CRIMSON EXPLORATION INC.
FINANCIAL REPORT
DECEMBER 31, 2011
CONTENTS
| |
Page
|
|
REPORT OF MANAGEMENT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
|
F-1
|
| |
|
|
REPORTS OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
|
F-2
|
| |
|
|
FINANCIAL STATEMENTS
|
|
| |
|
|
Consolidated Balance Sheets
|
F-4
|
| |
|
|
Consolidated Statements of Operations
|
F-5
|
| |
|
|
Consolidated Statements of Stockholders’ Equity
|
F-6
|
| |
|
|
Consolidated Statements of Cash Flows
|
F-7
|
| |
|
|
Notes to Consolidated Financial Statements
|
F-8
|
| |
|
|
FINANCIAL STATEMENT SCHEDULE
|
|
| |
|
|
Schedule II Valuation And Qualifying Accounts
|
F-30
|
All other financial statement schedules have been omitted because they are either inapplicable or the information required is included in the financial statements or the notes thereto.
REPORT OF MANAGEMENT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management of the Company is responsible for the preparation and integrity of the consolidated financial statements appearing in the annual report on form 10-K. The financial statements were prepared in conformity with accounting principles generally accepted in the United States and include amounts that are based on management’s best estimates and judgments.
Management of the Company is responsible for establishing and maintaining effective internal control over financial reporting as such term is defined in Rule 13a-15(f) under the Securities Exchange Act of 1934 (“Exchange Act”). The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the consolidated financial statements. Our internal control over financial reporting is supported by a program of appropriate reviews by management, written policies and guidelines, careful selection and training of qualified personnel and a written code of business conduct adopted by our Company’s board of directors, applicable to all Company directors and all officers and employees of our Company and subsidiaries.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even when determined to be effective, can only provide reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2011. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control —Integrated Framework. Based on our assessment, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2011.
| |
/s/ Allan D. Keel
|
| |
Allan D. Keel
|
| |
President and Chief Executive Officer
|
| |
|
| |
|
| |
/s/ E. Joseph Grady
|
| |
E. Joseph Grady
|
| |
Senior Vice President and Chief Financial Officer
|
| |
|
| |
|
Houston, Texas
March 13, 2012
Report of Independent Registered Public Accounting Firm
Board of Directors and Shareholders
Crimson Exploration Inc.:
We have audited the accompanying consolidated balance sheets of Crimson Exploration Inc. and subsidiaries (collectively, the “Company”) as of December 31, 2011 and 2010, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2011. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Crimson Exploration Inc. and subsidiaries as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated March 13, 2012 expressed an unqualified opinion that Crimson Exploration Inc. and subsidiaries maintained, in all material respects, effective internal control over financial reporting.
/s/ GRANT THORNTON LLP
Houston, Texas
March 13, 2012
Report of Independent Registered Public Accounting Firm
Board of Directors and Shareholders
Crimson Exploration Inc.:
We have audited Crimson Exploration Inc.’s and subsidiaries internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Crimson Exploration Inc. and subsidiaries’ management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on Crimson Exploration Inc. and subsidiaries’ internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Crimson Exploration Inc. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control – Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Crimson Exploration Inc. and subsidiaries as of December 31, 2011 and 2010 and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2011, and our report dated March 13, 2012, expressed an unqualified opinion on those consolidated financial statements.
/s/ GRANT THORNTON LLP
Houston, Texas
March 13, 2012
PART I. FINANCIAL INFORMATION
|
ITEM 1.
|
FINANCIAL STATEMENTS.
|
CRIMSON EXPLORATION INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
| |
|
December 31,
|
|
| |
|
2011
|
|
|
2010
|
|
| |
|
|
|
|
|
|
|
CURRENT ASSETS
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$ |
— |
|
|
$ |
— |
|
|
Accounts receivable, net of allowance (see Note 2)
|
|
|
16,059,667 |
|
|
|
14,225,932 |
|
|
Prepaid expenses
|
|
|
473,616 |
|
|
|
168,766 |
|
|
Derivative instruments
|
|
|
4,538,897 |
|
|
|
6,836,366 |
|
|
Deferred tax asset, net
|
|
|
— |
|
|
|
6,331,152 |
|
|
Total current assets
|
|
|
21,072,180 |
|
|
|
27,562,216 |
|
| |
|
|
|
|
|
|
|
|
|
PROPERTY AND EQUIPMENT
|
|
|
|
|
|
|
|
|
|
Oil and gas properties (successful efforts method of accounting)
|
|
|
663,414,446 |
|
|
|
590,248,138 |
|
|
Other property and equipment
|
|
|
3,345,798 |
|
|
|
3,345,798 |
|
|
Accumulated depreciation, depletion and amortization
|
|
|
(269,978,945 |
) |
|
|
(213,547,504 |
) |
|
Total property and equipment, net
|
|
|
396,781,299 |
|
|
|
380,046,432 |
|
| |
|
|
|
|
|
|
|
|
|
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
|
|
Deposits
|
|
|
34,743 |
|
|
|
34,743 |
|
|
Debt issuance cost
|
|
|
1,140,031 |
|
|
|
2,364,469 |
|
|
Deferred tax asset, net
|
|
|
17,297,621 |
|
|
|
2,678,966 |
|
|
Total noncurrent assets
|
|
|
18,472,395 |
|
|
|
5,078,178 |
|
| |
|
|
|
|
|
|
|
|
|
TOTAL ASSETS
|
|
$ |
436,325,874 |
|
|
$ |
412,686,826 |
|
| |
| |
|
CURRENT LIABILITIES
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$ |
49,539,258 |
|
|
$ |
30,795,692 |
|
|
Accrued liabilities
|
|
|
16,131,324 |
|
|
|
12,799,176 |
|
|
Asset retirement obligations
|
|
|
935,705 |
|
|
|
732,126 |
|
|
Derivative instruments
|
|
|
290,703 |
|
|
|
3,043,078 |
|
|
Deferred tax liability, net
|
|
|
189,146 |
|
|
|
— |
|
|
Total current liabilities
|
|
|
67,086,136 |
|
|
|
47,370,072 |
|
| |
|
|
|
|
|
|
|
|
|
NONCURRENT LIABILITIES
|
|
|
|
|
|
|
|
|
|
Long-term debt, net of current portion
|
|
|
190,041,933 |
|
|
|
172,013,490 |
|
|
Asset retirement obligations
|
|
|
9,071,064 |
|
|
|
9,101,895 |
|
|
Other noncurrent liabilities
|
|
|
621,043 |
|
|
|
670,398 |
|
|
Total noncurrent liabilities
|
|
|
199,734,040 |
|
|
|
181,785,783 |
|
| |
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
266,820,176 |
|
|
|
229,155,855 |
|
| |
|
|
|
|
|
|
|
|
|
COMMITMENTS AND CONTINGENCIES (see Note 10)
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
|
|
Common stock (Par value $0.001; 200,000,000 shares authorized; 45,270,768 and 44,952,405 shares issued and 45,129,407 and 44,857,259 shares outstanding as of December 31, 2011 and 2010, respectively)
|
|
|
45,271 |
|
|
|
44,952 |
|
|
Additional paid-in capital
|
|
|
243,484,877 |
|
|
|
241,488,749 |
|
|
Retained deficit
|
|
|
(73,352,170 |
) |
|
|
(57,506,788 |
) |
|
Treasury stock (At cost, 141,361 and 95,146 shares as of December 31, 2011 and 2010, respectively)
|
|
|
(672,280 |
) |
|
|
(495,942 |
) |
|
Total stockholders’ equity
|
|
|
169,505,698 |
|
|
|
183,530,971 |
|
| |
|
|
|
|
|
|
|
|
|
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
|
|
$ |
436,325,874 |
|
|
$ |
412,686,826 |
|
The Notes to Consolidated Financial Statements are an integral part of these statements.
|
CRIMSON EXPLORATION INC. AND SUBSIDIARIES
|
|
|
CONSOLIDATED STATEMENTS OF OPERATIONS
|
|
| |
|
|
|
|
|
|
|
|
|
| |
|
For the Years Ended December 31,
|
|
| |
|
2011
|
|
|
2010
|
|
|
2009
|
|
| |
|
|
|
|
|
|
|
|
|
|
OPERATING REVENUES
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales
|
|
$ |
56,666,485 |
|
|
$ |
59,861,551 |
|
|
$ |
71,494,889 |
|
|
Crude oil sales
|
|
|
36,760,014 |
|
|
|
22,021,906 |
|
|
|
27,283,772 |
|
|
Natural gas liquids sales
|
|
|
20,209,534 |
|
|
|
14,048,766 |
|
|
|
13,024,103 |
|
|
Operating overhead and other income
|
|
|
721,472 |
|
|
|
609,744 |
|
|
|
644,882 |
|
|
Total operating revenues
|
|
|
114,357,505 |
|
|
|
96,541,967 |
|
|
|
112,447,646 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
13,273,760 |
|
|
|
15,001,954 |
|
|
|
17,358,670 |
|
|
Production and ad valorem taxes
|
|
|
6,732,545 |
|
|
|
6,061,033 |
|
|
|
7,131,400 |
|
|
Exploration expenses
|
|
|
995,412 |
|
|
|
967,322 |
|
|
|
2,723,953 |
|
|
Depreciation, depletion and amortization
|
|
|
56,920,515 |
|
|
|
45,022,272 |
|
|
|
53,294,809 |
|
|
Impairment and abandonment of oil and gas properties
|
|
|
14,954,633 |
|
|
|
22,254,059 |
|
|
|
6,721,215 |
|
|
General and administrative
|
|
|
19,068,400 |
|
|
|
20,480,608 |
|
|
|
18,757,981 |
|
|
Loss on sale of assets
|
|
|
— |
|
|
|
1,069,616 |
|
|
|
6,847,454 |
|
|
Total operating expenses
|
|
|
111,945,265 |
|
|
|
110,856,864 |
|
|
|
112,835,482 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME (LOSS) FROM OPERATIONS
|
|
|
2,412,240 |
|
|
|
(14,314,897 |
) |
|
|
(387,836 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER INCOME (EXPENSE)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net of amount capitalized
|
|
|
(25,104,073 |
) |
|
|
(22,324,535 |
) |
|
|
(23,172,082 |
) |
|
Other financing costs
|
|
|
(1,706,812 |
) |
|
|
(4,311,779 |
) |
|
|
(3,341,854 |
) |
|
Unrealized (loss) gain on derivative instruments
|
|
|
454,906 |
|
|
|
(6,500,825 |
) |
|
|
(23,862,580 |
) |
|
Total other income (expense)
|
|
|
(26,355,979 |
) |
|
|
(33,137,139 |
) |
|
|
(50,376,516 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
LOSS BEFORE INCOME TAXES
|
|
|
(23,943,739 |
) |
|
|
(47,452,036 |
) |
|
|
(50,764,352 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Tax Benefit
|
|
|
8,098,357 |
|
|
|
16,607,139 |
|
|
|
16,694,362 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
NET LOSS
|
|
|
(15,845,382 |
) |
|
|
(30,844,897 |
) |
|
|
(34,069,990 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends on Preferred Stock
|
|
|
— |
|
|
|
— |
|
|
|
(4,522,645 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
NET LOSS AVAILABLE TO COMMON STOCKHOLDERS
|
|
$ |
(15,845,382 |
) |
|
$ |
(30,844,897 |
) |
|
$ |
(38,592,635 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
NET LOSS PER SHARE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$ |
(0.35 |
) |
|
$ |
(0.78 |
) |
|
$ |
(4.91 |
) |
|
Diluted
|
|
$ |
(0.35 |
) |
|
$ |
(0.78 |
) |
|
$ |
(4.91 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED AVERAGE SHARES OUTSTANDING
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
44,788,551 |
|
|
|
39,397,486 |
|
|
|
7,861,054 |
|
|
Diluted
|
|
|
44,788,551 |
|
|
|
39,397,486 |
|
|
|
7,861,054 |
|
The Notes to Consolidated Financial Statements are an integral part of these statements.
|
CRIMSON EXPLORATION INC. AND SUBSIDIARIES
|
|
|
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
|
|
|
FOR THE YEARS ENDED DECEMBER 31, 2011, 2010 AND 2009
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
NUMBER OF SHARES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
OUTSTANDING
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
PREFERRED STOCK
|
|
|
COMMON STOCK
|
|
|
PREFERRED STOCK
|
|
|
COMMON STOCK
|
|
|
ADDITIONAL
PAID-IN CAPITAL
|
|
|
RETAINED EARNINGS (DEFICIT)
|
|
|
TREASURY STOCK
|
|
|
TOTAL STOCKHOLDERS’ EQUITY
|
|
|
BALANCE, DECEMBER 31, 2008
|
|
|
82,600 |
|
|
|
5,787,287 |
|
|
$ |
826 |
|
|
$ |
5,808 |
|
|
$ |
95,676,875 |
|
|
$ |
26,189,888 |
|
|
$ |
(250,594 |
) |
|
$ |
121,622,803 |
|
|
Current year net loss
|
|
|
— |
|
|
|
|
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(34,069,990 |
) |
|
|
— |
|
|
|
(34,069,990 |
) |
|
Share-based compensation
|
|
|
— |
|
|
|
661,156 |
|
|
|
— |
|
|
|
661 |
|
|
|
2,400,231 |
|
|
|
— |
|
|
|
— |
|
|
|
2,400,892 |
|
|
Preferred G converted
|
|
|
(80,500 |
) |
|
|
8,050,000 |
|
|
|
(805 |
) |
|
|
8,050 |
|
|
|
(7,245 |
) |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
Preferred H converted
|
|
|
(2,100 |
) |
|
|
300,001 |
|
|
|
(21 |
) |
|
|
300 |
|
|
|
(279 |
) |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
Dividends paid on preferred stock
|
|
|
— |
|
|
|
3,759,135 |
|
|
|
— |
|
|
|
3,759 |
|
|
|
18,778,030 |
|
|
|
(18,781,789 |
) |
|
|
— |
|
|
|
— |
|
|
Common stock issuance
|
|
|
— |
|
|
|
20,000,000 |
|
|
|
— |
|
|
|
20,000 |
|
|
|
92,890,901 |
|
|
|
— |
|
|
|
— |
|
|
|
92,910,901 |
|
|
Treasury stock
|
|
|
— |
|
|
|
(40,921 |
) |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(133,718 |
) |
|
|
(133,718 |
) |
|
BALANCE, DECEMBER 31, 2009
|
|
|
— |
|
|
|
38,516,658 |
|
|
|
— |
|
|
|
38,578 |
|
|
|
209,738,513 |
|
|
|
(26,661,891 |
) |
|
|
(384,312 |
) |
|
|
182,730,888 |
|
|
Current year net loss
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(30,844,897 |
) |
|
|
— |
|
|
|
(30,844,897 |
) |
|
Share-based compensation
|
|
|
— |
|
|
|
374,201 |
|
|
|
— |
|
|
|
374 |
|
|
|
1,856,771 |
|
|
|
— |
|
|
|
— |
|
|
|
1,857,145 |
|
|
Common stock issuance
|
|
|
— |
|
|
|
6,000,000 |
|
|
|
— |
|
|
|
6,000 |
|
|
|
29,893,465 |
|
|
|
— |
|
|
|
— |
|
|
|
29,899,465 |
|
|
Treasury stock
|
|
|
— |
|
|
|
(33,600 |
) |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(111,630 |
) |
|
|
(111,630 |
) |
|
BALANCE, DECEMBER 31, 2010
|
|
|
— |
|
|
|
44,857,259 |
|
|
|
— |
|
|
|
44,952 |
|
|
|
241,488,749 |
|
|
|
(57,506,788 |
) |
|
|
(495,942 |
) |
|
|
183,530,971 |
|
|
Current year net loss
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(15,845,382 |
) |
|
|
— |
|
|
|
(15,845,382 |
) |
|
Share-based compensation
|
|
|
— |
|
|
|
318,363 |
|
|
|
— |
|
|
|
319 |
|
|
|
1,996,128 |
|
|
|
— |
|
|
|
— |
|
|
|
1,996,447 |
|
|
Treasury stock
|
|
|
— |
|
|
|
(46,215 |
) |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(176,338 |
) |
|
|
(176,338 |
) |
|
BALANCE, DECEMBER 31, 2011
|
|
|
— |
|
|
|
45,129,407 |
|
|
$ |
— |
|
|
$ |
45,271 |
|
|
$ |
243,484,877 |
|
|
$ |
(73,352,170 |
) |
|
$ |
(672,280 |
) |
|
$ |
169,505,698 |
|
The Notes to Consolidated Financial Statements are an integral part of these statements.
|
CRIMSON EXPLORATION INC. AND SUBSIDIARIES
|
|
|
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
| |
|
|
|
| |
|
For the Years ended December 31,
|
|
| |
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
CASH FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$ |
(15,845,382 |
) |
|
$ |
(30,844,897 |
) |
|
$ |
(34,069,990 |
) |
|
Adjustments to reconcile net loss to net cash provided by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
56,920,515 |
|
|
|
45,022,272 |
|
|
|
53,294,809 |
|
|
Asset retirement obligations
|
|
|
(392,861 |
) |
|
|
(162,668 |
) |
|
|
(375,149 |
) |
|
Stock compensation expense
|
|
|
1,935,886 |
|
|
|
1,789,031 |
|
|
|
2,400,892 |
|
|
Amortization of financing costs and discounts
|
|
|
2,321,158 |
|
|
|
4,192,875 |
|
|
|
3,167,481 |
|
|
Deferred charges
|
|
|
— |
|
|
|
— |
|
|
|
1,324,907 |
|
|
Deferred income taxes
|
|
|
(8,098,357 |
) |
|
|
(16,378,441 |
) |
|
|
(16,572,200 |
) |
|
Impairment and abandonment of oil and gas properties
|
|
|
14,954,633 |
|
|
|
22,254,059 |
|
|
|
6,721,215 |
|
|
Loss on sale of assets
|
|
|
— |
|
|
|
1,069,616 |
|
|
|
6,847,454 |
|
|
Unrealized loss (gain) on derivative instruments
|
|
|
(454,906 |
) |
|
|
6,500,825 |
|
|
|
23,862,580 |
|
|
Provision for bad debts
|
|
|
445 |
|
|
|
167,819 |
|
|
|
239,676 |
|
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Increase) decrease in accounts receivable, net
|
|
|
(1,534,180 |
) |
|
|
379,494 |
|
|
|
6,065,890 |
|
|
(Increase) decrease in prepaid expenses
|
|
|
(304,849 |
) |
|
|
(168,766 |
) |
|
|
77,293 |
|
|
Increase (decrease) in accounts payable and accrued liabilities
|
|
|
22,148,113 |
|
|
|
14,188,815 |
|
|
|
(43,329,185 |
) |
|
Net cash provided by operating activities
|
|
|
71,650,215 |
|
|
|
48,010,034 |
|
|
|
9,655,673 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(87,511,475 |
) |
|
|
(54,745,840 |
) |
|
|
(21,893,154 |
) |
|
Acquisition of oil and gas properties
|
|
|
(954,687 |
) |
|
|
— |
|
|
|
493,532 |
|
|
Sale of assets
|
|
|
— |
|
|
|
(224,776 |
) |
|
|
7,553,480 |
|
|
Deposits
|
|
|
— |
|
|
|
69,954 |
|
|
|
— |
|
|
Net cash used in investing activities
|
|
|
(88,466,162 |
) |
|
|
(54,900,662 |
) |
|
|
(13,846,142 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments on debt
|
|
|
(139,975,774 |
) |
|
|
(286,802,034 |
) |
|
|
(196,079,649 |
) |
|
Proceeds from debt
|
|
|
156,953,711 |
|
|
|
265,783,020 |
|
|
|
110,367,869 |
|
|
Proceeds from issuance of common stock
|
|
|
60,562 |
|
|
|
29,967,579 |
|
|
|
92,910,901 |
|
|
Debt issuance expenditures
|
|
|
(46,214 |
) |
|
|
(1,946,307 |
) |
|
|
(2,874,934 |
) |
|
Purchase of treasury stock
|
|
|
(176,338 |
) |
|
|
(111,630 |
) |
|
|
(133,718 |
) |
|
Net cash provided by financing activities
|
|
|
16,815,947 |
|
|
|
6,890,628 |
|
|
|
4,190,469 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of year
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid for interest
|
|
$ |
24,618,488 |
|
|
$ |
25,982,510 |
|
|
$ |
20,092,443 |
|
|
Cash paid for income taxes
|
|
$ |
— |
|
|
$ |
22,233 |
|
|
$ |
173,851 |
|
The Notes to Consolidated Financial Statements are an integral part of these statements.
CRIMSON EXPLORATION INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
1.
|
Organization and Nature of Operations
|
Crimson Exploration Inc., together with its subsidiaries, (“Crimson”, “we”, “our”, “us”) is an independent energy company engaged in the acquisition, exploitation, exploration and development of natural gas and crude oil properties. We have historically focused our operations in the onshore U.S. Gulf Coast and South Texas regions, which are generally characterized by high rates of return in known, prolific producing trends. We have expanded our strategic focus to include longer reserve life resource plays that we believe provide significant long-term growth potential in multiple formations. We are also focusing on further developing our oil/liquid weighted assets.
We intend to grow reserves and production by developing our existing producing property base, developing our East Texas and South Texas resource potential, and pursuing opportunistic acquisitions in areas where we have specific operating expertise. We have developed a significant project inventory of associated with our existing property base. Our technical team has a successful track record of adding reserves through the drill bit. Since January 2008, we have drilled 56 gross (26.9 net) wells with an overall success rate of 93%. At December 31, 2011, we had 4 wells in progress.
As of December 31, 2011, our proved reserves, as estimated by Netherland, Sewell & Associates, Inc. (“NSAI”), our independent petroleum engineering firm, in accordance with reserve reporting guidelines mandated by the SEC, were 200.4 Bcfe, consisting of 162.7 Bcf of natural gas and 6.3 MMBbl of crude oil, condensate and natural gas liquids, with a PV-10 of $266.5 million. As of December 31, 2011, 81% of our proved reserves were natural gas, 37% were proved developed and 87% were attributed to wells and properties operated by us. During 2011 we grew proved reserves to 200.4 Bcfe at December 31, 2011 from 166.5 Bcfe at December 31, 2010. Our average daily production increased to 45.4 MMcfe/d for the twelve months ended December 31, 2011 from 35.4 MMcfe/d for the twelve months ended December 31, 2010.
|
2.
|
Summary of Significant Accounting Policies
|
Basis of Presentation
Our consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States. Our operations are considered to fall within a single industry segment, which is the acquisition, development, exploitation and production of natural gas and crude oil properties in the United States. All significant intercompany balances and transactions have been eliminated upon consolidation. Certain reclassifications have been made to the prior year financial statements to conform to the current year presentation. Significant policies are discussed below.
Cash and Cash Equivalents
We consider all highly liquid investment instruments purchased with remaining maturities of three months or less to be cash equivalents for purposes of the consolidated statements of cash flows and other statements. We maintain cash on deposit in non-interest bearing accounts, which, at times, exceed federally insured limits. We have not experienced any losses on such accounts and believe we are not exposed to any significant credit risk on cash and equivalents.
Oil and Gas Properties
We use the successful efforts method of accounting for natural gas and crude oil producing activities. Costs to acquire mineral interests in natural gas and crude oil properties are capitalized. Costs to drill and develop development wells and costs to drill and develop exploratory wells that find proved reserves are also capitalized. Costs to drill exploratory wells are capitalized pending determination of whether the well has found proved reserves in economically producible quantities. We assess the status of suspended exploratory well costs on a quarterly basis.
Costs to drill exploratory wells that do not find proved reserves, delay rentals and geological and geophysical costs are expensed (except those costs used to determine a drill site location). The costs of unproved leaseholds, including interest costs associated with in-progress period activities incurred prior to bringing those projects to their intended use, are capitalized pending the results of exploration efforts.
Gains and losses on disposal or retirements that are significant are included in income from operations on our Consolidated Statements of Operations.
Oil and Gas Reserves
The estimates of proved natural gas, crude oil and natural gas liquids reserves utilized in the preparation of the financial statements are estimated in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and the Financial Accounting Standards Board (“FASB”), which require that reserve estimates be prepared under existing economic and operating conditions using a 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements.
We emphasize that reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. Our policy is to deplete capitalized natural gas, crude oil and natural gas liquids costs on the unit of production method, based upon these reserve estimates. It is possible that, because of changes in market conditions or the inherent imprecise nature of these reserve estimates, that the estimates of future cash inflows, future gross revenues, the amount of natural gas, crude oil and natural gas liquids reserves, the remaining estimated lives of the natural gas and crude oil properties, or any combination of the above may be increased or reduced. See Note 17 – “Oil and Gas Reserves (unaudited)” for further information.
Other Property and Equipment
Other property and equipment consist primarily of furniture and fixtures, field vehicles, office equipment, computer equipment and software.
Depreciation, depletion and amortization
Depreciation, depletion and amortization (“DD&A”) of capitalized drilling and development costs of producing natural gas and crude oil properties, including related support equipment and facilities and net of salvage value, are computed using the unit-of-production method on a field basis based on total estimated proved developed natural gas and crude oil reserves. Amortization of producing leaseholds is based on the unit-of-production method using total estimated proved reserves. Upon sale or retirement of properties, the cost and related accumulated depreciation, depletion and amortization are eliminated from the accounts and the resulting gain or loss, if any, is recognized. Unit-of-production rates are revised whenever there is an indication of a need, but at least annually. Revisions are accounted for prospectively as changes in accounting estimates.
Other property and equipment are depreciated using the straight-line method over their estimated useful lives which range between 3 and 13 years.
Impairment of Oil and Gas Properties
Proved natural gas and crude oil properties are reviewed for impairment on a field basis when events and circumstances indicate a possible decline in the recoverability of the carrying value of such property. Impairments, measured using fair market value, are recognized whenever events or changes in circumstances indicate that the carrying amount of long-lived assets may not be recoverable and the future undiscounted cash flows attributable to the asset are less than its carrying value. Estimated fair values are determined using discounted cash flow models. The discounted cash flow models include management’s estimates of future oil and gas production, commodity prices based on forward commodity price curves as of the date of the estimate, operating and development costs, and discount rates.
Unproved properties are regularly assessed on a property-by-property basis for the impairment of individual unproved properties whose acquisition costs are relatively significant. Unproved properties whose acquisition costs are not relatively significant are amortized in the aggregate over the lesser of three years or the average remaining
lease term. As exploration work progresses and the reserves on significant properties are proven, capitalized costs of these properties will be subject to depreciation and depletion. If the exploration work is unsuccessful, the capitalized costs of the properties related to the unsuccessful work will be charged to exploration expense. The timing of any write-downs of these unproven properties, if warranted, depends upon the nature, timing and extent of future exploration and development activities and their results.
See Note 4 - "Oil and Gas Properties" for further information.
Asset Retirement Obligations
We recognize an estimated liability for the plugging and abandonment of our natural gas and crude oil wells and associated pipelines and equipment. The liability and the associated increase in the related long-lived asset are recorded in the period in which the related assets are placed in service or acquired. The liability is accreted to its present value each period and the capitalized cost is depleted over the useful life of the related asset. The accretion expense is included in depreciation, depletion and amortization expense.
The estimated liability is based on historical experience in plugging and abandoning wells. The estimated remaining lives of the wells is based on reserve life estimates and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free rate.
Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs, changes in the risk-free rate or changes in the remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. At the time of abandonment, we recognize a gain or loss on abandonment to the extent that actual costs do not equal the estimated costs. This gain or loss on abandonment is included in impairment and abandonment of oil and gas properties expense.
See Note 8 – “Asset Retirement Obligations” for further information.
Revenue Recognition and Oil and Gas Imbalances
We follow the “sales” method of accounting for natural gas, crude oil and natural gas liquids revenues. Under this method, we recognize revenues on production as it is taken and delivered to its purchasers. The volumes sold may be more or less than the volumes we are entitled to based on our ownership interest in the property. These differences result in a condition known in the industry as a production imbalance. Our crude oil and natural gas imbalances are not significant.
Trade Accounts Receivable
We grant credit to creditworthy independent and major natural gas and crude oil marketing companies for the sale of natural gas, crude oil and natural gas liquids. In addition, we grant credit to our oil and gas working interest partners. Receivables from our working interest partners are generally secured by the underlying ownership interests in the properties.
The accounts receivable (“A/R”) balance at year-end primarily relates to A/R Trade (net of allowance for doubtful accounts), A/R joint interest billing (net of legal suspense/prepayments from partners), Accrued revenue (two months for operated properties, three months for non-operated properties), and A/R Other. Accrued revenue is recorded net to our interest (excludes outside interest holders).
The allowance for doubtful accounts is recognized by management based upon a review of specific customer balances, historical losses and general economic conditions. The allowance for doubtful accounts at December 31, 2011 and 2010 was $579,588 and $579,143, respectively.
Fair Value Measurements
Accounting guidance establishes a single authoritative definition of fair value based upon the assumptions market participants would use when pricing an asset or liability and creates a fair value hierarchy that prioritizes the
information used to develop those assumptions. Additional disclosures are required, including disclosures of fair value measurements by level within the fair value hierarchy. We incorporate a credit risk assumption into the measurement of certain assets and liabilities. See Note 5 – “Fair Value Measurements” for further information.
Debt Issuance Costs
Debt issuance costs incurred are capitalized and subsequently amortized over the term of the related debt.
Share-Based Compensation
We measure the grant date fair value of stock options and other stock-based compensation issued to employees and directors and expense the fair value over the requisite service period of the award. It is our policy to issue new shares for any options exercised. We use the Black-Scholes option pricing model to measure the fair value of stock options.
We estimate forfeitures based on historical data in calculating the expense related to stock-based compensation as opposed to recognizing forfeitures as they occur. All of our unvested options are held by our executive officers, employees and directors. See Note 11 – “Share-Based Compensation” for further information.
Income Taxes
Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized when items of income and expense are recognized in the financial statements in different periods than when recognized in the applicable tax return. Deferred tax assets arise when expenses are recognized in the financial statements before the tax returns or when income items are recognized in the tax return prior to the financial statements. Deferred tax assets also arise when operating losses or tax credits are available to offset tax payments due in future years. Deferred tax liabilities arise when income items are recognized in the financial statements before the tax returns or when expenses are recognized in the tax return prior to the financial statements. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the date when the change in the tax rate was enacted.
We routinely assess the realizability of our deferred tax assets. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the tax asset is reduced by a valuation allowance. In addition we routinely assess uncertain tax positions, and accrue for tax positions that are not more-likely-than-not to be sustained upon examination by taxing authorities. See Note 14 - "Income Taxes" for further information.
Recently Issued Accounting Standards
In January 2010, the Financial Accounting Standards Board (“FASB”)issued Accounting Standards Update No. 2010-06 “Fair Value Measurements and Disclosures (Topic 820) – Improving Disclosures about Fair Value Measurements”. The guidance requires disclosure of transfers of assets and liabilities between Level 1 and Level 2 in the fair value measurement hierarchy, including the reasons for the transfers and disclosure of major purchases, sales, issuances, and settlements on a gross basis in the reconciliation of the assets and liabilities measured under Level 3 of the fair value measurement hierarchy. The guidance was effective for interim and annual periods beginning after December 15, 2009, except for the Level 3 reconciliation disclosures, which are effective for interim and annual periods beginning after December 15, 2010. We adopted the provisions for the quarter ended March 31, 2010, except for the Level 3 reconciliation disclosures, which we adopted for the quarter ended March 31, 2011. Adopting the disclosure requirements did not have a material impact on our financial position or results of operations.
In May 2011, the FASB issued Accounting Standards Update No. 2011—04: “Fair Value Measurement (Topic 820) – Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs”. This accounting update clarifies application of fair value measurement and disclosure requirements and is
effective for annual periods beginning after December 15, 2011. We are currently evaluating the provisions of this accounting update and assessing the impact, if any, it may have on our financial position and results of operations.
In December 2011, the FASB issued Accounting Standards Update No. 2011—11 “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities”. This accounting update requires that an entity disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. The accounting update is effective for annual periods beginning on or after January 1, 2013. We are currently evaluating the provisions of this accounting update and assessing the impact, if any, it may have on our financial position and results of operations.
3. Use of Estimates
The preparation of consolidated financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates included in the consolidated financial statements are: (1) natural gas, crude oil and natural gas liquids revenues and reserves; (2) depreciation, depletion and amortization; (3) valuation allowances associated with income taxes and accounts receivables; (4) accrued assets and liabilities; (5) stock-based compensation; (6) asset retirement obligations (“AROs”); (7) valuation of derivative instruments and (8) impairment of oil and gas properties. Although management believes these estimates are reasonable, changes in facts and circumstances or discovery of new information may result in revised estimates. Actual results could differ from those estimates.
In July 2011 we changed our lease operating accrual process for direct operating expenses. The change in the accrual process was a direct result of an in depth analysis of recent historical information combined with better insight and improved judgment in estimating direct operating expenses. In accordance with Accounting Standards Codification 250 “Accounting Changes and Error Corrections” (“ASC 250”) we have treated the adjustment as a change in accounting estimate. A change in estimate under ASC 250 is defined as a revision in accounting measurement based on the occurrence of new events, additional experience, subsequent developments, better insight, and/or improved judgment. As required under ASC 250 regarding changes in accounting estimates, we recorded a $2.3 million reduction to accrued liabilities (and related lease operating expenses) in the “period of change” which we have interpreted to be the third quarter of 2011.
|
4.
|
Oil and Gas Properties
|
The following tables set forth certain information with respect to our oil and gas producing activities (all within the United States) for the periods presented:
The following table sets forth the composition of exploration expenses:
| |
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
Lease rental expense
|
|
$ |
— |
|
|
$ |
70,839 |
|
|
$ |
224,258 |
|
|
Geological and geophysical
|
|
|
374,782 |
|
|
|
591,909 |
|
|
|
1,733,426 |
|
|
Settled asset retirement obligations
|
|
|
620,630 |
|
|
|
304,574 |
|
|
|
766,269 |
|
| |
|
$ |
995,412 |
|
|
$ |
967,322 |
|
|
$ |
2,723,953 |
|
The following table sets forth the composition of impairment and abandonment expenses:
| |
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
Impairment and abandonment of proved properties
|
|
$ |
— |
|
|
$ |
473,105 |
|
|
$ |
5,658,898 |
|
|
Impairment and abandonment of unproved properties
|
|
|
14,954,633 |
|
|
|
21,780,954 |
|
|
|
1,062,317 |
|
| |
|
$ |
14,954,633 |
|
|
$ |
22,254,059 |
|
|
$ |
6,721,215 |
|
2011 Asset Impairments. Non-cash impairments of unproved properties include $12.2 million related to our East Texas acreage and $2.8 million related to individually insignificant acreage.
2010 Asset Impairments. Following a change in strategic focus from gas to oil-weighted opportunities, we re-allocated our future capital budget. As a result of this change in strategy, we incurred a $22.3 million non-cash impairment expense primarily related to our East Texas acreage.
2009 Asset Impairments. Due to declines in natural gas prices and recent drilling results, we determined that the carrying amount of certain conventional South Texas and Southwest Louisiana properties were impaired which resulted in a $6.7 million non-cash impairment expense.
The following table shows oil and gas property dispositions:
| |
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
Oil and gas properties
|
|
$ |
— |
|
|
$ |
2,601,997 |
|
|
$ |
42,995,459 |
|
|
Accumulated depreciation, depletion, amortization and impairments
|
|
|
— |
|
|
|
(1,406,066 |
) |
|
|
(23,158,221 |
) |
|
Net oil and gas properties
|
|
$ |
— |
|
|
$ |
1,195,931 |
|
|
$ |
19,837,238 |
|
The dispositions resulted in a net loss of zero, $1.1 million and $6.8 million for 2011, 2010 and 2009, respectively.
We have capitalized $3.5 million and zero, respectively, in exploratory well costs pending determination of proved reserves for periods less than one year at December 31, 2011 and 2010. We have not capitalized exploratory well costs for periods greater than one year at December 31, 2011 and 2010.
|
5.
|
Fair Value Measurements
|
Certain of our assets and liabilities are reported at fair value in our consolidated balance sheets. The following methods and assumptions were used to estimate the fair values for each class of financial instruments:
Cash and Cash Equivalents, Accounts Receivable and Accounts Payable. The carrying amounts approximate fair value due to the short-term nature or maturity of the instruments.
Derivative Instruments. Our derivative instruments consist of variable to fixed price commodity swaps, costless collars and interest rate swaps. The fair value measurement of our unrealized natural gas, crude oil and interest rate swaps and collars were obtained from financial institutions and adjusted for non-performance risk, and were evaluated for accuracy using our crude oil, natural gas and interest rate swap and collar agreements and future commodity and interest rate curves. Differences between management’s calculation and that of the financial institution were evaluated for reasonableness. See Note 6 – “Derivative Instruments” for further information.
Impairments. We review proved oil and gas properties for impairment when events and circumstances indicate a decline in the recoverability of the carrying value of such properties, such as a downward revision of the reserve estimates or lower commodity prices. We estimate the future cash flows expected in connection with the properties and compare such future cash flows to the carrying amounts of the properties to determine if the carrying amounts are recoverable. The factors used to determine fair value include, but are not limited to, estimates of proved and probable reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Because these significant fair value inputs are typically not observable, we classify impairments of long-lived assets as a level 3 fair value measure.
Asset Retirement Obligations. The initial measurement of ARO at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. The factors used to determine fair value include, but are not limited to, plugging costs and reserve lives.
Debt. The fair value of floating-rate debt is estimated to be equivalent to carrying amounts because the interest rates paid on such debt are set for periods of three months or less. See Note 9 - “Debt” for further information.
FASB guidance established a fair value hierarchy which prioritizes the inputs to valuation techniques used to measure fair value into three levels. The fair value hierarchy gives the highest priority to quoted market prices (unadjusted) in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 inputs are inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly. There have been no transfers between Level 1, Level 2 or Level 3.
Fair value information for financial assets and (liabilities) was as follows at December 31, 2011:
| |
|
Total
|
|
|
Fair Value Measurements Using
|
|
| |
|
Carrying Value
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity price contracts
|
|
$ |
4,248,194 |
|
|
$ |
— |
|
|
$ |
4,248,194 |
|
|
$ |
— |
|
Fair value information for financial assets and (liabilities) was as follows at December 31, 2010:
| |
|
Total
|
|
|
Fair Value Measurements Using
|
|
| |
|
Carrying Value
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity price contracts
|
|
$ |
5,186,028 |
|
|
$ |
— |
|
|
$ |
5,186,028 |
|
|
$ |
— |
|
|
Interest rate swaps
|
|
|
(1,392,740 |
) |
|
|
— |
|
|
|
(1,392,740 |
) |
|
|
— |
|
|
Total
|
|
$ |
3,793,288 |
|
|
$ |
— |
|
|
$ |
3,793,288 |
|
|
$ |
— |
|
Fair value information for non-financial assets and (liabilities) valued on a non-recurring basis was as follows:
| |
|
Carrying
|
|
|
Fair Value Measurements Using
|
|
|
Total Pre-tax (Non-cash) Impairment
|
|
| |
|
Value (1)
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Loss
|
|
|
Year Ended December 31, 2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment of proved properties
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
Year Ended December 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment of proved properties
|
|
|
2,320,977 |
|
|
|
— |
|
|
|
— |
|
|
|
1,847,872 |
|
|
|
473,105 |
|
|
Year Ended December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment of proved properties
|
|
|
8,843,822 |
|
|
|
— |
|
|
|
— |
|
|
|
3,184,924 |
|
|
|
5,658,898 |
|
(1) Amounts represent carrying value at the time of the assessment.
See Note 4 - “Oil and Gas Properties” for a discussion of the methods and assumptions used to estimate the fair values of the impaired assets.
|
6.
|
Derivative Instruments
|
At the end of each reporting period we record on our balance sheet the mark-to-market valuation of our derivative instruments. We recorded net assets for derivative instruments of $4.2 million and $3.8 million at December 31, 2011 and December 31, 2010, respectively. As a result of these agreements, we recorded a non-cash unrealized gain for unsettled contracts, of $0.5 million for the year ended December 31, 2011, and non-cash unrealized losses for unsettled contracts of $6.5 million and $23.9 million for the years ended December 31, 2010 and 2009, respectively. The estimated change in fair value of the derivatives is reported in other income (expense) as unrealized gain (loss) on derivative instruments. The realized gain (loss) on derivative instruments is included in
natural gas, crude oil and natural gas liquids sales for our commodity price hedges and as an (increase) decrease in interest expense for our interest rate swaps. Our final interest rate swap terminated on May 8, 2011.
In the past we have entered into, and may in the future enter into, certain derivative arrangements with respect to portions of our natural gas and crude oil production, to reduce our sensitivity to volatile commodity prices, and with respect to portions of our debt, to reduce our sensitivity to volatile interest rates. None of our derivative instruments are designated as cash flow or fair value hedges. We believe that these derivative arrangements, although not free of risk, allow us to achieve a more predictable cash flow and to reduce exposure to commodity price and interest rate fluctuations. However, derivative arrangements limit the benefit of increases in the prices of natural gas, crude oil and natural gas liquids sales and limit the benefit of decreases in interest rates. Moreover, our derivative arrangements apply only to a portion of our production and our debt and provide only partial protection against declines in commodity prices and increases in interest rates, respectively. Such arrangements may expose us to risk of financial loss in certain circumstances. We continuously reevaluate our hedging programs in light of changes in production, market conditions, commodity price forecasts, capital spending, interest rate forecasts and debt service requirements.
We use a mix of commodity swaps, put options, costless collars and interest rate swaps to accomplish our hedging strategy. Derivative assets and liabilities with the same counterparty, subject to contractual terms which provide for net settlement, are reported on a net basis on our consolidated balance sheets. We have exposure to financial institutions in the form of derivative transactions in connection with our hedges. These transactions are with counterparties in the financial services industry, and specifically with members of our bank group. These transactions could expose us to credit risk in the event of default of our counterparties. We believe our counterparty risk is low in part because of the offsetting relationship we have with each of our counterparties provided for in our revolving credit agreement and various hedge contracts. See Note 5 - “Fair Value Measurements” for further information.
The following derivative contracts were in place at December 31, 2011:
|
Crude Oil
|
|
|
|
Volume/Month
|
|
Price/Unit
|
|
Fair Value
|
|
|
Jan 2012-Dec 2012
|
|
Collar
|
|
5,100 Bbls
|
|
$80.00-$107.30
|
$
|
(133,586
|
)
|
|
Jan 2012-Dec 2012
|
|
Collar
|
|
5,000 Bbls
|
|
$85.00-$102.70
|
|
(169,166
|
)
|
|
Jan 2012-Dec 2012
|
|
Collar
|
|
4,500 Bbls
|
|
$90.00-$110.46
|
|
65,659
|
|
|
Jan 2012-Dec 2012
|
|
Swap
|
|
11,000 Bbls
|
|
$101.35
|
|
75,109
|
|
|
Apr 2012-June 2012
|
|
Swap
|
|
9,000 Bbls
|
|
$100.75
|
|
37,480
|
|
|
Jul 2012-Sep 2012
|
|
Swap
|
|
8,000 Bbls
|
|
$99.28
|
|
12,048
|
|
|
Oct 2012-Dec 2012
|
|
Swap
|
|
6,000 Bbls
|
|
$98.05
|
|
2,305
|
|
| |
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
Jan 2012-Dec 2012
|
|
Put
|
|
320,000 Mmbtu
|
|
$5.00
|
|
4,358,345
|
|
| |
|
|
|
|
|
|
|
|
|
|
Total net fair value of derivative instruments
|
$
|
4,248,194
|
|
We entered into the following commodity swaps with a counterparty in our bank group on February 16, 2012:
|
Crude Oil
|
|
|
|
Volume/Month
|
|
Price/Unit
|
|
|
Mar 2012-Jun 2012
|
|
Swap
|
|
13,000 Bbls
|
|
$118.30 (1)
|
|
|
Jul 2012-Dec 2012
|
|
Swap
|
|
10,000 Bbls
|
|
$114.85 (1)
|
|
|
Jan 2013-Dec 2013
|
|
Swap
|
|
14,000 Bbls
|
|
$101.25 (2)
|
|
(1) Commodity derivative based on Brent crude oil
(2) Commodity derivative based on West Texas Intermediate crude oil
The following table details the effect of derivative contracts on the Consolidated Statements of Operations:
|
Contract Type
|
|
Location of Gain or (Loss) Recognized in Income
|
|
Amount of Gain or (Loss) Recognized in Income
|
|
| |
|
|
|
Twelve months ended December 31,
|
|
| |
|
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
Natural gas contracts
|
|
Natural gas sales
|
|
$ |
11,283,031 |
|
|
$ |
19,465,873 |
|
|
$ |
30,118,915 |
|
|
Crude oil contracts
|
|
Crude oil sales
|
|
|
(3,531,207 |
|
|
|
1,446,686 |
|
|
|
8,664,939 |
|
|
Natural gas liquids contract
|
|
Natural gas liquids sales
|
|
|
(254,220 |
) |
|
|
— |
|
|
|
— |
|
|
Interest rate contracts
|
|
Interest expense
|
|
|
(1,410,764 |
) |
|
|
(4,594,968 |
) |
|
|
(4,432,364 |
) |
| |
|
Realized gain (loss)
|
|
$ |
6,086,840 |
|
|
$ |
16,317,591 |
|
|
$ |
34,351,490 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas contracts
|
|
Unrealized (loss) gain on derivative instruments
|
|
$ |
(3,637,188 |
) |
|
$ |
(8,241,131 |
) |
|
$ |
(7,544,562 |
) |
|
Crude oil contracts
|
|
Unrealized (loss) gain on derivative instruments
|
|
|
2,699,354 |
|
|
|
(1,477,423 |
) |
|
|
(17,393,075 |
) |
|
Natural gas liquids contract
|
|
Unrealized (loss) gain on derivative instruments
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
Interest rate contracts
|
|
Unrealized (loss) gain on derivative instruments
|
|
|
1,392,740 |
|
|
|
3,217,729 |
|
|
|
1,075,057 |
|
| |
|
Unrealized gain (loss)
|
|
$ |
454,906 |
|
|
$ |
(6,500,825 |
) |
|
$ |
(23,862,580 |
) |
7. Accrued Liabilities
Accrued liabilities consist of the following:
| |
|
December 31,
|
|
| |
|
2011
|
|
|
2010
|
|
|
Capital drilling and operating costs
|
|
$ |
12,708,058 |
|
|
$ |
8,188,159 |
|
|
Accrued compensation
|
|
|
2,800,000 |
|
|
|
2,857,000 |
|
|
Interest and loan fees
|
|
|
82,604 |
|
|
|
569,001 |
|
|
Other
|
|
|
540,662 |
|
|
|
1,185,016 |
|
| |
|
$ |
16,131,324 |
|
|
$ |
12,799,176 |
|
|
8.
|
Asset Retirement Obligations
|
We estimate the fair values of asset retirement obligations ("AROs") based on historical experience of plug and abandonment costs by field and, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO; estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free rate to be used and inflation rates.
A roll forward of our asset retirement obligation liability is as follows:
| |
|
December 31,
|
|
| |
|
2011
|
|
|
2010
|
|
|
Balance beginning of year
|
|
$ |
9,834,021 |
|
|
$ |
9,702,653 |
|
|
Accretion expense
|
|
|
489,077 |
|
|
|
585,951 |
|
|
Liabilities incurred
|
|
|
87,106 |
|
|
|
59,178 |
|
|
Liabilities settled
|
|
|
(404,594 |
) |
|
|
(513,761 |
) |
|
Revisions
|
|
|
1,159 |
|
|
|
— |
|
|
Balance end of year
|
|
$ |
10,006,769 |
|
|
$ |
9,834,021 |
|
9. Debt
Revolving Credit Agreement
On May 8, 2007, we entered into a $400.0 million revolving credit agreement with Wells Fargo Bank, National Association (“Wells Fargo Bank”), as agent, and the lender parties thereto (the “Senior Credit Agreement”) dated as of July 15, 2005, as amended. Since that time, we have amended and restated this agreement as necessary. Our Senior Credit Agreement provides for aggregate borrowings of up to $400.0 million for acquisitions of crude oil and gas properties and for general corporate cash requirements. The Senior Credit Agreement includes usual and customary covenants for credit facilities of the respective types and sizes, including, among others, limitations on liens, hedging, mergers, asset sales or dispositions, payments of dividends, incurrence of additional indebtedness, certain leases and investments outside of the ordinary course of business, as well as events of default.
The Senior Credit Agreement contains certain financial covenants, including those currently requiring us to maintain (i) a ratio of current assets (including borrowing base availability and excluding derivative instruments) to current liabilities (excluding current portion of long-term debt and derivative instruments) of at least 1.0 to 1.0, (ii) the ratio of our total debt to Adjusted EBITDAX for any four trailing fiscal quarters which may not be greater than (a) 4.25 to 1.00 as of the end of any fiscal quarter through June 30, 2011, (b) 3.75 to 1.00 for the fiscal quarters ending September 30, 2011 and December 31, 2011, and (c) 3.50 to 1.00 thereafter, (iii) the ratio of Adjusted EBITDAX to cash interest expense for any four trailing fiscal quarters may not be less than (a) 2.00 through March 31, 2011, (b) 2.25 to 1.00 for the fiscal quarters ending June 30, 2011, September 30, 2011 and December 31, 2011, and (c) 2.50 to 1.00 for the quarters ending March 31, 2012 and June 30, 2012 and (d) 2.75 to 1.00 thereafter, and (iv) the ratio of the sum of (a) the aggregate outstanding principal amount of the Loans under the revolver plus (b) the aggregate face amount of all undrawn and uncancelled Letters of Credit, plus the aggregate of all amounts drawn under all Letters of Credit and not yet reimbursed, as of such date to EBITDAX for the four fiscal quarters ending on such date to not be greater than 2.25 to 1.00. EBITDAX represents net income (loss) before net interest expense, taxes, and depreciation, amortization and exploration expenses. Adjusted EBITDAX, as defined in our credit agreements, represents EBITDAX as further adjusted for (i) unrealized gain or loss on derivative instruments, (ii) non-cash share-based compensation charges, (iii) impaired assets, (iv) other financing costs and (v) gains or losses on the disposition of assets, all of which will be required in determining our compliance with financial covenants under our Senior Credit Agreement and second lien term loan agreement.
Borrowings under our Senior Credit Agreement are subject to a borrowing base limitation based on our proved crude oil and natural gas reserves. The borrowing base under our Senior Credit Agreement is currently $100.0 million. The next borrowing base re-determination is scheduled for May 1, 2012 and is subject to semi-annual redeterminations, although our lenders may elect to make one additional redetermination between scheduled redetermination dates. We may also issue up to $200 million in senior unsecured notes. Any such issuance of senior unsecured notes will reduce our borrowing base by 25% of the net proceeds from such issuance in excess of $150 million. Our Senior Credit Agreement also provides for the issuance of letters-of-credit up to a $5.0 million sub-limit. At December 31, 2011, no senior unsecured notes or letters-of-credit were outstanding. All principal amounts, together with all accrued and unpaid interest outstanding under our Senior Credit Agreement will be due and payable in full on May 31, 2013. We have started discussions with Wells Fargo Bank to extend our Senior Credit Agreement and expect to finalize these discussions before the debt becomes current on May 31, 2012.
Advances under our Senior Credit Agreement are in the form of either base rate loans or LIBOR loans. The interest rate on the base rate loans fluctuates based upon the higher of the lender’s “prime rate” and the Federal Funds rate. The interest rate on the LIBOR loans fluctuates based upon the rate at which Eurodollar deposits in the LIBOR market are quoted for the maturity selected. Pursuant to our Senior Credit Agreement, the applicable margin is between 2.75% and 3.50%, for LIBOR loans, and between 1.50% and 2.00%, for base rate loans. The specific interest margin applicable is determined by, in each case, the percent of the borrowing base utilized at the time of the credit extension. LIBOR loans of one, two, three and six months may be selected. The commitment fee payable on the unused portion of our borrowing base is 0.50%, which fee accrues and is payable quarterly in arrears.
At December 31, 2011, we had $21.0 million outstanding under our Senior Credit Agreement, with availability of $79.0 million.
Second Lien Credit Agreement
We entered into a new second lien credit agreement with Barclays Bank Plc, as agent, and the lender parties thereto, including an affiliate of OCM GW Holdings, LLC (“Oaktree Holdings”), our largest stockholder (the “Second Lien Credit Agreement”) which provided for term loans, made to us in a single draw, in an aggregate principal amount of $175 million on December 27, 2010. Our Second Lien Credit Agreement replaced our then existing $150 million Second Lien Credit Agreement with Credit Suisse, which was paid off in full and terminated at closing. Our Second Lien Credit Agreement matures on December 27, 2015.
Advances under our new Second Lien Credit Agreement are in the form of either base rate loans or LIBOR loans. The interest rate on the base rate loans fluctuates based upon the greatest of (i) 4.00% per annum, (ii) the “prime rate”, (iii) the Federal Funds Effective Rate plus ½ of 1% and (iv) the LIBO rate for a one month interest period plus 1.00%. The applicable margin for base rate loans is 8.50%. The interest rate on the LIBOR loans fluctuates based upon the higher of (i) 3.0% per annum and (ii) the LIBOR rate per annum. The applicable margin for LIBOR loans is 9.50%.
In addition to certain of the Senior Credit Agreement covenants described above, the Second Lien Credit Agreement also requires the ratio of PV-10 Value to total Net Debt to be greater than 1.25 to 1.00 as of the end of the second and fourth calendar quarters through June 30, 2012 and 1.50 to 1.00 thereafter. The PV-10 Value represents the present value of estimated future revenues less severance and ad valorem taxes, operating, gathering, transportation and marketing expenses and capital expenditures from the production of proved reserves on our oil and gas properties as set forth in the most recent reserve reports. At December 31, 2011, we had a principal amount of $175.0 million outstanding under our Second Lien Credit Agreement, with a discount of $5.9 million using the estimated market value interest rate at the time of issuance, for a net balance of $169.1 million.
Summary
At December 31, 2011, we were in compliance with the covenants under our Senior Credit Agreement and Second Lien Credit Agreement.
Our Senior Credit Agreement and our Second Lien Credit Agreement are secured by liens on substantially all of our assets, including the capital stock of our subsidiaries. The liens securing the obligations under our Second Lien Credit Agreement are junior to those under our Senior Credit Agreement. Unpaid interest is payable under our credit agreements as borrowings mature and renew.
Our debt consists of the following:
| |
|
December 31,
|
|
| |
|
2011
|
|
|
2010
|
|
|
Senior Credit Agreement (weighted average interest rate in effect at December 31, 2011 was 3.14%)
|
|
$ |
20,977,937 |
|
|
$ |
4,000,000 |
|
| |
|
|
|
|
|
|
|
|
|
Second Lien Credit Agreement (interest rate in effect at December 31, 2011 was 12.50%)
|
|
|
175,000,000 |
|
|
|
175,000,000 |
|
| |
|
|
195,977,937 |
|
|
|
179,000,000 |
|
| |
|
|
|
|
|
|
|
|
|
Less: current portion unamortized debt discount
|
|
|
(5,936,004 |
) |
|
|
(6,986,510 |
) |
|
Total long-term debt
|
|
$ |
190,041,933 |
|
|
$ |
172,013,490 |
|
Estimated annual maturities for long-term debt are as follows:
| |
|
Long-Term Debt
|
|
2012
|
$
|
—
|
|
2013
|
|
20,977,937
|
|
2014
|
|
—
|
|
2015
|
|
175,000,000
|
|
2016
|
|
—
|
| |
$
|
195,977,937
|
|
10.
|
Commitments and Contingencies
|
Lease Obligations
We currently lease and sublease, through January 31, 2014, 54,939 square feet of executive and corporate office space located at 717 Texas Avenue in downtown Houston, Texas. Total general and administrative rent expense for the years ended December 31, 2011, 2010 and 2009, was approximately $1.3 million, $1.1 million and $2.2 million, respectively. Effective January 1, 2010, we subleased to a subtenant 27,144 square feet of this space for a total rental of approximately $86,000 per month through September 30, 2011. The sublease rent has been accounted for as a reduction to rent expense. We have entered into various vehicle leases for periods ranging from 12 to 24 months. These contracts will expire at various times with the latest contract expiring in November 2012. We also have various other equipment leases, with the latest contract expiring in August 2012. Total operational rent expense for the years ended December 31, 2011, 2010 and 2009, were approximately $2.4 million, $2.3 million and $3.0 million, respectively.
The following table provides information about our total operating lease obligations as of December 31, 2011:
| |
|
Operating leases
|
|
2012
|
$
|
1,648,040
|
|
2013
|
|
1,482,127
|
|
2014
|
|
141,335
|
|
2015
|
|
—
|
|
2016
|
|
—
|
|
Thereafter
|
|
—
|
|
Total
|
$
|
3,271,502
|
Legal Proceedings
From time to time, we are involved in litigation relating to claims arising out of our properties or operations or from disputes with vendors in the normal course of business.
Mineral interest owners in East Texas (Haynesville Shale) filed two causes of action against us on May 26, 2009 and August 26, 2009, respectively, in the District Court for San Augustine County, Texas alleging breach of contract for not paying lease bonuses on certain prospective oil and gas leases that were pursued by our leasing agent but never taken by Crimson. The damages alleged are currently approximately $3.2 million and we have received approximately $2.0 million in written demands from other mineral interest owners in this area that we believe may contemplate legal proceedings. We are vigorously defending these lawsuits, and believe we have meritorious defenses. We do not believe that these claims will have a material adverse effect on our business, financial position, results of operations or cash flows, although we cannot guarantee that a material adverse effect will not occur.
The holders of oil and gas leases in South Louisiana filed suit against Crimson and several co-defendants alleging failure to act as a reasonably prudent operator, failure to explore, waste, breach of contract, etc. in connection with two wells in Jefferson Davis Parish, Louisiana. Many of the alleged improprieties occurred prior to our ownership of an interest in the wells at issue, although we may have assumed liability otherwise attributable to
our predecessors-in-interest through the acquisition documents relating to the acquisition of our interest in these wells. The damages currently alleged are approximately $13.4 million. We and our co-defendants are vigorously defending this lawsuit and we believe that we have meritorious defenses. We do not believe this suit will have a material adverse effect on our business, financial position, results of operations or cash flows, although we cannot guarantee that a material adverse effect will not occur.
In November 2010, we and several predecessor operators were named in a lawsuit filed by an entity alleging that it owns a working interest in a productive formation that has not been recognized by us or by predecessor operators to which we have granted indemnification rights. In dispute is whether ownership rights in specific depths were transferred through a number of decade-old poorly documented transactions. The maximum amount asserted in the suit filed could be determined at up to approximately $4.9 million. We are vigorously defending this lawsuit and believe we have meritorious defenses. We currently do not believe that this claim will have a material adverse effect on our business, financial position, results of operations or cash flows, although we cannot guarantee that a material adverse effect will not occur.
Employment Agreements
In June 2011, we entered into amended and restated employment agreements with our President/Chief Executive Officer and Senior Vice President/Chief Financial Officer. Each agreement has a term of three years with automatic yearly extensions unless we or the executive officer elects not to extend the agreement. These agreements provide for an annual base salary of $450,000 and $365,000, respectively, subject to increases at the discretion of the Compensation Committee. If the contracts are terminated by us without cause or by the employee for good reason, and the employee has been in compliance with employee contract terms, the employee may receive a cash payment equal to 2.99 times the sum of the current calendar year’s base salary plus prior year’s annual cash incentive bonus, health insurance benefits for 36 months and acceleration to 100% vested status for all stock, stock option and other equity awards.
Also in June 2011, we entered into amended and restated employment agreements with two other Senior Vice Presidents. Each agreement has a term of two years with automatic yearly extensions unless we or the executive officer elects not to extend the agreement. These agreements provide for an annual base salary ranging from $220,000 to $230,000, subject to increases at the discretion of the Compensation Committee. If the contracts are terminated by us without cause or by the employee for good reason, and the employee has been in compliance with the employee contract terms, the employee is entitled to receive a cash payment equal to two times current year base salary plus prior year’s annual cash incentive bonus, health insurance benefits for 24 months and acceleration to 100% vested status for all stock, stock option and other equity awards.
In May 2010, we entered into an employment agreement with a new Senior Vice President. This agreement has a term of two years with automatic yearly extensions unless we or the executive officer elects not to extend the agreement. This agreement provides for an initial base salary of $230,000 per year, subject to increases at the discretion of the Compensation Committee. If the contracts are terminated by us without cause or by the employee for good reason, and the employee has been in compliance with the employee contract terms, the employee is entitled to receive a cash payment equal to two times current year base salary plus prior year’s annual cash incentive bonus, health insurance benefits for 24 months and acceleration to 100% vested status for all stock, stock option and other equity awards.
|
11.
|
Share-Based Compensation
|
As of December 31, 2011, we had share-based compensation, which includes both stock options and restricted stock awarded to employees and directors that were either performance related or granted upon initial employment.
Incentive Plans
In the third quarter 2008, our Board of Directors formally adopted an amendment to our performance based cash bonus plan and adopted a new performance based long term stock bonus plan for the benefit of all employees - the Crimson Cash Incentive Bonus Plan (“CIBP”) and the Crimson Long-Term Incentive Plan (“LTIP”), respectively. Both plans and specific targeted performance measures under those plans, were approved by the Compensation Committee. Upon achieving the performance levels established each year, bonus awards were
calculated as a percentage of base salary for the plan year. The plan awards were disbursed in the first quarter of the following year. Employees must have been employed by us at the time that final plan awards were dispersed to have been eligible.
The CIBP awards are paid out in cash (“Cash Awards”). The performance targets were evaluated on a quarterly basis and used to estimate the approximate expense earned to date for each year. The Board of Directors suspended the CIBP for 2009. However, discretionary cash bonus awards of approximately $1.2 million were approved by the Board of Directors for fiscal year 2009 and were paid in March 2010. The CIBP was reinstated by the Board of Directors for fiscal year 2010. Approximately $2.8 million and $2.9 million was recognized as compensation expense related to the Cash Awards for the twelve months ended December 31, 2011 and 2010, respectively and were paid in March 2012 and 2011, respectively.
The LTIP bonus awards can be paid in either restricted Common Stock or stock options (“Stock Awards”). The Stock Awards vest 25% per year, over the first through fourth anniversaries from the date of grant, at which time 100% of all Stock Awards will be vested. The number of shares of restricted Common Stock and the number of shares underlying the stock options granted as Stock Awards were determined based upon the fair market value of the Common Stock on the date of the grant. The fair value of the stock options to be awarded as part of this plan was determined through use of the Black-Scholes valuation model. The Stock Awards granted pursuant to this plan were granted under the existing amended and restated 2005 Stock Incentive Plan.
In March 2009, the Board of Directors approved the awarding of approximately 1.1 million shares to our employees under the LTIP for the 2008 calendar year. Due to the decline in our stock price, the Board of Directors suspended the LTIP in 2009. The LTIP has not yet been reinstated. However at the Board of Directors’ discretion, bonus awards may be made in the form of restricted stock or stock options.
Stock Options
We maintain a 2005 Stock Incentive Plan (“2005 Plan”) and authorized the issuance of up to approximately 5.8 million shares of Common Stock pursuant to awards under the plan. In 2007, we also issued 250,000 shares of restricted Common Stock to our executive officers outside of these plans. Approximately 1.7 million (0.1 million vested) stock options and 1.2 million unvested restricted shares were outstanding at December 31, 2011. Option awards outstanding have exercise prices ranging from $2.13 to $7.90 per share. In 2011 and 2010, respectively, 354,051 and 326,364 shares of restricted Common Stock vested, of which 46,215 and 33,600 shares were withheld by us to satisfy the employees’ tax liability resulting from the vesting of these shares, as provided for in the restricted stock agreement, with the remaining shares being released to the employees and associated directors. At December 31, 2011, we had approximately 2.1 million shares of Common Stock available for future grant under the 2005 Plan.
For stock options, we recorded $0.6 million, $0.3 million and $1.1 million in expense (included on the Consolidated Statements of Operations in general and administrative expense) for the years ended December 31, 2011, 2010 and 2009, respectively, and an estimated $1.2 million will be expensed over the remaining vesting period.
The fair value of each option award is estimated on the date of grant using the Black-Scholes option pricing model. Assumptions used in the valuation are disclosed in the following table. Expected volatilities are based on historical volatility of our stock with a look back period based on the expected term. The expected dividend yield is zero as we have never declared dividends on our Common Stock. The expected term of options granted represents the period of time that the options are expected to be outstanding. The risk-free rate is based on U.S. Treasury bills with a duration equal or close to the expected term of the options at the time of grant. The forfeiture rates are based on historical forfeitures.
| |
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
Weighted average fair value of awards
|
|
$ |
2.07 |
|
|
$ |
2.19 |
|
|
$ |
1.41 |
|
|
Pre-vest forfeiture rate
|
|
|
6.92 |
% |
|
|
5.01 |
% |
|
|
3.62 |
% |
|
Average grant price
|
|
$ |
3.35 |
|
|
$ |
3.19 |
|
|
$ |
2.40 |
|
|
Expected volatility
|
|
|
74.47 |
% |
|
|
75.38 |
% |
|
|
60.98 |
% |
|
Risk-free rate
|
|
|
1.65 |
% |
|
|
2.55 |
% |
|
|
2.48 |
% |
|
Expected dividend yields
|
|
None
|
|
|
None
|
|
|
None
|
|
|
Expected term (in years)
|
|
|
6.34 |
|
|
|
6.36 |
|
|
|
6.25 |
|
The following table summarizes stock option activity for the three years ended December 31, 2011:
| |
|
Number of Shares Underlying Options
|
|
|
Weighted Average Exercise Price
|
|
|
Intrinsic Value
|
|
|
Outstanding at December 31, 2009
|
|
|
1,957,529 |
|
|
$ |
8.82 |
|
|
|
|
|
Granted
|
|
|
189,500 |
|
|
|
3.16 |
|
|
|
|
|
Exercised
|
|
|
(28,381 |
) |
|
|
2.40 |
|
|
$ |
25,208 |
|
|
Cancelled/forfeited
|
|
|
(361,105 |
) |
|
|
6.48 |
|
|
|
|
|
|
Expired
|
|
|
(16,000 |
) |
|
|
4.50 |
|
|
|
|
|
|
Outstanding at December 31, 2010
|
|
|
1,741,543 |
|
|
|
8.84 |
|
|
|
|
|
|
Granted
|
|
|
1,453,240 |
|
|
|
4.79 |
|
|
|
|
|
|
Exercised
|
|
|
(25,036 |
) |
|
|
2.42 |
|
|
$ |
17,251 |
|
|
Cancelled/forfeited
|
|
|
(1,457,286 |
) |
|
|
10.18 |
|
|
|
|
|
|
Outstanding at December 31, 2011
|
|
|
1,712,461 |
|
|
|
4.35 |
|
|
$ |
112,857 |
|
|
Exercisable at December 31, 2011
|
|
|
144,370 |
|
|
|
2.71 |
|
|
$ |
52,615 |
|
Restricted Stock Awards
For restricted stock awards, we recorded $1.4 million, $1.5 million and $1.3 million in expense (included on the Consolidated Statements of Operations in general and administrative expense) for the years ended December 31, 2011, 2010 and 2009, respectively and an estimated $2.7 million will be expensed over the remaining vesting period.
In 2011, we issued 446,725 shares of unvested Common Stock, pursuant to restricted stock awards under the 2005 Stock Plan, of which 43,020 were subsequently forfeited. The restricted stock will vest over a four year period. We also issued 39,267 shares of Common Stock pursuant to restricted stock awards to three members of our board of directors as compensation pursuant to the Director Compensation Plan. The fair value of the unvested Common Stock was calculated as approximately $1.8 million on the grant date and will be amortized over the vesting period.
In 2010, we issued 402,859 shares of unvested Common Stock, pursuant to restricted stock awards under the 2005 Stock Plan, of which 22,000 were subsequently forfeited. The restricted stock will vest over a four year period. We also issued 31,646 shares of Common Stock pursuant to restricted stock awards to two members of our board of directors as compensation pursuant to the Director Compensation Plan. The fair value of the unvested Common Stock was calculated as approximately $1.2 million on the grant date and will be amortized over the vesting period.
In 2009, we issued 648,936 shares of unvested Common Stock, pursuant to restricted stock awards under the 2005 Stock Plan, of which 36,366 were subsequently forfeited. The restricted stock will vest over a four year period. The fair value of the unvested Common Stock was calculated as approximately $1.6 million on the grant date and will be amortized using the straight-line method over the vesting period. We also issued 48,586 shares of Common Stock pursuant to restricted stock awards to two members of our board of directors as compensation pursuant to the Director Compensation Plan.
Restricted stock activity for the three years ended December 31, 2011 is summarized below:
| |
|
|
|
|
Weighted-Average
|
|
| |
|
|
|
|
Grant Date
|
|
| |
|
Shares
|
|
|
Fair Value
|
|
|
Non-vested as of December 31, 2009
|
|
|
1,248,581 |
|
|
$ |
3.41 |
|
|
Granted
|
|
|
434,505 |
|
|
|
3.09 |
|
|
Vested
|
|
|
(326,364 |
) |
|
|
3.71 |
|
|
Cancelled/forfeited
|
|
|
(88,685 |
) |
|
|
2.53 |
|
|
Non-vested as of December 31, 2010
|
|
|
1,268,037 |
|
|
|
3.28 |
|
|
Granted
|
|
|
485,992 |
|
|
|
3.78 |
|
|
Vested
|
|
|
(354,051 |
) |
|
|
3.48 |
|
|
Cancelled/forfeited
|
|
|
(192,665 |
) |
|
|
3.70 |
|
|
Non-vested as of December 31, 2011
|
|
|
1,207,313 |
|
|
|
3.36 |
|
Certain of these restricted stock awards were issued separately from the 2005 Plan.
12. Income (Loss) Per Common Share
The following is a reconciliation of the numerators and denominators used in computing income (loss) per share:
| |
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
Net loss
|
|
$ |
(15,845,382 |
) |
|
$ |
(30,844,897 |
) |
|
$ |
(34,069,990 |
) |
|
Preferred stock dividends
|
|
|
— |
|
|
|
— |
|
|
|
(4,522,645 |
) |
|
Net loss available to common stockholders
|
|
$ |
(15,845,382 |
) |
|
$ |
(30,844,897 |
) |
|
$ |
(38,592,635 |
) |
|
Weighted-average number of shares of Common Stock – basic (denominator)
|
|
|
44,788,551 |
|
|
|
39,397,486 |
|
|
|
7,861,054 |
|
|
Loss per share - basic
|
|
$ |
(0.35 |
) |
|
$ |
(0.78 |
) |
|
$ |
(4.91 |
) |
|
Weighted-average number of shares of Common Stock – diluted (denominator)
|
|
|
44,788,551 |
|
|
|
39,397,486 |
|
|
|
7,861,054 |
|
|
Loss per share – diluted
|
|
$ |
(0.35 |
) |
|
$ |
(0.78 |
) |
|
$ |
(4.91 |
) |
The numerator for basic earnings per share is income (loss) available to common stockholders. The numerator for diluted earnings per share is net loss available to common stockholders, due to antidilution.
Potential dilutive securities (stock options, stock warrants and convertible preferred stock) have not been considered since we reported a net loss and, accordingly, their effects would be antidilutive. The potentially dilutive shares would have been 82,634 shares, 95,967 shares and 4,770,404 shares in 2011, 2010 and 2009, respectively.
13. Supplementary Disclosures of the Consolidated Statements of Cash Flows
The following table sets forth non-cash investing and financing activities for the three years ended December 31,:
| |
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
Liabilities released on property dispositions
|
|
$ |
— |
|
|
$ |
351,092 |
|
|
$ |
5,309,005 |
|
|
Conversion of preferred stock dividends
|
|
|
— |
|
|
|
— |
|
|
|
(18,753,649 |
) |
|
Promissory note, net of discount
|
|
|
— |
|
|
|
— |
|
|
|
(1,749,751 |
) |
Income tax benefit (for 2011, 2010 and 2009 consist of the following:
| |
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
Current tax benefit
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
122,162 |
|
|
Deferred tax benefit
|
|
|
8,098,357 |
|
|
|
16,607,139 |
|
|
|
16,572,200 |
|
|
Income tax benefit
|
|
$ |
8,098,357 |
|
|
$ |
16,607,139 |
|
|
$ |
16,694,362 |
|
The following is a reconciliation of effective income tax rates by applying the federal statutory rate of 35% to the income and loss for the years ended December 31, 2011, 2010 and 2009, respectively:
| |
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
Income (Loss) Before Income Taxes
|
|
$ |
(23,943,739 |
) |
|
$ |
(47,452,036 |
) |
|
$ |
(50,764,352 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Tax Benefit (Expense) at Statutory Rate
|
|
$ |
8,380,309 |
|
|
$ |
16,608,213 |
|
|
$ |
17,767,523 |
|
|
Adjustment to NOL carryforward
|
|
|
— |
|
|
|
(261,154 |
) |
|
|
(1,562,704 |
) |
|
Effect for Permanent Items
|
|
|
(17,306 |
) |
|
|
(23,699 |
) |
|
|
(4,002 |
) |
|
State Taxes and Other
|
|
|
(264,646 |
) |
|
|
283,779 |
|
|
|
493,545 |
|
|
Income Tax Benefit (Expense)
|
|
$ |
8,098,357 |
|
|
$ |
16,607,139 |
|
|
$ |
16,694,362 |
|
As of December 31, 2011, we had federal and state net operating loss carryforwards of approximately $169.0 million and $9.5 million, respectively, which are available to reduce future taxable income and the related income tax liability; however, we expect we will not be able to utilize carryforwards of approximately $8.7 million due to the limitations of Internal Revenue Code Section 382. The net operating loss carryforward expires at various dates beginning in 2012 and ending in 2032.
Significant components of our deferred tax assets and liabilities are as follows:
| |
|
December 31,
|
|
| |
|
2011
|
|
|
2010
|
|
|
Deferred tax assets
|
|
|
|
|
|
|
|
Net operating loss carryforwards
|
|
$ |
59,443,480 |
|
|
$ |
34,902,077 |
|
|
Income tax credits
|
|
|
281,424 |
|
|
|
283,789 |
|
|
Deferred compensation
|
|
|
7,177,942 |
|
|
|
6,486,831 |
|
|
Other
|
|
|
(425,885 |
) |
|
|
(213,305 |
) |
|
Deferred tax assets before valuation allowance
|
|
|
66,476,961 |
|
|
|
41,459,392 |
|
|
Valuation allowance
|
|
|
(3,238,656 |
) |
|
|
(3,387,923 |
) |
|
Net deferred tax assets
|
|
|
63,238,305 |
|
|
|
38,071,469 |
|
| |
|
|
|
|
|
|
|
|
|
Deferred tax liabilities
|
|
|
|
|
|
|
|
|
|
Oil and gas properties
|
|
|
(44,780,151 |
) |
|
|
(27,874,074 |
) |
|
Derivative instruments
|
|
|
(1,349,679 |
) |
|
|
(1,187,277 |
) |
|
Deferred tax liabilities
|
|
|
(46,129,830 |
) |
|
|
(29,061,351 |
) |
|
Net deferred tax assets
|
|
$ |
17,108,475 |
|
|
$ |
9,010,118 |
|
In assessing the realizability of deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. We consider the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. Based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, we believe it is more likely than not that we will realize the benefits of these deductible differences net of a tax-adjusted $3.2 million valuation allowance. The amount of the deferred tax assets considered realizable could be reduced in the future if estimates of future taxable income during the carryforward period are reduced.
ASC 740, Income Taxes (“ASC 740”) prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of income tax positions taken or expected to be taken in an income tax return. For those benefits to be recognized, an income tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. There was not a material impact on our operating results, financial position or cash flows as a result of the adoption of the provisions of ASC 740. A reconciliation of the beginning and ending amount of unrecognized income tax benefits is as follows:
| |
|
Unrecognized Tax Benefits
|
|
|
Balance at December 31, 2010
|
|
$ |
518,219 |
|
|
Additions based on tax positions related to the current year
|
|
|
— |
|
|
Additions based on tax positions related to prior years
|
|
|
— |
|
|
Additions due to acquisitions
|
|
|
— |
|
|
Reductions due to a lapse of the applicable statute of limitations
|
|
|
— |
|
|
Balance at December 31, 2011
|
|
$ |
518,219 |
|
Generally, our income tax years of 2007 through the current year remain open and subject to examination by Federal tax authorities or the tax authorities in Texas, Louisiana and Colorado which are the jurisdictions where we have our principal operations. These audits can result in adjustments of taxes due or adjustments of the net operating loss carryforwards that are available to offset future taxable income.
Our policy is to recognize interest and penalties related to uncertain tax positions as income tax benefit (expense) in our Consolidated Statements of Operations. For the years ended December 31, 2011 and 2010, respectively, we recorded no interest expense and penalties related to unrecognized tax benefits associated with uncertain tax positions recognized in our provision for income taxes.
The total amount of unrecognized tax benefit if recognized that would affect the effective tax rate was zero. Our tax returns are subject to periodic audits by the various jurisdictions in which we operate. These audits can result in adjustments of taxes due or adjustments of the net operating loss carryforwards that are available to offset future taxable income.
We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits and the expiration of statute of limitations prior to December 31, 2011. However, due to the complexity of the application of tax law and regulations, it is possible that the ultimate resolution of these positions may result in liabilities which could be materially different from these estimates.
|
15.
|
Disclosure of Major Customers
|
For the years ended December 31, 2011, 2010 and 2009, there were two customers who accounted for more than 10% of revenues:
| |
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
|
Customer 1
|
|
$ |
31,727,341 |
|
|
$ |
23,224,023 |
|
|
$ |
19,411,991 |
|
|
|
Customer 2
|
|
|
22,579,414 |
|
|
|
10,951,458 |
|
|
|
— |
(1) |
|
(1) Customer 2 represented less than 10% of revenues for the year ended December 31, 2009
|
16.
|
Quarterly Results (Unaudited) |
Summary data relating to the results of operations for each quarter for the years ended December 31, 2011 and 2010 follows:
| |
|
Three Months Ended
|
|
| |
|
March 31
|
|
|
June 30
|
|
|
September 30
|
|
|
December 31
|
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net revenues
|
|
$ |
27,783,547 |
|
|
$ |
29,827,266 |
|
|
$ |
29,094,997 |
|
|
$ |
27,651,695 |
|
|
Income (loss) from operations
|
|
|
(1,471,782 |
) |
|
|
363,577 |
|
|
|
3,100,247 |
|
|
|
420,198 |
|
|
Net income (loss) available to common stockholders
|
|
|
(8,545,962 |
) |
|
|
(2,826,563 |
) |
|
|
526,600 |
|
|
|
(4,999,457 |
) |
|
Income(loss)per common share (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$ |
(0.19 |
) |
|
$ |
(0.06 |
) |
|
$ |
0.01 |
|
|
$ |
(0.11 |
) |
|
Diluted
|
|
$ |
(0.19 |
) |
|
$ |
(0.06 |
) |
|
$ |
0.01 |
|
|
$ |
(0.11 |
) |
|
Weighted average shares outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
44,939,828 |
|
|
|
45,188,542 |
|
|
|
45,121,172 |
|
|
|
43,904,661 |
|
|
Diluted
|
|
|
44,939,828 |
|
|
|
45,188,542 |
|
|
|
45,166,566 |
|
|
|
43,904,661 |
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net revenues
|
|
$ |
22,609,859 |
|
|
$ |
21,452,943 |
|
|
$ |
24,535,907 |
|
|
$ |
27,943,258 |
|
|
Income (loss) from operations
|
|
|
1,195,435 |
|
|
|
402,731 |
|
|
|
1,714,557 |
|
|
|
(17,627,620 |
) |
|
Net income (loss) available to common stockholders
|
|
|
208,815 |
|
|
|
(6,370,850 |
) |
|
|
(3,819,908 |
) |
|
|
(20,862,954 |
) |
|
Income(loss)per common share (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$ |
0.01 |
|
|
$ |
(0.16 |
) |
|
$ |
(0.10 |
) |
|
$ |
(0.50 |
) |
|
Diluted
|
|
$ |
0.01 |
|
|
$ |
(0.16 |
) |
|
$ |
(0.10 |
) |
|
$ |
(0.50 |
) |
|
Weighted average shares outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
38,506,160 |
|
|
|
38,635,725 |
|
|
|
38,819,780 |
|
|
|
42,113,808 |
|
|
Diluted
|
|
|
38,653,645 |
|
|
|
38,635,725 |
|
|
|
38,819,780 |
|
|
|
42,113,808 |
|
(1) Quarterly income (loss) per share is based on the weighted average number of shares outstanding during the quarter. Because of changes in the number of shares outstanding during the quarters, due to the exercise of stock options and issuance of common stock, the sum of quarterly earnings per share may not equal earnings per share for the year.
17. Oil and Gas Reserves (unaudited)
All information set forth herein relating to our proved reserves, estimated future net cash flows and present values is taken or derived from reports prepared by NSAI. The estimates of these engineers were based upon their review of production histories and other geological, economic, ownership and engineering data provided by and relating to us. No reports on our reserves have been filed with any federal agency. In accordance with the SEC’s guidelines, our estimates of proved reserves and the future net revenues from which present values are derived beginning with 2009 are based on an unweighted 12-month average of the first-day-of-the-month price for the period January through December for that year held constant throughout the life of the properties. Operating costs,
development costs and certain production-related taxes were deducted in arriving at estimated future net revenues, but such costs do not include debt service, general and administrative expenses and income taxes.
Proved Oil and Gas Reserve Quantities
The following table sets forth net proved natural gas, crude oil and natural gas liquids reserves, all within the United States, at December 31, 2011, 2010 and 2009, together with the changes therein.
| |
|
Natural Gas (MMcf)
|
|
|
Crude Oil (MBbls)
|
|
|
Natural Gas Liquids
(MBbls)
|
|
|
Total
(Mcfe)
|
|
|
QUANTITIES OF PROVED RESERVES:
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2009
|
|
|
69,860 |
|
|
|
1,964 |
|
|
|
2,641 |
|
|
|
97,489 |
|
|
Revisions (1)
|
|
|
12,654 |
|
|
|
137 |
|
|
|
341 |
|
|
|
15,526 |
|
|
Extensions, discoveries and additions
|
|
|
62,527 |
|
|
|
335 |
|
|
|
337 |
|
|
|
66,559 |
|
|
Sales (2)
|
|
|
(80 |
) |
|
|
(12 |
) |
|
|
— |
|
|
|
(151 |
) |
|
Production
|
|
|
(9,286 |
) |
|
|
(260 |
) |
|
|
(346 |
) |
|
|
(12,925 |
) |
|
Balance December 31, 2010
|
|
|
135,675 |
|
|
|
2,164 |
|
|
|
2,973 |
|
|
|
166,498 |
|
|
Revisions (1)
|
|
|
(18,645 |
) |
|
|
2 |
|
|
|
(165 |
) |
|
|
(19,625 |
) |
|
Extensions, discoveries and additions
|
|
|
57,311 |
|
|
|
1,943 |
|
|
|
154 |
|
|
|
69,890 |
|
|
Sales (2)
|
|
|
35 |
|
|
|
22 |
|
|
|
— |
|
|
|
170 |
|
|
Production
|
|
|
(11,676 |
) |
|
|
(397 |
) |
|
|
(418 |
) |
|
|
(16,564 |
) |
|
Balance December 31, 2011
|
|
|
162,700 |
|
|
|
3,734 |
|
|
|
2,544 |
|
|
|
200,369 |
|
|
PROVED DEVELOPED RESERVES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
|
49,075 |
|
|
|
1,274 |
|
|
|
1,977 |
|
|
|
68,581 |
|
|
December 31, 2010
|
|
|
60,325 |
|
|
|
1,403 |
|
|
|
1,898 |
|
|
|
80,130 |
|
|
December 31, 2011
|
|
|
53,024 |
|
|
|
1,845 |
|
|
|
1,637 |
|
|
|
73,913 |
|
|
PROVED UNDEVELOPED RESERVES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
|
20,784 |
|
|
|
690 |
|
|
|
664 |
|
|
|
28,907 |
|
|
December 31, 2010
|
|
|
75,350 |
|
|
|
761 |
|
|
|
1,075 |
|
|
|
86,368 |
|
|
December 31, 2011
|
|
|
109,676 |
|
|
|
1,890 |
|
|
|
907 |
|
|
|
126,456 |
|
(1) Periodic revisions to the estimated reserves and future cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, oil and natural gas prices, cost changes, technological advances, new geological or geophysical data, or other economic factors.
(2) Sales are calculated based on the beginning of the year reserves adjusted for current year production with no adjustment for revisions.
Capitalized Costs Relating to Oil and Gas Producing Activities
| |
|
2011
|
|
|
2010
|
|
|
Unproved oil and gas properties
|
|
$ |
17,799,420 |
|
|
$ |
31,885,067 |
|
|
Proved oil and gas properties
|
|
|
592,699,504 |
|
|
|
519,765,781 |
|
|
Wells and related equipment and facilities
|
|
|
52,915,523 |
|
|
|
38,597,290 |
|
| |
|
|
663,414,447 |
|
|
|
590,248,138 |
|
|
Less accumulated depreciation, depletion, amortization and impairment
|
|
|
(267,614,210 |
) |
|
|
(211,506,271 |
) |
|
Net capitalized costs
|
|
$ |
395,800,237 |
|
|
$ |
378,741,867 |
|
Costs Incurred
The following table shows the costs incurred in our crude oil and gas producing activities for the past three years ended December 31, 2011:
| |
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
Property Acquisitions:
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
$ |
1,101,868 |
|
|
$ |
— |
|
|
$ |
(493,532 |
) |
|
Unproved
|
|
|
8,221,361 |
|
|
|
5,774,043 |
|
|
|
1,833,949 |
|
|
Development Costs
|
|
|
69,595,880 |
|
|
|
47,973,323 |
|
|
|
11,398,237 |
|
|
Exploration Costs
|
|
|
10,199,440 |
|
|
|
2,000,941 |
|
|
|
11,815,450 |
|
|
Total
|
|
$ |
89,118,549 |
|
|
$ |
55,748,307 |
|
|
$ |
24,554,104 |
|
These costs include crude oil and gas property acquisition, exploration and development activities regardless of whether the costs were capitalized or charged to expense, including lease rental expenses and geological and geophysical expenses and changes to the long-lived asset related to our asset retirement obligation.
Results of Operations for Oil and Natural Gas Producing Activities
The following table shows the results of operations for oil and natural gas producing activities for the years ended December 31, 2011, 2010 and 2009, respectively:
| |
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
Natural gas, oil and natural gas liquids sales
|
|
$ |
106,138,430 |
|
|
$ |
75,019,664 |
|
|
$ |
73,018,910 |
|
|
Production costs
|
|
|
21,001,717 |
|
|
|
22,030,309 |
|
|
|
27,214,023 |
|
|
Depreciation, depletion and amortization
|
|
|
56,920,515 |
|
|
|
45,022,272 |
|
|
|
53,294,809 |
|
|
Impairment and abandonment of oil and gas properties
|
|
|
14,954,633 |
|
|
|
22,254,059 |
|
|
|
6,721,215 |
|
|
Income before income taxes
|
|
|
13,261,565 |
|
|
|
(14,286,976 |
) |
|
|
(14,211,137 |
) |
|
Income tax benefit
|
|
|
(4,568,841 |
) |
|
|
(5,000,118 |
) |
|
|
(4,673,474 |
) |
|
Results of operations
|
|
$ |
8,692,724 |
|
|
$ |
(19,287,094 |
) |
|
$ |
(18,884,611 |
) |
Sales are based on market prices and exclude the effects of realized derivative hedging gains of $7.5 million, $20.9 million and $38.8 million for the years 2011, 2010 and 2009, respectively. The results of operations for oil and natural gas producing activities exclude general and administrative expenses, interest and other financing charges, gain on sale of assets and the effects of unrealized derivative hedging gains and losses.
Standardized Measure of Discounted Future Net Cash Flows
The following table sets forth as of December 31 for each of the preceding three years, the estimated future net cash flow from and Standardized Measure of Discounted Future Net Cash Flows (“Standardized Measure”) of our proved reserves, which were prepared in accordance with the rules and regulations of the SEC and the Financial Accounting Standards Board. Future net cash flow represents future gross cash flow from the production and sale of proved reserves, net of crude oil, natural gas and natural gas liquids production costs (including production taxes, ad valorem taxes and operating expenses) and future development costs. The calculations used to produce the figures in this table are based on current cost and price factors at December 31 for each year. Future income taxes were estimated using future cash inflows, future tax depletion expense on existing producing properties and available net operating loss carryforwards that existed at year-end for all years reported. At December 31, 2010, the future pretax net cash flows from our proved oil and gas reserves are estimated to be less than the sum of the tax basis of the applicable producing properties and our available net operating loss (“NOLs”) carryforward; therefore, there was zero future tax benefit or expense at December 31, 2010. We believe it is more likely than not that all of our total available NOLs will be realized within the appropriate carryforward period. Our operations and all NOLs are attributable to our oil and gas assets. We cannot assure you that the proved reserves will all be developed within the periods used in the calculations or that those prices and costs will remain constant. A Standardized Measure is not required to be presented for interim financial presentation dates.
Standardized Measure relating to proved reserves:
| |
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
Future cash inflows
|
|
$ |
1,133,153,500 |
|
|
$ |
860,655,250 |
|
|
$ |
475,007,800 |
|
|
Future production and development costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
(305,301,493 |
) |
|
|
(218,221,203 |
) |
|
|
(156,581,500 |
) |
|
Development
|
|
|
(299,390,312 |
) |
|
|
(195,819,078 |
) |
|
|
(55,021,500 |
) |
|
Future cash flows before income taxes
|
|
|
528,461,695 |
|
|
|
446,614,969 |
|
|
|
263,404,800 |
|
|
Future income taxes
|
|
|
(40,347,466 |
) |
|
|
(37,624,289 |
) |
|
|
— |
|
|
Future net cash flows after income taxes
|
|
|
488,114,229 |
|
|
|
408,990,680 |
|
|
|
263,404,800 |
|
|
10% annual discount for estimated timing of cash flows
|
|
|
(232,782,186 |
) |
|
|
(182,476,004 |
) |
|
|
(86,982,100 |
) |
|
Standardized measure of discounted future net cash flows
|
|
$ |
255,332,043 |
|
|
$ |
226,514,676 |
|
|
$ |
176,422,700 |
|
Our calculations of the Standardized Measure include the effect of estimated future income tax expenses for all years reported. At December 31, 2010, the future pretax net cash flows from our proved oil and gas reserves are estimated to be less than the sum of the tax basis of the applicable producing properties and our available NOLs carryforward; therefore, there was zero future tax benefit or expense at December 31, 2010. We believe it is more likely than not that all of our total available NOLs will be realized within the appropriate carryforward period. Our operations and all NOLs are attributable to our oil and gas assets.
The following reconciles the change in the Standardized Measure:
| |
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
Beginning of year
|
|
$ |
226,514,676 |
|
|
$ |
176,422,700 |
|
|
$ |
260,902,233 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchases of proved reserves
|
|
|
226,395 |
|
|
|
— |
|
|
|
— |
|
|
Sales of producing properties
|
|
|
— |
|
|
|
(408,190 |
) |
|
|
(25,350,512 |
) |
|
Extensions, discoveries and improved recovery, less related costs
|
|
|
113,088,953 |
|
|
|
109,361,697 |
|
|
|
3,864,603 |
|
|
Sales of natural gas, crude oil and natural gas liquids produced, net of production costs
|
|
|
(86,132,123 |
) |
|
|
(53,956,677 |
) |
|
|
(48,528,840 |
) |
|
Revision of quantity estimates(1)
|
|
|
(29,416,407 |
) |
|
|
9,476,255 |
|
|
|
(26,277,363 |
) |
|
Accretion of discount
|
|
|
(70,061,524 |
) |
|
|
17,642,270 |
|
|
|
29,094,980 |
|
|
Change in income taxes
|
|
|
2,064,758 |
|
|
|
(13,206,215 |
) |
|
|
30,352,367 |
|
|
Changes in estimated future development costs
|
|
|
(11,283,184 |
) |
|
|
(11,801,896 |
) |
|
|
14,712,798 |
|
|
Development costs incurred that reduced future development costs
|
|
|
75,258,100 |
|
|
|
11,788,100 |
|
|
|
7,085,480 |
|
|
Change in sales and transfer prices, net of production costs
|
|
|
35,843,018 |
|
|
|
(1,102,871 |
) |
|
|
(64,108,501 |
) |
|
Changes in production rates (timing) and other
|
|
|
(770,619 |
) |
|
|
(17,700,499 |
) |
|
|
(5,324,545 |
) |
|
End of year
|
|
$ |
255,332,043 |
|
|
$ |
226,514,676 |
|
|
$ |
176,422,700 |
|
(1) Periodic revisions to the quantity estimates may be necessary as a result of a number of factors, including reservoir performance, new drilling, oil and natural gas prices, cost changes, technological advances, new geological or geophysical data, or other economic factors.
This disclosure excludes the effects of realized hedges ($7,497,604 gain in 2011, $20,912,559 gain in 2010; $38,783,854 gain in 2009) which are included in natural gas and crude oil sales on the Statements of Operations.
CRIMSON EXPLORATION INC. AND SUBSIDIARIES
SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2011, 2010 AND 2009
|
DESCRIPTION
|
|
BALANCE AT BEGINNING OF PERIOD
|
|
|
PROVISIONS/ ADDITIONS
|
|
|
RECOVERIES/ DEDUCTIONS
|
|
|
BALANCE AT END OF PERIOD
|
|
|
For the year ended December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for doubtful accounts
|
|
$ |
215,015 |
|
|
|
239,676 |
|
|
|
(43,367 |
) |
|
$ |
411,324 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Valuation allowance for deferred tax assets
|
|
$ |
3,260,875 |
|
|
|
— |
|
|
|
— |
|
|
$ |
3,260,875 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the year ended December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for doubtful accounts
|
|
$ |
411,324 |
|
|
|
167,819 |
|
|
|
— |
|
|
$ |
579,143 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Valuation allowance for deferred tax assets
|
|
$ |
3,260,875 |
|
|
|
127,048 |
|
|
|
— |
|
|
$ |
3,387,923 |
|
|
For the year ended December 31, 2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for doubtful accounts
|
|
$ |
579,143 |
|
|
|
60,057 |
|
|
|
(59,612 |
) |
|
$ |
579,588 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Valuation allowance for deferred tax assets
|
|
$ |
3,387,923 |
|
|
|
— |
|
|
|
(149,267 |
) |
|
$ |
3,238,656 |
|
F-30