907
|
|
|
Natural gas liquids production
|
8,077
|
|
|
2,956
|
|
|
—
|
|
|
—
|
|
|
11,033
|
|
|
Total operating revenue
|
30,228
|
|
|
119,297
|
|
|
—
|
|
|
—
|
|
|
149,525
|
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
5,111
|
|
|
22,318
|
|
|
—
|
|
|
—
|
|
|
27,429
|
|
|
Transportation, processing and gathering expenses
|
17,974
|
|
|
1,966
|
|
|
—
|
|
|
—
|
|
|
19,940
|
|
|
Production taxes
|
1,436
|
|
|
391
|
|
|
—
|
|
|
—
|
|
|
1,827
|
|
|
Depreciation, depletion and amortization
|
44,052
|
|
|
33,899
|
|
|
—
|
|
|
—
|
|
|
77,951
|
|
|
Write-down of oil and gas properties
|
179,125
|
|
|
—
|
|
|
45,169
|
|
|
—
|
|
|
224,294
|
|
|
Accretion expense
|
91
|
|
|
6,317
|
|
|
—
|
|
|
—
|
|
|
6,408
|
|
|
Salaries, general and administrative expenses
|
16,398
|
|
|
—
|
|
|
20
|
|
|
—
|
|
|
16,418
|
|
|
Incentive compensation expense
|
1,264
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,264
|
|
|
Other operational expenses
|
1,454
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,454
|
|
|
Derivative expense, net
|
—
|
|
|
701
|
|
|
—
|
|
|
—
|
|
|
701
|
|
|
Total operating expenses
|
266,905
|
|
|
65,592
|
|
|
45,189
|
|
|
—
|
|
|
377,686
|
|
|
Income (loss) from operations
|
(236,677
|
)
|
|
53,705
|
|
|
(45,189
|
)
|
|
—
|
|
|
(228,161
|
)
|
|
Other (income) expenses:
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
10,472
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10,472
|
|
|
Interest income
|
(46
|
)
|
|
(19
|
)
|
|
(1
|
)
|
|
—
|
|
|
(66
|
)
|
|
Other income
|
(187
|
)
|
|
(423
|
)
|
|
(3
|
)
|
|
—
|
|
|
(613
|
)
|
|
(Income) loss from investment in subsidiaries
|
(16,147
|
)
|
|
—
|
|
|
28,918
|
|
|
(12,771
|
)
|
|
—
|
|
|
Total other (income) expenses
|
(5,908
|
)
|
|
(442
|
)
|
|
28,914
|
|
|
(12,771
|
)
|
|
9,793
|
|
|
Income (loss) before taxes
|
(230,769
|
)
|
|
54,147
|
|
|
(74,103
|
)
|
|
12,771
|
|
|
(237,954
|
)
|
|
Provision (benefit) for income taxes:
|
|
|
|
|
|
|
|
|
|
|
Deferred
|
(77,863
|
)
|
|
9,082
|
|
|
(16,267
|
)
|
|
—
|
|
|
(85,048
|
)
|
|
Total income taxes
|
(77,863
|
)
|
|
9,082
|
|
|
(16,267
|
)
|
|
—
|
|
|
(85,048
|
)
|
|
Net income (loss)
|
$
|
(152,906
|
)
|
|
$
|
45,065
|
|
|
$
|
(57,836
|
)
|
|
$
|
12,771
|
|
|
$
|
(152,906
|
)
|
|
Comprehensive income (loss)
|
$
|
(183,062
|
)
|
|
$
|
45,065
|
|
|
$
|
(57,836
|
)
|
|
$
|
12,771
|
|
|
$
|
(183,062
|
)
|
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
SIX MONTHS ENDED JUNE 30, 2016
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
Guarantor
Subsidiaries
|
|
Non-
Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
|
Operating revenue:
|
|
|
|
|
|
|
|
|
|
|
Oil production
|
$
|
1,384
|
|
|
$
|
131,602
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
132,986
|
|
|
Natural gas production
|
6,426
|
|
|
21,300
|
|
|
—
|
|
|
—
|
|
|
27,726
|
|
|
Natural gas liquids production
|
3,509
|
|
|
4,944
|
|
|
—
|
|
|
—
|
|
|
8,453
|
|
|
Other operational income
|
693
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
693
|
|
|
Total operating revenue
|
12,012
|
|
|
157,846
|
|
|
—
|
|
|
—
|
|
|
169,858
|
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
6,542
|
|
|
31,818
|
|
|
13
|
|
|
—
|
|
|
38,373
|
|
|
Transportation, processing and gathering expenses
|
7,567
|
|
|
457
|
|
|
—
|
|
|
—
|
|
|
8,024
|
|
|
Production taxes
|
642
|
|
|
417
|
|
|
—
|
|
|
—
|
|
|
1,059
|
|
|
Depreciation, depletion and amortization
|
19,064
|
|
|
88,725
|
|
|
—
|
|
|
—
|
|
|
107,789
|
|
|
Write-down of oil and gas properties
|
15,858
|
|
|
231,645
|
|
|
350
|
|
|
—
|
|
|
247,853
|
|
|
Accretion expense
|
116
|
|
|
19,949
|
|
|
—
|
|
|
—
|
|
|
20,065
|
|
|
Salaries, general and administrative expenses
|
32,967
|
|
|
(199
|
)
|
|
—
|
|
|
—
|
|
|
32,768
|
|
|
Incentive compensation expense
|
9,649
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9,649
|
|
|
Restructuring fees
|
10,389
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10,389
|
|
|
Other operational expenses
|
33,845
|
|
|
280
|
|
|
6,082
|
|
|
—
|
|
|
40,207
|
|
|
Derivative expense, net
|
—
|
|
|
488
|
|
|
—
|
|
|
—
|
|
|
488
|
|
|
Total operating expenses
|
136,639
|
|
|
373,580
|
|
|
6,445
|
|
|
—
|
|
|
516,664
|
|
|
Loss from operations
|
(124,627
|
)
|
|
(215,734
|
)
|
|
(6,445
|
)
|
|
—
|
|
|
(346,806
|
)
|
|
Other (income) expenses:
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
32,840
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
32,840
|
|
|
Interest income
|
(416
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(416
|
)
|
|
Other income
|
(59
|
)
|
|
(509
|
)
|
|
—
|
|
|
—
|
|
|
(568
|
)
|
|
Other expense
|
11
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
11
|
|
|
Loss from investment in subsidiaries
|
230,729
|
|
|
—
|
|
|
6,444
|
|
|
(237,173
|
)
|
|
—
|
|
|
Total other (income) expenses
|
263,105
|
|
|
(509
|
)
|
|
6,444
|
|
|
(237,173
|
)
|
|
31,867
|
|
|
Loss before taxes
|
(387,732
|
)
|
|
(215,225
|
)
|
|
(12,889
|
)
|
|
237,173
|
|
|
(378,673
|
)
|
|
Provision (benefit) for income taxes:
|
|
|
|
|
|
|
|
|
|
|
Current
|
(3,187
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,187
|
)
|
|
Deferred
|
—
|
|
|
9,059
|
|
|
—
|
|
|
—
|
|
|
9,059
|
|
|
Total income taxes
|
(3,187
|
)
|
|
9,059
|
|
|
—
|
|
|
—
|
|
|
5,872
|
|
|
Net loss
|
$
|
(384,545
|
)
|
|
$
|
(224,284
|
)
|
|
$
|
(12,889
|
)
|
|
$
|
237,173
|
|
|
$
|
(384,545
|
)
|
|
Comprehensive loss
|
$
|
(395,112
|
)
|
|
$
|
(224,284
|
)
|
|
$
|
(12,889
|
)
|
|
$
|
237,173
|
|
|
$
|
(395,112
|
)
|
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
SIX MONTHS ENDED JUNE 30, 2015
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
Guarantor
Subsidiaries
|
|
Non-
Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
|
Operating revenue:
|
|
|
|
|
|
|
|
|
|
|
Oil production
|
$
|
10,854
|
|
|
$
|
208,238
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
219,092
|
|
|
Natural gas production
|
32,264
|
|
|
22,980
|
|
|
—
|
|
|
—
|
|
|
55,244
|
|
|
Natural gas liquids production
|
17,956
|
|
|
5,443
|
|
|
—
|
|
|
—
|
|
|
23,399
|
|
|
Other operational income
|
1,792
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,792
|
|
|
Derivative income, net
|
—
|
|
|
2,427
|
|
|
—
|
|
|
—
|
|
|
2,427
|
|
|
Total operating revenue
|
62,866
|
|
|
239,088
|
|
|
—
|
|
|
—
|
|
|
301,954
|
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
10,087
|
|
|
44,919
|
|
|
—
|
|
|
—
|
|
|
55,006
|
|
|
Transportation, processing and gathering expenses
|
34,082
|
|
|
3,561
|
|
|
—
|
|
|
—
|
|
|
37,643
|
|
|
Production taxes
|
3,634
|
|
|
708
|
|
|
—
|
|
|
—
|
|
|
4,342
|
|
|
Depreciation, depletion and amortization
|
86,164
|
|
|
78,209
|
|
|
—
|
|
|
—
|
|
|
164,373
|
|
|
Write-down of oil and gas properties
|
670,537
|
|
|
—
|
|
|
45,169
|
|
|
—
|
|
|
715,706
|
|
|
Accretion expense
|
182
|
|
|
12,635
|
|
|
—
|
|
|
—
|
|
|
12,817
|
|
|
Salaries, general and administrative expenses
|
33,399
|
|
|
1
|
|
|
25
|
|
|
—
|
|
|
33,425
|
|
|
Incentive compensation expense
|
2,827
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,827
|
|
|
Other operational expenses
|
1,170
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,170
|
|
|
Total operating expenses
|
842,082
|
|
|
140,033
|
|
|
45,194
|
|
|
—
|
|
|
1,027,309
|
|
|
Income (loss) from operations
|
(779,216
|
)
|
|
99,055
|
|
|
(45,194
|
)
|
|
—
|
|
|
(725,355
|
)
|
|
Other (income) expenses:
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
20,816
|
|
|
21
|
|
|
—
|
|
|
—
|
|
|
20,837
|
|
|
Interest income
|
(147
|
)
|
|
(35
|
)
|
|
(6
|
)
|
|
—
|
|
|
(188
|
)
|
|
Other income
|
(320
|
)
|
|
(433
|
)
|
|
(3
|
)
|
|
—
|
|
|
(756
|
)
|
|
(Income) loss from investment in subsidiaries
|
(45,174
|
)
|
|
—
|
|
|
28,918
|
|
|
16,256
|
|
|
—
|
|
|
Total other (income) expenses
|
(24,825
|
)
|
|
(447
|
)
|
|
28,909
|
|
|
16,256
|
|
|
19,893
|
|
|
Income (loss) before taxes
|
(754,391
|
)
|
|
99,502
|
|
|
(74,103
|
)
|
|
(16,256
|
)
|
|
(745,248
|
)
|
|
Provision (benefit) for income taxes:
|
|
|
|
|
|
|
|
|
|
|
Deferred
|
(274,097
|
)
|
|
25,410
|
|
|
(16,267
|
)
|
|
—
|
|
|
(264,954
|
)
|
|
Total income taxes
|
(274,097
|
)
|
|
25,410
|
|
|
(16,267
|
)
|
|
—
|
|
|
(264,954
|
)
|
|
Net income (loss)
|
$
|
(480,294
|
)
|
|
$
|
74,092
|
|
|
$
|
(57,836
|
)
|
|
$
|
(16,256
|
)
|
|
$
|
(480,294
|
)
|
|
Comprehensive income (loss)
|
$
|
(522,953
|
)
|
|
$
|
74,092
|
|
|
$
|
(57,836
|
)
|
|
$
|
(16,256
|
)
|
|
$
|
(522,953
|
)
|
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
SIX MONTHS ENDED JUNE 30, 2016
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
Guarantor
Subsidiaries
|
|
Non-Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
$
|
(384,545
|
)
|
|
$
|
(224,284
|
)
|
|
$
|
(12,889
|
)
|
|
$
|
237,173
|
|
|
$
|
(384,545
|
)
|
|
Adjustments to reconcile net loss to net cash provided by operating activities:
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
19,064
|
|
|
88,725
|
|
|
—
|
|
|
—
|
|
|
107,789
|
|
|
Write-down of oil and gas properties
|
15,858
|
|
|
231,645
|
|
|
350
|
|
|
—
|
|
|
247,853
|
|
|
Accretion expense
|
116
|
|
|
19,949
|
|
|
—
|
|
|
—
|
|
|
20,065
|
|
|
Deferred income tax provision
|
—
|
|
|
9,059
|
|
|
—
|
|
|
—
|
|
|
9,059
|
|
|
Settlement of asset retirement obligations
|
—
|
|
|
(9,807
|
)
|
|
(899
|
)
|
|
—
|
|
|
(10,706
|
)
|
|
Non-cash stock compensation expense
|
4,682
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,682
|
|
|
Non-cash derivative expense
|
—
|
|
|
1,025
|
|
|
—
|
|
|
—
|
|
|
1,025
|
|
|
Non-cash interest expense
|
9,403
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9,403
|
|
|
Other non-cash expense
|
—
|
|
|
—
|
|
|
6,081
|
|
|
—
|
|
|
6,081
|
|
|
Change in current income taxes
|
(3,187
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,187
|
)
|
|
Non-cash loss from investment in subsidiaries
|
230,729
|
|
|
—
|
|
|
6,444
|
|
|
(237,173
|
)
|
|
—
|
|
|
Change in intercompany receivables/payables
|
(1,658
|
)
|
|
1,658
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(Increase) decrease in accounts receivable
|
(8,471
|
)
|
|
19,109
|
|
|
(883
|
)
|
|
—
|
|
|
9,755
|
|
|
(Increase) decrease in other current assets
|
(5,316
|
)
|
|
—
|
|
|
33
|
|
|
—
|
|
|
(5,283
|
)
|
|
Increase (decrease) in accounts payable
|
2,226
|
|
|
(2,547
|
)
|
|
—
|
|
|
—
|
|
|
(321
|
)
|
|
Decrease in other current liabilities
|
(5,565
|
)
|
|
(355
|
)
|
|
—
|
|
|
—
|
|
|
(5,920
|
)
|
|
Other
|
(7,372
|
)
|
|
(508
|
)
|
|
—
|
|
|
—
|
|
|
(7,880
|
)
|
|
Net cash (used in) provided by operating activities
|
(134,036
|
)
|
|
133,669
|
|
|
(1,763
|
)
|
|
—
|
|
|
(2,130
|
)
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
|
|
Investment in oil and gas properties
|
(45,292
|
)
|
|
(133,670
|
)
|
|
(349
|
)
|
|
—
|
|
|
(179,311
|
)
|
|
Investment in fixed and other assets
|
(898
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(898
|
)
|
|
Change in restricted funds
|
—
|
|
|
—
|
|
|
1,045
|
|
|
—
|
|
|
1,045
|
|
|
Investment in subsidiaries
|
—
|
|
|
—
|
|
|
717
|
|
|
(717
|
)
|
|
—
|
|
|
Net cash (used in) provided by investing activities
|
(46,190
|
)
|
|
(133,670
|
)
|
|
1,413
|
|
|
(717
|
)
|
|
(179,164
|
)
|
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
|
|
Proceeds from bank borrowings
|
477,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
477,000
|
|
|
Repayments of bank borrowings
|
(135,500
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(135,500
|
)
|
|
Repayments of building loan
|
(189
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(189
|
)
|
|
Deferred financing costs
|
(900
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(900
|
)
|
|
Equity proceeds from parent
|
—
|
|
|
—
|
|
|
(717
|
)
|
|
717
|
|
|
—
|
|
|
Net payments for share-based compensation
|
(673
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(673
|
)
|
|
Net cash provided by (used in) financing activities
|
339,738
|
|
|
—
|
|
|
(717
|
)
|
|
717
|
|
|
339,738
|
|
|
Effect of exchange rate changes on cash
|
—
|
|
|
—
|
|
|
(9
|
)
|
|
—
|
|
|
(9
|
)
|
|
Net change in cash and cash equivalents
|
159,512
|
|
|
(1
|
)
|
|
(1,076
|
)
|
|
—
|
|
|
158,435
|
|
|
Cash and cash equivalents, beginning of period
|
9,681
|
|
|
2
|
|
|
1,076
|
|
|
—
|
|
|
10,759
|
|
|
Cash and cash equivalents, end of period
|
$
|
169,193
|
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
169,194
|
|
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
SIX MONTHS ENDED JUNE 30, 2015
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
Guarantor
Subsidiaries
|
|
Non-Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
$
|
(480,294
|
)
|
|
$
|
74,092
|
|
|
$
|
(57,836
|
)
|
|
$
|
(16,256
|
)
|
|
$
|
(480,294
|
)
|
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
86,164
|
|
|
78,209
|
|
|
—
|
|
|
—
|
|
|
164,373
|
|
|
Write-down of oil and gas properties
|
670,537
|
|
|
—
|
|
|
45,169
|
|
|
—
|
|
|
715,706
|
|
|
Accretion expense
|
182
|
|
|
12,635
|
|
|
—
|
|
|
—
|
|
|
12,817
|
|
|
Deferred income tax (benefit) provision
|
(274,097
|
)
|
|
25,410
|
|
|
(16,267
|
)
|
|
—
|
|
|
(264,954
|
)
|
|
Settlement of asset retirement obligations
|
(14
|
)
|
|
(35,909
|
)
|
|
—
|
|
|
—
|
|
|
(35,923
|
)
|
|
Non-cash stock compensation expense
|
6,028
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6,028
|
|
|
Non-cash derivative expense
|
—
|
|
|
7,931
|
|
|
—
|
|
|
—
|
|
|
7,931
|
|
|
Non-cash interest expense
|
8,737
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8,737
|
|
|
Change in current income taxes
|
7,206
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
7,206
|
|
|
Non-cash (income) expense from investment in subsidiaries
|
(45,174
|
)
|
|
—
|
|
|
28,918
|
|
|
16,256
|
|
|
—
|
|
|
Change in intercompany receivables/payables
|
15,070
|
|
|
(24,802
|
)
|
|
9,732
|
|
|
—
|
|
|
—
|
|
|
Decrease in accounts receivable
|
16,968
|
|
|
6,079
|
|
|
—
|
|
|
—
|
|
|
23,047
|
|
|
Increase in other current assets
|
(1,895
|
)
|
|
—
|
|
|
(64
|
)
|
|
—
|
|
|
(1,959
|
)
|
|
(Increase) decrease in inventory
|
(2,415
|
)
|
|
2,415
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Decrease in accounts payable
|
(500
|
)
|
|
(7,326
|
)
|
|
—
|
|
|
—
|
|
|
(7,826
|
)
|
|
Decrease in other current liabilities
|
(8,409
|
)
|
|
(311
|
)
|
|
—
|
|
|
—
|
|
|
(8,720
|
)
|
|
Other
|
(71
|
)
|
|
(433
|
)
|
|
—
|
|
|
—
|
|
|
(504
|
)
|
|
Net cash (used in) provided by operating activities
|
(1,977
|
)
|
|
137,990
|
|
|
9,652
|
|
|
—
|
|
|
145,665
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
|
|
Investment in oil and gas properties
|
(128,333
|
)
|
|
(124,506
|
)
|
|
(11,516
|
)
|
|
—
|
|
|
(264,355
|
)
|
|
Proceeds from sale of oil and gas properties, net of expenses
|
—
|
|
|
10,100
|
|
|
—
|
|
|
—
|
|
|
10,100
|
|
|
Investment in fixed and other assets
|
(727
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(727
|
)
|
|
Change in restricted funds
|
177,647
|
|
|
—
|
|
|
1,828
|
|
|
—
|
|
|
179,475
|
|
|
Investment in subsidiaries
|
—
|
|
|
—
|
|
|
(9,684
|
)
|
|
9,684
|
|
|
—
|
|
|
Net cash provided by (used in) investing activities
|
48,587
|
|
|
(114,406
|
)
|
|
(19,372
|
)
|
|
9,684
|
|
|
(75,507
|
)
|
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
|
|
Proceeds from bank borrowings
|
5,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5,000
|
|
|
Repayments of bank borrowings
|
(5,000
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(5,000
|
)
|
|
Equity proceeds from parent
|
—
|
|
|
—
|
|
|
9,684
|
|
|
(9,684
|
)
|
|
—
|
|
|
Net payments for share-based compensation
|
(3,069
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,069
|
)
|
|
Net cash (used in) provided by financing activities
|
(3,069
|
)
|
|
—
|
|
|
9,684
|
|
|
(9,684
|
)
|
|
(3,069
|
)
|
|
Effect of exchange rate changes on cash
|
—
|
|
|
—
|
|
|
78
|
|
|
—
|
|
|
78
|
|
|
Net change in cash and cash equivalents
|
43,541
|
|
|
23,584
|
|
|
42
|
|
|
—
|
|
|
67,167
|
|
|
Cash and cash equivalents, beginning of period
|
72,886
|
|
|
1,450
|
|
|
152
|
|
|
—
|
|
|
74,488
|
|
|
Cash and cash equivalents, end of period
|
$
|
116,427
|
|
|
$
|
25,034
|
|
|
$
|
194
|
|
|
$
|
—
|
|
|
$
|
141,655
|
|
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Forward-Looking Statements
The information in this Quarterly Report on Form 10-Q (this “Form 10-Q”) includes “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical or current facts, that address activities, events, outcomes and other matters that we plan, expect, intend, assume, believe, budget, predict, forecast, project, estimate or anticipate (and other similar expressions) will, should or may occur in the future are forward-looking statements. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements as described in our
2015
Annual Report on Form 10-K and in this Form 10-Q.
Forward-looking statements may appear in a number of places in this Form 10-Q and include statements with respect to, among other things:
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expected results from risk-weighted drilling success;
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estimates of our future oil and natural gas production, including estimates of any increases in oil and natural gas production;
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planned capital expenditures and the availability of capital resources to fund capital expenditures;
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our outlook on oil and natural gas prices;
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estimates of our oil and natural gas reserves;
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any estimates of future earnings growth;
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the impact of political and regulatory developments;
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our outlook on the resolution of pending litigation and government inquiry;
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estimates of the impact of new accounting pronouncements on earnings in future periods;
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our future financial condition or results of operations and our future revenues and expenses;
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the outcome of restructuring efforts and asset sales;
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the amount, nature and timing of any potential acquisition or divestiture transactions;
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any expected results or benefits associated with our acquisitions;
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our access to capital and our anticipated liquidity;
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estimates of future income taxes; and
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our business strategy and other plans and objectives for future operations.
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We caution you that these forward-looking statements are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and marketing of oil and natural gas. These risks include, among other things:
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commodity price volatility, including further or sustained declines in the prices we receive for our oil and natural gas production;
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domestic and worldwide economic conditions, which may adversely affect the demand for and supply of oil and natural gas;
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the availability of capital on economic terms to fund our operations, capital expenditures, acquisitions and other obligations;
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our future level of indebtedness, liquidity, compliance with debt covenants and our ability to continue as a going concern;
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our future financial condition, results of operations, revenues, cash flows and expenses;
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the potential need to sell certain assets, restructure our debt, raise additional capital or seek bankruptcy protection;
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our ability to continue to borrow under our credit facility;
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our ability to post additional collateral for current bonds or comply with new supplemental bonding requirements imposed by BOEM;
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declines in the value of our oil and gas properties resulting in a decrease in our borrowing base under our bank credit facility and impairments;
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our ability to develop, explore for, acquire and replace oil and natural gas reserves and sustain production;
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the impact of a financial crisis on our business operations, financial condition and ability to raise capital;
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the ability of financial counterparties to perform or fulfill their obligations under existing agreements;
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third-party interruption of sales to market;
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lack of availability and cost of goods and services;
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market conditions relating to potential acquisition and divestiture transactions;
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regulatory and environmental risks associated with drilling and production activities, including, for example, compliance with the Bureau of Safety and Environmental Enforcement's recently finalized well control rule;
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our ability to establish operations or production on our acreage prior to the expiration of related leaseholds;
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availability of drilling and production equipment, facilities, field service providers, gathering, processing and transportation;
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competition in the oil and gas industry;
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our inability to retain and attract key personnel;
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drilling and other operating risks, including the consequences of a catastrophic event;
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unsuccessful exploration and development drilling activities;
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hurricanes and other weather conditions;
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availability, cost and adequacy of insurance coverage;
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adverse effects of changes in applicable tax, environmental, derivatives, permitting, bonding and other regulatory requirements and legislation, as well as agency interpretation and enforcement and judicial decisions regarding the foregoing, including changes affecting our offshore and Appalachian operations;
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uncertainty inherent in estimating proved oil and natural gas reserves and in projecting future rates of production and timing of development expenditures; and
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other risks described in this Form 10-Q.
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For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see (1)
Part II, Item 1A. Risk Factors
, of this Form 10-Q and (2) Part I, Item 1A, of our
2015
Annual Report on Form 10-K. Should one or more of the risks or uncertainties described above, in our
2015
Annual Report on Form 10-K or elsewhere in this Form 10-Q occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages. All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) contained in this Form 10-Q should be read in conjunction with the MD&A contained in our
2015
Annual Report on Form 10-K.
Critical Accounting Estimates
Our
2015
Annual Report on Form 10-K describes the accounting estimates that we believe are critical to the reporting of our financial position and operating results and that require management’s most difficult, subjective or complex judgments. Our most significant estimates are:
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remaining proved oil and natural gas reserve volumes and the timing of their production;
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estimated costs to develop and produce proved oil and natural gas reserves;
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accruals of exploration costs, development costs, operating costs and production revenue;
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timing and future costs to abandon our oil and gas properties;
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effectiveness and estimated fair value of derivative positions;
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classification of unevaluated property costs;
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capitalized general and administrative costs and interest;
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estimates of fair value in business combinations;
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current and deferred income taxes; and
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This Form 10-Q should be read together with the discussion contained in our
2015
Annual Report on Form 10-K regarding these critical accounting policies.
Other Factors Affecting Our Business and Financial Results
In addition to the matters discussed above, our business, financial condition and results of operations are affected by a number of other factors. This Form 10-Q should be read in conjunction with the discussion in Part I, Item 1A, of our
2015
Annual Report on Form 10-K and in this Form 10-Q under
Part II, Item 1A. Risk Factors
, regarding our known material risk factors.
Overview
We are an independent oil and natural gas company engaged in the acquisition, exploration, exploitation, development and operation of oil and gas properties. We have been operating in the GOM Basin since our incorporation in 1993 and have established a technical and operational expertise in this area. We have leveraged our experience in the GOM conventional shelf and expanded our reserve base into the more prolific basins of the GOM deep water, Gulf Coast deep gas and the Marcellus and Utica shales in Appalachia.
We experienced significant declines in oil, natural gas and NGL prices during the second half of 2014, with lower prices continuing throughout 2015 and into 2016, which resulted in reduced revenue and cash flows and caused us to reduce our planned capital expenditures for 2015 and 2016 and shut in our Mary field in Appalachia in September 2015. The lower commodity prices have negatively impacted our liquidity position. Additionally, the level of our indebtedness and the current commodity price environment have presented challenges as they relate to our ability to comply with the covenants in the agreements governing our indebtedness. As of
August 2, 2016
, we had total indebtedness of
$1,428 million
, including $300 million of 2017 Convertible Notes, $775 million of 2022 Notes,
$341.5 million
outstanding under our bank credit facility and
$11.5 million
outstanding under our Building Loan.
On March 10, 2016, we borrowed $385 million under our bank credit facility, which at the time, represented substantially all of the undrawn amount on our $500 million borrowing base. On April 13, 2016, the borrowing base under our bank credit facility was reduced by the lenders from $500 million to $300 million. On that date, we had $457 million of outstanding borrowings and $18.3 million of outstanding letters of credit under the bank credit facility, resulting in a $175.3 million borrowing base deficiency. In June 2016, however, we entered into the Amendment to our bank credit facility which, among other things, resulted in an increase of our borrowing base from $300 million to $360 million and relaxed certain financial covenants through December 31, 2016. In addition, the Amendment requires that we maintain minimum liquidity (as defined in the Amendment) of $125.0 million through January 15, 2017, imposes limitations on capital expenditures from June to December 2016 and provides for anti-hoarding cash provisions for amounts in excess of $50.0 million beginning after December 10, 2016. Upon execution of the Amendment, we repaid the balance of our borrowing base deficiency, resulting in approximately $360 million outstanding under the credit facility at that time. As of June 30, 2016, we were in compliance with all covenants under the bank credit facility and the indentures governing our notes, however, we anticipate that the minimum liquidity requirement and other restrictions under the bank credit facility may prevent us from being able to meet our interest payment obligation on the 2022 Notes in the fourth quarter of 2016 as well as the subsequent maturity of our 2017 Convertible Notes in March 2017. Further, we anticipate that we could exceed the Consolidated Funded Leverage financial covenant of 3.75 to 1 at the end of the first quarter of 2017, when the relaxed covenant levels end, unless a material portion of our debt is repaid, reduced or exchanged into equity. See
"Liquidity and Capital Resources"
.
In late June 2016, we terminated our deep water drilling rig contract with Ensco for total consideration of $20 million. Additionally, in late June 2016, we entered into an interim Appalachian midstream contract with Williams at the Mary field in Appalachia, allowing us to resume production at the Mary field. See
"Liquidity and Capital Resources"
.
We have retained Lazard as our financial advisor and Latham & Watkins LLP as our legal advisor to assist the Company in analyzing and considering financial, transactional and strategic alternatives. We are in the process of analyzing various strategic alternatives to address our liquidity and capital structure, including strategic and refinancing alternatives through a private restructuring, asset sales and a prepackaged or prearranged bankruptcy filing. We are currently engaged in negotiations with financial advisors for certain holders of the 2017 Convertible Notes and 2022 Notes regarding the restructuring of the notes. To the extent the restructuring efforts result in an exchange of debt for equity, it may result in significant dilution for the existing stockholders. We cannot provide any assurances that we will be able to complete a private restructuring or asset sales on satisfactory terms to provide the liquidity to restructure or pay down our senior indebtedness.
Known Trends and Uncertainties
Declining Commodity Prices
– We experienced significant declines in oil, natural gas and NGL prices during the second half of 2014, with lower prices continuing throughout 2015 and into 2016, which resulted in reduced revenue and cash flows and caused us to reduce our planned capital expenditures for 2015 and 2016. Additionally, the low commodity prices have adversely affected the estimated value and quantities of our proved oil, natural gas and NGL reserves, which contributed to ceiling test write-downs of our oil and gas properties. For the years ended December 31, 2014 and 2015 and the first and second quarters of 2016, we recognized ceiling test write-downs of our oil and gas properties of $351 million, $1,362 million,
$129 million
and
$119 million
, respectively. If NYMEX commodity prices remain at current levels (approximately $44 per Bbl of oil and $2.90 per MMBtu of natural gas), we would expect only minimal downward revisions of our estimated proved reserve quantities and would expect to recognize an additional ceiling test write-down between $0 and $100 million in the third quarter of 2016.
Bank Credit Facility
–
The level of our indebtedness and the current commodity price environment have presented challenges as they relate to our ability to comply with the covenants in the agreements governing our indebtedness. On June 14, 2016, we entered into the Amendment to the bank credit facility to, among other things, increase the borrowing base to $360 million from $300 million and revise the maximum Consolidated Funded Leverage financial covenant to be 5.25 to 1 for the fiscal quarter ended June 30, 2016, 6.50 to1 for the fiscal quarter ending September 30, 2016, 9.50 to 1 for the fiscal quarter ending December 31, 2016 and 3.75 to 1 thereafter. See
"Liquidity and Capital Resources"
. We were in compliance with all covenants under the bank credit facility and the indentures governing our outstanding notes as of June 30, 2016. However, we anticipate that the minimum liquidity requirement and other restrictions under the bank credit facility may prevent us from being able to meet our interest payment obligation on the 2022 Notes in the fourth quarter of 2016 as well as the subsequent maturity of our 2017 Convertible Notes in March 2017. Further, we anticipate that we could exceed the Consolidated Funded Leverage financial covenant of 3.75 to 1 at the end of the first quarter of 2017, when the relaxed covenant levels end, unless a material portion of our debt is repaid, reduced or exchanged into equity. If we are unable to reach an agreement with our banks or find acceptable alternative financing, it may lead to an event of default under our bank credit facility. If following an event of default, the banks were to accelerate repayment under the bank credit facility, it would result in an event of default and may result in the acceleration of our other debt instruments.
Additionally, the significant decline in commodity prices has materially adversely impacted the value of our estimated proved reserves and, in turn, the market value used by the lenders to determine our borrowing base. The borrowing base under our bank credit facility as of
August 2, 2016
was $360 million, a reduction from the borrowing base of $500 million as of April 12, 2016. See
"Liquidity and Capital Resources"
. Continued low commodity prices or further declines in commodity prices could have a further adverse impact on
the estimated value and quantities of our proved reserves and could result in additional reductions of our borrowing base under our bank credit facility.
BOEM Financial Assurance Requirements –
The BOEM requires all operators in federal waters to provide financial assurances to cover the cost of plugging and abandoning wells and decommissioning offshore facilities. Historically, we and many other operators have been able to obtain an exemption from most bonding obligations based on financial net worth. On March 21, 2016, we received notice letters from BOEM stating that BOEM had determined that we no longer qualified for a supplemental bonding waiver under the financial criteria specified in BOEM’s guidance to lessees at that time. BOEM's notice letters indicated the amount of Stone's supplemental bonding needs could be as much as $565 million. In late March 2016, we proposed a tailored plan to BOEM for financial assurances relating to our abandonment obligations, which provides for posting some incremental financial assurances in favor of BOEM. On May 13, 2016, we received notice letters from BOEM rescinding its demand for supplemental bonding with the understanding that we will continue to make progress with BOEM in finalizing and implementing our long-term tailored plan. Currently, we have posted an aggregate of approximately $230 million in surety bonds in favor of BOEM, third party bonds and letters of credit, all relating to our offshore abandonment obligations.
We have submitted our tailored plan to BOEM and are awaiting its review and approval. Our proposed plan would require approximately $16 million of incremental financial assurance or bonding for 2016, a majority of which may require cash collateral. Under the submitted plan, additional financial assurance would be required for subsequent years. There is no assurance this tailored plan will be approved by BOEM. Additionally, on July 14, 2016, BOEM issued a new NTL that augments requirements for the posting of additional financial assurance by offshore lessees. We are reviewing the new NTL and its potential impact to Stone.
The new NTL is likely to result in the loss of supplemental bonding waivers for a large number of operators on the outer continental shelf ("OCS"), which will in turn force these operators to seek additional surety bonds and could, consequently, exceed the surety bond market’s current capacity for providing such additional financial assurance. Operators who have already leveraged their assets as a result of the declining oil market could face difficulty obtaining surety bonds because of concerns the surety may have about the priority of their lien on the operator's collateral. All of these factors may make it more difficult for us to obtain the financial assurances required by BOEM to conduct operations on the OCS. These and other changes to BOEM bonding and financial assurance requirements could result in increased costs on our operations and consequently have a material adverse effect on our business and results of operations.
In addition, although the surety companies have not historically required collateral from us to back our surety bonds, we have recently provided some cash collateral on a portion of our existing surety bonds and may be required to provide cash collateral on additional surety bonds we expect will be required to satisfy BOEM's financial assurance requirements.
We cannot provide assurance that we will be able to satisfy collateral demands for current bonds or for additional bonds to comply with supplemental bonding requirements of the BOEM. This need to obtain additional surety bonds, or some other form of financial assurances, could impact our liquidity.
Hurricanes –
Since a large portion of our production originates in the GOM, we are particularly vulnerable to the effects of hurricanes on production. Additionally, affordable and practical insurance coverage for property damage to our facilities for hurricanes has been difficult to obtain for some time so we have eliminated our hurricane insurance coverage. Significant hurricane impacts could include reductions and/or deferrals of future oil and natural gas production and revenues, increased lease operating expenses for evacuations and repairs and possible increases to and/or acceleration of plugging and abandonment costs, all of which could also affect our ability to remain in compliance with the covenants under our bank credit facility.
Deep Water Operations
– We are currently operating two significant properties in the deep water of the GOM and engage in deep water drilling operations. Operations in the deep water involve high operational risks. Despite technological advances over the last several years, liabilities for environmental losses, personal injury and loss of life and significant regulatory fines in the event of a disaster could be well in excess of insured amounts and result in significant losses on our statement of operations as well as going concern issues.
Liquidity and Capital Resources
Overview.
On April 13, 2016, the borrowing base under our bank credit facility was reduced from $500 million to $300 million. On that date, we had $457 million of outstanding borrowings and $18.3 million of outstanding letters of credit under the bank credit facility, resulting in a $175.3 million borrowing base deficiency. At the time, we elected to pay the deficiency in six equal monthly installments, making the first two payments of $29.2 million in May and June 2016. On June 14, 2016, we entered into the Amendment to the bank credit facility to, among other things, increase the borrowing base to $360 million, and on that date, we repaid $56.8 million in borrowings, which eliminated the borrowing base deficiency and brought the total borrowings and letters of credit outstanding under the bank credit facility in conformity with the borrowing base limitation. See "
Bank Credit Facility"
below. As of
August 2, 2016
, we had
$341.5 million
of outstanding borrowings and
$18.3 million
of outstanding letters of credit, leaving approximately
$0.2 million
of availability under the bank credit facility. We have $300 million of 2017 Convertible Notes that we need to restructure or repay by March 1, 2017 (see "
Senior Notes"
below). As of
August 2, 2016
, we had cash on hand of approximately $165.5 million.
Our capital expenditure budget for 2016 was set by the board of directors at $200 million, and assumed success in farming out the ENSCO 8503 deep water drilling rig to other operators for five to six months and the reduction in our working interests to acceptable levels on potential exploration wells to be drilled, or if unsuccessful, stacking the rig. The farm out subsidies and rig stacking expenses would be charges to our statement of operations as "Other operational expenses" and are expected to range between $40 million and $50 million. During the first two quarters of 2016, we successfully executed two separate rig farm out arrangements for the ENSCO 8503 with other operators. On June 24, 2016, our contract with Ensco was terminated for total consideration of $20 million, approximately $5 million of which was a deposit previously provided to Ensco pursuant to the drilling services contract. Further, we agreed to provide Ensco the opportunity to perform certain drilling services commenced before December 31, 2019, and paid Ensco a $5 million deposit to be used against future drilling activities initiated before March 31, 2017, subject to extension in certain circumstances. The ENSCO 8503 deep water drilling rig contract included an operating day rate of $341,000 and was scheduled to expire in August 2017. To further reduce capital expenditures for 2016, we elected to temporarily stack the Pompano platform drilling rig in place. We currently expect to reinstate drilling operations in early 2017. The updated rig schedule and cost reduction efforts have decreased our projected 2016 capital expenditures to approximately $160 million to $170 million, excluding any deep water exploration drilling in the third and fourth quarters of 2016. The 2016 capital expenditure budget excludes material acquisitions and capitalized salaries, general and administrative (“SG&A”) expenses and interest as well as potential subsidy expense associated with rig farm outs, rig stacking charges and termination consideration.
Also, in late June 2016, Stone entered into an interim Appalachian midstream contract with Williams at the Mary field in Appalachia. The interim agreement provides near-term relief for Stone by permitting Stone to resume profitable production and positive cash flow at the Mary field. The initial term of the interim agreement is through August 31, 2016 and it continues on a month to month basis thereafter unless terminated by either party. Subsequent to the execution of the interim agreement, production from much of the Mary field resumed in late June and averaged over 75 MMcfe per day in July, with total Appalachia volumes averaging 95 MMcfe per day in July. We expect daily production rates from Appalachia to reach over 125 MMcfe per day in the third quarter of 2016, resulting in increased cash flow along with increases in lease operating and transportation, processing and gathering expenses.
Based on our current outlook of commodity prices and our estimated production for 2016, we expect to fund our 2016 capital expenditures primarily with cash on hand from borrowings under our bank credit facility and expected cash flows from operating activities, as well as possible financings or asset sales. In order to address the March 2017 maturity of our 2017 Convertible Notes, we continue to analyze a variety of financing options, including a restructuring with current holders of the 2017 Convertible Notes (which may include exchanges of our 2017 Convertible Notes for new debt and/or equity securities), securing a secondary credit facility or second lien notes, sale or joint venture of core or non-core assets, a sale and leaseback of owned infrastructure and issuance of debt or equity in the public or private markets. Such transactions, if any, will depend on prevailing market conditions, contractual restrictions and other factors, some of which may be outside of our control. Current market conditions may put limitations on our ability to issue new debt or equity securities in the public or private markets. The ability of oil and gas companies to access the equity and high yield debt markets has been significantly limited since the significant decline in commodity prices throughout 2015 and into 2016.
Historically, we have been able to obtain an exemption from supplemental bonding requirements on our offshore leases for abandonment obligations based on financial net worth, however, on March 21, 2016, we received notice letters from BOEM stating that BOEM had determined that we no longer qualified for a supplemental bonding waiver under the financial criteria specified in BOEM’s guidance to lessees at that time. In late March 2016, we proposed a tailored plan to BOEM for financial assurances relating to our abandonment obligations, which provides for posting some incremental financial assurances in favor of BOEM. On May 13, 2016, we received notice letters from BOEM rescinding its demand for supplemental bonding with the understanding that we will continue to make progress with BOEM in finalizing and implementing our long-term tailored plan. We have submitted our tailored plan to BOEM and are awaiting its review and approval. Our proposed plan would require approximately $16 million of incremental financial assurance or bonding for 2016, a majority of which may require cash collateral. Under the submitted plan, additional financial assurance would be required for subsequent years. There is no assurance this tailored plan will be approved by BOEM. Additionally, on July 14, 2016, BOEM issued a new NTL that augments requirements for the posting of additional financial assurances by offshore lessees. We are reviewing the new NTL and its potential impact to Stone.
Although the surety companies have not historically required collateral from us to back our surety bonds, we have recently provided some cash collateral on a portion of our existing surety bonds and may be required to provide cash collateral on additional surety bonds we expect will be required to satisfy BOEM's financial assurance requirements. This need to obtain additional surety bonds or some other form of financial assurance, could impact our liquidity. See
Known Trends and Uncertainties
.
Indebtedness.
Bank Credit Facility –
On June 24, 2014, we entered into a revolving credit facility with commitments totaling $900 million (subject to borrowing base limitations) through a syndicated bank group, replacing our previous facility. The bank credit facility matures on July 1, 2019 and is guaranteed by our Guarantor Subsidiaries. The borrowing base under the bank credit facility is redetermined semi-annually, typically in May and November, by the lenders, taking into consideration the estimated loan value of our oil and gas properties and those of our subsidiaries that guarantee the bank facility in accordance with the lenders’ customary practices for oil and gas loans. In addition, we and the lenders each have discretion at any time, but not more than two additional times in any calendar year, to have the borrowing
base redetermined. On
April 13, 2016
, we received notice that our borrowing base under the bank credit facility was reduced from $500 million to $300 million. On that date, we had
$457 million
of outstanding borrowings and
$18.3 million
of outstanding letters of credit, or
$175.3 million
in excess of the redetermined borrowing base (referred to as a borrowing base deficiency). Our agreement with the banks provides that within 30 days after notification of a borrowing base deficiency, we must elect to cure the borrowing base deficiency through any combination of the following actions: (1) repay amounts outstanding sufficient to cure the deficiency within 10 days after our written election to do so; (2) add additional oil and gas properties acceptable to the banks to the borrowing base and take such actions necessary to grant the banks a mortgage in the properties within 30 days after our written election to do so; and/or (3) arrange to pay the deficiency in six equal monthly installments. At that time, we elected to pay the deficiency in six equal monthly installments, making the first two payments of $29.2 million in May and June 2016.
On June 14, 2016, we entered into the Amendment to the bank credit facility to (i) increase the borrowing base to $360 million from $300 million, (ii) provide for no redetermination of the borrowing base by the lenders until January 15, 2017, other than an automatic reduction upon the sale of certain of our properties, (iii) permit second lien indebtedness to refinance the existing 2017 Convertible Notes and 2022 Notes, (iv) revise the maximum Consolidated Funded Leverage financial covenant to be 5.25 to 1 for the fiscal quarter ended June 30, 2016, 6.50 to 1 for the fiscal quarter ending September 30, 2016, 9.50 to 1 for the fiscal quarter ending December 31, 2016 and 3.75 to 1 thereafter, (v) require minimum liquidity (as defined in the Amendment) of at least $125.0 million until January 15, 2017, (vi) impose limitations on capital expenditures from June through December 2016, (vii) grant the lenders a perfected security interest in all deposit accounts and (viii) provide for anti-hoarding cash provisions for amounts in excess of $50.0 million to apply after December 10, 2016. Upon execution of the Amendment, we repaid $56.8 million in borrowings under the credit facility, bringing total borrowings and letters of credit outstanding under the bank credit facility in conformity with the borrowing base limitation. On
August 2, 2016
, we had
$341.5 million
of outstanding borrowings and
$18.3 million
of outstanding letters of credit, leaving
$0.2 million
of availability under the bank credit facility.
The bank credit facility is collateralized by substantially all of our assets and the assets of our material subsidiaries. We are required to mortgage and grant a security interest in our oil and natural gas reserves representing at least 86% of the discounted present value of the future net cash flows from our proved oil and natural gas reserves reviewed in determining the borrowing base. Low commodity prices and negative price differentials have had a material adverse impact on the value of our estimated proved reserves and, in turn, the market value used by the lenders to determine our borrowing base. Continued low commodity prices or further declines in commodity prices will likely have a further material adverse impact on the value of our estimated proved reserves.
Interest on loans under the bank credit facility is calculated using the LIBOR rate or the base rate, at our election. The margin for loans at the LIBOR rate is determined based on borrowing base utilization and ranges from 1.500% to 2.500%. In addition to the covenants discussed above, the bank credit facility provides that we must maintain a ratio of consolidated EBITDA to consolidated Net Interest Expense, as defined in the credit agreement, for the preceding four quarterly periods of not less than 2.5 to 1. The bank credit facility also includes certain customary restrictions or requirements with respect to disposition of properties, incurrence of additional debt, change of control and reporting responsibilities. These covenants may limit or prohibit us from paying cash dividends but do allow for limited stock repurchases. These covenants also restrict our ability to prepay other indebtedness under certain circumstances.
As of June 30, 2016, we were in compliance with all covenants under the bank credit facility and the indentures governing our notes. However, we anticipate that the minimum liquidity requirement and other restrictions under the bank credit facility may prevent us from being able to meet our interest payment obligation on the 2022 Notes in the fourth quarter of 2016 as well as the subsequent maturity of our 2017 Convertible Notes in March 2017. Further, we anticipate that we could exceed the Consolidated Funded Leverage financial covenant of 3.75 to 1 at the end of the first quarter of 2017, when the relaxed covenant levels end, unless a material portion of our debt is repaid, reduced or exchanged into equity.
If we are unable to reach an agreement with our banks or find acceptable alternative financing, it may lead to an event of default under our bank credit facility. If following an event of default, the banks were to accelerate repayment under the bank credit facility, it would result in an event of default and may result in the acceleration of our other debt instruments.
Senior Notes –
Our senior notes consist of $300 million of 2017 Convertible Notes and $775 million of 2022 Notes. The 2017 Convertible Notes will be due on March 1, 2017, unless earlier converted or repurchased by us at the option of the holder(s). We are actively analyzing a variety of financing options to address the March 2017 maturity of our 2017 Convertible Notes (see
Overview
). We have an interest payment obligation under our 2017 Convertible Notes of approximately $2.6 million, due on September 1, 2016, and one under our 2022 Notes of approximately $29.2 million, due on November 15, 2016.
Cash Flow and Working Capital.
Net cash (used in) provided by operating activities totaled
($2.1) million
during the
six
months ended
June 30, 2016
compared to $
145.7 million
during the comparable period in
2015
. The decrease was primarily due to the decline in our hedge-effected oil, natural gas and NGL prices, the decline in natural gas and NGL production volumes, restructuring fees, rig subsidy and stacking expenses and the ENSCO 8503 termination fee, partially offset by a decline in lease operating and transportation, processing and gathering expenses. See "
Results of Operations
" for additional information relative to commodity prices, production and operating expense variances.
Net cash used in investing activities totaled $
179.2 million
during the
six
months ended
June 30, 2016
, which primarily represents our investment in oil and gas properties. Net cash used in investing activities totaled $
75.5 million
during the
six
months ended
June 30, 2015
, which primarily represents our investment in oil and gas properties of $
264.4 million
, offset by
$179.5 million
of previously restricted proceeds from the sale of oil and gas properties.
Net cash provided by financing activities totaled $
339.7 million
during the
six
months ended
June 30, 2016
, which primarily represents
$477.0 million
of borrowings under our bank credit facility less $
135.5 million
in repayments of borrowings under our bank credit facility. Net cash used in financing activities totaled $
3.1 million
during the
six
months ended
June 30, 2015
, which primarily represents net payments for share-based compensation. During the
six
months ended
June 30, 2015
, we had $
5.0 million
in borrowings and $
5.0 million
in repayments of borrowings under our bank credit facility.
We had a working capital deficit at
June 30, 2016
of $
123.0 million
, which included $288.3 million related to the 2017 Convertible Notes due on March 1, 2017.
Capital Expenditures.
During the three months ended
June 30, 2016
, additions to oil and gas property costs of
$40.2 million
included
$0.7 million
of lease and property acquisition costs,
$6.6 million
of capitalized SG&A expenses (inclusive of incentive compensation) and
$6.9 million
of capitalized interest. During the
six
months ended
June 30, 2016
, additions to oil and gas property costs of
$127.5 million
included
$1.3 million
of lease and property acquisition costs,
$12.4 million
of capitalized SG&A expenses (inclusive of incentive compensation) and
$14.3 million
of capitalized interest. These investments were financed with cash on hand and cash flows from operating activities.
Contractual Obligations and Other Commitments
We have various contractual obligations and other commitments in the normal course of operations. For further information, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Contractual Obligations and Other Commitments” in our
2015
Annual Report on Form 10-K. On October 6, 2014, we entered into an agreement to contract the ENSCO 8503 deep water drilling rig for our multi-year deep water drilling program in the GOM. On June 24, 2016, our contract with Ensco was terminated for total consideration of $20 million, approximately $5 million of which was a deposit previously provided to Ensco pursuant to the drilling services contract. Further, we agreed to provide Ensco the opportunity to perform certain drilling services commenced before December 31, 2019, and paid Ensco a $5 million deposit to be used against future drilling activities initiated before March 31, 2017, subject to extension in certain circumstances. The ENSCO 8503 deep water rig contract included an operating day rate of $341,000 and was scheduled to expire in August 2017. Other than the termination of the Ensco contract, there have been no material changes to this disclosure during the six months ended June 30, 2016.
Results of Operations
The following table sets forth certain information with respect to our oil and gas operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
|
|
|
|
|
2016
|
|
2015
|
|
Variance
|
|
% Change
|
|
Production:
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
1,548
|
|
|
1,534
|
|
|
14
|
|
|
1
|
%
|
|
Natural gas (MMcf)
|
5,100
|
|
|
12,581
|
|
|
(7,481
|
)
|
|
(59
|
)%
|
|
NGLs (MBbls)
|
244
|
|
|
794
|
|
|
(550
|
)
|
|
(69
|
)%
|
|
Oil, natural gas and NGLs (MBoe)
|
2,642
|
|
|
4,425
|
|
|
(1,783
|
)
|
|
(40
|
)%
|
|
Oil, natural gas and NGLs (MMcfe)
|
15,852
|
|
|
26,549
|
|
|
(10,697
|
)
|
|
(40
|
)%
|
|
Revenue data (in thousands):
(1)
|
|
|
|
|
|
|
|
|
Oil revenue
|
$
|
72,711
|
|
|
$
|
111,585
|
|
|
$
|
(38,874
|
)
|
|
(35
|
)%
|
|
Natural gas revenue
|
12,553
|
|
|
26,907
|
|
|
(14,354
|
)
|
|
(53
|
)%
|
|
NGLs revenue
|
3,718
|
|
|
11,033
|
|
|
(7,315
|
)
|
|
(66
|
)%
|
|
Total oil, natural gas and NGL revenue
|
$
|
88,982
|
|
|
$
|
149,525
|
|
|
$
|
(60,543
|
)
|
|
(40
|
)%
|
|
Average prices:
|
|
|
|
|
|
|
|
|
Prior to the cash settlement of effective hedging contracts
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
$
|
43.66
|
|
|
$
|
55.55
|
|
|
$
|
(11.89
|
)
|
|
(21
|
)%
|
|
Natural gas (per Mcf)
|
1.72
|
|
|
1.82
|
|
|
(0.10
|
)
|
|
(5
|
)%
|
|
NGLs (per Bbl)
|
15.24
|
|
|
13.90
|
|
|
1.34
|
|
|
10
|
%
|
|
Oil, natural gas and NGLs (per Boe)
|
30.31
|
|
|
26.93
|
|
|
3.38
|
|
|
13
|
%
|
|
Oil, natural gas and NGLs (per Mcfe)
|
5.05
|
|
|
4.49
|
|
|
0.56
|
|
|
12
|
%
|
|
Including the cash settlement of effective hedging contracts
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
$
|
46.97
|
|
|
$
|
72.74
|
|
|
$
|
(25.77
|
)
|
|
(35
|
)%
|
|
Natural gas (per Mcf)
|
2.46
|
|
|
2.14
|
|
|
0.32
|
|
|
15
|
%
|
|
NGLs (per Bbl)
|
15.24
|
|
|
13.90
|
|
|
1.34
|
|
|
10
|
%
|
|
Oil, natural gas and NGLs (per Boe)
|
33.68
|
|
|
33.79
|
|
|
(0.11
|
)
|
|
—
|
%
|
|
Oil, natural gas and NGLs (per Mcfe)
|
5.61
|
|
|
5.63
|
|
|
(0.02
|
)
|
|
—
|
%
|
|
Expenses (per Mcfe):
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
$
|
1.19
|
|
|
$
|
1.03
|
|
|
$
|
0.16
|
|
|
16
|
%
|
|
Transportation, processing and gathering expenses
|
0.45
|
|
|
0.75
|
|
|
(0.30
|
)
|
|
(40
|
)%
|
|
SG&A expenses (2)
|
1.26
|
|
|
0.62
|
|
|
0.64
|
|
|
103
|
%
|
|
DD&A expense on oil and gas properties
|
2.85
|
|
|
2.89
|
|
|
(0.04
|
)
|
|
(1
|
)%
|
|
|
|
|
(1)
|
Includes the cash settlement of effective hedging contracts.
|
|
|
|
|
(2)
|
Excludes incentive compensation expense.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
June 30,
|
|
|
|
|
|
|
2016
|
|
2015
|
|
Variance
|
|
% Change
|
|
Production:
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
3,183
|
|
|
3,156
|
|
|
27
|
|
|
1
|
%
|
|
Natural gas (MMcf)
|
11,946
|
|
|
23,738
|
|
|
(11,792
|
)
|
|
(50
|
)%
|
|
NGLs (MBbls)
|
608
|
|
|
1,477
|
|
|
(869
|
)
|
|
(59
|
)%
|
|
Oil, natural gas and NGLs (MBoe)
|
5,782
|
|
|
8,589
|
|
|
(2,807
|
)
|
|
(33
|
)%
|
|
Oil, natural gas and NGLs (MMcfe)
|
34,692
|
|
|
51,536
|
|
|
(16,844
|
)
|
|
(33
|
)%
|
|
Revenue data (in thousands):
(1)
|
|
|
|
|
|
|
|
|
Oil revenue
|
$
|
132,986
|
|
|
$
|
219,092
|
|
|
$
|
(86,106
|
)
|
|
(39
|
)%
|
|
Natural gas revenue
|
27,726
|
|
|
55,244
|
|
|
(27,518
|
)
|
|
(50
|
)%
|
|
NGLs revenue
|
8,453
|
|
|
23,399
|
|
|
(14,946
|
)
|
|
(64
|
)%
|
|
Total oil, natural gas and NGL revenue
|
$
|
169,165
|
|
|
$
|
297,735
|
|
|
$
|
(128,570
|
)
|
|
(43
|
)%
|
|
Average prices:
|
|
|
|
|
|
|
|
|
Prior to the cash settlement of effective hedging contracts
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
$
|
37.27
|
|
|
$
|
50.28
|
|
|
$
|
(13.01
|
)
|
|
(26
|
)%
|
|
Natural gas (per Mcf)
|
1.71
|
|
|
2.04
|
|
|
(0.33
|
)
|
|
(16
|
)%
|
|
NGLs (per Bbl)
|
13.90
|
|
|
15.84
|
|
|
(1.94
|
)
|
|
(12
|
)%
|
|
Oil, natural gas and NGLs (per Boe)
|
25.51
|
|
|
26.85
|
|
|
(1.34
|
)
|
|
(5
|
)%
|
|
Oil, natural gas and NGLs (per Mcfe)
|
4.25
|
|
|
4.47
|
|
|
(0.22
|
)
|
|
(5
|
)%
|
|
Including the cash settlement of effective hedging contracts
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
$
|
41.78
|
|
|
$
|
69.42
|
|
|
$
|
(27.64
|
)
|
|
(40
|
)%
|
|
Natural gas (per Mcf)
|
2.32
|
|
|
2.33
|
|
|
(0.01
|
)
|
|
—
|
%
|
|
NGLs (per Bbl)
|
13.90
|
|
|
15.84
|
|
|
(1.94
|
)
|
|
(12
|
)%
|
|
Oil, natural gas and NGLs (per Boe)
|
29.26
|
|
|
34.66
|
|
|
(5.40
|
)
|
|
(16
|
)%
|
|
Oil, natural gas and NGLs (per Mcfe)
|
4.88
|
|
|
5.78
|
|
|
(0.90
|
)
|
|
(16
|
)%
|
|
Expenses (per Mcfe):
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
$
|
1.11
|
|
|
$
|
1.07
|
|
|
$
|
0.04
|
|
|
4
|
%
|
|
Transportation, processing and gathering expenses
|
0.23
|
|
|
0.73
|
|
|
(0.50
|
)
|
|
(68
|
)%
|
|
SG&A expenses (2)
|
0.94
|
|
|
0.65
|
|
|
0.29
|
|
|
45
|
%
|
|
DD&A expense on oil and gas properties
|
3.04
|
|
|
3.14
|
|
|
(0.10
|
)
|
|
(3
|
)%
|
|
|
|
|
(1)
|
Includes the cash settlement of effective hedging contracts.
|
|
|
|
|
(2)
|
Excludes incentive compensation expense.
|
Net Loss.
During the three months ended
June 30, 2016
, we reported a net loss totaling approximately
$195.8 million
, or
$35.05
per share, compared to a net loss for the three months ended
June 30, 2015
of
$152.9 million
, or
$27.68
per share. During the
six
months ended
June 30, 2016
, we reported a net loss totaling approximately
$384.5 million
, or
$68.94
per share, compared to a net loss for the
six
months ended
June 30, 2015
of
$480.3 million
, or
$86.99
per share. All per share amounts are on a diluted basis.
We follow the full cost method of accounting for oil and gas properties. During the three months ended
June 30, 2016
and 2015, we recognized ceiling test write-downs of our U.S. oil and gas properties totaling
$118.6 million
and
$224.3 million
, respectively. During the three months ended March 31, 2016 and 2015, we recognized ceiling test write-downs of our U.S. oil and gas properties totaling
$128.9 million
and $491.4 million, respectively. During the three months ended March 31, 2016, we recognized a ceiling test write-down of our Canadian oil and gas properties, which were deemed fully impaired at the end of 2015, totaling
$0.3 million
. The write-downs did not impact our cash flows from operating activities but did reduce net income and stockholders’ equity.
The variance in the three and
six
month periods’ results was also due to the following components:
Production.
During the three months ended
June 30, 2016
, total production volumes decreased to
15.9
Bcfe compared to
26.5
Bcfe produced during the comparable
2015
period, representing a
40%
decrease. Oil production during the three months ended
June 30, 2016
totaled approximately
1,548
MBbls compared to
1,534
MBbls produced during the comparable
2015
period. Natural gas production totaled
5.1
Bcf during the three months ended
June 30, 2016
compared to
12.6
Bcf during the comparable
2015
period. NGL production during the three months ended
June 30, 2016
totaled approximately
244
MBbls compared to
794
MBbls produced during the comparable
2015
period. The decreases in natural gas and NGL production volumes during the three months ended June 30, 2016 were primarily attributable to the shut-in of production at our Mary field from September 2015 until late June 2016.
During the
six
months ended
June 30, 2016
, total production volumes decreased to
34.7
Bcfe compared to
51.5
Bcfe produced during the comparable
2015
period, representing a
33%
decrease. Oil production during the
six
months ended
June 30, 2016
totaled approximately
3,183
MBbls compared to
3,156
MBbls produced during the comparable
2015
period. Natural gas production totaled
11.9
Bcf during the
six
months ended
June 30, 2016
compared to
23.7
Bcf during the comparable
2015
period. NGL production during the
six
months ended
June 30, 2016
totaled approximately
608
MBbls compared to
1,477
MBbls produced during the comparable
2015
period. The decreases in natural gas and NGL production volumes during the six months ended June 30, 2016 were primarily attributable to the shut-in of production at our Mary field from September 2015 until late June 2016.
Prices
.
Prices realized during the three months ended
June 30, 2016
averaged
$46.97
per Bbl of oil,
$2.46
per Mcf of natural gas and
$15.24
per Bbl of NGLs, compared to average realized prices of
$72.74
per Bbl of oil,
$2.14
per Mcf of natural gas and
$13.90
per Bbl of NGLs during the comparable
2015
period. Prices realized during the
six
months ended
June 30, 2016
averaged
$41.78
per Bbl of oil,
$2.32
per Mcf of natural gas and
$13.90
per Bbl of NGLs, or
16%
lower, on an Mcfe basis, than average realized prices of
$69.42
per Bbl of oil,
$2.33
per Mcf of natural gas and
$15.84
per Bbl of NGLs during the comparable
2015
period. All unit pricing amounts include the cash settlement of effective hedging contracts.
We enter into various derivative contracts in order to reduce our exposure to the possibility of declining oil and natural gas prices. Our effective hedging transactions increased our average realized natural gas price by
$0.74
per Mcf and increased our average realized oil price by
$3.31
per Bbl during the three months ended
June 30, 2016
. During the three months ended
June 30, 2015
, our effective hedging transactions increased our average realized natural gas price by
$0.32
per Mcf and increased our average realized oil price by
$17.19
per Bbl. During the
six
months ended
June 30, 2016
, our effective hedging transactions increased our average realized natural gas price by
$0.61
per Mcf and increased our average realized oil price by
$4.51
per Bbl. During the
six
months ended
June 30, 2015
, our effective hedging transactions increased our average realized natural gas price by
$0.29
per Mcf and increased our average realized oil price by
$19.14
per Bbl.
Revenue.
Oil, natural gas and NGL revenue was
$89.0 million
during the three months ended
June 30, 2016
compared to
$149.5 million
during the comparable period of
2015
. For the
six
months ended
June 30, 2016
and 2015, oil, natural gas and NGL revenue totaled
$169.2 million
and
$297.7 million
, respectively. The decrease in total revenue for the three months ended
June 30, 2016
was primarily due to a
40%
decrease in production volumes and a
35%
decrease in average realized oil prices from the comparable period of 2015. The decrease in total revenue for the
six
months ended
June 30, 2016
was primarily due to a
33%
decrease in production volumes and a
16%
decrease in average realized prices on an equivalent basis from the comparable period of 2015.
Derivative Income/Expense.
Net derivative expense for the three months ended
June 30, 2016
totaled
$0.6 million
, comprised of
$0.2 million
of income from cash settlements and
$0.8 million
of non-cash expense resulting from changes in the fair value of unsettled derivative instruments. For the three months ended
June 30, 2015
, net derivative expense totaled
$0.7 million
, comprised of
$5.7 million
of income from cash settlements and
$6.4 million
of non-cash expense resulting from changes in the fair value of unsettled derivative instruments. Net derivative expense for the
six
months ended
June 30, 2016
totaled
$0.5 million
, comprised of
$0.5 million
of income from cash settlements and
$1.0 million
of non-cash expense resulting from changes in the fair value of unsettled derivative instruments. For the
six
months ended
June 30, 2015
, net derivative income totaled
$2.4 million
, comprised of
$10.3 million
of income from cash settlements and
$7.9 million
of non-cash expense resulting from changes in the fair value of unsettled derivative instruments.
Expenses.
Lease operating expenses during the three months ended
June 30, 2016
and
2015
totaled
$18.8 million
and
$27.4 million
, respectively. For the
six
months ended
June 30, 2016
and
2015
, lease operating expenses totaled
$38.4 million
and
$55.0 million
, respectively. The decrease in lease operating expenses during the three and
six
months ended
June 30, 2016
was primarily attributable to service cost reductions, the implementation of cost-savings measures, operating efficiencies and the shut-in of production at our Mary field from September 2015 until late June 2016. On a unit of production basis, lease operating expenses were
$1.19
per Mcfe and
$1.03
per Mcfe for the three months ended
June 30, 2016
and
2015
, respectively, and
$1.11
per Mcfe and
$1.07
per Mcfe for the
six
months ended
June 30, 2016
and
2015
, respectively. The unit cost of lease operating expenses increased during the three and six months ended June 30, 2016 from the comparable periods of 2015 as a result of decreased production volumes from Appalachia.
Transportation, processing and gathering expenses during the three months ended
June 30, 2016
and
2015
totaled
$7.2 million
and
$19.9 million
, respectively, or
$0.45
per Mcfe and
$0.75
per Mcfe, respectively. For the
six
months ended
June 30, 2016
and
2015
, transportation, processing and gathering expenses totaled
$8.0 million
and
$37.6 million
, respectively, or
$0.23
per Mcfe and
$0.73
per Mcfe, respectively. The decrease was attributable to the shut-in of production at our Mary field from September 2015 until late June 2016 as well as the recoupment of previously paid transportation costs allocable to the Federal government's portion of certain of our deep water production, which amounted to approximately $4 million.
Depreciation, depletion and amortization ("DD&A") expense on oil and gas properties for the three months ended
June 30, 2016
totaled
$45.1 million
compared to
$76.8 million
during the comparable period of
2015
. For the
six
months ended
June 30, 2016
and
2015
, DD&A expense totaled
$105.6 million
and
$162.0 million
, respectively. On a unit of production basis, DD&A expense was
$2.85
per Mcfe and
$2.89
per Mcfe during the three months ended
June 30, 2016
and
2015
, respectively. For the
six
months ended
June 30, 2016
and
2015
, DD&A expense, on a unit of production basis, was
$3.04
per Mcfe and
$3.14
per Mcfe, respectively. The decrease in DD&A during the three and
six
months ended
June 30, 2016
was primarily due to the ceiling test write-downs of our oil and gas properties.
Other operational expenses for the three months ended
June 30, 2016
and
2015
totaled
$27.7 million
and
$1.5 million
, respectively. Included in other operational expenses for the three months ended June 30, 2016 is a $20 million charge related to the termination of our deep water drilling rig contract with Ensco and approximately $7.5 million of rig subsidy and stacking charges related to the ENSCO 8503 deep water drilling rig, the Saxon Appalachian rig and the platform rig at Pompano. For the
six
months ended
June 30, 2016
and
2015
, other operational expenses totaled
$40.2 million
and
$1.2 million
, respectively. Included in other operational expenses for the six months ended June 30, 2016 is the $20 million Ensco contract termination charge, approximately $13.6 million of rig subsidy and stacking charges related to the ENSCO 8503 deep water drilling rig, the Saxon Appalachian rig and the platform rig at Pompano and a $6.0 million cumulative foreign currency translation loss on the substantial liquidation of our foreign subsidiary, Stone Energy Canada ULC, which was reclassified from accumulated other comprehensive income.
SG&A expenses (exclusive of incentive compensation) for the three months ended
June 30, 2016
were
$20.0 million
compared to
$16.4 million
for the three months ended
June 30, 2015
. For the
six
months ended
June 30, 2016
and
2015
, SG&A expenses (exclusive of incentive compensation) totaled
$32.8 million
and
$33.4 million
, respectively. On a unit of production basis, SG&A expenses were
$1.26
per Mcfe and
$0.62
per Mcfe for the three months ended
June 30, 2016
and
2015
, respectively. For the
six
months ended
June 30, 2016
and
2015
, SG&A expenses, on a unit of production basis, were
$0.94
per Mcfe and
$0.65
per Mcfe, respectively. The increase in SG&A expenses for the three months ended
June 30, 2016
was primarily attributable to legal fees pertaining to Stone's pursuit of a claim for damages against a third party, partially offset by staff and other cost reductions.
For the three and six months ended June 30, 2016, restructuring fees totaled $9.4 million and $10.4 million, respectively. These fees related to expenses supporting a restructuring effort including legal and financial advisory costs for Stone, our bank group and our noteholders.
For the three months ended
June 30, 2016
and
2015
, incentive compensation expense totaled
$4.7 million
and
$1.3 million
, respectively. For the
six
months ended
June 30, 2016
and
2015
, incentive compensation expense totaled
$9.6 million
and
$2.8 million
, respectively. The 2016 incentive compensation cash bonuses are calculated based on the achievement of certain strategic objectives for each quarter of 2016. Portions of the 2016 incentive cash bonuses replace amounts previously awarded to employees as stock-based compensation, reflected in SG&A expenses, resulting in higher incentive compensation expense in the 2016 periods as compared to the 2015 periods.
Interest expense for the three months ended
June 30, 2016
totaled
$17.6 million
, net of
$6.9 million
of capitalized interest, compared to interest expense of
$10.5 million
, net of
$10.8 million
of capitalized interest, during the comparable
2015
period. For the
six
months ended
June 30, 2016
, interest expense totaled
$32.8 million
, net of
$14.3 million
of capitalized interest, compared to interest expense of
$20.8 million
, net of
$21.6 million
of capitalized interest, during the comparable
2015
period. The increase in interest expense was primarily the result of interest expense associated with the increased borrowings under our bank credit facility and a decrease in the amount of interest capitalized to oil and gas properties.
For the
six
months ended
June 30, 2016
and
2015
, we recorded an income tax provision (benefit) of
$5.9 million
and
($265.0) million
, respectively. The income tax benefit recorded for the
six
months ended June 30, 2015 was a result of our loss before income taxes attributable to the ceiling test write-downs of our oil and gas properties. As a result of the significant declines in commodity prices and the resulting ceiling test write-downs and net losses incurred, we determined in the third quarter of 2015 that it was more likely than not that a portion of our deferred tax assets will not be realized in the future. Accordingly, we established a valuation allowance against a portion of our deferred tax assets. The change in the valuation allowance was recorded as an adjustment to income tax expense.
Off-Balance Sheet Arrangements
None.
Recent Accounting Developments
In February 2016, the FASB issued ASU 2016-02, "
Leases (Topic 842)
" to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The standard is effective for public entities for fiscal years beginning after December 15, 2018, and for interim periods within those fiscal years, with earlier application permitted. Upon adoption the lessee will apply the new standard retrospectively to all periods presented or retrospectively using a cumulative effect adjustment in the year of adoption. We are currently evaluating the effect that this new standard may have on our financial statements.
In March 2016, the FASB issued ASU 2016-09, "
Compensation – Stock Compensation (Topic 718)
" to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and forfeitures, as well as classification in the statement of cash flows. The standard is effective for public entities for fiscal years beginning after December 15, 2016, and for interim periods within those fiscal years. Early adoption is permitted for any entity in any interim or annual period. An entity that elects early adoption must adopt all of the amendments in ASU 2016-09 in the same period. We are currently evaluating the effect that this new standard may have on our financial statements, but we do not anticipate the implementation of this new standard will have a material effect.
Defined Terms
Oil, condensate and NGLs are stated in barrels (“Bbls”) or thousand barrels (“MBbls”). Natural gas is stated in billion cubic feet (“Bcf”), million cubic feet (“MMcf”) or thousand cubic feet (“Mcf”). Oil, condensate and NGLs are converted to natural gas at a ratio of one barrel of liquids per six Mcf of gas. Bcfe, MMcfe and Mcfe represent one billion cubic feet, one million cubic feet and one thousand cubic feet of gas equivalent, respectively. MMBoe and MBoe represent one million and one thousand barrels of oil equivalent, respectively. MMBtu represents one million British Thermal Units. An active property is an oil and gas property with existing production. A primary term lease is an oil and gas property with no existing production, in which we have a specific time frame to establish production without losing the rights to explore the property. Liquidity is defined as the ability to obtain cash quickly either through the conversion of assets or incurrence of liabilities.