Attached files
file | filename |
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EXCEL - IDEA: XBRL DOCUMENT - STONE ENERGY CORP | Financial_Report.xls |
EX-15.1 - EX-15.1 - STONE ENERGY CORP | h85092xexv15w1.htm |
EX-32.1 - EX-32.1 - STONE ENERGY CORP | h85092xexv32w1.htm |
EX-31.1 - EX-31.1 - STONE ENERGY CORP | h85092xexv31w1.htm |
EX-31.2 - EX-31.2 - STONE ENERGY CORP | h85092xexv31w2.htm |
Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-Q
(Mark One)
þ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended September 30, 2011
or
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number 1-12074
STONE ENERGY CORPORATION
(Exact Name of Registrant as Specified in Its Charter)
Delaware (State or Other Jurisdiction of Incorporation or Organization) |
72-1235413 (I.R.S. Employer Identification No.) |
|
625 E. Kaliste Saloom Road Lafayette, Louisiana (Address of Principal Executive Offices) |
70508 (Zip Code) |
Registrants Telephone Number, Including Area Code: (337) 237-0410
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for
such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period
that the registrant was required to submit and post such files).
Yes þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a
non-accelerated filer, or a smaller reporting company. See the definitions of large accelerated
filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act.
Large accelerated filer o | Accelerated filer þ | Non-accelerated filer o | Smaller reporting company o | |||
(Do not check if a smaller reporting company) |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act).
Yes o No þ
As of November 2, 2011, there were 48,982,571 shares of the registrants common stock, par value
$.01 per share, outstanding.
TABLE OF CONTENTS
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EX-15.1 | ||||||||
EX-31.1 | ||||||||
EX-31.2 | ||||||||
EX-32.1 | ||||||||
EX-101 INSTANCE DOCUMENT | ||||||||
EX-101 SCHEMA DOCUMENT | ||||||||
EX-101 CALCULATION LINKBASE DOCUMENT | ||||||||
EX-101 LABELS LINKBASE DOCUMENT | ||||||||
EX-101 PRESENTATION LINKBASE DOCUMENT |
Table of Contents
PART I FINANCIAL INFORMATION
Item 1. Financial Statements
STONE ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEET
(In thousands of dollars)
(In thousands of dollars)
September 30, | December 31, | |||||||
2011 | 2010 | |||||||
(Unaudited) | ||||||||
Assets |
||||||||
Current assets: |
||||||||
Cash and cash equivalents |
$ | 65,454 | $ | 106,956 | ||||
Restricted cash |
| 5,500 | ||||||
Accounts receivable |
113,547 | 88,529 | ||||||
Fair value of hedging contracts |
56,767 | 12,955 | ||||||
Current income tax receivable |
22,149 | | ||||||
Deferred taxes |
4,713 | 27,274 | ||||||
Inventory |
4,802 | 6,465 | ||||||
Other current assets |
933 | 768 | ||||||
Total current assets |
268,365 | 248,447 | ||||||
Oil and gas properties, full cost method of accounting: |
||||||||
Proved |
6,101,241 | 5,789,578 | ||||||
Less: accumulated depreciation, depletion and amortization |
(5,009,076 | ) | (4,804,949 | ) | ||||
Net proved oil and gas properties |
1,092,165 | 984,629 | ||||||
Unevaluated |
511,574 | 413,180 | ||||||
Other property and equipment, net |
11,191 | 10,722 | ||||||
Fair value of hedging contracts |
50,171 | | ||||||
Other assets, net |
23,795 | 22,112 | ||||||
Total assets |
$ | 1,957,261 | $ | 1,679,090 | ||||
Liabilities and Stockholders Equity |
||||||||
Current liabilities: |
||||||||
Accounts payable to vendors |
$ | 90,659 | $ | 103,208 | ||||
Undistributed oil and gas proceeds |
16,924 | 10,037 | ||||||
Accrued interest |
9,358 | 14,062 | ||||||
Fair value of hedging contracts |
951 | 32,144 | ||||||
Asset retirement obligations |
55,068 | 42,300 | ||||||
Current income tax payable |
| 239 | ||||||
Other current liabilities |
17,496 | 16,075 | ||||||
Total current liabilities |
190,456 | 218,065 | ||||||
Long-term debt |
575,000 | 575,000 | ||||||
Deferred taxes |
219,393 | 99,227 | ||||||
Asset retirement obligations |
289,604 | 331,620 | ||||||
Fair value of hedging contracts |
| 3,606 | ||||||
Other long-term liabilities |
19,034 | 21,215 | ||||||
Total liabilities |
1,293,487 | 1,248,733 | ||||||
Commitments and contingencies |
||||||||
Stockholders equity: |
||||||||
Common stock, $.01 par value; authorized 100,000,000 shares;
issued 48,076,951 and 47,764,505 shares, respectively |
481 | 478 | ||||||
Treasury stock (16,582 shares, respectively, at cost) |
(860 | ) | (860 | ) | ||||
Additional paid-in capital |
1,336,460 | 1,331,500 | ||||||
Accumulated deficit |
(737,748 | ) | (886,557 | ) | ||||
Accumulated other comprehensive income (loss) |
65,441 | (14,204 | ) | |||||
Total stockholders equity |
663,774 | 430,357 | ||||||
Total liabilities and stockholders equity |
$ | 1,957,261 | $ | 1,679,090 | ||||
The accompanying notes are an integral part of this statement.
1
Table of Contents
STONE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
(In thousands, except per share amounts)
(Unaudited)
(In thousands, except per share amounts)
(Unaudited)
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Operating revenue: |
||||||||||||||||
Oil production |
$ | 157,436 | $ | 97,688 | $ | 484,788 | $ | 301,412 | ||||||||
Gas production |
50,244 | 55,522 | 152,615 | 179,571 | ||||||||||||
Other operational income |
1,245 | 1,802 | 2,994 | 4,489 | ||||||||||||
Derivative income, net |
4,082 | 405 | 3,300 | 3,818 | ||||||||||||
Total operating revenue |
213,007 | 155,417 | 643,697 | 489,290 | ||||||||||||
Operating expenses: |
||||||||||||||||
Lease operating expenses |
47,767 | 36,882 | 133,307 | 112,429 | ||||||||||||
Other operational expenses |
654 | 3,003 | 1,452 | 5,450 | ||||||||||||
Production taxes |
2,492 | 1,517 | 6,828 | 4,761 | ||||||||||||
Depreciation, depletion and amortization |
64,462 | 60,482 | 204,777 | 184,900 | ||||||||||||
Accretion expense |
7,700 | 8,460 | 23,134 | 25,384 | ||||||||||||
Salaries, general and administrative expenses |
7,151 | 9,751 | 29,494 | 30,199 | ||||||||||||
Incentive compensation expense |
2,087 | 767 | 7,104 | 2,113 | ||||||||||||
Total operating expenses |
132,313 | 120,862 | 406,096 | 365,236 | ||||||||||||
Income from operations |
80,694 | 34,555 | 237,601 | 124,054 | ||||||||||||
Other (income) expenses: |
||||||||||||||||
Interest expense |
1,379 | 2,667 | 6,470 | 9,273 | ||||||||||||
Interest income |
(23 | ) | (51 | ) | (170 | ) | (1,110 | ) | ||||||||
Other income |
(372 | ) | | (1,499 | ) | (776 | ) | |||||||||
Loss on early extinguishment of debt |
| | 607 | 1,820 | ||||||||||||
Other expense |
308 | 57 | 501 | 546 | ||||||||||||
Total other expenses |
1,292 | 2,673 | 5,909 | 9,753 | ||||||||||||
Net income before income taxes |
79,402 | 31,882 | 231,692 | 114,301 | ||||||||||||
Provision (benefit) for income taxes: |
||||||||||||||||
Current |
(12,681 | ) | 10,182 | (15,043 | ) | 4,918 | ||||||||||
Deferred |
40,262 | 2,318 | 97,926 | 36,711 | ||||||||||||
Total income taxes |
27,581 | 12,500 | 82,883 | 41,629 | ||||||||||||
Net income |
$ | 51,821 | $ | 19,382 | $ | 148,809 | $ | 72,672 | ||||||||
Basic earnings per share |
$ | 1.06 | $ | 0.40 | $ | 3.04 | $ | 1.50 | ||||||||
Diluted earnings per share |
$ | 1.06 | $ | 0.40 | $ | 3.04 | $ | 1.50 | ||||||||
Average shares outstanding |
48,029 | 47,713 | 47,963 | 47,659 | ||||||||||||
Average shares outstanding assuming dilution. |
48,071 | 47,727 | 48,006 | 47,681 |
The accompanying notes are an integral part of this statement.
2
Table of Contents
STONE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
(In thousands of dollars)
(Unaudited)
(In thousands of dollars)
(Unaudited)
Nine Months Ended | ||||||||
September 30, | ||||||||
2011 | 2010 | |||||||
Cash flows from operating activities: |
||||||||
Net income |
$ | 148,809 | $ | 72,672 | ||||
Adjustments to reconcile net income to net cash provided
by operating activities: |
||||||||
Depreciation, depletion and amortization |
204,777 | 184,900 | ||||||
Accretion expense |
23,134 | 25,384 | ||||||
Deferred income tax provision |
97,926 | 36,711 | ||||||
Settlement of asset retirement obligations |
(52,543 | ) | (28,652 | ) | ||||
Non-cash stock compensation expense |
4,492 | 4,023 | ||||||
Excess tax benefits |
(1,490 | ) | (297 | ) | ||||
Non-cash derivative income |
(4,337 | ) | (1,459 | ) | ||||
Loss on early extinguishment of debt |
607 | 1,820 | ||||||
Other non-cash expense |
50 | 741 | ||||||
Change in current income taxes |
(21,710 | ) | (6,014 | ) | ||||
(Increase) decrease in accounts receivable |
(17,117 | ) | 39,569 | |||||
Increase in other current assets |
(185 | ) | (305 | ) | ||||
Decrease in inventory |
1,606 | 1,778 | ||||||
Increase (decrease) in accounts payable |
2,679 | (1,265 | ) | |||||
Increase (decrease) in other current liabilities |
3,604 | (21,401 | ) | |||||
Other |
(1,889 | ) | 1,261 | |||||
Net cash provided by operating activities |
388,413 | 309,466 | ||||||
Cash flows from investing activities: |
||||||||
Investment in oil and gas properties |
(430,711 | ) | (261,970 | ) | ||||
Proceeds from sale of oil and gas properties, net of expenses |
7,692 | 31,635 | ||||||
Investment in fixed and other assets |
(1,788 | ) | (1,722 | ) | ||||
Net cash used in investing activities |
(424,807 | ) | (232,057 | ) | ||||
Cash flows from financing activities: |
||||||||
Repayments of bank borrowings |
| (125,000 | ) | |||||
Redemption of senior subordinated notes |
| (200,503 | ) | |||||
Proceeds from issuance of senior notes |
| 275,000 | ||||||
Deferred financing costs |
(4,017 | ) | (9,766 | ) | ||||
Excess tax benefits |
1,490 | 297 | ||||||
Net payments for share based compensation |
(2,581 | ) | (1,360 | ) | ||||
Net cash used in financing activities |
(5,108 | ) | (61,332 | ) | ||||
Net increase (decrease) in cash and cash equivalents |
(41,502 | ) | 16,077 | |||||
Cash and cash equivalents, beginning of period |
106,956 | 69,293 | ||||||
Cash and cash equivalents, end of period |
$ | 65,454 | $ | 85,370 | ||||
The accompanying notes are an integral part of this statement.
3
Table of Contents
STONE ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(Unaudited)
Note 1 Interim Financial Statements
The condensed consolidated financial statements of Stone Energy Corporation (Stone) and its
subsidiaries as of September 30, 2011 and for the three and nine-month periods ended September 30,
2011 and 2010 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 at December 31, 2010 has been derived from the audited financial statements at that
date. The condensed consolidated financial statements should be read in conjunction with the
consolidated financial statements and notes thereto, together with managements discussion and
analysis of financial condition and results of operations, contained in our Annual Report on Form
10-K for the year ended December 31, 2010. The results of operations for the three and nine-month
periods ended September 30, 2011 are not necessarily indicative of future financial results.
Certain 2010 amounts have been changed from amounts originally presented to correct a prior period
immaterial error.
Note 2 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 | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
(in thousands, except per share data) | ||||||||||||||||
Income (numerator): |
||||||||||||||||
Basic: |
||||||||||||||||
Net income |
$ | 51,821 | $ | 19,382 | $ | 148,809 | $ | 72,672 | ||||||||
Net income attributable to participating securities |
(976 | ) | (315 | ) | (2,807 | ) | (1,181 | ) | ||||||||
Net income attributable to common stock basic |
$ | 50,845 | $ | 19,067 | $ | 146,002 | $ | 71,491 | ||||||||
Diluted: |
||||||||||||||||
Net income |
$ | 51,821 | $ | 19,382 | $ | 148,809 | $ | 72,672 | ||||||||
Net income attributable to participating securities |
(975 | ) | (314 | ) | (2,805 | ) | (1,180 | ) | ||||||||
Net income attributable to common stock diluted |
$ | 50,846 | $ | 19,068 | $ | 146,004 | $ | 71,492 | ||||||||
Weighted average shares (denominator): |
||||||||||||||||
Weighted average shares basic |
48,029 | 47,713 | 47,963 | 47,659 | ||||||||||||
Diluted effect of stock options |
42 | 14 | 43 | 22 | ||||||||||||
Weighted average shares diluted |
48,071 | 47,727 | 48,006 | 47,681 | ||||||||||||
Basic income per common share |
$ | 1.06 | $ | 0.40 | $ | 3.04 | $ | 1.50 | ||||||||
Diluted income per common share |
$ | 1.06 | $ | 0.40 | $ | 3.04 | $ | 1.50 | ||||||||
Stock options that were considered antidilutive because the exercise price of the option
exceeded the average price of our common stock for the applicable period totaled approximately
376,000 and 422,000 shares for the three months ended September 30, 2011 and 2010, respectively.
Stock options that were considered antidilutive totaled approximately 376,000 and 422,000 shares
during the nine months ended September 30, 2011 and 2010, respectively.
During each of the three-month periods ended September 30, 2011 and 2010, approximately 59,000
shares of common stock were issued upon the vesting of restricted stock by employees and
nonemployee directors. During the nine months ended September 30, 2011 and 2010, approximately
312,000 and 254,000 shares of common stock, respectively, were issued upon the vesting of
restricted stock by employees and nonemployee directors.
4
Table of Contents
Note 3 Derivative Instruments and Hedging Activities
Our hedging strategy is designed to protect our near and intermediate term cash flow 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 hedging transactions to secure a
commodity price for a portion of future production that is acceptable at the time of the
transaction. These hedges are designated as cash flow hedges upon entering into the contract. We
do not enter into hedging transactions for trading purposes. We have no fair value hedges.
The nature of a derivative instrument must be evaluated to determine if it qualifies for hedge
accounting treatment. If the instrument qualifies for hedge accounting treatment, it is recorded
as either an asset or liability measured at fair value and subsequent changes in the derivatives
fair value are recognized in equity through other comprehensive income (loss), net of related
taxes, to the extent the hedge is considered effective. Additionally, monthly settlements of
effective hedges are reflected in revenue from oil and gas production and cash flows from
operations. Instruments not qualifying for hedge accounting are recorded in the balance sheet at
fair value and changes in fair value are recognized in earnings through derivative expense
(income). Typically, a small portion of our derivative contracts are determined to be ineffective.
This is 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
contracts. Monthly settlements of ineffective hedges are recognized in earnings through derivative
expense (income) and cash flows from operations.
We have entered into fixed-price swaps with various counterparties for a portion of our
expected 2011, 2012, 2013 and 2014 oil and natural gas production from the Gulf Coast Basin. Some
of our fixed-price oil swap settlements are based upon an average of the New York Mercantile
Exchange (NYMEX) closing price for West Texas Intermediate (WTI) during the entire calendar
month and some are based on the average of the Intercontinental Exchange (ICE) closing price for
Brent 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 month. Swaps typically provide for monthly
payments by us if prices rise above the swap price or to us if prices fall below the swap price.
Our fixed-price swap contracts for 2011, 2012, 2013 and 2014 are with J.P. Morgan Chase Bank, N.A.,
The Toronto-Dominion Bank, Barclays Bank PLC, BNP Paribas, The Bank of Nova Scotia, Bank of America
and Natixis.
All of our derivative instruments at September 30, 2011 and December 31, 2010 were designated
as effective cash flow hedges; however, during the nine-month periods ended September 30, 2011 and
2010, certain of our derivative contracts were determined to be partially ineffective. The
following tables disclose the location and fair value amounts of derivative instruments reported in
our balance sheet at September 30, 2011 and December 31, 2010.
Fair Value of Derivative Instruments at September 30, 2011
(in millions)
(in millions)
Asset Derivatives | Liability Derivatives | |||||||||||
Description | Balance Sheet Location | Fair Value | Balance Sheet Location | Fair Value | ||||||||
Commodity contracts
|
Current assets: Fair value of hedging contracts | $ | 56.8 | Current liabilities: Fair value of hedging contracts | ($1.0 | ) | ||||||
Long-term assets: Fair value of hedging contracts | 50.2 | Long-term liabilities: Fair value of hedging contracts | | |||||||||
$ | 107.0 | ($1.0 | ) | |||||||||
Fair Value of Derivative Instruments at December 31, 2010
(in millions)
(in millions)
Asset Derivatives | Liability Derivatives | |||||||||||
Description | Balance Sheet Location | Fair Value | Balance Sheet Location | Fair Value | ||||||||
Commodity contracts
|
Current assets: Fair value of hedging contracts | $ | 13.0 | Current liabilities: Fair value of hedging contracts | ($32.1 | ) | ||||||
Long-term assets: Fair value of hedging contracts | | Long-term liabilities: Fair value of hedging contracts | (3.6 | ) | ||||||||
$ | 13.0 | ($35.7 | ) | |||||||||
5
Table of Contents
The following tables disclose the effect of derivative instruments in the statement of
operations for the three and nine-month periods ended September 30, 2011 and 2010.
The Effect of Derivative Instruments on the Statement of Operations for the Three Months Ended September 30, 2011 and 2010
(in millions)
(in millions)
Amount of Gain | ||||||||||||||||||||||||||||||||
Derivatives in | (Loss) Recognized | Gain Reclassified from | Gain Recognized in Income | |||||||||||||||||||||||||||||
Cash Flow Hedging | in OCI on | Accumulated OCI into Income | on Derivatives | |||||||||||||||||||||||||||||
Relationships | Derivatives (a) | (Effective Portion) (b) | (Ineffective Portion) | |||||||||||||||||||||||||||||
2011 | 2010 | Location | 2011 | 2010 | Location | 2011 | 2010 | |||||||||||||||||||||||||
Operating revenue - | ||||||||||||||||||||||||||||||||
Commodity contracts |
$ | 76.0 | ($6.5 | ) | oil/gas production | $ | 1.3 | $ | 6.0 | Derivative income, net | $ | 4.1 | $ | 0.4 | ||||||||||||||||||
Total |
$ | 76.0 | ($6.5 | ) | $ | 1.3 | $ | 6.0 | $ | 4.1 | $ | 0.4 | ||||||||||||||||||||
(a) | Net of related tax effect. | |
(b) | For the three months ended September 30, 2011, effective hedging contracts decreased oil revenue by $3.3 million and increased gas revenue by $4.6 million. For the three months ended September 30, 2010, effective hedging contracts decreased oil revenue by $3.7 million and increased gas revenue by $9.7 million. |
The Effect of Derivative Instruments on the Statement of Operations for the Nine Months Ended September 30, 2011 and 2010
(in millions)
(in millions)
Amount of Gain | ||||||||||||||||||||||||||||||||
Derivatives in | (Loss) Recognized | Gain Reclassified from | Gain Recognized in Income | |||||||||||||||||||||||||||||
Cash Flow Hedging | in OCI on | Accumulated OCI into Income | on Derivatives | |||||||||||||||||||||||||||||
Relationships | Derivatives (a) | (Effective Portion) (b) | (Ineffective Portion) | |||||||||||||||||||||||||||||
2011 | 2010 | Location | 2011 | 2010 | Location | 2011 | 2010 | |||||||||||||||||||||||||
Operating revenue - | ||||||||||||||||||||||||||||||||
Commodity contracts |
$ | 79.6 | $ | 21.6 | oil/gas production | ($13.1 | ) | $ | 8.2 | Derivative income, net | $ | 3.3 | $ | 3.8 | ||||||||||||||||||
Total |
$ | 79.6 | $ | 21.6 | ($13.1 | ) | $ | 8.2 | $ | 3.3 | $ | 3.8 | ||||||||||||||||||||
(a) | Net of related tax effect. | |
(b) | For the nine months ended September 30, 2011, effective hedging contracts decreased oil revenue by $26.1 million and increased gas revenue by $13.0 million. For the nine months ended September 30, 2010, effective hedging contracts decreased oil revenue by $17.8 million and increased gas revenue by $26.0 million. |
At September 30, 2011, we had accumulated other comprehensive income of $65.4 million,
net of tax, which related to the fair value of our swap contracts that were outstanding as of
September 30, 2011. We believe that approximately $32.3 million of the accumulated other
comprehensive income will be reclassified into earnings in the next twelve months.
6
Table of Contents
The following table illustrates our hedging positions for calendar years 2011, 2012, 2013 and
2014 as of November 2, 2011:
Fixed-Price Swaps | ||||||||||||||||
NYMEX (except where noted) | ||||||||||||||||
Natural Gas | Oil | |||||||||||||||
Daily Volume | Swap | Daily Volume | Swap | |||||||||||||
(MMBtus/d) | Price | (Bbls/d) | Price | |||||||||||||
2011 |
10,000 | (a) | $ | 4.565 | 1,000 | $ | 70.05 | |||||||||
2011 |
20,000 | 5.200 | 1,000 | 78.20 | ||||||||||||
2011 |
10,000 | 6.830 | 1,000 | 80.20 | ||||||||||||
2011 |
1,000 | 83.00 | ||||||||||||||
2011 |
1,000 | 83.05 | ||||||||||||||
2011 |
1,000 | (b) | 85.20 | |||||||||||||
2011 |
1,000 | 85.25 | ||||||||||||||
2011 |
1,000 | 89.00 | ||||||||||||||
2011 |
1,000 | (c) | 97.75 | |||||||||||||
2011 |
1,000 | (c) | 104.30 | |||||||||||||
2012 |
10,000 | 5.035 | 1,000 | 90.30 | ||||||||||||
2012 |
10,000 | 5.040 | 1,000 | 90.41 | ||||||||||||
2012 |
10,000 | 5.050 | 1,000 | 90.45 | ||||||||||||
2012 |
1,000 | 95.50 | ||||||||||||||
2012 |
1,000 | 97.60 | ||||||||||||||
2012 |
1,000 | 100.00 | ||||||||||||||
2012 |
1,000 | 101.55 | ||||||||||||||
2012 |
1,000 | 104.25 | ||||||||||||||
2012 |
1,000 | | 111.02 | |||||||||||||
2013 |
10,000 | 5.270 | 1,000 | 97.15 | ||||||||||||
2013 |
10,000 | 5.320 | 1,000 | 101.53 | ||||||||||||
2013 |
1,000 | 103.00 | ||||||||||||||
2013 |
1,000 | 104.50 | ||||||||||||||
2013 |
1,000 | | 107.30 | |||||||||||||
2014 |
1,000 | | 103.30 | |||||||||||||
(a) | February December | |
(b) | January June | |
(c) | July December | |
| Brent oil contract |
Note 4 Long-Term Debt
Long-term debt consisted of the following at:
September 30, | December 31, | ||||||||
2011 | 2010 | ||||||||
(in millions) | |||||||||
63/4% Senior Subordinated Notes due 2014 |
$ | 200.0 | $ | 200.0 | |||||
85/8% Senior Notes due 2017 |
375.0 | 375.0 | |||||||
Bank debt |
| | |||||||
Total long-term debt |
$ | 575.0 | $ | 575.0 | |||||
On September 30, 2011, we had no outstanding borrowings under our bank credit facility and
letters of credit totaling $61.1 million had been issued pursuant to the facility. On April 26,
2011, we entered into an amended and restated revolving credit facility totaling $700 million
through a syndicated bank group, replacing our previous $700 million facility. The new credit
facility matures on September 15, 2014. However, if the notes issued under our 2004 indenture are
retired on or before April 15, 2014, the new credit facility then matures on April 26, 2015. Our
initial borrowing base under the new credit facility was set at $400 million. On October 31, 2011,
the bank group reaffirmed the existing borrowing base at $400 million. As of November 2, 2011, we
had no outstanding borrowings under our bank credit facility and letters of credit totaling $61.1
million had been issued pursuant to the facility, leaving $338.9 million of availability under the
facility. Our bank credit facility is guaranteed by our
only material subsidiary, Stone Energy Offshore, L.L.C. (Stone Offshore).
7
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The borrowing base under our bank credit facility is redetermined by the lenders
semi-annually, typically on May 1 and November 1, taking into consideration the estimated value of
our oil and gas properties and those of our direct and indirect material subsidiaries 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. Our bank credit facility is collateralized by substantially all
of Stones and Stone Offshores assets. Stone and Stone Offshore are required to mortgage, and
grant a security interest in, their oil and gas reserves representing at least 80% of the
discounted present value of the future net cash flows from their oil and gas reserves reviewed in
determining the borrowing base. At our option, loans under our bank credit facility will bear
interest at a rate based on the adjusted Libor Rate plus an applicable margin, or a rate based on
the prime rate or Federal funds rate plus an applicable margin. Our bank credit facility provides
for optional and mandatory prepayments, affirmative and negative covenants, and interest coverage
ratio and leverage ratio maintenance covenants. We were in compliance with all covenants as of
September 30, 2011.
Note 5 Comprehensive Income
The following table illustrates the components of comprehensive income for the three and
nine-month periods ended September 30, 2011 and 2010:
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
(in millions) | ||||||||||||||||
Net income |
$ | 51.8 | $ | 19.4 | $ | 148.8 | $ | 72.7 | ||||||||
Other comprehensive income (loss), net of tax effect: |
||||||||||||||||
Adjustment for fair value accounting of derivatives |
76.0 | (6.5 | ) | 79.6 | 21.6 | |||||||||||
Comprehensive income |
$ | 127.8 | $ | 12.9 | $ | 228.4 | $ | 94.3 | ||||||||
Note 6 Asset Retirement Obligations
The change in our asset retirement obligations during the nine months ended September 30, 2011
is set forth below:
Nine Months | ||||
Ended | ||||
September 30, 2011 | ||||
(in millions) | ||||
Asset retirement obligations as of the beginning of the period, including current portion |
$ | 373.9 | ||
Liabilities settled |
(51.5 | ) | ||
Divestment of properties |
(0.8 | ) | ||
Accretion expense |
23.1 | |||
Asset retirement obligations as of the end of the period, including current portion |
$ | 344.7 | ||
In October 2010, we received notification from the Bureau of Ocean Energy Management,
Regulation and Enforcement (BOEMRE) indicating that certain identified wells and facilities
operated by us would need to be retired on a timing schedule which was accelerated from the timing
estimated in calculating liabilities for asset retirement obligations at December 31, 2009. In
February 2011, we submitted an abandonment plan addressing the identified wells and facilities.
The successor to the BOEMRE in this matter, the Bureau of Safety and Environmental Enforcement
(BSEE), indicated it will issue a final order following its review of the plan. During 2010, we
increased our asset retirement obligations in the amount of $54.4 million for the estimated impact
of the accelerated timing of the retirement of these assets and other factors. The final order,
expected to be issued by the BSEE, will ultimately determine the impact on our asset retirement
obligations and could result in additional upward or downward revisions.
Note 7 Fair Value Measurements
U.S. Generally Accepted Accounting Principles establish a fair value hierarchy which 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.
8
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As of September 30, 2011 and December 31, 2010, we held certain financial assets and
liabilities that are required to be measured at fair value on a recurring basis, including our
commodity derivative instruments and our investments in money market funds. 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. For a more detailed
description of our derivative instruments, see Note 3 Derivative Instruments and Hedging
Activities. We used the market approach in determining the fair value of our investments in money
market funds, which are included within the Level 1 fair value hierarchy.
The following tables present our assets and liabilities that are measured at fair value on a
recurring basis at September 30, 2011:
Fair Value Measurements at September 30, 2011 | ||||||||||||||||
Quoted Prices in | ||||||||||||||||
Active Markets for | Significant Other | Significant | ||||||||||||||
Identical Assets | Observable Inputs | Unobservable Inputs | ||||||||||||||
Assets | Total | (Level 1) | (Level 2) | (Level 3) | ||||||||||||
(in millions) | ||||||||||||||||
Money market funds |
$ | 5.3 | $ | 5.3 | $ | | $ | | ||||||||
Hedging contracts |
106.9 | | 106.9 | | ||||||||||||
Total |
$ | 112.2 | $ | 5.3 | $ | 106.9 | $ | | ||||||||
Fair Value Measurements at September 30, 2011 | ||||||||||||||||
Quoted Prices | ||||||||||||||||
in Active Markets | ||||||||||||||||
for Identical | Significant Other | Significant | ||||||||||||||
Liabilities | Observable Inputs | Unobservable Inputs | ||||||||||||||
Liabilities | Total | (Level 1) | (Level 2) | (Level 3) | ||||||||||||
(in millions) | ||||||||||||||||
Hedging contracts |
($1.0 | ) | $ | | ($1.0 | ) | $ | | ||||||||
Total |
($1.0 | ) | $ | | ($1.0 | ) | $ | | ||||||||
The following tables present our assets and liabilities that are measured at fair value on a
recurring basis at December 31, 2010:
Fair Value Measurements at December 31, 2010 | ||||||||||||||||
Quoted Prices in | ||||||||||||||||
Active Markets for | Significant Other | Significant | ||||||||||||||
Identical Assets | Observable Inputs | Unobservable Inputs | ||||||||||||||
Assets | Total | (Level 1) | (Level 2) | (Level 3) | ||||||||||||
(in millions) | ||||||||||||||||
Money market funds |
$ | 7.3 | $ | 7.3 | $ | | $ | | ||||||||
Hedging contracts |
13.0 | | 13.0 | | ||||||||||||
Total |
$ | 20.3 | $ | 7.3 | $ | 13.0 | $ | | ||||||||
Fair Value Measurements at December 31, 2010 | ||||||||||||||||
Quoted Prices | ||||||||||||||||
in Active Markets | ||||||||||||||||
for Identical | Significant Other | Significant | ||||||||||||||
Liabilities | Observable Inputs | Unobservable Inputs | ||||||||||||||
Liabilities | Total | (Level 1) | (Level 2) | (Level 3) | ||||||||||||
(in millions) | ||||||||||||||||
Hedging contracts |
($35.7 | ) | $ | | ($35.7 | ) | $ | | ||||||||
Total |
($35.7 | ) | $ | | ($35.7 | ) | $ | | ||||||||
The fair value of cash and cash equivalents approximated book value at September 30, 2011 and
December 31, 2010. As of September 30, 2011 and December 31, 2010, the fair value of our $375
million 85/8% Senior Notes due 2017 was
9
Table of Contents
approximately $363.8 million and $380.6 million,
respectively. As of September 30, 2011 and December 31, 2010, the fair
value of our $200 million 63/4% Senior Subordinated Notes due 2014 was approximately $196.0
million and $197.0 million, respectively. The fair value of our outstanding notes was determined
based upon quotes obtained from brokers.
Note 8 Commitments and Contingencies
We are named as a defendant in certain lawsuits and are a party to certain regulatory
proceedings arising in the ordinary course of business. We do not expect these matters,
individually or in the aggregate, will have a material adverse effect on our financial condition.
Franchise Tax Action. We have been served with several petitions filed by the Louisiana
Department of Revenue (LDR) in Louisiana state court claiming additional franchise taxes due. In
addition, we have received preliminary assessments from the LDR for additional franchise taxes
resulting from audits of Stone and our subsidiaries. These assessments all relate to the LDRs
assertion that sales of crude oil and natural gas from properties located on the Outer Continental
Shelf, which are transported through the state of Louisiana, should be sourced to the state of
Louisiana for purposes of computing the Louisiana franchise tax apportionment ratio. Total
asserted claims plus estimated accrued interest amount to approximately $29.7 million. The
franchise tax year 2010 for Stone remains subject to examination, which potentially exposes us to
additional estimated assessments of $0.8 million including accrued interest.
Lafourche Parish, Louisiana, Landowner Action. In December 2008, Stephen E. Coignet, et al.,
filed civil action No. 110741 in the 17th Judicial District Court, Lafourche Parish,
Louisiana, against Stone. Plaintiffs have since filed three supplemental petitions, including a
third supplemental and restated petition on October 25, 2010. Plaintiffs are landowners of
approximately sixty acres that are subject to mineral leases in favor of Stone. Plaintiffs alleged
that Stone conducted its mineral operations imprudently resulting in damages to plaintiffs. The
Company disagreed with plaintiffs contentions. In October 2011, the parties agreed to a
settlement of all claims asserted in this action, and we anticipate that the settlement will be
effected not later than January 2012. The settlement was accrued in the current period financial
statements, which did not have a material impact on our financial position or results of operations.
Note 9 Subsequent Event
On October 28, 2011 we entered into a definitive agreement to sell our interest in one of our
offshore Gulf of Mexico fields to an unrelated third party for approximately $80 million. The sale
will be accounted for as an adjustment to our net full cost pool with no gain or loss recognized
since the adjustment is not expected to significantly alter the relationship between capitalized
costs and proved reserves.
10
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Note 10 Guarantor Financial Statements
Stone Offshore is an unconditional guarantor (the Guarantor Subsidiary) of our 63/4% Senior
Subordinated Notes due 2014 and our 85/8% Senior Notes due 2017. Our remaining subsidiaries (the
Non-Guarantor Subsidiaries) have not provided guarantees. The following presents condensed
consolidating financial information as of September 30, 2011 and December 31, 2010 and for the
three and nine-month periods ended September 30, 2011 and 2010 on an issuer (parent company),
guarantor subsidiary, non-guarantor subsidiaries, and consolidated basis. Elimination entries
presented are necessary to combine the entities.
CONDENSED CONSOLIDATING BALANCE SHEET (UNAUDITED)
SEPTEMBER 30, 2011
(In thousands of dollars)
SEPTEMBER 30, 2011
(In thousands of dollars)
Non- | ||||||||||||||||||||
Guarantor | Guarantor | |||||||||||||||||||
Parent | Subsidiary | Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
Assets |
||||||||||||||||||||
Current assets: |
||||||||||||||||||||
Cash and cash equivalents |
$ | 64,426 | $ | 915 | $ | 113 | $ | | $ | 65,454 | ||||||||||
Accounts receivable |
78,421 | 69,702 | 1,226 | (35,802 | ) | 113,547 | ||||||||||||||
Fair value of hedging contracts |
| 56,767 | | | 56,767 | |||||||||||||||
Current income tax receivable |
19,796 | 2,353 | | | 22,149 | |||||||||||||||
Deferred taxes * |
4,684 | 29 | | | 4,713 | |||||||||||||||
Inventory |
4,519 | 283 | | | 4,802 | |||||||||||||||
Other current assets |
933 | | | | 933 | |||||||||||||||
Total current assets |
172,779 | 130,049 | 1,339 | (35,802 | ) | 268,365 | ||||||||||||||
Oil and gas properties, full cost method: |
||||||||||||||||||||
Proved, net |
239,458 | 849,496 | 3,211 | | 1,092,165 | |||||||||||||||
Unevaluated |
305,945 | 205,629 | | | 511,574 | |||||||||||||||
Other property and equipment, net |
11,191 | | | | 11,191 | |||||||||||||||
Fair value of hedging contracts |
| 50,171 | | | 50,171 | |||||||||||||||
Other assets, net |
23,795 | | | | 23,795 | |||||||||||||||
Investment in subsidiary |
668,677 | 2,347 | | (671,024 | ) | | ||||||||||||||
Total assets |
$ | 1,421,845 | $ | 1,237,692 | $ | 4,550 | ($706,826 | ) | $ | 1,957,261 | ||||||||||
Liabilities and Stockholders Equity |
||||||||||||||||||||
Current liabilities: |
||||||||||||||||||||
Accounts payable to vendors |
$ | 75,576 | $ | 50,885 | $ | | ($35,802 | ) | $ | 90,659 | ||||||||||
Undistributed oil and gas proceeds |
15,609 | 1,315 | | | 16,924 | |||||||||||||||
Accrued interest |
9,358 | | | | 9,358 | |||||||||||||||
Fair value of hedging contracts |
| 951 | | | 951 | |||||||||||||||
Asset retirement obligations |
| 55,068 | | | 55,068 | |||||||||||||||
Other current liabilities |
15,786 | 1,710 | | | 17,496 | |||||||||||||||
Total current liabilities |
116,329 | 109,929 | | (35,802 | ) | 190,456 | ||||||||||||||
Long-term debt |
575,000 | | | | 575,000 | |||||||||||||||
Deferred taxes * |
54,226 | 165,167 | | | 219,393 | |||||||||||||||
Asset retirement obligations |
194 | 284,721 | 4,689 | | 289,604 | |||||||||||||||
Other long-term liabilities |
12,322 | 6,712 | | | 19,034 | |||||||||||||||
Total liabilities |
758,071 | 566,529 | 4,689 | (35,802 | ) | 1,293,487 | ||||||||||||||
Commitments and contingencies |
||||||||||||||||||||
Stockholders equity: |
||||||||||||||||||||
Common stock |
481 | | | | 481 | |||||||||||||||
Treasury stock |
(860 | ) | | | | (860 | ) | |||||||||||||
Additional paid-in capital |
1,336,460 | 1,673,597 | 1,639 | (1,675,236 | ) | 1,336,460 | ||||||||||||||
Accumulated earnings (deficit) |
(737,748 | ) | (1,067,875 | ) | (1,778 | ) | 1,069,653 | (737,748 | ) | |||||||||||
Accumulated other comprehensive income (loss). |
65,441 | 65,441 | | (65,441 | ) | 65,441 | ||||||||||||||
Total stockholders equity |
663,774 | 671,163 | (139 | ) | (671,024 | ) | 663,774 | |||||||||||||
Total liabilities and stockholders equity |
$ | 1,421,845 | $ | 1,237,692 | $ | 4,550 | ($706,826 | ) | $ | 1,957,261 | ||||||||||
* | Deferred income taxes have been allocated to guarantor subsidiary where related oil and gas properties reside. |
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CONDENSED CONSOLIDATING BALANCE SHEET (UNAUDITED)
DECEMBER 31, 2010
(In thousands of dollars)
DECEMBER 31, 2010
(In thousands of dollars)
Non- | ||||||||||||||||||||
Guarantor | Guarantor | |||||||||||||||||||
Parent | Subsidiary | Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
Assets |
||||||||||||||||||||
Current assets: |
||||||||||||||||||||
Cash and cash equivalents |
$ | 105,115 | $ | 1,659 | $ | 182 | $ | | $ | 106,956 | ||||||||||
Restricted cash |
5,500 | | | | 5,500 | |||||||||||||||
Accounts receivable |
26,760 | 61,560 | 902 | (693 | ) | 88,529 | ||||||||||||||
Fair value of hedging contracts |
12,955 | | | | 12,955 | |||||||||||||||
Deferred taxes * |
27,274 | | | | 27,274 | |||||||||||||||
Inventory |
6,168 | 297 | | | 6,465 | |||||||||||||||
Other current assets |
753 | 15 | | | 768 | |||||||||||||||
Total current assets |
184,525 | 63,531 | 1,084 | (693 | ) | 248,447 | ||||||||||||||
Oil and gas properties, full cost method: |
||||||||||||||||||||
Proved, net |
260,434 | 720,309 | 3,886 | | 984,629 | |||||||||||||||
Unevaluated |
337,725 | 75,455 | | | 413,180 | |||||||||||||||
Other property and equipment, net |
10,722 | | | | 10,722 | |||||||||||||||
Other assets, net |
22,112 | | | | 22,112 | |||||||||||||||
Investment in subsidiary |
427,273 | 1,561 | | (428,834 | ) | | ||||||||||||||
Total assets |
$ | 1,242,791 | $ | 860,856 | $ | 4,970 | ($429,527 | ) | $ | 1,679,090 | ||||||||||
Liabilities and Stockholders Equity |
||||||||||||||||||||
Current liabilities: |
||||||||||||||||||||
Accounts payable to vendors |
$ | 60,019 | $ | 43,881 | $ | | ($692 | ) | $ | 103,208 | ||||||||||
Undistributed oil and gas proceeds |
9,491 | 546 | | | 10,037 | |||||||||||||||
Accrued interest |
14,062 | | | | 14,062 | |||||||||||||||
Fair value of hedging contracts |
32,144 | | | | 32,144 | |||||||||||||||
Asset retirement obligations |
| 42,300 | | | 42,300 | |||||||||||||||
Current income tax payable |
239 | | | | 239 | |||||||||||||||
Other current liabilities |
16,075 | | | | 16,075 | |||||||||||||||
Total current liabilities |
132,030 | 86,727 | | (692 | ) | 218,065 | ||||||||||||||
Long-term debt |
575,000 | | | | 575,000 | |||||||||||||||
Deferred taxes * |
(41,804 | ) | 141,031 | | | 99,227 | ||||||||||||||
Asset retirement obligations |
129,100 | 198,105 | 4,415 | | 331,620 | |||||||||||||||
Fair value of hedging contracts |
3,606 | | | | 3,606 | |||||||||||||||
Other long-term liabilities |
14,502 | 6,713 | | | 21,215 | |||||||||||||||
Total liabilities |
812,434 | 432,576 | 4,415 | (692 | ) | 1,248,733 | ||||||||||||||
Commitments and contingencies |
||||||||||||||||||||
Stockholders equity: |
||||||||||||||||||||
Common stock |
478 | | | | 478 | |||||||||||||||
Treasury stock |
(860 | ) | | | | (860 | ) | |||||||||||||
Additional paid-in capital |
1,331,500 | 1,673,598 | 1,640 | (1,675,238 | ) | 1,331,500 | ||||||||||||||
Accumulated earnings (deficit) |
(886,557 | ) | (1,245,318 | ) | (1,085 | ) | 1,246,403 | (886,557 | ) | |||||||||||
Accumulated other comprehensive loss |
(14,204 | ) | | | | (14,204 | ) | |||||||||||||
Total stockholders equity |
430,357 | 428,280 | 555 | (428,835 | ) | 430,357 | ||||||||||||||
Total liabilities and stockholders equity |
$ | 1,242,791 | $ | 860,856 | $ | 4,970 | ($429,527 | ) | $ | 1,679,090 | ||||||||||
* | Deferred income taxes have been allocated to guarantor subsidiary where related oil and gas properties reside. |
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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS (UNAUDITED)
THREE MONTHS ENDED SEPTEMBER 30, 2011
(In thousands of dollars)
THREE MONTHS ENDED SEPTEMBER 30, 2011
(In thousands of dollars)
Non- | ||||||||||||||||||||
Guarantor | Guarantor | |||||||||||||||||||
Parent | Subsidiary | Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
Operating revenue: |
||||||||||||||||||||
Oil production |
$ | 1,248 | $ | 156,188 | $ | | $ | | $ | 157,436 | ||||||||||
Gas production |
6,772 | 43,472 | | | 50,244 | |||||||||||||||
Other operational income |
1,050 | 94 | 101 | | 1,245 | |||||||||||||||
Derivative income, net |
| 4,082 | | | 4,082 | |||||||||||||||
Total operating revenue |
9,070 | 203,836 | 101 | | 213,007 | |||||||||||||||
Operating expenses: |
||||||||||||||||||||
Lease operating expenses |
1,716 | 45,858 | 193 | | 47,767 | |||||||||||||||
Other operational expense |
622 | 32 | | | 654 | |||||||||||||||
Production taxes |
422 | 2,070 | | | 2,492 | |||||||||||||||
Depreciation, depletion, amortization |
5,615 | 58,630 | 217 | | 64,462 | |||||||||||||||
Accretion expense |
3 | 7,605 | 92 | | 7,700 | |||||||||||||||
Salaries, general and administrative |
7,193 | (43 | ) | 1 | | 7,151 | ||||||||||||||
Incentive compensation expense |
2,087 | | | | 2,087 | |||||||||||||||
Total operating expenses |
17,658 | 114,152 | 503 | | 132,313 | |||||||||||||||
Income (loss) from operations |
(8,588 | ) | 89,684 | (402 | ) | | 80,694 | |||||||||||||
Other (income) expenses: |
||||||||||||||||||||
Interest expense |
1,305 | 74 | | | 1,379 | |||||||||||||||
Interest income |
(23 | ) | | | | (23 | ) | |||||||||||||
Other (income) expense, net |
302 | (366 | ) | | | (64 | ) | |||||||||||||
(Income) loss from investment in subsidiaries |
(60,498 | ) | 401 | | 60,097 | | ||||||||||||||
Total other (income) expenses |
(58,914 | ) | 109 | | 60,097 | 1,292 | ||||||||||||||
Income (loss) before taxes |
50,326 | 89,575 | (402 | ) | (60,097 | ) | 79,402 | |||||||||||||
Provision (benefit) for income taxes: |
||||||||||||||||||||
Current |
(12,681 | ) | | | | (12,681 | ) | |||||||||||||
Deferred |
11,186 | 29,076 | | | 40,262 | |||||||||||||||
Total income taxes |
(1,495 | ) | 29,076 | | | 27,581 | ||||||||||||||
Net income (loss) |
$ | 51,821 | $ | 60,499 | ($402 | ) | ($60,097 | ) | $ | 51,821 | ||||||||||
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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS (UNAUDITED)
THREE MONTHS ENDED SEPTEMBER 30, 2010
(In thousands of dollars)
THREE MONTHS ENDED SEPTEMBER 30, 2010
(In thousands of dollars)
Non- | ||||||||||||||||||||
Guarantor | Guarantor | |||||||||||||||||||
Parent | Subsidiary | Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
Operating revenue: |
||||||||||||||||||||
Oil production |
$ | 16,653 | $ | 81,035 | $ | | $ | | $ | 97,688 | ||||||||||
Gas production |
14,742 | 40,780 | | | 55,522 | |||||||||||||||
Other operational income |
1,509 | | 293 | | 1,802 | |||||||||||||||
Derivative income, net |
405 | | | | 405 | |||||||||||||||
Total operating revenue |
33,309 | 121,815 | 293 | | 155,417 | |||||||||||||||
Operating expenses: |
||||||||||||||||||||
Lease operating expenses |
19,865 | 17,017 | | | 36,882 | |||||||||||||||
Other operational expense |
698 | 2,305 | | | 3,003 | |||||||||||||||
Production taxes |
1,172 | 345 | | | 1,517 | |||||||||||||||
Depreciation, depletion, amortization |
10,824 | 49,418 | 240 | | 60,482 | |||||||||||||||
Accretion expense |
3,624 | 4,725 | 111 | | 8,460 | |||||||||||||||
Salaries, general and administrative |
9,742 | 8 | 1 | | 9,751 | |||||||||||||||
Incentive compensation expense |
767 | | | | 767 | |||||||||||||||
Total operating expenses |
46,692 | 73,818 | 352 | | 120,862 | |||||||||||||||
Income (loss) from operations |
(13,383 | ) | 47,997 | (59 | ) | | 34,555 | |||||||||||||
Other (income) expenses: |
||||||||||||||||||||
Interest expense |
2,654 | 13 | | | 2,667 | |||||||||||||||
Interest income |
(49 | ) | (2 | ) | | | (51 | ) | ||||||||||||
Other (income) expense, net |
73 | (16 | ) | | | 57 | ||||||||||||||
(Income) loss from investment in subsidiaries |
(29,671 | ) | 59 | | 29,612 | | ||||||||||||||
Total other (income) expenses |
(26,993 | ) | 54 | | 29,612 | 2,673 | ||||||||||||||
Income (loss) before taxes |
13,610 | 47,943 | (59 | ) | (29,612 | ) | 31,882 | |||||||||||||
Provision (benefit) for income taxes: |
||||||||||||||||||||
Current |
10,182 | | | | 10,182 | |||||||||||||||
Deferred |
(15,954 | ) | 18,272 | | | 2,318 | ||||||||||||||
Total income taxes |
(5,772 | ) | 18,272 | | | 12,500 | ||||||||||||||
Net income (loss) |
$ | 19,382 | $ | 29,671 | ($59 | ) | ($29,612 | ) | $ | 19,382 | ||||||||||
14
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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS (UNAUDITED)
NINE MONTHS ENDED SEPTEMBER 30, 2011
(In thousands of dollars)
NINE MONTHS ENDED SEPTEMBER 30, 2011
(In thousands of dollars)
Non- | ||||||||||||||||||||
Guarantor | Guarantor | |||||||||||||||||||
Parent | Subsidiary | Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
Operating revenue: |
||||||||||||||||||||
Oil production |
$ | 2,766 | $ | 482,022 | $ | | $ | | $ | 484,788 | ||||||||||
Gas production |
12,355 | 140,260 | | | 152,615 | |||||||||||||||
Other operational income |
2,359 | 179 | 456 | | 2,994 | |||||||||||||||
Derivative income, net |
| 3,300 | | | 3,300 | |||||||||||||||
Total operating revenue |
17,480 | 625,761 | 456 | | 643,697 | |||||||||||||||
Operating expenses: |
||||||||||||||||||||
Lease operating expenses |
2,462 | 130,652 | 193 | | 133,307 | |||||||||||||||
Other operational expense |
715 | 734 | 3 | | 1,452 | |||||||||||||||
Production taxes |
814 | 6,014 | | | 6,828 | |||||||||||||||
Depreciation, depletion, amortization |
11,533 | 192,566 | 678 | | 204,777 | |||||||||||||||
Accretion expense |
11 | 22,849 | 274 | | 23,134 | |||||||||||||||
Salaries, general and administrative |
29,486 | 7 | 1 | | 29,494 | |||||||||||||||
Incentive compensation expense |
7,104 | | | | 7,104 | |||||||||||||||
Total operating expenses |
52,125 | 352,822 | 1,149 | | 406,096 | |||||||||||||||
Income (loss) from operations |
(34,645 | ) | 272,939 | (693 | ) | | 237,601 | |||||||||||||
Other (income) expenses: |
||||||||||||||||||||
Interest expense |
6,315 | 155 | | | 6,470 | |||||||||||||||
Interest income |
(164 | ) | (6 | ) | | | (170 | ) | ||||||||||||
Other (income) expense, net |
481 | (1,479 | ) | | | (998 | ) | |||||||||||||
Loss on early extinguishment of debt |
607 | | | | 607 | |||||||||||||||
(Income) loss from investment in subsidiaries |
(177,442 | ) | 692 | | 176,750 | | ||||||||||||||
Total other (income) expenses |
(170,203 | ) | (638 | ) | | 176,750 | 5,909 | |||||||||||||
Income (loss) before taxes |
135,558 | 273,577 | (693 | ) | (176,750 | ) | 231,692 | |||||||||||||
Provision (benefit) for income taxes: |
||||||||||||||||||||
Current |
(12,690 | ) | (2,353 | ) | | | (15,043 | ) | ||||||||||||
Deferred |
(561 | ) | 98,487 | | | 97,926 | ||||||||||||||
Total income taxes |
(13,251 | ) | 96,134 | | | 82,883 | ||||||||||||||
Net income (loss) |
$ | 148,809 | $ | 177,443 | ($693 | ) | ($176,750 | ) | $ | 148,809 | ||||||||||
15
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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS (UNAUDITED)
NINE MONTHS ENDED SEPTEMBER 30, 2010
(In thousands of dollars)
NINE MONTHS ENDED SEPTEMBER 30, 2010
(In thousands of dollars)
Non- | ||||||||||||||||||||
Guarantor | Guarantor | |||||||||||||||||||
Parent | Subsidiary | Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
Operating revenue: |
||||||||||||||||||||
Oil production |
$ | 41,262 | $ | 260,150 | $ | | $ | | $ | 301,412 | ||||||||||
Gas production |
44,166 | 135,405 | | | 179,571 | |||||||||||||||
Other operational income |
3,696 | (30 | ) | 823 | | 4,489 | ||||||||||||||
Derivative income, net |
3,818 | | | | 3,818 | |||||||||||||||
Total operating revenue |
92,942 | 395,525 | 823 | | 489,290 | |||||||||||||||
Operating expenses: |
||||||||||||||||||||
Lease operating expenses |
37,061 | 75,368 | | | 112,429 | |||||||||||||||
Other operational expense |
1,973 | 3,477 | | | 5,450 | |||||||||||||||
Production taxes |
3,481 | 1,280 | | | 4,761 | |||||||||||||||
Depreciation, depletion, amortization |
31,650 | 152,467 | 783 | | 184,900 | |||||||||||||||
Accretion expense |
10,878 | 14,174 | 332 | | 25,384 | |||||||||||||||
Salaries, general and administrative |
30,184 | 14 | 1 | | 30,199 | |||||||||||||||
Incentive compensation expense |
2,113 | | | | 2,113 | |||||||||||||||
Total operating expenses |
117,340 | 246,780 | 1,116 | | 365,236 | |||||||||||||||
Income (loss) from operations |
(24,398 | ) | 148,745 | (293 | ) | | 124,054 | |||||||||||||
Other (income) expenses: |
||||||||||||||||||||
Interest expense |
9,283 | (10 | ) | | | 9,273 | ||||||||||||||
Interest income |
(1,106 | ) | (4 | ) | | | (1,110 | ) | ||||||||||||
Other (income) expense, net |
442 | (688 | ) | 16 | | (230 | ) | |||||||||||||
Loss on early extinguishment of debt |
1,820 | | | | 1,820 | |||||||||||||||
(Income) loss from investment in subsidiaries |
(95,536 | ) | 309 | | 95,227 | | ||||||||||||||
Total other (income) expenses |
(85,097 | ) | (393 | ) | 16 | 95,227 | 9,753 | |||||||||||||
Income (loss) before taxes |
60,699 | 149,138 | (309 | ) | (95,227 | ) | 114,301 | |||||||||||||
Provision (benefit) for income taxes: |
||||||||||||||||||||
Current |
5,006 | (88 | ) | | | 4,918 | ||||||||||||||
Deferred |
(16,979 | ) | 53,690 | | | 36,711 | ||||||||||||||
Total income taxes |
(11,973 | ) | 53,602 | | | 41,629 | ||||||||||||||
Net income (loss) |
$ | 72,672 | $ | 95,536 | ($309 | ) | ($95,227 | ) | $ | 72,672 | ||||||||||
16
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CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (UNAUDITED)
NINE MONTHS ENDED SEPTEMBER 30, 2011
(In thousands of dollars)
NINE MONTHS ENDED SEPTEMBER 30, 2011
(In thousands of dollars)
Non- | ||||||||||||||||||||
Guarantor | Guarantor | |||||||||||||||||||
Parent | Subsidiary | Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
Cash flows from operating activities: |
||||||||||||||||||||
Net income (loss) |
$ | 148,809 | $ | 177,443 | ($693 | ) | ($176,750 | ) | $ | 148,809 | ||||||||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |
||||||||||||||||||||
Depreciation, depletion and amortization |
11,533 | 192,566 | 678 | | 204,777 | |||||||||||||||
Accretion expense |
11 | 22,849 | 274 | | 23,134 | |||||||||||||||
Deferred income tax provision (benefit) |
(561 | ) | 98,487 | | | 97,926 | ||||||||||||||
Settlement of asset retirement obligations |
| (52,543 | ) | | | (52,543 | ) | |||||||||||||
Non-cash stock compensation expense |
4,492 | | | | 4,492 | |||||||||||||||
Excess tax benefits |
(1,490 | ) | | | | (1,490 | ) | |||||||||||||
Non-cash derivative income |
| (4,337 | ) | | | (4,337 | ) | |||||||||||||
Loss on early extinguishment of debt |
607 | | | | 607 | |||||||||||||||
Non-cash (income) loss from investment in subsidiaries |
(175,962 | ) | (788 | ) | | 176,750 | | |||||||||||||
Other non-cash expense |
50 | | | | 50 | |||||||||||||||
Change in current income taxes |
(19,357 | ) | (2,353 | ) | | | (21,710 | ) | ||||||||||||
Change in intercompany receivables/payables |
233,904 | (233,577 | ) | (327 | ) | | | |||||||||||||
(Increase) decrease in accounts receivable |
(16,878 | ) | (242 | ) | 3 | | (17,117 | ) | ||||||||||||
(Increase) decrease in other current assets |
(200 | ) | 15 | | | (185 | ) | |||||||||||||
Decrease in inventory |
1,592 | 14 | | | 1,606 | |||||||||||||||
Increase (decrease) in accounts payable |
2,709 | (30 | ) | | | 2,679 | ||||||||||||||
Increase in other current liabilities |
1,124 | 2,480 | | | 3,604 | |||||||||||||||
Other |
(1,889 | ) | | | | (1,889 | ) | |||||||||||||
Net cash provided by (used in) operating activities |
188,494 | 199,984 | (65 | ) | | 388,413 | ||||||||||||||
Cash flows from investing activities: |
||||||||||||||||||||
Investment in oil and gas properties |
(227,862 | ) | (202,845 | ) | (4 | ) | | (430,711 | ) | |||||||||||
Proceeds from sale of oil and gas properties, net of expenses |
5,575 | 2,117 | | | 7,692 | |||||||||||||||
Investment in fixed and other assets |
(1,788 | ) | | | | (1,788 | ) | |||||||||||||
Net cash used in investing activities |
(224,075 | ) | (200,728 | ) | (4 | ) | | (424,807 | ) | |||||||||||
Cash flows from financing activities: |
||||||||||||||||||||
Deferred financing costs |
(4,017 | ) | | | | (4,017 | ) | |||||||||||||
Excess tax benefits |
1,490 | | | | 1,490 | |||||||||||||||
Net payments for share based compensation |
(2,581 | ) | | | | (2,581 | ) | |||||||||||||
Net cash used in financing activities |
(5,108 | ) | | | | (5,108 | ) | |||||||||||||
Net decrease in cash and cash equivalents |
(40,689 | ) | (744 | ) | (69 | ) | | (41,502 | ) | |||||||||||
Cash and cash equivalents, beginning of period |
105,115 | 1,659 | 182 | | 106,956 | |||||||||||||||
Cash and cash equivalents, end of period |
$ | 64,426 | $ | 915 | $ | 113 | $ | | $ | 65,454 | ||||||||||
17
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CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (UNAUDITED)
NINE MONTHS ENDED SEPTEMBER 30, 2010
(In thousands of dollars)
NINE MONTHS ENDED SEPTEMBER 30, 2010
(In thousands of dollars)
Non- | ||||||||||||||||||||
Guarantor | Guarantor | |||||||||||||||||||
Parent | Subsidiary | Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
Cash flows from operating activities: |
||||||||||||||||||||
Net income (loss) |
$ | 72,672 | $ | 95,536 | ($309 | ) | ($95,227 | ) | $ | 72,672 | ||||||||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |
| |||||||||||||||||||
Depreciation, depletion and amortization |
31,650 | 152,467 | 783 | | 184,900 | |||||||||||||||
Accretion expense |
10,878 | 14,174 | 332 | | 25,384 | |||||||||||||||
Deferred income tax provision (benefit) |
(16,979 | ) | 53,690 | | | 36,711 | ||||||||||||||
Settlement of asset retirement obligations |
(5,012 | ) | (23,640 | ) | | | (28,652 | ) | ||||||||||||
Non-cash stock compensation expense |
4,023 | | | | 4,023 | |||||||||||||||
Excess tax benefits |
(297 | ) | | | | (297 | ) | |||||||||||||
Non-cash derivative income |
(1,459 | ) | | | | (1,459 | ) | |||||||||||||
Loss on early extinguishment of debt |
1,820 | | | | 1,820 | |||||||||||||||
Non-cash (income) loss from investment in subsidiaries |
(95,536 | ) | 309 | | 95,227 | | ||||||||||||||
Other non-cash expenses |
741 | | | | 741 | |||||||||||||||
Change in current income taxes |
(5,926 | ) | (88 | ) | | | (6,014 | ) | ||||||||||||
(Increase) decrease in accounts receivable |
231,945 | (191,343 | ) | (1,033 | ) | | 39,569 | |||||||||||||
(Increase) decrease in other current assets |
(361 | ) | 56 | | | (305 | ) | |||||||||||||
Decrease in inventory |
1,503 | 275 | | | 1,778 | |||||||||||||||
Increase (decrease) in accounts payable |
(959 | ) | (306 | ) | | | (1,265 | ) | ||||||||||||
Decrease in other current liabilities |
(21,171 | ) | (230 | ) | | | (21,401 | ) | ||||||||||||
Other |
561 | 700 | | | 1,261 | |||||||||||||||
Net cash provided by (used in) operating activities |
208,093 | 101,600 | (227 | ) | | 309,466 | ||||||||||||||
Cash flows from investing activities: |
||||||||||||||||||||
Investment in oil and gas properties |
(157,192 | ) | (104,687 | ) | (91 | ) | | (261,970 | ) | |||||||||||
Proceeds from sale of oil and gas properties, net of expenses |
30,955 | 680 | | | 31,635 | |||||||||||||||
Investment in fixed and other assets |
(1,722 | ) | | | | (1,722 | ) | |||||||||||||
Net cash used in investing activities |
(127,959 | ) | (104,007 | ) | (91 | ) | | (232,057 | ) | |||||||||||
Cash flows from financing activities: |
||||||||||||||||||||
Repayment of bank borrowings |
(125,000 | ) | | | | (125,000 | ) | |||||||||||||
Redemption of senior subordinated notes |
(200,503 | ) | | | | (200,503 | ) | |||||||||||||
Proceeds from issuance of senior notes |
275,000 | | | | 275,000 | |||||||||||||||
Deferred financing costs |
(9,766 | ) | | | | (9,766 | ) | |||||||||||||
Excess tax benefits |
297 | | | | 297 | |||||||||||||||
Net payments for share based compensation |
(1,360 | ) | | | | (1,360 | ) | |||||||||||||
Net cash used in financing activities |
(61,332 | ) | | | | (61,332 | ) | |||||||||||||
Net increase (decrease) in cash and cash equivalents |
18,802 | (2,407 | ) | (318 | ) | | 16,077 | |||||||||||||
Cash and cash equivalents, beginning of period |
64,830 | 3,963 | 500 | | 69,293 | |||||||||||||||
Cash and cash equivalents, end of period |
$ | 83,632 | $ | 1,556 | $ | 182 | $ | | $ | 85,370 | ||||||||||
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Table of Contents
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
TO THE STOCKHOLDERS OF
STONE ENERGY CORPORATION:
STONE ENERGY CORPORATION:
We have reviewed the condensed consolidated balance sheet of Stone Energy Corporation as of
September 30, 2011, and the related condensed consolidated statement of operations for the three
and nine-month periods ended September 30, 2011 and 2010, and the condensed consolidated statement
of cash flows for the nine-month periods ended September 30, 2011 and 2010. These financial
statements are the responsibility of the Companys management.
We conducted our review in accordance with the standards of the Public Company Accounting Oversight
Board (United States). A review of interim financial information consists principally of applying
analytical procedures and making inquiries of persons responsible for financial and accounting
matters. It is substantially less in scope than an audit conducted in accordance with standards of
the Public Company Accounting Oversight Board, the objective of which is the expression of an
opinion regarding the financial statements taken as a whole. Accordingly, we do not express such
an opinion.
Based on our review, we are not aware of any material modifications that should be made to the
condensed consolidated financial statements referred to above for them to be in conformity with
U.S. generally accepted accounting principles.
We have previously audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheet of Stone Energy Corporation as of
December 31, 2010, and the related consolidated statements of operations, cash flows, changes in
stockholders equity and comprehensive income for the year then ended (not presented herein) and in
our report dated March 3, 2011, we expressed an unqualified opinion on those consolidated financial
statements. In our opinion, the information set forth in the accompanying condensed consolidated
balance sheet as of December 31, 2010, is fairly stated, in all material respects, in relation to
the consolidated balance sheet from which it has been derived.
/s/ Ernst & Young LLP
New Orleans, Louisiana
November 7, 2011
November 7, 2011
19
Table of Contents
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
Forward-Looking Statements
The information in this Quarterly Report on Form 10-Q includes forward-looking
statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the
Securities Exchange Act of 1934. 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 managements 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 Annual Report on Form 10-K and in this Quarterly Report on Form 10-Q.
Forward-looking statements appear in a number of places and include statements with respect
to, among other things:
| any expected results or benefits associated with our acquisitions; | ||
| estimates of our future oil and natural gas production, including estimates of any increases in oil and gas production; | ||
| planned capital expenditures and the availability of capital resources to fund capital expenditures; | ||
| our outlook on oil and gas prices; | ||
| estimates of our oil and gas reserves; | ||
| any estimates of future earnings growth; | ||
| the impact of political and regulatory developments; | ||
| our outlook on the resolution of pending litigation and government inquiry; | ||
| estimates of the impact of new accounting pronouncements on earnings in future periods; | ||
| our future financial condition or results of operations and our future revenues and expenses; | ||
| our access to capital and our anticipated liquidity; | ||
| estimates of future income taxes; and | ||
| our business strategy and other plans and objectives for future operations. |
We caution you that these forward-looking statements are subject to 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:
| commodity price volatility; | ||
| domestic and worldwide economic conditions; | ||
| the availability of capital on economic terms to fund our capital expenditures and acquisitions; | ||
| our level of indebtedness; | ||
| declines in the value of our oil and gas properties resulting in a decrease in our borrowing base under our credit facility and ceiling test write-downs and impairments; | ||
| our ability to replace and sustain production; | ||
| the impact of a financial crisis on our business operations, financial condition and ability to raise capital; | ||
| the ability of financial counterparties to perform or fulfill their obligations under existing agreements; | ||
| third party interruption of sales to market; | ||
| lack of availability and cost of goods and services; | ||
| regulatory and environmental risks associated with drilling and production activities; | ||
| drilling and other operating risks; | ||
| unsuccessful exploration and development drilling activities; | ||
| hurricanes and other weather conditions; | ||
| the adverse effects of changes in applicable tax, environmental, derivatives and other regulatory legislation, including changes affecting our offshore and Appalachian operations; | ||
| consequences of the Deepwater Horizon oil spill and resulting stringent regulatory requirements; | ||
| the uncertainty inherent in estimating proved oil and natural gas reserves and in projecting future rates of production and timing of development expenditures; and | ||
| the other risks described in our Annual Report on Form 10-K and our Quarterly Reports on Form 10-Q. |
Should one or more of the risks or uncertainties described above, in our Annual Report on Form
10-K for the year ended December 31, 2010, or in our Quarterly Reports on 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
20
Table of Contents
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.
Managements 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 Annual
Report on Form 10-K for the year ended December 31, 2010. Certain 2010 amounts have been changed
from amounts originally presented to correct a prior period immaterial error. All period to period
comparisons are based upon corrected amounts.
Overview
We are an independent oil and gas company engaged in the acquisition, exploration,
exploitation, development and operation of oil and gas properties located primarily in the Gulf of
Mexico (GOM). We have been operating in the Gulf Coast Basin since our incorporation in 1993 and
have established a technical and operational expertise in this area. More recently, we have made
strategic investments in the deep water and deep shelf GOM and in the Gulf Coast onshore, which we
have targeted as important exploration areas. We are also active in the Appalachian region, where
we have established a significant acreage position and have development operations in the Marcellus
Shale. We have also targeted several exploratory oil projects in the Rocky Mountain region.
Throughout this document, reference to our Gulf Coast Basin properties includes our Gulf Coast
onshore, shelf, deep shelf and deep water properties.
Critical Accounting Policies
Our Annual Report on Form 10-K describes the accounting policies that we believe are critical
to the reporting of our financial position and operating results and that require managements most
difficult, subjective or complex judgments. Our most significant estimates are:
| remaining proved oil and gas reserves volumes and the timing of their production; | ||
| estimated costs to develop and produce proved oil and gas reserves; | ||
| accruals of exploration costs, development costs, operating costs and production revenue; | ||
| timing and future costs to abandon our oil and gas properties; | ||
| the effectiveness and estimated fair value of derivative positions; | ||
| classification of unevaluated property costs; | ||
| capitalized general and administrative costs and interest; | ||
| insurance recoveries related to hurricanes and other events; | ||
| estimates of fair value in business combinations; | ||
| current income taxes; and | ||
| contingencies. |
This Quarterly Report on Form 10-Q should be read together with the discussion contained in
our 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 Quarterly Report on Form 10-Q should be
read in conjunction with the discussion in Part I, Item 1A, of our Annual Report on Form 10-K
regarding these other risk factors and in this report under Part II, Item 1A, Risk Factors.
Known Trends and Uncertainties
Deepwater Horizon Explosion and Oil Spill - The April 2010 explosion and sinking of the
Deepwater Horizon drilling rig and resulting oil spill has created uncertainties about the impact
on our future operations in the GOM. Increased regulation in a number of areas could disrupt,
delay or prohibit future drilling programs and ultimately impact the fair value of our
unevaluated properties, a substantial portion of which is in the deep water of the GOM. As of
September 30, 2011, we have substantial investments in unevaluated oil and gas properties that
relate to offshore leases, the majority of which are in the deep water GOM. If the fair value of
these investments were to fall below the recorded amounts, the excess would be transferred to
evaluated oil and gas properties thereby affecting the computation of amounts for depreciation,
depletion and amortization and potentially our ceiling test computation. As of September 30, 2011,
the computation of our ceiling test indicated a cushion of approximately $549.6 million.
21
Table of Contents
Asset Retirement Obligations In October 2010, we received notification from BOEMRE
indicating that certain identified wells and facilities operated by us would need to be retired on
a timing schedule which was accelerated from the timing estimated in calculating liabilities for
asset retirement obligations at December 31, 2009. In February 2011, we submitted an abandonment
plan addressing the identified wells and facilities. The successor to BOEMRE in this matter, the
BSEE, indicated it will issue a final order following its review of the plan. During 2010, we
increased our asset retirement obligations in the amount of $54.4 million for the estimated impact
of the accelerated timing of the retirement of these assets and other factors. The final order,
expected to be issued by the BSEE, will ultimately determine the impact on our asset retirement
obligations and could result in additional upward or downward revisions.
Hurricanes Since the majority of our production originates in the GOM, we are particularly
vulnerable to the effects of hurricanes on production. Additionally, affordable insurance coverage
for property damage to our facilities for hurricanes is becoming more difficult to obtain. We have
narrowed our insurance coverage to selected properties, increased our deductibles and are
shouldering more hurricane related risk in the environment of rising insurance rates. 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 acceleration of plugging and abandonment costs.
Louisiana Franchise Taxes We have been involved in litigation with the state of Louisiana
over the proper computation of franchise taxes allocable to the state. This litigation relates to
the states position that sales of crude oil and natural gas from properties located on the Outer
Continental Shelf (OCS), which are transported through the state of Louisiana, should be sourced
to Louisiana for purposes of computing franchise taxes. We disagree with the states position.
However, if the states position were to be upheld, we could incur additional expenses for alleged
underpaid franchise taxes in prior years and higher franchise tax expense in future years. See
Part II, Item 1. Legal Proceedings.
Liquidity and Capital Resources
At November 2, 2011, we had $338.9 million of availability under our bank credit facility and
cash on hand of approximately $69.4 million. In May 2011, our capital expenditure budget for 2011
was increased from $425 million up to $500 million
due to a projected increase in
production, oil prices and estimated cash flow, combined with an attractive inventory of capital
projects. Our capital expenditure budget excludes material acquisitions and capitalized salaries,
general and administrative expenses and interest. We intend to finance our capital expenditure
budget primarily with cash flow from operations and borrowings under our bank credit facility if
necessary. If we do not have sufficient cash flow from operations or availability under our bank
credit facility, we may be forced to reduce our capital expenditures. To the extent that 2011 cash
flow from operations exceeds our estimated 2011 capital expenditures, we may expand our capital
budget or invest in money markets.
Although we do not budget material acquisitions, we are continually evaluating opportunities
that fit our specific acquisition profile. To the extent any possible transaction would exceed our
current sources of capital, we would consider accessing the public markets or monetizing other
assets as a source of financing. On October 28, 2011, we entered into
a definitive agreement to sell our interest in one of our offshore
Gulf of Mexico fields to an unrelated third party for approximately
$80 million. We expect to close on this transaction in the fourth
quarter of 2011. We intend to utilize the provisions of Internal
Revenue Code section 1031 to minimize the potential current tax
impacts of this transaction. This will entail acquiring like-kind
replacement property within 180 days of the closing on the sold property.
There is a significant amount of uncertainty regarding our industry resulting from the
explosion and sinking of the Deepwater Horizon oil rig in the Gulf of Mexico and resulting oil
spill. Several bills were introduced before Congress in the months following the Deepwater Horizon
incident which would, if adopted as originally proposed, have required us to demonstrate our
capabilities for greater financial responsibility in the event of spills. In addition, we are
subject to an annual evaluation by the Bureau of Ocean Energy Management, a successor to BOEMRE,
for a continuation of our current exemption from supplemental bonding on plugging and abandoning
obligations. It is possible that future legislation or agency action could have an adverse impact
on our liquidity in the event we are required to post additional bonds or letters of credit.
Cash Flow and Working Capital. Net cash flow provided by operating activities totaled $388.4
million during the nine months ended September 30, 2011 compared to $309.5 million in the
comparable period in 2010. Based on our outlook of commodity prices and our estimated production,
we expect to fund our 2011 capital expenditures with cash flow provided by operating activities and
borrowings under our bank credit facility.
Net cash flow used in investing activities totaled $424.8 million and $232.1 million during
the nine months ended September 30, 2011 and 2010, respectively, which primarily represents our
investment in oil and natural gas properties, offset by proceeds from the sale of oil and natural
gas properties.
Net cash flow used in financing activities totaled $5.1 million for the nine months ended
September 30, 2011, which primarily represents $4.0 million of deferred financing costs associated
with our new bank credit facility and $2.6 million of net payments for share based compensation,
slightly offset by $1.5 million of excess tax benefits related to share based compensation. Net
cash flow used in financing activities totaled $61.3 million for the nine months ended September
30, 2010, which primarily represents repayments of borrowings under our bank credit facility of
$125.0 million, the redemption of our 81/4% Senior
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Subordinated Notes due 2011 of $200.5 million, net of proceeds from the public offering of our
85/8% Senior Notes due 2017 of approximately $275 million less $9.8 million of deferred
financing costs.
We had working capital at September 30, 2011 of $77.9 million.
Capital Expenditures. During the three months ended September 30, 2011, additions to oil and
gas property costs of $158.2 million included $12.2 million of lease and property acquisition
costs, $5.0 million of capitalized salaries, general and administrative expenses (inclusive of
incentive compensation) and $11.5 million of capitalized interest. During the nine months ended
September 30, 2011, additions to oil and gas property costs of $410.1 million included $46.9
million of lease and property acquisition costs, $17.1 million of capitalized salaries, general and
administrative expenses (inclusive of incentive compensation) and $32.0 million of capitalized
interest. These investments were financed by cash flow from operations.
Bank Credit Facility. On September 30, 2011, we had no outstanding borrowings under our bank
credit facility and letters of credit totaling $61.1 million had been issued pursuant to the
facility. On April 26, 2011, we entered into an amended and restated revolving credit facility
totaling $700 million through a syndicated bank group, replacing our previous $700 million
facility. The new credit facility matures on September 15, 2014. However, if the notes issued
under our 2004 indenture are retired on or before April 15, 2014, the new credit facility then
matures on April 26, 2015. Our initial borrowing base under the new credit facility was set at
$400 million. On October 31, 2011, the bank group reaffirmed the existing borrowing base at $400
million. As of November 2, 2011, we had no outstanding borrowings under our bank credit facility
and letters of credit totaling $61.1 million had been issued pursuant to the facility, leaving
$338.9 million of availability under the facility. Our bank credit facility is guaranteed by our
only material subsidiary, Stone Energy Offshore, L.L.C. (Stone Offshore).
The borrowing base under our bank credit facility is redetermined by the lenders
semi-annually, on May 1 and November 1, taking into consideration the estimated value of our oil
and gas properties and those of our direct and indirect material subsidiaries 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. Our bank credit facility is collateralized by substantially all of
Stones and Stone Offshores assets. Stone and Stone Offshore are required to mortgage, and grant
a security interest in, their oil and gas reserves representing at least 80% of the discounted
present value of the future net cash flows from their oil and gas reserves reviewed in determining
the borrowing base. At our option, loans under the credit facility will bear interest at a rate
based on the adjusted Libor Rate plus an applicable margin, or a rate based on the prime rate or
Federal funds rate plus an applicable margin. Our bank credit facility provides for optional and
mandatory prepayments, affirmative and negative covenants, and interest coverage ratio and leverage
ratio maintenance covenants. We were in compliance with all covenants as of September 30,
2011.
Share Repurchase Program. On September 24, 2007, our Board of Directors authorized a share
repurchase program for an aggregate amount of up to $100 million. The shares may be repurchased
from time to time in the open market or through privately negotiated transactions. The repurchase
program is subject to business and market conditions, and may be suspended or discontinued at any
time. Through September 30, 2011, 300,000 shares had been repurchased under this program at a
total cost of approximately $7.1 million, or an average price of $23.57 per share. No shares were
repurchased during the nine months ended September 30, 2011.
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Results of Operations
The following tables set forth certain information with respect to our oil and gas operations.
Three Months Ended | ||||||||||||||||
September 30, | ||||||||||||||||
2011 | 2010 | Variance | % Change | |||||||||||||
Production: |
||||||||||||||||
Oil (MBbls) |
1,521 | 1,347 | 174 | 13 | % | |||||||||||
Natural gas (MMcf) |
9,713 | 10,130 | (417 | ) | (4 | %) | ||||||||||
Oil and natural gas (MMcfe) |
18,839 | 18,212 | 627 | 3 | % | |||||||||||
Revenue data (in thousands) (a): |
||||||||||||||||
Oil revenue |
$ | 157,436 | $ | 97,688 | $ | 59,748 | 61 | % | ||||||||
Natural gas revenue |
50,244 | 55,522 | (5,278 | ) | (10 | %) | ||||||||||
Total oil and natural gas revenue |
$ | 207,680 | $ | 153,210 | $ | 54,470 | 36 | % | ||||||||
Average prices (a): |
||||||||||||||||
Oil (per Bbl) |
$ | 103.51 | $ | 72.52 | $ | 30.99 | 43 | % | ||||||||
Natural gas (per Mcf) |
5.17 | 5.48 | (0.31 | ) | (6 | %) | ||||||||||
Oil and natural gas (per Mcfe) |
11.02 | 8.41 | 2.61 | 31 | % | |||||||||||
Expenses (per Mcfe): |
||||||||||||||||
Lease operating expenses |
$ | 2.54 | $ | 2.03 | $ | 0.51 | 25 | % | ||||||||
Salaries, general and administrative expenses (b) |
0.38 | 0.54 | (0.16 | ) | (30 | %) | ||||||||||
DD&A expense on oil and gas properties |
3.38 | 3.24 | 0.14 | 4 | % |
(a) | Includes the cash settlement of effective hedging contracts. | |
(b) | Exclusive of incentive compensation expense. |
Nine Months Ended | ||||||||||||||||
September 30, | ||||||||||||||||
2011 | 2010 | Variance | % Change | |||||||||||||
Production: |
||||||||||||||||
Oil (MBbls) |
4,804 | 4,199 | 605 | 14 | % | |||||||||||
Natural gas (MMcf) |
29,907 | 31,874 | (1,967 | ) | (6 | %) | ||||||||||
Oil and natural gas (MMcfe) |
58,731 | 57,068 | 1,663 | 3 | % | |||||||||||
Revenue data (in thousands) (a): |
||||||||||||||||
Oil revenue |
$ | 484,788 | $ | 301,412 | $ | 183,376 | 61 | % | ||||||||
Natural gas revenue |
152,615 | 179,571 | (26,956 | ) | (15 | %) | ||||||||||
Total oil and natural gas revenue |
$ | 637,403 | $ | 480,983 | $ | 156,420 | 33 | % | ||||||||
Average prices (a): |
||||||||||||||||
Oil (per Bbl) |
$ | 100.91 | $ | 71.78 | $ | 29.13 | 41 | % | ||||||||
Natural gas (per Mcf) |
5.10 | 5.63 | (0.53 | ) | (9 | %) | ||||||||||
Oil and natural gas (per Mcfe) |
10.85 | 8.43 | 2.42 | 29 | % | |||||||||||
Expenses (per Mcfe): |
||||||||||||||||
Lease operating expenses |
$ | 2.27 | $ | 1.97 | $ | 0.30 | 15 | % | ||||||||
Salaries, general and administrative expenses (b) |
0.50 | 0.53 | (0.03 | ) | (6 | %) | ||||||||||
DD&A expense on oil and gas properties |
3.44 | 3.16 | 0.28 | 9 | % |
(a) | Includes the cash settlement of effective hedging contracts. | |
(b) | Exclusive of incentive compensation expense. |
During the three months ended September 30, 2011, we reported net income totaling $51.8
million, or $1.06 per share, compared to net income for the three months ended September 30, 2010
of $19.4 million, or $0.40 per share. During the nine months ended September 30, 2011, we reported
net income totaling $148.8 million, or $3.04 per share, compared to net income for the nine months
ended September 30, 2010 of $72.7 million, or $1.50 per share. All per share amounts are on a
diluted basis.
The variance in the three and nine-month periods results was due to the following components:
Production. During the three months ended September 30, 2011, total production volumes
increased to 18.8 Bcfe compared to 18.2 Bcfe produced during the comparable 2010 period. Oil
production during the three months ended September 30, 2011 totaled approximately 1,521,000 barrels
compared to 1,347,000 barrels produced during the three months ended
September 30, 2010, while natural gas production totaled 9.7 Bcf during the three months ended
September 30, 2011 compared to
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10.1 Bcf
produced during the comparable period of 2010. Production for the
three months ended September 30, 2011 was impacted by GOM
shut-ins from Tropical Storm Lee, Appalachia shut-ins from Hurricane
Irene and third party pipeline downtime in the GOM. During the
nine months ended September 30, 2011, total production volumes increased to 58.7 Bcfe compared to
57.1 Bcfe produced during the comparable 2010 period. Oil production during the nine months ended
September 30, 2011 totaled approximately 4,804,000 barrels compared to 4,199,000 barrels produced
during the nine months ended September 30, 2010, while natural gas production totaled 29.9 Bcf
during the nine months ended September 30, 2011 compared to 31.9 Bcf produced during the comparable
period of 2010. The increase in oil production volumes was primarily due to increases in
production at our Mississippi Canyon Block 109 and Ship Shoal Block 113 fields where we have
development programs ongoing. The decrease in gas production volumes was primarily due to natural
production declines.
Prices. Prices realized during the three months ended September 30, 2011 averaged $103.51 per
Bbl of oil and $5.17 per Mcf of natural gas, or 31% higher, on an Mcfe basis, than average realized
prices of $72.52 per Bbl of oil and $5.48 per Mcf of natural gas during the comparable 2010 period.
Prices realized during the nine months ended September 30, 2011 averaged $100.91 per Bbl of oil
and $5.10 per Mcf of natural gas, or 29% higher, on an Mcfe basis, than average realized prices of
$71.78 per Bbl of oil and $5.63 per Mcf of natural gas during the comparable 2010 period. All unit
pricing amounts include the cash settlement of effective hedging contracts.
We enter into various hedging contracts in order to reduce our exposure to the possibility of
declining oil and gas prices. Our effective hedging transactions increased our average realized
natural gas price by $0.47 per Mcf and decreased our average realized oil price by $2.16 per Bbl
during the three months ended September 30, 2011. During the three months ended September 30,
2010, our effective hedging transactions increased our average realized natural gas price by $0.96
per Mcf and decreased our average realized oil price by $2.79 per Bbl. During the nine months
ended September 30, 2011, effective hedging transactions increased our average realized natural gas
price by $0.43 per Mcf and decreased our average realized oil price by $5.43 per Bbl. During the
nine months ended September 30, 2010, effective hedging transactions increased our average realized
natural gas price by $0.81 per Mcf and decreased our average realized oil price by $4.26 per Bbl.
Revenue. Oil and natural gas revenue was $207.7 million during the three months ended
September 30, 2011, compared to $153.2 million during the comparable period of 2010. The increase
is attributable to a 43% increase in average realized oil prices along with a 13% increase in oil
production volumes, partially offset by a decline in average realized gas prices and gas production
volumes. Oil and natural gas revenue for the nine months ended September 30, 2011 totaled $637.4
million compared to $481.0 million during the comparable period of 2010. The increase is
attributable to a 41% increase in average realized oil prices along with a 14% increase in oil
production volumes, partially offset by a decline in average realized gas prices and gas production
volumes.
Derivative Income/Expense. During the nine months ended September 30, 2011 and 2010, certain
of our derivative contracts were determined to be partially ineffective because of differences in
the relationship between the fixed price in the derivative contract and actual prices realized.
Net derivative income for the three months ended September 30, 2011, totaled $4.1 million,
consisting of $0.1 million of cash settlements on the ineffective portion of derivative contracts,
less $4.2 million of changes in the fair market value of the ineffective portion of derivative
contracts. Net derivative income for the three months ended September 30, 2010, totaled $0.4
million, consisting of $0.8 million of cash settlements on the ineffective derivative contracts,
less $0.4 million of changes in the fair market value of the ineffective portion of derivative
contracts.
Net derivative income for the nine months ended September 30, 2011, totaled $3.3 million,
consisting of $1.0 million of cash settlements on the ineffective portion of derivative contracts,
less $4.3 million of changes in the fair market value of the ineffective portion of derivative
contracts. Net derivative income for the nine months ended September 30, 2010, totaled $3.8
million, consisting of $2.4 million of cash settlements on the ineffective derivative contracts,
plus $1.4 million of changes in the fair market value of the ineffective portion of derivative
contracts.
Expenses. Lease operating expenses during the three months ended September 30, 2011 and 2010
totaled $47.8 million and $36.9 million, respectively. For the nine months ended September 30,
2011 and 2010, lease operating expenses totaled $133.3 million and $112.4 million, respectively.
On a unit of production basis, lease operating expenses were $2.27 per Mcfe and $1.97 per Mcfe for
the nine months ended September 30, 2011 and 2010, respectively. The increase in lease operating
expenses in 2011 was primarily attributable to increased platform and well maintenance.
The other operational expense charge of $0.7 million for the three months ended September 30,
2011 was primarily related to a $0.3 million loss on the sale of non-dedicated tubular inventory
and approximately $0.2 million of miscellaneous inventory charges. The other operational expense
charge of $3.0 million for the three months ended September 30, 2010 included a $0.8 million loss
on the sale of non-dedicated tubular inventory and $2.2 million of charges related to a delay in
the drilling of the second well in our Amberjack drilling program as a result of the deep water
drilling moratorium.
For the nine months ended September 30, 2011, other operational expenses of $1.5 million
included $0.7 million for the settlement of litigation associated with an expensed operation in the
first quarter of 2011, a $0.3 million loss on the sale of non-
dedicated tubular inventory and $0.4 million of miscellaneous inventory charges. For the nine
months ended September 30, 2010,
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other operational expenses of $5.5 million included a $2.2 million
loss on the sale of non-dedicated tubular inventory and a total of $3.3 million of charges related
to a delay in the drilling of the second well in our Amberjack drilling program as a result of the
deep water drilling moratorium.
Depreciation, depletion and amortization (DD&A) on oil and gas properties for the three
months ended September 30, 2011 totaled $63.8 million, or $3.38 per Mcfe, compared to $59.0
million, or $3.24 per Mcfe, during the comparable period of 2010. For the nine months ended
September 30, 2011 and 2010, DD&A expense totaled $201.9 million, or $3.44 per Mcfe, and $180.4
million, or $3.16 per Mcfe, respectively. The increase in DD&A in 2011 on a unit basis was
primarily attributable to the unit cost of current year net reserve additions (including future
development costs) exceeding the per unit amortizable base as of the beginning of the year.
Accretion expense for the three months ended September 30, 2011 was $7.7 million compared to
$8.5 million for the comparable period of 2010. For the nine months ended September 30, 2011 and
2010, accretion expense totaled $23.1 million and $25.4 million, respectively. The decrease is
primarily due to a change in the timing on certain of our asset retirement obligations.
Salaries, general and administrative (SG&A) expenses (exclusive of incentive compensation)
for the three months ended September 30, 2011 were $7.2 million compared to $9.8 million for the
three months ended September 30, 2010. The decrease is primarily the result of the settlement of
litigation and a resulting significant reimbursement of legal fees incurred in prior periods. For
the nine months ended September 30, 2011 and 2010, SG&A (exclusive of incentive compensation)
totaled $29.5 million and $30.2 million, respectively.
For the three months ended September 30, 2011 and 2010, incentive compensation expense totaled
$2.1 million and $0.8 million, respectively. For the nine months ended September 30, 2011 and
2010, incentive compensation expense totaled $7.1 million and $2.1 million, respectively. These
amounts relate to the accrual of estimated incentive compensation bonuses calculated based on the
projected achievement of certain strategic objectives for each fiscal year.
Interest expense for the three months ended September 30, 2011 totaled $1.4 million, net of
$11.5 million of capitalized interest, compared to interest expense of $2.7 million, net of $8.0
million of capitalized interest, during the comparable 2010 period. For the nine months ended
September 30, 2011, interest expense totaled $6.5 million, net of $32.0 million of capitalized
interest, compared to interest expense of $9.3 million, net of capitalized interest of $21.6
million for the comparable 2010 period. The decrease in interest expense is primarily the result
of an increase in the amount of interest capitalized as a part of the cost oil and gas properties.
Our effective tax rate was 34.7% and 35.8% for the three and nine months ended September 30,
2011, respectively, and 39.2% and 36.4% for the comparable 2010 periods. The decreased effective
tax rate for the three and nine-month periods relates to the finalization of permanent deductions
in the filing of prior period amended returns. Additionally, the effective tax rate for the
quarter ended September 30, 2010 was impacted by the cumulative effect of higher effective state
income tax rates resulting from increased onshore activities.
Off Balance Sheet Arrangements
None.
Recent Accounting Developments
None.
Defined Terms
Oil and condensate are stated in barrels (Bbls) or thousand barrels (MBbls). Natural gas
is stated herein in billion cubic feet (Bcf), million cubic feet (MMcf) or thousand cubic feet
(Mcf). Oil and condensate 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. MMBtu represents one million British
Thermal Units and BBtu represents one billion 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.
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Item 3. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
Our major market risk exposure continues to be the pricing applicable to our oil and natural
gas production. Our revenues, profitability and future rate of growth depend substantially upon
the market prices of oil and natural gas, which fluctuate widely. Oil and natural gas price
declines and volatility could adversely affect our revenues, cash flows and profitability. Price
volatility is expected to continue. In order to manage our exposure to oil and natural gas price
declines, we occasionally enter into oil and natural gas price hedging arrangements to secure a
price for a portion of our expected future production.
Our hedging policy provides that not more than 50% of our estimated production quantities can
be hedged without the consent of the board of directors. We believe our current hedging positions
have hedged approximately 43% of our estimated 2011 production, 39% of our estimated 2012
production from estimated proved reserves, 27% of our estimated 2013 production from estimated
proved reserves and 4% of our estimated 2014 production from estimated proved reserves. See Item
1. Financial Statements Note 3 Derivative Instruments and Hedging Activities for a detailed
discussion of hedges in place to manage our exposure to oil and natural gas price declines.
Since the filing of our Annual Report on Form 10-K for the year ended December 31, 2010, there
have been no material changes in reported market risk as it relates to commodity prices.
Interest Rate Risk
We had total debt outstanding of $575 million at September 30, 2011, all of which bears
interest at fixed rates. The $575 million of fixed-rate debt is comprised of $375 million of 85/8%
Senior Notes due 2017 and $200 million of 63/4% Senior Subordinated Notes due 2014. We had no
outstanding borrowings under our variable-rate bank credit facility during the nine months ended
September 30, 2011. We currently have no interest rate hedge positions in place to reduce our
exposure to changes in interest rates.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
We have established disclosure controls and procedures to ensure that material information
relating to Stone Energy Corporation and its consolidated subsidiaries (collectively Stone) is
made known to the officers who certify Stones financial reports and the Board of Directors.
Disclosure controls and procedures, as defined in the rules and regulations of the Securities
Exchange Act of 1934, means controls and other procedures of an issuer that are designed to ensure
that information required to be disclosed by the issuer in the reports that it files or submits
under the Act (15 U.S.C. 78a et seq.) is recorded, processed, summarized and reported, within the
time periods specified in the Commissions rules and forms. Disclosure controls and procedures
include, without limitation, controls and procedures designed to ensure that information required
to be disclosed by an issuer in the reports that it files or submits under the Act is accumulated
and communicated to the issuers management, including its principal executive and principal
financial officers, or persons performing similar functions, as appropriate to allow timely
decisions regarding required disclosure. There are inherent limitations to the effectiveness of
any system of disclosure controls and procedures, including the possibility of human error and the
circumvention or overriding of controls and procedures. Accordingly, even effective disclosure
controls and procedures can only provide reasonable assurance of achieving their control
objectives.
Our principal executive officer and our principal financial officer, with the participation of
other members of our senior management, reviewed and evaluated the effectiveness of Stones
disclosure controls and procedures as of the end of the quarterly period ended September 30, 2011.
Based on this evaluation, our principal executive officer and principal financial officer believe
that as of the end of the quarterly period ended September 30, 2011:
| Stones disclosure controls and procedures were effective to ensure that information required to be disclosed by Stone in the reports it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SECs rules and forms; and |
| Stones disclosure controls and procedures were effective to ensure that information required to be disclosed by Stone in the reports that it files or submits under the Securities Exchange Act of 1934 was accumulated and |
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communicated to Stones management, including Stones principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure. |
Changes in Internal Controls Over Financial Reporting
There has not been any change in our internal control over financial reporting that occurred
during the quarter ended September 30, 2011 that has materially affected, or is reasonably likely
to materially affect, our internal control over financial reporting.
PART II OTHER INFORMATION
Item 1. Legal Proceedings
Franchise Tax Action. On December 30, 2004, Stone was served with two petitions (civil
action numbers 2004-6227 and 2004-6228) filed by the Louisiana Department of Revenue (LDR) in the
15th Judicial District Court (Parish of Lafayette, Louisiana) claiming additional franchise taxes
due. In one case, the LDR is seeking additional franchise taxes from Stone in the amount of
$640,000, plus accrued interest of $352,000 (calculated through December 15, 2004), for the
franchise tax year 2001. In the other case, the LDR is seeking additional franchise taxes from
Stone (as successor to Basin Exploration, Inc.) in the amount of $274,000, plus accrued interest of
$159,000 (calculated through December 15, 2004), for the franchise tax years 1999, 2000 and 2001.
On December 29, 2005, the LDR filed another petition in the 15th Judicial District Court
claiming additional franchise taxes due for the taxable years ended December 31, 2002 and 2003 in
the amount of $2.6 million plus accrued interest calculated through December 15, 2005 in the amount
of $1.2 million. Also, on January 2, 2008, Stone was served with a petition (civil action number
2007-6754) claiming $1.5 million of additional franchise taxes due for the 2004 franchise tax year,
plus accrued interest of $800,000 calculated through November 30, 2007. Further, on January 7,
2009, Stone was served with a petition (civil action number 2008-7193) claiming additional
franchise taxes due for the taxable years ended December 31, 2005 and 2006 in the amount of $4.0
million plus accrued interest calculated through October 21, 2008 in the amount of $1.7 million.
In addition, we have received assessments from the LDR for additional franchise taxes in the amount
of $2.9 million resulting from audits of Stone and our subsidiaries. These assessments all relate
to the LDRs assertion that sales of crude oil and natural gas from properties located on the Outer
Continental Shelf, which are transported through the State of Louisiana, should be sourced to the
State of Louisiana for purposes of computing the Louisiana franchise tax apportionment ratio. The
Company disagrees with these contentions and intends to vigorously defend itself against these
claims. The franchise tax year 2010 for Stone remains subject to examination.
Lafourche Parish, Louisiana, Landowner Action. In December 2008, Stephen E. Coignet, et al.,
filed civil action No. 110741 in the 17th Judicial District Court, Lafourche Parish,
Louisiana, against Stone. Plaintiffs subsequently filed three supplemental petitions, including a
third supplemental and restated petition on October 25, 2010. Plaintiffs are landowners of
approximately sixty acres that are subject to mineral leases in favor of Stone. Plaintiffs alleged
that Stone conducted its mineral operations imprudently resulting in damages to plaintiffs in
excess of $60 million. Plaintiffs expert witness provided his report, dated December 28, 2010,
stating his opinion that one well did not produce as much production as it should have, resulting
in a loss to plaintiffs in excess of $4 million, that imprudent operations destroyed hydrocarbon
bearing zones resulting in a loss to plaintiffs in excess of $20 million, and that imprudent
operation of a water injection secondary recovery project resulted in damages to plaintiffs of
approximately $4,755,000. There were also allegations of failure to protect from drainage from a
well on adjoining land, trespass, and various other breaches of the mineral leases. The Company
disagreed with plaintiffs contentions. In October 2011, the parties agreed to a settlement of all
claims asserted in this action, and we anticipate that the settlement will be effected not later
than January 2012. The settlement will not have a materially adverse effect on the Company.
Litigation is subject to substantial uncertainties concerning the outcome of material factual
and legal issues relating to the litigation. Accordingly, we cannot currently predict the manner
and timing of the resolution of these matters and are unable to estimate a range of possible losses
or any minimum loss from such matters.
Item 1A. Risk Factors
There have been no material changes with respect to Stones risk factors previously
reported in Stones Annual Report on Form 10-K for the year ended December 31, 2010.
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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
On September 24, 2007, our Board of Directors authorized a share repurchase program for
an aggregate amount of up to $100 million. The shares may be repurchased from time to time in the
open market or through privately negotiated transactions. The repurchase program is subject to
business and market conditions, and may be suspended or discontinued at any time. Additionally,
shares were withheld from certain employees to pay taxes associated with the employees vesting of
restricted stock. The following table sets forth information regarding our repurchases or
acquisitions of common stock during the three months ended September 30, 2011:
Maximum Number (or | ||||||||||||||||
Total Number of | Approximate Dollar | |||||||||||||||
Shares (or Units) | Value) of Shares | |||||||||||||||
Purchased as Part | (or Units) that May | |||||||||||||||
Total Number of | of Publicly | Yet be Purchased | ||||||||||||||
Shares (or Units) | Average Price Paid | Announced Plans or | Under the Plans or | |||||||||||||
Period | Purchased | per Share (or Unit) | Programs | Programs | ||||||||||||
Share
Repurchase Program: |
||||||||||||||||
July 2011 |
| | | |||||||||||||
August 2011 |
| | | |||||||||||||
September 2011 |
| | | |||||||||||||
| | | $ | 92,928,632 | ||||||||||||
Other: |
||||||||||||||||
July 2011 |
4,807 | (a) | $ | 30.71 | | |||||||||||
August 2011 |
| | | |||||||||||||
September 2011 |
22,069 | (a) | 26.12 | | ||||||||||||
26,876 | $ | 26.94 | | N/A | ||||||||||||
Total |
26,876 | $ | 26.94 | | ||||||||||||
(a) | Amounts include shares withheld from employees upon the vesting of restricted stock in order to satisfy the required tax withholding obligations. |
29
Table of Contents
Item 6. Exhibits
3.1
|
Certificate of Incorporation of the Registrant, as amended (incorporated by reference to Exhibit 3.1 to the Registrants Registration Statement on Form S-1 (Registration No. 33-62362)). | |
3.2
|
Certificate of Amendment of the Certificate of Incorporation of Stone Energy Corporation, dated February 1, 2001 (incorporated by reference to Exhibit 4.1 to the Registrants Form 8-K, filed February 7, 2001). | |
3.3
|
Amended & Restated Bylaws of Stone Energy Corporation, dated May 15, 2008 (incorporated by reference to Exhibit 3.1 to the Registrants Current Report on Form 8-K dated May 15, 2008 (File No. 001-12074)). | |
4.1
|
Indenture between Stone Energy Corporation and JPMorgan Chase Bank, National Association, as trustee, dated December 15, 2004 (incorporated by reference to Exhibit 4.1 to the Registrants Current Report on Form 8-K filed on December 15, 2004.) | |
4.2
|
First Supplemental Indenture, dated August 28, 2008, to the Indenture between Stone Energy Corporation and JPMorgan Chase Bank, National Association, as trustee, dated December 15, 2004 (incorporated by reference to Exhibit 4.2 to the Registrants Current Report on Form 8-K filed August 29, 2008 (File No. 001-12074)). | |
4.3
|
Second Supplemental Indenture, dated January 26, 2010, among Stone Energy Corporation, Stone Energy Offshore, L.L.C., and The Bank of New York Mellon Trust Company, N.A., successor to JPMorgan Chase Bank, as trustee (incorporated by reference to Exhibit 4.1 to the Registrants Current Report on Form 8-K filed January 29, 2010 (File No. 001-12074)). | |
4.4
|
Indenture, dated January 26, 2010, among Stone Energy Corporation, Stone Energy Offshore, L.L.C., and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.2 to the Registrants Current Report on Form 8-K filed January 29, 2010 (File No. 001-12074)). | |
4.5
|
First Supplemental Indenture, dated January 26, 2010, among Stone Energy Corporation, Stone Energy Offshore, L.L.C., and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.3 to the Registrants Current Report on Form 8-K filed January 29, 2010 (File No. 001-12074)). | |
4.6
|
First Amendment to Stone Energy Corporation 2009 Amended and Restated Stock Incentive Plan (incorporated by reference to Exhibit 4.6 to the Registrants Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 (File No. 001-12074)). | |
*15.1
|
Letter from Ernst & Young LLP dated November 7, 2011, regarding unaudited interim financial information. | |
*31.1
|
Certification of Principal Executive Officer of Stone Energy Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934. | |
*31.2
|
Certification of Principal Financial Officer of Stone Energy Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934. | |
*#32.1
|
Certification of Chief Executive Officer and Chief Financial Officer of Stone Energy Corporation pursuant to 18 U.S.C. § 1350. | |
**101.INS
|
XBRL Instance Document | |
**101.SCH
|
XBRL Schema Document | |
**101.CAL
|
XBRL Calculation Linkbase Document |
30
Table of Contents
**101.LAB
|
XBRL Label Linkbase Document | |
**101.PRE
|
XBRL Presentation Linkbase Document |
* | Filed or furnished herewith. | |
** | Furnished, not filed. Users of this data submitted electronically herewith are advised pursuant to Rule 406T of Regulation S-T that this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections. | |
# | Not considered to be filed for the purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section. | |
| Identifies management contracts and compensatory plans or arrangements. |
31
Table of Contents
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
STONE ENERGY CORPORATION |
||||
Date: November 7, 2011 | By: | /s/ J. Kent Pierret | ||
J. Kent Pierret | ||||
Senior Vice President, Chief Accounting Officer and Treasurer (On behalf of the Registrant and as Chief Accounting Officer) |
32
Table of Contents
EXHIBIT INDEX
Exhibit Number | Description | |
3.1
|
Certificate of Incorporation of the Registrant, as amended (incorporated by reference to Exhibit 3.1 to the Registrants Registration Statement on Form S-1 (Registration No. 33-62362)). | |
3.2
|
Certificate of Amendment of the Certificate of Incorporation of Stone Energy Corporation, dated February 1, 2001 (incorporated by reference to Exhibit 4.1 to the Registrants Form 8-K, filed February 7, 2001). | |
3.3
|
Amended & Restated Bylaws of Stone Energy Corporation, dated May 15, 2008 (incorporated by reference to Exhibit 3.1 to the Registrants Current Report on Form 8-K dated May 15, 2008 (File No. 001-12074)). | |
4.1
|
Indenture between Stone Energy Corporation and JPMorgan Chase Bank, National Association, as trustee, dated December 15, 2004 (incorporated by reference to Exhibit 4.1 to the Registrants Current Report on Form 8-K filed on December 15, 2004.) | |
4.2
|
First Supplemental Indenture, dated August 28, 2008, to the Indenture between Stone Energy Corporation and JPMorgan Chase Bank, National Association, as trustee, dated December 15, 2004 (incorporated by reference to Exhibit 4.2 to the Registrants Current Report on Form 8-K filed August 29, 2008 (File No. 001-12074)). | |
4.3
|
Second Supplemental Indenture, dated January 26, 2010, among Stone Energy Corporation, Stone Energy Offshore, L.L.C., and The Bank of New York Mellon Trust Company, N.A., successor to JPMorgan Chase Bank, as trustee (incorporated by reference to Exhibit 4.1 to the Registrants Current Report on Form 8-K filed January 29, 2010 (File No. 001-12074)). | |
4.4
|
Indenture, dated January 26, 2010, among Stone Energy Corporation, Stone Energy Offshore, L.L.C., and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.2 to the Registrants Current Report on Form 8-K filed January 29, 2010 (File No. 001-12074)). | |
4.5
|
First Supplemental Indenture, dated January 26, 2010, among Stone Energy Corporation, Stone Energy Offshore, L.L.C., and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.3 to the Registrants Current Report on Form 8-K filed January 29, 2010 (File No. 001-12074)). | |
4.6
|
First Amendment to Stone Energy Corporation 2009 Amended and Restated Stock Incentive Plan (incorporated by reference to Exhibit 4.6 to the Registrants Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 (File No. 001-12074)). | |
*15.1
|
Letter from Ernst & Young LLP dated November 7, 2011, regarding unaudited interim financial information. | |
*31.1
|
Certification of Principal Executive Officer of Stone Energy Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934. | |
*31.2
|
Certification of Principal Financial Officer of Stone Energy Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934. | |
*#32.1
|
Certification of Chief Executive Officer and Chief Financial Officer of Stone Energy Corporation pursuant to 18 U.S.C. § 1350. | |
**101.INS
|
XBRL Instance Document | |
**101.SCH
|
XBRL Schema Document | |
**101.CAL
|
XBRL Calculation Linkbase Document |
33
Table of Contents
Exhibit Number | Description | |
**101.LAB
|
XBRL Label Linkbase Document | |
**101.PRE
|
XBRL Presentation Linkbase Document |
* | Filed or furnished herewith. | |
** | Furnished, not filed. Users of this data submitted electronically herewith are advised pursuant to Rule 406T of Regulation S-T that this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections. | |
# | Not considered to be filed for the purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section. | |
| Identifies management contracts and compensatory plans or arrangements. |
34