UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2005
OR
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to __________
Commission File Number: 000-22433
Brigham Exploration Company
(Exact name of registrant as specified in its charter)
Delaware | 1311 | 75-2692967 | ||
(State of other jurisdiction of incorporation or organization) | (Primary Standard Industrial Classification Code Number) | (I.R.S. Employer Identification Number) |
6300 Bridge Point Parkway, Building 2, Suite 500, Austin, Texas 78730
(Address of principal executive offices)
(512) 427-3300
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding twelve months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.
Yes x No ¨
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12 b-2 of the Act).
Yes x No ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12 b-2 of the Act).
Yes ¨ No x
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date.
Class | Outstanding |
Common Stock, par value $.01 per share as of November 4, 2005 | 42,748,513 |
Brigham Exploration Company
Third Quarter 2005 Form 10-Q Report
TABLE OF CONTENTS
Page | |||
PART I - FINANCIAL INFORMATION | |||
ITEM 1. | FINANCIAL STATEMENTS | ||
1 | |||
2 | |||
3 | |||
4 | |||
5 | |||
ITEM 2. | 14 | ||
ITEM 3. | 33 | ||
ITEM 4. | 34 | ||
PART II - OTHER INFORMATION | |||
ITEM 1. | 35 | ||
ITEM 2. | 35 | ||
ITEM 3. | 35 | ||
ITEM 4. | 35 | ||
ITEM 5. | 35 | ||
ITEM 6. | 35 | ||
36 |
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
(Unaudited)
September 30, | December 31, | ||||||
2005 | 2004 | ||||||
ASSETS | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 5,873 | $ | 2,281 | |||
Accounts receivable | 18,882 | 17,573 | |||||
Deferred income taxes | 2,324 | 239 | |||||
Other current assets | 1,251 | 901 | |||||
Total current assets | 28,330 | 20,994 | |||||
Oil and natural gas properties, net (full cost method) | 324,693 | 261,979 | |||||
Other property and equipment, net | 997 | 1,209 | |||||
Deferred loan fees | 2,264 | 1,745 | |||||
Other noncurrent assets | 695 | 380 | |||||
Total assets | $ | 356,979 | $ | 286,307 | |||
LIABILITIES AND STOCKHOLDERS' EQUITY | |||||||
Current liabilities: | |||||||
Accounts payable | $ | 16,837 | $ | 22,465 | |||
Royalties payable | 6,461 | 6,072 | |||||
Accrued drilling costs | 6,634 | 6,099 | |||||
Participant advances received | 1,798 | 3,633 | |||||
Other current liabilities | 8,907 | 2,225 | |||||
Total current liabilities | 40,637 | 40,494 | |||||
Senior credit facility | 58,100 | 21,000 | |||||
Senior subordinated notes | 30,000 | 20,000 | |||||
Series A Preferred Stock, mandatorily redeemable, $.01 par value, $20 stated and redemption value, 2,250,000 shares authorized, 505,051 and 475,986 shares issued and outstanding at September 30, 2005 and December 31, 2004, respectively | 10,101 | 9,520 | |||||
Deferred income taxes | 17,524 | 9,031 | |||||
Other noncurrent liabilities | 3,428 | 2,986 | |||||
Commitments and contingencies (Note 5) | |||||||
Stockholders' equity: | |||||||
Common stock, $.01 par value, 50 million shares authorized, 43,513,978 and 43,231,499 shares issued and 42,295,601 and 42,034,351 shares outstanding at September 30, 2005 and December 31, 2004, respectively | 435 | 432 | |||||
Additional paid-in capital | 177,087 | 175,270 | |||||
Treasury stock, at cost; 1,218,377 and 1,197,148 shares at September 30, 2005 and December 31, 2004, respectively | (4,897 | ) | (4,707 | ) | |||
Unearned stock compensation | (1,671 | ) | (1,570 | ) | |||
Accumulated other comprehensive income (loss) | (3,655 | ) | (503 | ) | |||
Retained earnings | 29,890 | 14,354 | |||||
Total stockholders’ equity | 197,189 | 183,276 | |||||
Total liabilities and stockholders' equity | $ | 356,979 | $ | 286,307 |
The accompanying notes are an integral part of these consolidated financial statements.
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
(Unaudited)
Three Months Ended | Nine Months Ended | ||||||||||||
September 30, | September 30, | ||||||||||||
2005 | 2004 | 2005 | 2004 | ||||||||||
Restated | Restated | ||||||||||||
Revenues: | |||||||||||||
Oil and natural gas sales | $ | 25,189 | $ | 17,240 | $ | 60,326 | $ | 51,975 | |||||
Other revenue | 37 | 27 | 136 | 69 | |||||||||
25,226 | 17,267 | 60,462 | 52,044 | ||||||||||
Costs and expenses: | |||||||||||||
Lease operating | 1,541 | 1,648 | 5,149 | 4,362 | |||||||||
Production taxes | 741 | 675 | 1,909 | 2,434 | |||||||||
General and administrative | 1,317 | 1,304 | 3,719 | 3,723 | |||||||||
Depletion of oil and natural gas properties | 7,953 | 5,860 | 21,612 | 16,508 | |||||||||
Depreciation and amortization | 183 | 179 | 543 | 544 | |||||||||
Accretion of discount on asset retirement obligations | 44 | 40 | 126 | 117 | |||||||||
11,779 | 9,706 | 33,058 | 27,688 | ||||||||||
Operating income | 13,447 | 7,561 | 27,404 | 24,356 | |||||||||
Other income (expense): | |||||||||||||
Interest income | 62 | 26 | 153 | 55 | |||||||||
Interest expense, net | (1,138 | ) | (872 | ) | (2,645 | ) | (2,508 | ) | |||||
Other income (expense) | (497 | ) | (168 | ) | (851 | ) | (159 | ) | |||||
(1,573 | ) | (1,014 | ) | (3,343 | ) | (2,612 | ) | ||||||
Income before income taxes | 11,874 | 6,547 | 24,061 | 21,744 | |||||||||
Income tax expense: | |||||||||||||
Current | — | — | — | — | |||||||||
Deferred | (4,196 | ) | (2,056 | ) | (8,525 | ) | (7,190 | ) | |||||
(4,196 | ) | (2,056 | ) | (8,525 | ) | (7,190 | ) | ||||||
Net income | $ | 7,678 | $ | 4,491 | $ | 15,536 | $ | 14,554 | |||||
Net income per share available to common stockholders: | |||||||||||||
Basic | $ | 0.18 | $ | 0.11 | $ | 0.37 | $ | 0.37 | |||||
Diluted | $ | 0.18 | $ | 0.11 | $ | 0.36 | $ | 0.35 | |||||
Weighted average shares outstanding: | |||||||||||||
Basic | 42,236 | 41,227 | 42,175 | 39,921 | |||||||||
Diluted | 43,528 | 42,340 | 43,244 | 41,078 |
The accompanying notes are an integral part of these consolidated financial statements.
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
(In thousands)
(Unaudited)
Common Stock | Additional Paid In | Treasury | Unearned Stock | Accumulated Other Comprehensive | Retained | Total Stockholders' | |||||||||||||||||||
Shares | Amounts | Capital | Stock | Compensation | Income (Loss) | Earnings | Equity | ||||||||||||||||||
Balance, December 31, 2004 | 43,231 | $ | 432 | $ | 175,270 | $ | (4,707 | ) | $ | (1,570 | ) | $ | (503 | ) | $ | 14,354 | $ | 183,276 | |||||||
Comprehensive income: | |||||||||||||||||||||||||
Net income | — | — | — | — | — | — | 15,536 | 15,536 | |||||||||||||||||
Unrealized gain (losses) on cash flow hedges | — | — | — | — | — | (5,738 | ) | — | (5,738 | ) | |||||||||||||||
Tax benefits related to cash flow hedges | — | — | — | — | — | 1,696 | — | 1,696 | |||||||||||||||||
Net losses realized and included in net income | — | — | — | — | — | 890 | — | 890 | |||||||||||||||||
Comprehensive income | 12,384 | ||||||||||||||||||||||||
Exercises of employee stock options | 218 | 2 | 795 | — | — | — | — | 797 | |||||||||||||||||
Vesting of restricted stock | 65 | 1 | (1 | ) | — | — | — | — | — | ||||||||||||||||
Issuance of restricted stock | — | — | 602 | — | (602 | ) | — | — | — | ||||||||||||||||
Tax benefit from the exercise of stock options | — | — | 421 | — | — | — | — | 421 | |||||||||||||||||
Repurchases of common stock | — | — | — | (190 | ) | — | — | — | (190 | ) | |||||||||||||||
Amortization of unearned stock compensation | — | — | — | — | 501 | — | — | 501 | |||||||||||||||||
Balance, September 30, 2005 | 43,514 | $ | 435 | $ | 177,087 | $ | (4,897 | ) | $ | (1,671 | ) | $ | (3,655 | ) | $ | 29,890 | $ | 197,189 |
The accompanying notes are an integral part of these consolidated financial statements.
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
Nine Months Ended | |||||||
September 30, | |||||||
2005 | 2004 | ||||||
Restated (1) | |||||||
Cash flows from operating activities: | |||||||
Net income | $ | 15,536 | $ | 14,554 | |||
Adjustments to reconcile net income to cash provided by operating activities: | |||||||
Depletion of oil and natural gas properties | 21,612 | 16,508 | |||||
Depreciation and amortization | 543 | 544 | |||||
Interest paid through issuance of additional mandatorily redeemable preferred stock | 581 | 538 | |||||
Amortization of deferred loan fees and debt issuance costs | 373 | 574 | |||||
Market value adjustment for derivative instruments | 995 | 227 | |||||
Accretion of discount on asset retirement obligations | 126 | 117 | |||||
Deferred income taxes | 8,525 | 7,190 | |||||
Other noncash items | 103 | — | |||||
Changes in operating assets and liabilities: | |||||||
Accounts receivable | (1,320 | ) | (48 | ) | |||
Other current assets | (459 | ) | 2,427 | ||||
Accounts payable | (5,628 | ) | (3,249 | ) | |||
Royalties payable | 389 | 614 | |||||
Participant advances received | (1,835 | ) | (628 | ) | |||
Other current liabilities | 543 | (1,737 | ) | ||||
Other noncurrent assets and liabilities | (22 | ) | (126 | ) | |||
Net cash provided by operating activities | 40,062 | 37,505 | |||||
Cash flows from investing activities: | |||||||
Additions to oil and natural gas properties | (83,306 | ) | (61,160 | ) | |||
Additions to other property and equipment | (184 | ) | (186 | ) | |||
Decrease (increase) in drilling advances paid | 205 | (137 | ) | ||||
Net cash used by investing activities | (83,285 | ) | (61,483 | ) | |||
Cash flows from financing activities: | |||||||
Increase in senior credit facility | 49,100 | 28,000 | |||||
Repayment of senior credit facility | (12,000 | ) | (23,500 | ) | |||
Increase in senior subordinated notes | 10,000 | — | |||||
Proceeds from the issuance of common stock, net of issuance costs | — | 22,132 | |||||
Deferred loan fees paid and equity costs | (892 | ) | (10 | ) | |||
Proceeds from exercise of employee stock options | 797 | 684 | |||||
Repurchases of common stock | (190 | ) | (156 | ) | |||
Net cash provided by financing activities | 46,815 | 27,150 | |||||
Net increase (decrease) in cash and cash equivalents | 3,592 | 3,172 | |||||
Cash and cash equivalents, beginning of year | 2,281 | 5,779 | |||||
Cash and cash equivalents, end of period | $ | 5,873 | $ | 8,951 | |||
(1) | Only individual line items in cash flows from operating activities have been restated. Total cash flows from operating, investing and financing activities were unaffected. |
The accompanying notes are an integral part of these consolidated financial statements.
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. | Organization and Nature of Operations |
Brigham Exploration Company is a Delaware corporation formed on February 25, 1997 for the purpose of exchanging its common stock for the common stock of Brigham, Inc. and the partnership interests of Brigham Oil & Gas, L.P. (the “Partnership”). Hereinafter, Brigham Exploration Company and the Partnership are collectively referred to as “Brigham.” Brigham, Inc. is a Nevada corporation whose only asset is its ownership interest in the Partnership. The Partnership was formed in May 1992 to explore and develop onshore domestic oil and natural gas properties using 3-D seismic imaging and other advanced technologies. Since its inception, the Partnership has focused its exploration and development of oil and natural gas properties primarily in the onshore Texas Gulf Coast, the Anadarko Basin and West Texas.
2. | Basis of Presentation |
The accompanying unaudited consolidated financial statements include the accounts of Brigham and its wholly-owned subsidiaries, and its proportionate share of assets, liabilities and income and expenses of the limited partnerships in which Brigham, or any of its subsidiaries, has a participating interest. All significant intercompany accounts and transactions have been eliminated.
The accompanying consolidated financial statements are unaudited, and in the opinion of management, reflect all adjustments that are necessary for a fair statement of the financial position and results of operations for the periods presented. All such adjustments are of a normal and recurring nature. The unaudited consolidated financial statements are presented in accordance with the rules and regulations of the U.S. Securities and Exchange Commission requirements of Form 10-Q and do not include all disclosures normally required by accounting principles generally accepted in the United States of America. The results of operations for the periods presented are not necessarily indicative of the results to be expected for the entire year. The unaudited consolidated financial statements should be read in conjunction with Brigham's 2004 Annual Report on Form 10-K pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.
Stock Based Compensation
Brigham accounts for employee stock-based compensation using the intrinsic value method prescribed by Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees". Accordingly, Brigham has adopted the disclosure-only provisions of Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation" (SFAS 123).
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Had compensation cost for Brigham's stock options been determined based on the fair market value at the grant dates of the awards consistent with the methodology prescribed by SFAS 123, as amended by SFAS 148, Brigham's net income and net income per share for the three and nine month periods ended September 30, 2005 and 2004 would have been the pro forma amounts indicated below:
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||
2005 | 2004 | 2005 | 2004 | ||||||||||
(In thousands, except per share amounts) | |||||||||||||
Net income, as reported (as restated for 2004) | $ | 7,678 | $ | 4,491 | $ | 15,536 | $ | 14,554 | |||||
Add back: Stock compensation expense previously included in net income | 111 | 103 | 333 | 340 | |||||||||
Effect of total employee stock-based compensation expense, determined under fair value method for all awards | (355 | ) | (916 | ) | (1,036 | ) | (1,908 | ) | |||||
Pro forma | $ | 7,434 | $ | 3,678 | $ | 14,833 | $ | 12,986 | |||||
Net income per share: | |||||||||||||
Basic, as reported | $ | 0.18 | $ | 0.11 | $ | 0.37 | $ | 0.37 | |||||
Basic, pro forma | 0.18 | 0.09 | 0.35 | 0.33 | |||||||||
Diluted, as reported | $ | 0.18 | $ | 0.11 | $ | 0.36 | $ | 0.35 | |||||
Diluted, pro forma | 0.17 | 0.09 | 0.34 | 0.32 |
3. | Restatement |
Brigham utilizes the full cost method of accounting for its proved oil and natural gas properties included in the consolidated financial statements. During March 2005, in conjunction with preparation of the financial statements for the year ended December 31, 2004, management evaluated the manner in which Brigham historically accounted for depletion expense associated with our oil and natural gas properties. Historically, Brigham had calculated a depletion rate at the end of each period within the year based on its updated reserve estimate. This depletion rate had then been retroactively applied to year-to-date production with the adjustment to previously recorded depletion expense recorded in the current quarter. Brigham determined that the revised depletion rate should have been applied on a prospective basis to production in the most current quarterly period only. As a result, depletion of oil and natural gas properties for the three and nine months ending September 30, 2004, has been restated.
The information in the quarterly financial statement information below represents only those consolidated statements of operations line items affected by the restatement (in thousands).
Three months ended September 30, 2004 | Nine months ended September 30, 2004 | ||||||||||||
As Reported | Restated | As Reported | Restated | ||||||||||
Consolidated Statements of Operations: | |||||||||||||
Depletion of oil and natural gas properties | $ | 5,871 | $ | 5,860 | $ | 16,374 | $ | 16,508 | |||||
Deferred income tax benefit (expense) | (2,051 | ) | (2,056 | ) | (7,234 | ) | (7,190 | ) | |||||
Net income | 4,485 | 4,491 | 14,644 | 14,554 | |||||||||
Net income (loss) per share available to common stockholders: | |||||||||||||
Basic | $ | 0.11 | $ | 0.11 | $ | 0.37 | $ | 0.37 | |||||
Diluted | $ | 0.11 | $ | 0.11 | $ | 0.36 | $ | 0.35 |
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
4. | Senior Credit Facility and Senior Subordinated Notes |
Senior Credit Facility
During June 2005, Brigham amended and restated its senior credit facility to provide for revolving credit borrowings up to a maximum principal amount of $200 million at any one time outstanding. Borrowings under Brigham’s senior credit facility cannot exceed its borrowing base, which is determined at least semiannually. Brigham’s initial borrowing base under the amended and restated senior credit facility is $80 million. As of September 30, 2005, Brigham had $58.1 million in borrowings outstanding under its senior credit facility.
Brigham also extended the maturity of its senior credit facility from March 2009 to June 2010 and changed the interest rate that it pays on borrowings under the facility. Borrowings under the senior credit facility bear interest, at Brigham’s election, at a base rate (as the term is defined in the senior credit facility) or Eurodollar rate, plus in each case an applicable margin. The applicable interest rate margin varies from 0.0% to 0.5% in the case of borrowings based on the base rate (as the term is defined in the senior credit facility) and from 1.25% to 2.0% in the case of borrowings based on the Eurodollar rate, depending on percentage of the available borrowing base utilized. In addition, Brigham is required to pay a commitment fee on the unused portion of its borrowing base. The applicable commitment fee varies from 0.25% to 0.375%, depending on the percentage of the available borrowing base utilized.
The senior credit facility contains various covenants, including among others restrictions on liens, restrictions on incurring other indebtedness, restrictions on mergers, restrictions on investments, and restrictions on hedging activity of a speculative nature or with counterparties having credit ratings below specified levels. The senior credit facility requires Brigham to maintain a current ratio (as defined) of at least 1 to 1 and an interest coverage ratio (as defined) of at least 3 to 1.
Senior Subordinated Notes
During June 2005, Brigham amended its $20 million subordinated credit agreement to provide up to $40 million of borrowings and extended the maturity of the notes from March 2009 until June 2010. As of September 30, 2005, Brigham had $30 million of senior subordinated notes outstanding. The senior subordinated notes are secured obligations ranking junior to Brigham’s senior credit facility. Brigham will have the opportunity to draw the additional $10 million available under the subordinated credit agreement until December 29, 2006.
Borrowings under the subordinated credit agreement bear interest based on the Eurodollar rate plus a margin as defined.
Brigham has an interest rate swap that converts $20 million of the borrowings under its subordinated credit agreement from floating to fixed rate debt. At closing this interest rate was 7.61%. This interest rate could increase if Brigham borrows additional debt under its subordinated credit agreement and borrowings under its senior credit agreement reach or exceed 75% of Brigham’s available borrowing base. In addition, a commitment fee of 0.750% is payable on the unused portion subordinated credit agreement.
5. | Commitments and Contingencies |
Brigham is, from time to time, party to certain lawsuits and claims arising in the ordinary course of business. While the outcome of lawsuits and claims cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on the financial condition, results of operations or cash flows of Brigham.
On October 8, 2002, relatives of a contractor’s employee filed a wrongful death action against Brigham and three other contractors in the District Court of Matagorda County, Texas in connection with the employee’s death on Brigham’s Burkhart #1-R location. On March 23, 2004, a jury determined that Brigham had no liability in the accidental death of the contractor’s employee. The trial judge, however, granted plaintiffs’ motion for a new trial. The new trial took place in September 2005. During jury deliberations, plaintiffs and Brigham’s insurer agreed in principle to settle the dispute. The settlement will result in a nominal payment to the plaintiffs.
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
As of September 30, 2005, there are no known environmental or other regulatory matters related to Brigham’s operations that are reasonably expected to result in a material liability to Brigham. Compliance with environmental laws and regulations has not had, and is not expected to have, a material adverse effect on Brigham’s financial position, results of operations or cash flows.
6. | Earnings Per Common Share |
Basic earnings per share (EPS) is computed by dividing net income (the numerator) by the weighted average number of common shares outstanding for the period (the denominator). Diluted EPS is computed by dividing net income by the weighted average number of common shares and potential common shares outstanding (if dilutive) during each period. Potential common shares include stock options and restricted stock. The number of potential common shares outstanding relating to stock options and restricted stock is computed using the treasury stock method.
The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the three and nine months ended September 30, 2005 and 2004 are as follows (in thousands):
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||
2005 | 2004 | 2005 | 2004 | ||||||||||
Weighted average common shares outstanding - basic | 42,236 | 41,227 | 42,175 | 39,921 | |||||||||
Plus: Potential common shares | |||||||||||||
Stock options and restricted stock | 1,292 | 1,113 | 1,069 | 1,157 | |||||||||
Weighted average common shares outstanding - diluted | 43,528 | 42,340 | 43,244 | 41,078 | |||||||||
Stock options excluded from diluted EPS due to the anti-dilutive effect | — | 656 | 10 | 676 |
7. | Derivative Instruments and Hedging Activities |
Brigham utilizes various commodity swap and option contracts to (i) reduce the effects of volatility in price changes on the oil and natural gas commodities it produces and sells, (ii) reduce commodity price risk and (iii) provide a base level of cash flow in order to assure it can execute at least a portion of its capital spending plans.
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
The following table sets forth Brigham's realized oil and natural gas prices including and excluding the hedging gains and losses and the increase or decrease in oil and natural gas revenues as a result of the hedging activities for the three and nine month periods ended September 30, 2005 and 2004:
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||
2005 | 2004 | 2005 | 2004 | ||||||||||
Natural Gas | |||||||||||||
Average price per Mcf as reported (including hedging results) | $ | 8.45 | $ | 5.44 | $ | 7.01 | $ | 5.68 | |||||
Average price per Mcf realized (excluding hedging results) | $ | 8.71 | $ | 5.62 | $ | 7.14 | $ | 5.87 | |||||
Decrease in revenue (in thousands) | $ | (590 | ) | $ | (390 | ) | $ | (831 | ) | $ | (1,250 | ) | |
Oil | |||||||||||||
Average price per Bbl as reported (including hedging results) | $ | 58.51 | $ | 36.82 | $ | 49.87 | $ | 33.51 | |||||
Average price per Bbl realized (excluding hedging results) | $ | 60.44 | $ | 42.50 | $ | 53.32 | $ | 38.01 | |||||
Decrease in revenue (in thousands) | $ | (208 | ) | $ | (843 | ) | $ | (1,134 | ) | $ | (2,018 | ) |
Ineffectiveness associated with Brigham's derivative commodity instruments designated as cash flow hedges is included in other income (expense). The following table provides a summary of the impact on earnings from ineffectiveness for the three and nine months ended September 30 (in thousands):
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||
2005 | 2004 | 2005 | 2004 | ||||||||||
Increase (decrease) in earnings due to ineffectiveness | $ | (477 | ) | $ | (146 | ) | $ | (890 | ) | $ | (206 | ) |
Natural Gas and Crude Oil Derivative Contracts
Cash-flow hedges
Brigham's cash-flow hedges consisted of costless collars (purchased put options and written call options). The costless collars are used to establish floor and ceiling prices on anticipated future oil and natural gas production. There were no net premiums received when Brigham entered into these option agreements.
Derivative positions included written put options that are not designated as hedges and are reflected at fair value on the balance sheet. These positions were entered into in conjunction with a costless collar to offset the cost of other option positions that are designated as hedges. At each balance sheet date, the value of derivatives not qualifying as hedging contracts is adjusted to reflect current fair value and any gains or losses are recognized as other income (expense). The following table provides a summary of the fair value of these derivatives included in other current liabilities (in thousands):
September 30, 2005 | December 31, 2004 | ||||||
Fair value of undesignated derivatives | $ | (137 | ) | $ | — |
The following table provides a summary of the impact on earnings from non-cash gains (losses) included in other income (expense) related to changes in the fair values of these derivative contracts for the three and nine months ended September 30 (in thousands):
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||
2005 | 2004 | 2005 | 2004 | ||||||||||
Increase (decrease) in earnings due to changes in fair value of undesignated derivatives | $ | (52 | ) | $ | (21 | ) | $ | (105 | ) | $ | (21 | ) |
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
The following table reflects open commodity derivative contracts at September 30, 2005, the associated volumes and the corresponding weighted average NYMEX reference price.
Notional Amount | ||||||||||||||||
Settlement Period | Derivative Instrument | Hedge Strategy | Gas (MMBTU) | Oil (Barrels) | Nymex Reference | |||||||||||
Costless Collars | ||||||||||||||||
10/01/05 - 10/31/05 | Purchased put | Cash flow | 60,000 | $ | 5.45 | |||||||||||
Written call | Cash flow | 60,000 | 8.00 | |||||||||||||
01/01/06 - 03/31/06 | Purchased put | Cash flow | 7,500 | $ | 62.00 | |||||||||||
Written call | Cash flow | 7,500 | 74.50 | |||||||||||||
04/01/06 - 06/30/06 | Purchased put | Cash flow | 16,500 | $ | 54.80 | |||||||||||
Written call | Cash flow | 16,500 | 75.00 | |||||||||||||
Three Way Costless Collars | ||||||||||||||||
10/01/05 - 03/31/06 | Purchased put | Cash flow | 36,000 | $ | 48.00 | |||||||||||
Written call | Cash flow | 36,000 | 60.70 | |||||||||||||
Written put | Undesignated | 36,000 | 38.00 | |||||||||||||
10/01/05 - 10/31/05 | Purchased put | Cash flow | 100,000 | $ | 6.00 | |||||||||||
Written call | Cash flow | 100,000 | 7.20 | |||||||||||||
Written put | Undesignated | 100,000 | 5.00 | |||||||||||||
10/01/05 - 12/31/05 | Purchased put | Cash flow | 15,000 | $ | 40.00 | |||||||||||
Written call | Cash flow | 15,000 | 53.00 | |||||||||||||
Written put | Undesignated | 15,000 | 30.00 | |||||||||||||
10/01/05 - 10/31/05 | Purchased put | Cash flow | 60,000 | $ | 7.00 | |||||||||||
Written call | Cash flow | 60,000 | 7.76 | |||||||||||||
Written put | Undesignated | 60,000 | 5.75 | |||||||||||||
11/01/05 - 03/31/06 | Purchased put | Cash flow | 250,000 | $ | 6.75 | |||||||||||
Written call | Cash flow | 250,000 | 8.80 | |||||||||||||
Written put | Undesignated | 250,000 | 5.50 | |||||||||||||
11/01/05 - 03/31/06 | Purchased put | Cash flow | 350,000 | $ | 8.00 | |||||||||||
Written call | Cash flow | 350,000 | 9.75 | |||||||||||||
Written put | Undesignated | 350,000 | 6.50 | |||||||||||||
11/01/05 - 03/31/06 | Purchased put | Cash flow | 400,000 | $ | 10.00 | |||||||||||
Written call | Cash flow | 400,000 | 13.08 | |||||||||||||
Written put | Undesignated | 400,000 | 8.50 | |||||||||||||
04/01/06 - 06/30/06 | Purchased put | Cash flow | 7,500 | $ | 63.00 | |||||||||||
Written call | Cash flow | 7,500 | 75.25 | |||||||||||||
Written put | Undesignated | 7,500 | 48.00 | |||||||||||||
07/01/06 - 09/30/06 | Purchased put | Cash flow | 15,000 | $ | 63.00 | |||||||||||
Written call | Cash flow | 15,000 | 75.65 | |||||||||||||
Written put | Undesignated | 15,000 | 48.00 | |||||||||||||
04/01/06 - 10/31/06 | Purchased put | Cash flow | 420,000 | $ | 7.50 | |||||||||||
Written call | Cash flow | 420,000 | 9.15 | |||||||||||||
Written put | Undesignated | 420,000 | 6.25 | |||||||||||||
04/01/06 - 10/31/06 | Purchased put | Cash flow | 490,000 | $ | 8.50 | |||||||||||
Written call | Cash flow | 490,000 | 9.96 | |||||||||||||
Written put | Undesignated | 490,000 | 7.00 |
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
The following table reflects commodity derivative contracts entered subsequent to September 30, 2005, the associated volumes and the corresponding weighted average NYMEX reference price.
Notional Amount | ||||||||||||||||
Settlement Period | Derivative Instrument | Hedge Strategy | Gas (MMBTU) | Oil (Barrels) | Nymex Reference Price | |||||||||||
Costless Collars | ||||||||||||||||
04/01/06 - 10/31/06 | Purchased put | Cash flow | 490,000 | $ | 8.00 | |||||||||||
Written call | Cash flow | 490,000 | 14.85 | |||||||||||||
11/01/06 - 03/31/07 | Purchased put | Cash flow | 450,000 | $ | 8.00 | |||||||||||
Written call | Cash flow | 450,000 | 21.20 |
Interest rate swap
Periodically, Brigham may use interest rate swap contracts to adjust the proportion of its total debt that is subject to variable interest rates. Under such an interest rate swap contract, Brigham agrees to pay an amount equal to a specified fixed-rate of interest for a certain notional amount and receive in return an amount equal to a variable-rate. The notional amounts of the contract are not exchanged. No other cash payments are made unless the contract is terminated prior to maturity. Although no collateral is held or exchanged for the contract, the interest rate swap contract is entered into with a major financial institution in order to minimize Brigham’s counterparty credit risk. The interest rate swap contract is designated as a cash flow hedge against changes in the amount of future cash flows associated with Brigham’s interest payments on variable-rate debt. The effect of this accounting on operating results is that interest expense on a portion of variable-rate debt being hedged is recorded based on fixed interest rates.
At September 30, 2005, Brigham had an interest rate swap contract to pay a fixed-rate of interest of 7.61% on $20.0 million notional amount of senior subordinated notes. The $20.0 million notional amount of the outstanding contract matures in March 2009. As of September 30, 2005, approximately $0.5 million of unrealized gains are included in accumulated other comprehensive income (loss) on the balance sheet and the fair value of the interest rate swap agreement represents approximately $0.5 million of other noncurrent assets. The fair value of the interest rate swap contract is based on quoted market prices and third-party provided calculations, which reflect the present values of the difference between estimated future variable-rate receipts and future fixed-rate payments.
Fair values
The fair value of hedging and interest rate swap contracts is reflected on the consolidated balance sheets as detailed in the following table. The current asset and liability amounts represent the fair values expected to be included in the results of operations for the next twelve months.
September 30, 2005 | December 31, 2004 | ||||||
(In thousands) | |||||||
Other current liabilities | $ | (6,872 | ) | $ | (870 | ) | |
Other noncurrent liabilities | (115 | ) | (1 | ) | |||
Other current assets | 33 | 142 | |||||
Other noncurrent assets | 523 | 3 | |||||
$ | (6,431 | ) | $ | (726 | ) |
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
8. | Asset Retirement Obligations |
Brigham has asset retirement obligations associated with the future plugging and abandonment of proved properties and related facilities. The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.
Brigham has no assets that are legally restricted for purposes of settling asset retirement obligations. The following table summarizes Brigham's asset retirement obligation transactions recorded in accordance with the provisions of SFAS 143 during the nine months ended September 30, 2005 and 2004 (in thousands):
Nine Months Ended September 30, | |||||||
2005 | 2004 | ||||||
Beginning asset retirement obligations | $ | 2,896 | $ | 2,320 | |||
Liabilities incurred for new wells placed on production | 244 | 394 | |||||
Liabilities settled | (10 | ) | (92 | ) | |||
Accretion of discount on asset retirement obligations | 126 | 117 | |||||
$ | 3,256 | $ | 2,739 |
9. | Accounting Pronouncements |
In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123R, “Share-Based Payment” (SFAS 123R), which is a revision of SFAS 123 and supersedes APB Opinion No. 25. SFAS 123R requires all share-based payments to employees, including grants of employee stock options, to be valued at fair value on the date of grant, and to be expensed over the applicable vesting period. Pro forma disclosure of the income statement effects of share-based payments is no longer an alternative. In addition, companies must also recognize compensation expense related to any awards that are not fully vested as of the effective date. The fair value is determined using a variety of assumptions, including those related to volatility rates, forfeiture rates and the option pricing model used (e.g. binomial or Black Scholes). These assumptions could differ from those Brigham has utilized in determining its pro forma compensation expense. SFAS 123R will also impact the manner in which Brigham recognizes the income tax impacts of its stock compensation programs in the consolidated financial statements. The effective date of SFAS 123R is January 1, 2006, for calendar year companies. Upon adoption Brigham will apply SFAS 123R prospectively for new stock-based compensation arrangements and to the unvested portion of existing arrangements. Brigham is currently assessing the impact of adopting SFAS 123R to its consolidated financial statements.
In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47), which clarifies the impact that uncertainty surrounding the timing or method of settling an obligation should have on accounting for that obligation under SFAS No. 143. FIN 47 is effective no later than the end of the fiscal year ending after December 15, 2005, or December 31, 2005 for calendar year companies. Brigham does not expect the adoption of FIN 47 to have a material impact on its consolidated financial statements.
In May 2005, the FASB issued Statement of Financial Accounting Standards No. 154, “Accounting Changes and Error Corrections — a replacement of APB Opinion No. 20 and FASB Statement No. 3” (SFAS 154). SFAS 154 establishes retrospective application as the required method for reporting a change in accounting principle, unless it is impracticable in which the changes should be applied to the latest practicable date presented for voluntary accounting changes and in the absence of specific guidance provided for in a new pronouncement issued by an authoritative body. SFAS 154 also requires that a correction of an error be reported as a prior period adjustment by restating prior period financial statements. SFAS 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005.
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
10. | Subsequent Event |
On November 1, 2005, Brigham paid $4.6 million in cash for the acquisition of approximately 46,000 net acres in the Bakken play located in 126 sections in northwestern North Dakota. Brigham acquired a 100% working interest in the Bakken Shale formation within the acreage.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following updates information as to our financial condition provided in our 2004 Annual Report on Form 10-K, and analyzes the changes in the results of operations between the three and nine month periods ended September 30, 2005, and the comparable periods of 2004. For definitions of commonly used gas and oil terms as used in this Form 10-Q, please refer to the "Glossary of Oil and Gas Terms" provided in our 2004 Annual Report on Form 10-K.
Overview of Third Quarter and First Nine Months of 2005
The price of natural gas during the first nine months of 2005 remained relatively high compared to historical prices due to forecasts for continued U.S. production declines, weather, increasing natural gas demand and similarly high crude oil prices, which limit fuel-switching flexibility. The average sales price, excluding hedging results, that we received for our natural gas in the third quarter and first nine months of 2005 was $8.71 and $7.14, respectively. This represents an increase of 55% over the price we received in third quarter of 2004 and an increase of 22% over the sales price we received during the first nine months of last year. Similarly, the average sales price that we received for oil in the third quarter and first nine months of 2005 also increased over the sales prices we received in those periods last year. The average sales price, excluding hedging results, that we received for oil during the third quarter 2005 and first nine months of 2005 was $60.44 and $53.32, respectively, up 42% when compared to the third quarter of last year and up 40% when compared to the first nine months of last year.
Our net capital expenditures for oil and natural gas activities during the third quarter of 2005 were $25.3 million and year to date through September 30, 2005 we have spent $84.3 million. Our average production was 32 MMcfe/d for the third quarter 2005 and 30.5 MMcfe/d for the first nine months of 2005 compared to 34 MMcfe/d and 34.1 MMcfe/d during the third quarter and first nine months of 2004, respectively. The natural decline of our existing production was only partially offset by production from recently completed wells, causing an overall decline in production for the periods. Furthermore, we estimate that third quarter production of approximately 0.5 MMcfe/d and approximately 0.2 MMcfe/d of the first nine months of 2005 production were lost due the need to shut-in wells in preparation for Hurricane Rita.
Net income for the third quarter 2005 was $7.7 million, or $0.18 per diluted share, on total revenues of $25.2 million. This compares to reported net income of $4.5 million, or $0.11 per diluted share on revenue of $17.3 million in the third quarter last year. The increase in net income was primarily due to an increase in our revenue and lower lease operating expense. These were partially offset by increases in our depletion expense, interest expense, other expense and deferred income tax expense. Net income for the first nine months 2005 was $15.5 million, or $0.36 per diluted share, on total revenues of $60.5 million. This compares to reported net income of $14.6 million, or $0.35 per diluted share, on total revenue of $52 million in the first nine months of last year. The increase in our net income for the first nine months of 2005 was primarily due to increases in our revenue. These were partially offset by increases in our production costs, depletion expense, interest expense, other expense, and deferred income tax expense.
For the third quarter 2005, net cash provided by operating activities funded approximately 45% of our cash used by investing activities and year to date through September 30, 2005, has funded 48% of our cash used by investing activities. During the third quarter 2005, we borrowed an additional $13.7 million of debt, net of repayments, under our senior credit facility and year to date through September 30, 2005 we had borrowed an additional $37.1 million of debt, net of repayments, under our senior credit facility and an additional $10 million of senior subordinated notes.
At September 30, 2005, we had $5.9 million in cash, total assets of $357 million and a debt to capitalization ratio of 33%.
Capital Commitments
Capital Expenditures
The timing of most of our capital expenditures is discretionary because we have no material long-term capital expenditure commitments. Consequently, we have a significant degree of flexibility to adjust the level of our capital expenditures as circumstances warrant. Our capital expenditure program includes the following:
· | cost of acquiring and maintaining our lease acreage position and our seismic resources; |
· | cost of drilling and completing new oil and natural gas wells; |
· | cost of installing new production infrastructure; |
· | cost of enhancing existing oil and natural gas wells and the associated infrastructure; |
· | cost related to plugging and abandoning unproductive or uneconomic wells; and, |
· | indirect costs related to our exploration activities, including payroll and other expenses attributable our exploration professional staff. |
On September 27, 2005, we announced that we increased our 2005 capital budget. For 2005, we now plan to spend approximately $119.1 million, which represents an increase of 32% over our original 2005 budget announced in March 2005. As part of our revised budget we now plan to drill 36 wells with an average working interest of 63% compared to 37 wells with an average working interest of 55% in our original budget.
The table below summarizes our budgeted capital expenditures, the amount we have spent through September 30, 2005 and the amount of our 2005 budget that remains to be spent.
Revised 2005 Budget | Amount Spent Through 09/30/05 | Amount Remaining (1) | ||||||||
(In thousands) | ||||||||||
Drilling | $ | 95,823 | $ | 66,172 | $ | 29,651 | ||||
Net land and seismic | 16,354 | 12,754 | 3,600 | |||||||
Capitalized interest and G&A | 6,654 | 5,156 | 1,498 | |||||||
Asset retirement obligation | — | 244 | — | |||||||
Other PP&E | 313 | 184 | 129 | |||||||
Total | $ | 119,144 | $ | 84,510 | $ | 34,878 |
(1) | Represents amount of our revised 2005 budget that remains to be spent. Calculated as the amount budgeted for 2005 less amount spent through September 30, 2005. |
Approximately $46.1 million of the drilling capital in our revised budget is allocated to drill 14 exploration wells with an average working interest of 65%. The drilling capital allocated to exploration drilling in our revised budget represents an increase of 33% over the amount in our original budget, where we planned to spend $34.7 million to drill 17 wells with an average working interest of 60%.
The remaining $49.7 million of drilling capital in our revised budget is allocated to drill 22 development wells with an average working interest of 62% and on other development activities. The drilling capital allocated to development activities in our revised budget represents an increase of 39% over the amount in our original budget, where we planned to spend $35.6 million to drill 20 development wells with an average working interest of 51% and on other development activities. Additionally, we now plan to spend $30.5 million to develop our proved undeveloped reserves compared to $26.5 million in our original budget.
Province Breakout
Revised Budget | Original Budget | Change | ||||||||||||||||||||||||||
Gross Well | Net Well | Avg. WI% | Gross Well | Net Well | Avg. WI% | Gross Well | Net Well | Avg. WI% | ||||||||||||||||||||
Onshore Gulf Coast | 18 | 13.2 | 73 | % | 17 | 11.0 | 65 | % | 1 | 2.2 | 8 | % | ||||||||||||||||
Anadarko Basin | 15 | 7.1 | 47 | % | 17 | 6.9 | 40 | % | (2 | ) | 0.2 | 7 | % | |||||||||||||||
West Texas | 3 | 2.5 | 83 | % | 3 | 2.4 | 82 | % | - | 0.1 | 1 | % | ||||||||||||||||
Total | 36 | 22.8 | 63 | % | 37 | 20.3 | 55 | % | (1 | ) | 2.5 | 8 | % |
Onshore Gulf Coast
Our revised 2005 budget for our Onshore Gulf Coast province is $74.9 million and is 42% higher than the $52.8 million allocated to this province in our original 2005 budget.
Approximately $63.9 million of our capital expenditures in our revised 2005 budget allocated to our Onshore Gulf Coast province will be spent to drill seven exploration wells with an average working interest of 65%, to drill 11 development wells with an average working interest of 78% and for other development activities. This compares to $43.8 million in our original budget to drill seven exploration wells with an average working interest of 64%, to drill 10 development wells with an average working interest of 65% and for other development activities.
The amount we now plan to spend in 2005 to drill exploration wells in our Onshore Gulf Coast province increased by $9.1 million, to $26 million, when compared to our original 2005 budget. As of September 30, 2005, three of the seven exploration wells in our revised 2005 budget planned for this province had been completed or were completing. The remaining four exploration wells that we plan to spud in 2005 will commence drilling in the fourth quarter of 2005. Three of these wells are higher risk but higher reserve potential wells.
The amount of drilling capital we plan to spend in 2005 on development activities in our Onshore Gulf Coast province increased by $11.1 million, to $37.9 million, when compared to our original 2005 budget. We have increased both the number of planned development wells for this province from 10 to 11 and our average working interest in these wells from 65% to 78%. As of September 30, 2005, eight of the eleven development wells in our revised 2005 budget for this province had been completed or were completing, while two were drilling. The remaining development well for this province will spud in the fourth quarter of 2005.
We also increased our 2005 budget for land and seismic activities in our Onshore Gulf Coast province from $9.0 million to $10.9 million.
Anadarko Basin
Our revised 2005 budget for our Anadarko Basin province is $30.9 million and is 14% higher than the $27 million allocated to this province in our original 2005 budget.
Approximately $28 million of our 2005 capital expenditures in our revised 2005 budget allocated to our Anadarko Basin province will be spent to drill five exploration wells with an average working interest of 51%, to drill 10 development wells with an average working interest of 46% and for other development activities. This compares to $23.5 million in our original budget to drill seven exploration wells with an average working interest of 46%, to drill ten development wells with an average working interest of 37% and for other development activities.
The amount we plan to spend in 2005 to drill exploration wells in our Anadarko Basin province increased by $2.5 million, to $17.3 million, when compared to our original 2005 budget. Although our number of planned exploration wells for this province has decreased from seven to five, we have increased our average working interest in the wells that we plan to drill from 46% to 51%. As of September 30, 2005, two of the five exploration wells in our revised 2005 budget for this province had been completed or were completing, while one was drilling. Both of the remaining exploration wells that we expect to spud in 2005 will commence drilling in the fourth quarter. One of these two wells is a higher risk but higher reserve potential well.
The amount of drilling capital we plan to spend on development activities in our Anadarko Basin province in 2005 increased by $2 million, to $10.7 million, when compared to our original 2005 budget. Although our number of planned development wells for this province has not changed, we have increased our average working interest in the development wells that we plan to drill from 37% to 46%. Seven of the ten development wells in our revised 2005 budget for this province have been completed or are currently completing. We expect the remaining three development wells to commence drilling in the fourth quarter of 2005. Two of these wells are Granite Wash wells in our Hobart Project.
We decreased our 2005 budget for land and seismic activities in our Anadarko Basin province from $3.5 million to $2.9 million.
West Texas
Our revised 2005 budget for our West Texas province is $6.4 million, which represents an increase of 78% over the $3.6 million allocated to this province in our original 2005 budget.
Approximately $3.8 million of our capital expenditures in our revised 2005 budget allocated to our West Texas province will be spent to drill two exploration wells with an average working interest of 100%, to drill one development well with an average working interest of 50% and for other development activities. This compares to $3 million in our original budget to drill three exploration wells with an average working interest of 82% and for other development activities.
The amount we plan to spend in 2005 to drill exploration wells in our West Texas province decreased by $200,000, to $2.7 million, when compared to our original 2005 budget. Although we have decreased the number of planned exploration wells for this province from three to two, we have increased our average working interest in the wells we plan to drill in 2005 from 82% to 100%. As of September 30, 2005, one of the two exploration wells currently planned for 2005 in our West Texas province had been completed and the other will be spud in the fourth quarter.
The amount of drilling capital we plan to spend in 2005 on development activities in our West Texas province has increased by $1 million, to $1.1 million, when compared to our original 2005 budget. We now plan to drill one development well in this province with a 50% working interest. This development well is planned to spud in the fourth quarter of 2005.
We also increased our 2005 budget for land and seismic activities in our West Texas province from $600,000 million to $2.5 million.
The capital that funds our drilling activities is allocated to individual prospects based on the value potential of a prospect, as measured by a risked net present value analysis. We start each year with a budget and reevaluate this budget monthly. The primary factors that impact this value creation measure include forecasted commodity prices, drilling and completion costs, and a prospect’s risked reserve size and risked initial producing rate. Other factors that are also monitored throughout the year that influence the amount and timing of all our budgeted expenditures include the level of production from our existing oil and natural gas properties, the availability of drilling and completion services, and the success and resulting production of our newly drilled wells. The outcome of our monthly analysis results in a reprioritization of our exploration and development well drilling schedule to ensure that we are optimizing our capital expenditure plan.
Additionally, we currently plan to capitalize approximately $6.7 million of our forecasted total general and administrative cost and forecasted interest in 2005.
The final determination with respect to our 2005 budgeted expenditures will depend on a number of factors, including:
· | commodity prices; |
· | production from our existing producing wells; |
· | the results of our current exploration and development drilling efforts; |
· | economic and industry conditions at the time of drilling, including the availability of drilling equipment; and |
· | the availability of more economically attractive prospects. |
There can be no assurance that the budgeted wells will, if drilled, encounter commercial quantities of natural gas or oil.
Senior Credit Facility
On June 29, 2005, we amended and restated our $100 million senior credit agreement to provide up to $200 million in borrowing capacity and to extend the maturity of our senior credit agreement from March 21, 2009, to June 29, 2010. Our committed borrowing base under our amended and restated senior credit agreement, which prior to amendment was $72 million, is $80 million.
As of September 30, 2005, we had $58.1 million in borrowings outstanding under our senior credit facility. During the first nine months of 2005 we borrowed an additional $49.1 million of additional debt under our senior credit facility and repaid $12 million. Approximately, $8.2 million of the total $12 million was repaid using proceeds from additional borrowing of senior subordinated notes. Borrowings outstanding under our senior credit facility at November 4, 2005, were $63.1 million which represented 79% of our available borrowing base.
During the third quarter 2005, we borrowed an additional $17.5 million of debt under our senior credit facility and repaid $3.8 million.
Pursuant to our senior credit agreement, we are required to maintain a current ratio of at least 1 to 1 and an interest coverage ratio for the four most recent quarters of at least 3 to 1. Our current ratio at September 30, 2005 and interest coverage ratio for the twelve-month period ended September 30, 2005, were 1.8 to 1 and 20.2 to 1, respectively. At September 30, 2005, and for the twelve-month period then ended, we were in compliance with all covenant requirements in connection with our senior credit agreement.
Senior Subordinated Notes
On June 29, 2005, we amended our $20 million subordinated credit agreement, dated January 21, 2005, to provide up to $40 million in borrowings and to extend the maturity of our subordinated credit agreement from March 21, 2009, to June 29, 2010. Upon closing, we borrowed an additional $10 million of senior subordinated notes under our subordinated credit agreement, which increased the total notes we have borrowed under our subordinated credit agreement to $30 million. We will have the opportunity to draw the remaining $10 million of our senior notes available under our subordinated credit agreement until December 29, 2006.
As of September 30, 2005, we had $30 million of senior subordinated notes outstanding. Pursuant to our subordinated credit agreement, we are required to maintain a current ratio of at least 1 to 1, and an interest coverage ratio for the four most recent quarters of at least 3 to 1. Our current ratio at September 30, 2005 and interest coverage ratio for the twelve-month period ended September 30, 2005, were 1.8 to 1 and 20.2 to 1, respectively. At September 30, 2005 and for the twelve-month period then ended, we were in compliance with all covenant requirements in connection with our subordinated credit agreement.
Mandatorily Redeemable Preferred Stock
As of September 30, 2005, we had $10.1 million in mandatorily redeemable Series A preferred stock outstanding, which is held by merchant banking funds managed by affiliates of CSFB Private Equity. During the third quarter of 2005 we issued 9,987 shares of additional shares of preferred stock to satisfy our third quarter 2005 dividend requirements. Year to date through September 30, 2005, we have issued 29,065 shares of additional preferred stock to satisfy our dividend requirements. Our option to pay the mandatorily redeemable Series A preferred stock dividend by issuing additional shares of our preferred stock expired on October 31, 2005. We are now required to pay the dividends on our Series A preferred stock in cash at an annual rate of 6%.
Capital Resources
We intend to fund our remaining 2005 capital expenditure program and contractual commitments through cash flows from operations, borrowings under both our senior credit facility and subordinated credit agreement and, if required and available, alternative financing sources. Our primary sources of cash during first nine months of 2005 were net cash provided by operations and additional borrowings under both our senior credit facility and subordinated credit agreement. We made aggregate cash payments of $2.7 million for interest in the first nine months of 2005.
Net cash provided by operating activities
Net cash provided by operating activities is a function of the prices that we receive from the sale of oil and natural gas, which are inherently volatile and unpredictable, gains or losses related to the settlement of derivative contracts, production, operating cost and our cost of capital. Our asset base, as with other extractive industries, is a depleting one in which each Mcf of natural gas or barrel of oil produced must be replaced or our ability to generate cash flow, and thus sustain our exploration and development activities, will diminish. Net cash provided by operating activities during the first nine months of 2005 funded 48% of our net cash used by investing activities compared to 61% in the first nine months last year.
Senior Credit Facility
As of November 4, 2005 the unused committed borrowing capacity available to us under our senior credit facility was $16.9 million. On June 29, 2005, our borrowing base increased from $72 million to $80 million when we amended and restated our senior credit agreement.
Senior Subordinated Notes
As of September 30, 2005, we had an additional $10 million of senior subordinated notes available to us under our subordinated credit agreement. These additional notes are available to us for borrowing until December 29, 2006.
The future amount of debt that we borrow under our senior credit facility and subordinated credit agreement will depend primarily on net cash provided by operating activities proceeds from other financing activities and proceeds generated from asset dispositions. We strive to manage the borrowings outstanding under our senior credit facility and subordinated credit agreement in order to maintain excess borrowing capacity.
Access to Capital Markets
We currently have an effective universal shelf registration statement covering the sale, from time to time, of our common stock, preferred stock, depositary shares, warrants and debt securities, or a combination of any of these securities. In July 2004, we sold 2,598,500 shares of our common stock under the universal shelf registration statement. Following this sale, our remaining capacity under the shelf registration statement is approximately $176.9 million. However, our ability to raise additional capital using our shelf registration statement may be limited due to overall conditions of the stock market or the oil and natural gas industry.
Results of Operations
Comparison of the three and nine month periods ended September 30, 2005 and 2004.
Revenues
Production volumes
Three months ended Sept. 30, | Nine months ended Sept 30, | ||||||||||||||||||
2005 | % Change | 2004 | 2005 | % Change | 2004 | ||||||||||||||
Oil (MBbls) | 108 | (27 | %) | 148 | 329 | (27 | %) | 449 | |||||||||||
Natural gas (MMcf) | 2,233 | 3 | % | 2,167 | 6,268 | (4 | %) | 6,506 | |||||||||||
Total (MMcfe)(1) | 2,881 | (6 | %) | 3,057 | 8,240 | (10 | %) | 9,199 | |||||||||||
Average daily production (MMcfe/d) | 32.0 | 34.0 | 30.5 | 34.1 |
(1) | Mcfe is defined one million cubic feet equivalent of natural gas, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids. |
Our net equivalent production volumes for the third quarter of 2005 were 2.9 Bcfe (32 MMcfe/d) down from 3.1 Bcfe (34 MMcfe/d) in the third quarter of 2004. Our net equivalent production volumes for the first nine months of 2005 were 8.2 Bcfe (30.5 MMcfe/d) down from 9.2 Bcfe (34.1 MMcfe/d) in 2004.
Natural gas represented 78% of our third quarter 2005 production volumes and 76% of our production volumes in the first nine months of 2005. Comparably, natural gas represented 71% of our third quarter 2004 production and 71% of our production for the first nine months of 2004.
The natural decline of our existing production was only partially offset by production from recently completed wells, causing an overall decline in production for the periods. Additionally, we estimate that approximately 0.5 MMcfe/d of our third quarter 2005 production and approximately 0.2 MMcfe/d of the first nine months of the year production were lost due to the need to shut-in wells in preparation for Hurricane Rita.
Hedging Results
The following table shows the type of derivative commodity contracts, the volumes, the weighted average NYMEX reference price for those volumes, and the associated gain /(loss) upon settlement of those contracts for the periods indicated.
Three months ended Sept. 30, | Nine months ended Sept 30, | ||||||||||||||||||
2005 | % Change | 2004 | 2005 | % Change | 2004 | ||||||||||||||
Oil swaps | |||||||||||||||||||
Volumes (Bbls) | — | (100 | %) | 13,800 | — | (100 | %) | 63,850 | |||||||||||
Average swap price ($ per Bbl) | $ | — | (100 | %) | $ | 23.91 | $ | — | (100 | %) | $ | 24.77 | |||||||
Gain /(loss) upon settlement ($ in thousands) | $ | — | (100 | %) | $ | (275 | ) | $ | — | (100 | %) | $ | (848 | ) | |||||
Oil collars | |||||||||||||||||||
Volumes (Bbls) | 33,000 | (32 | %) | 48,760 | 85,105 | (41 | %) | 144,310 | |||||||||||
Average floor price ($ per Bbl) | $ | 44.36 | 68 | % | $ | 26.34 | $ | 34.71 | 42 | % | $ | 24.51 | |||||||
Average ceiling price ($ per Bbl) | $ | 57.20 | 78 | % | $ | 32.20 | $ | 43.32 | 39 | % | $ | 31.09 | |||||||
Gain /(loss) upon settlement ($ in thousands) | $ | (208 | ) | (63 | %) | $ | (568 | ) | $ | (1,134 | ) | (3 | %) | $ | (1,170 | ) | |||
Total oil | |||||||||||||||||||
Volumes (Bbls) | 33,000 | (47 | %) | 62,560 | 85,105 | (59 | %) | 208,160 | |||||||||||
Gain /(loss) upon settlement ($ in thousands) | $ | (208 | ) | (75 | %) | $ | (843 | ) | $ | (1,134 | ) | (44 | %) | $ | (2,018 | ) | |||
Natural gas swaps | |||||||||||||||||||
Volumes (MMbtu) | — | (100 | %) | 138,000 | — | (100 | %) | 661,250 | |||||||||||
Average swap price ($ per MMbtu) | $ | — | (100 | %) | $ | 4.18 | $ | — | (100 | %) | $ | 4.56 | |||||||
Gain /(loss) upon settlement ($ in thousands) | $ | — | (100 | %) | $ | (230 | ) | $ | — | (100 | %) | $ | (836 | ) | |||||
Natural gas collars | |||||||||||||||||||
Volumes (MMbtu) | 660,000 | (9 | %) | 722,200 | 2,022,500 | 14 | % | 1,777,800 | |||||||||||
Average floor price ($ per MMbtu) | $ | 6.12 | 33 | % | $ | 4.61 | $ | 5.40 | 25 | % | $ | 4.32 | |||||||
Average ceiling price ($ per MMbtu) | $ | 7.57 | 17 | % | $ | 6.48 | $ | 7.30 | 7 | % | $ | 6.85 | |||||||
Gain /(loss) upon settlement ($ in thousands) | $ | (590 | ) | 269 | % | $ | (160 | ) | $ | (831 | ) | 101 | % | $ | (414 | ) | |||
Total natural gas | |||||||||||||||||||
Volumes (MMbtu) | 660,000 | (23 | %) | 860,200 | 2,022,500 | (17 | %) | 2,439,050 | |||||||||||
Gain /(loss) upon settlement ($ in thousands) | $ | (590 | ) | 51 | % | $ | (390 | ) | $ | (831 | ) | (34 | %) | $ | (1,250 | ) |
Reported revenues from the sale of oil and natural gas are based on the market price we receive for our commodities, adjusted for marketing charges and the results from the settlement of our derivative commodity contracts that qualify for cash flow hedge accounting treatment under SFAS 133.
We utilize commodity swap, collar, three way costless collar and floor contracts to (i) reduce the effect of price volatility on the commodities that we produce and sell, (ii) reduce commodity price risk and (iii) provide a base level of cash flow in order to assure we can execute at least a portion of our capital spending plans.
The effective portions of changes in the fair values of our derivative commodity contracts that qualify for cash flow hedge accounting treatment under SFAS 133 are reported as increases or decreases to stockholders’ equity until the underlying contract is settled. Consequentially, changes in the effective portions of these derivative contracts add volatility to our reported stockholders’ equity until the contract is settled or is terminated.
Gains or losses related to the settlement and the changes in the fair values of our derivative commodity contracts that do not qualify for cash flow hedge accounting treatment under SFAS 133 are reported in other income (expense).
Commodity prices and revenues
The following table shows our revenue from the sale of oil and natural gas for the periods indicated.
Three months ended Sept. 30, | Nine months ended Sept 30, | ||||||||||||||||||
2005 | % Change | 2004 | 2005 | % Change | 2004 | ||||||||||||||
(In thousands, except per unit measurements) | |||||||||||||||||||
Revenue from the sale of oil and natural gas: | |||||||||||||||||||
Oil sales | $ | 6,529 | 4% | $ | 6,304 | $ | 17,531 | 3% | $ | 17,058 | |||||||||
Gain (loss) due to hedging | (208 | ) | (75%) | (843 | ) | (1,134 | ) | (44%) | (2,018 | ) | |||||||||
Total revenue from the sale of oil | $ | 6,321 | 16% | $ | 5,461 | $ | 16,397 | 9% | $ | 15,040 | |||||||||
Natural gas sales | $ | 19,458 | 60% | $ | 12,169 | $ | 44,760 | 17% | $ | 38,185 | |||||||||
Gain (loss) due to hedging | (590 | ) | 51% | (390 | ) | (831 | ) | (34%) | (1,250 | ) | |||||||||
Total revenue from the sale of natural gas | $ | 18,868 | 60% | $ | 11,779 | $ | 43,929 | 19% | $ | 36,935 | |||||||||
Oil and natural gas sales | $ | 25,987 | 41% | $ | 18,473 | $ | 62,291 | 13% | $ | 55,243 | |||||||||
Gain (loss) due to hedging | (798 | ) | (35%) | (1,233 | ) | (1,965 | ) | (40%) | (3,268 | ) | |||||||||
Total revenue from the sale of oil and natural gas | $ | 25,189 | 46% | $ | 17,240 | $ | 60,326 | 16% | $ | 51,975 | |||||||||
Average prices: | |||||||||||||||||||
Oil sales price (per Bbl) | $ | 60.44 | 42% | $ | 42.50 | $ | 53.32 | 40% | $ | 38.01 | |||||||||
Gain (loss) due to hedging (per Bbl) | (1.93 | ) | (66%) | (5.68 | ) | (3.45 | ) | (23%) | (4.50 | ) | |||||||||
Realized oil price (per Bbl) | $ | 58.51 | 59% | $ | 36.82 | $ | 49.87 | 49% | $ | 33.51 | |||||||||
Natural gas sales price (per Mcf) | $ | 8.71 | 55% | $ | 5.62 | $ | 7.14 | 22% | $ | 5.87 | |||||||||
Gain (loss) due to hedging (per Mcf) | (0.26 | ) | 44% | (0.18 | ) | (0.13 | ) | (32%) | (0.19 | ) | |||||||||
Realized natural gas price (per Mcf) | $ | 8.45 | 55% | $ | 5.44 | $ | 7.01 | 23% | $ | 5.68 | |||||||||
Natural gas equivalent sales price (per Mcfe) | $ | 9.02 | 49% | $ | 6.04 | $ | 7.56 | 26% | $ | 6.01 | |||||||||
Gain (loss) due to hedging (per Mcfe) | (0.28 | ) | (30%) | (0.40 | ) | (0.24 | ) | (33%) | (0.36 | ) | |||||||||
Realized natural gas equivalent (per Mcfe) | $ | 8.74 | 55% | $ | 5.64 | $ | 7.32 | 30% | $ | 5.65 |
For the three month periods ended Sept 30 2005 and 2004 | For the nine month periods ended Sept 30 2005 and 2004 | ||||||
Change in revenue from the sale of oil | |||||||
Price variance impact | $ | 1,938 | $ | 5,034 | |||
Volume variance impact | (1,713 | ) | (4,561 | ) | |||
Cash settlement of hedging contracts | 635 | 884 | |||||
Total change | $ | 860 | $ | 1,357 | |||
Change in revenue from the sale of natural gas | |||||||
Price variance impact | $ | 6,909 | $ | 7,969 | |||
Volume variance impact | 380 | (1,394 | ) | ||||
Cash settlement of hedging contracts | (200 | ) | 419 | ||||
Total change | $ | 7,089 | $ | 6,994 |
Our revenue from the sale of oil and natural gas for the third quarter of 2005 increased by 46% when compared to our revenue in last year’s third quarter. The following were the primary factors that led to the changes in our third quarter 2005 revenue from the sale of oil and natural gas.
· | A 49% increase in the sales price we received for our oil and natural gas combined with a 35% decrease in losses from the cash settlement of derivative commodity contracts led to increases of $8.8 million and $435,000, respectively, to our revenue from the sale of oil and natural gas during the third quarter 2005. |
· | A decrease in this year’s third quarter production partially offset these increases and reduced our third quarter 2005 revenue from the sale of oil and natural gas by $1.3 million. |
Our revenue from the sale of oil and natural gas for the first nine months of 2005 increased by 16% when compared to revenue in the first nine months of last year. The following were the primary factors that led to the changes in our revenue from the sale of oil and natural gas for the first nine months of 2005.
· | A 26% increase in the sales price we received for our oil and natural gas combined with a 40% decrease in losses from the cash settlement of derivative commodity contracts led to increases of $13 million and $1.3 million, respectively, to our revenue from the sale of oil and natural gas during the first nine months of 2005. |
· | A decrease in our production for the first nine months of 2005 partially offset these increases and reduced our revenue for the first nine months of 2005 by $6 million. |
Other revenue. Other revenue relates to fees that we charge other parties who use our gas gathering systems that we own to move their production from the wellhead to third party gas pipeline systems. Other revenue for the third quarter of 2005 was $37,000 compared to $27,000 in the third quarter last year. Other revenue for the first nine months of 2005 was $136,000 compared to $69,000 in the first nine months of 2004. Costs related to our gas gathering systems are reported as lease operating expenses.
Operating costs and expenses
Production costs. Production costs include lease operating expenses and production taxes.
Three months ended Sept. 30, | Nine months ended Sept 30, | ||||||||||||||||||
2005 | % Change | 2004 | 2005 | % Change | 2004 | ||||||||||||||
(In thousands, except per unit measurements) | |||||||||||||||||||
Production costs: | |||||||||||||||||||
Operating & maintenance | $ | 1,410 | 17% | $ | 1,201 | $ | 4,221 | 30% | $ | 3,248 | |||||||||
Expensed workovers | (73 | ) | NM | 278 | 238 | (61%) | 617 | ||||||||||||
Ad valorem taxes | 204 | 21% | 169 | 690 | 39% | 497 | |||||||||||||
Lease operating expenses | $ | 1,541 | (6%) | $ | 1,648 | $ | 5,149 | 18% | $ | 4,362 | |||||||||
Production taxes | 741 | 10% | 675 | 1,909 | (22%) | 2,434 | |||||||||||||
Production costs | $ | 2,282 | (2%) | $ | 2,323 | $ | 7,058 | 4% | $ | 6,796 | |||||||||
Production cost ($ per Mcfe): | |||||||||||||||||||
Operating & maintenance | $ | 0.49 | 26% | $ | 0.39 | $ | 0.51 | 46% | $ | 0.35 | |||||||||
Expensed workovers | (0.03 | ) | NM | 0.09 | 0.03 | (57%) | 0.07 | ||||||||||||
Ad valorem taxes | 0.07 | 17% | 0.06 | 0.08 | 60% | 0.05 | |||||||||||||
Lease operating expenses | $ | 0.53 | (2%) | $ | 0.54 | $ | 0.62 | 32% | $ | 0.47 | |||||||||
Production taxes | 0.26 | 18% | 0.22 | 0.23 | (12%) | 0.26 | |||||||||||||
Production costs | $ | 0.79 | 4% | $ | 0.76 | $ | 0.85 | 16% | $ | 0.73 |
Our production costs for the third quarter 2005 decreased by 2% when compared to the third quarter last year. The following were the primary factors that led to the changes in third quarter 2005 production costs.
· | A decrease in expensed workovers during the third quarter 2005. This decrease is a result of less workover activity and actual costs associated with expensed workovers that were lower than estimated costs previously accrued. This decrease was partially offset by the following increases. |
· | An increase in operating and maintenance expenses due to cost associated with our new wells that were not producing in the third quarter last year. Our third quarter 2005 operating and maintenance expenses include $254,000 related to these new wells. Excluding costs associated with these new wells our operating and maintenance expenses for the third quarter 2005 decreased by 4% when compared to the third quarter last year. In the future we anticipate that our operating and maintenance expenses and total production costs will increase as we add new wells and production facilities and continue to maintain production from existing maturing properties. |
· | An increase in our third quarter ad valorem taxes due to an increase in property values due to higher oil and natural gas prices during 2004. |
· | An increase in production taxes due to an increase in commodity prices partially offset by a reduction in production taxes due to lower production volumes and production tax credits of approximately $517,000 related to six high cost gas wells. |
Our production costs for the first nine months of 2005 increased 4% from 2004. The following were the primary reasons for the changes to our production costs for the first nine months of 2005.
· | An increase in operating and maintenance expenses due to cost associated with our new wells that were not producing during the first nine months of last year. Our operating and maintenance expenses for the first nine months of 2005 included $610,000 related to these new wells. Excluding costs associated with these new wells, our operating and maintenance expenses for the first nine months of this year increased by 11% when compared to last year. Other expenses that contributed to the increase in our operating and maintenance expenses were increases in costs for saltwater disposal, compressor rental and maintenance, third party overhead fees, water treating, contract service and labor, equipment rental and miscellaneous lease operating expenses. In the future we anticipate that our operating and maintenance costs and total production costs will increase as we add new wells and production facilities and continue to maintain production from existing maturing properties. |
· | An increase in our ad valorem taxes due to an increase in property values due to higher oil and natural gas prices during 2004. |
· | These increases were partially offset by a decrease in production taxes and expensed workovers. A reduction in production for the first nine months of 2005 combined with production tax credits of approximately $1.1 million related to 12 high cost gas wells were the primary reasons for the decrease in our production taxes for the first nine months of 2005. These decreases were partially offset by increases in the sales price we received from the sale of our oil and natural gas. |
We believe that per unit of production measures is the best way to evaluate our production cost information. We use this information to evaluate our performance relative to our peers and to internally evaluate our performance.
For the third quarter of 2005, our unit production cost increased by 4% when compared to last year. The following were the primary factors that led to the changes in our unit production cost.
· | Our unit O&M expenses for the third quarter were up $0.10 per Mcfe when compared to last year. Approximately 90% of this increase was due to new wells that were not producing during the third quarter last year. The remainder of the increase was due to a decrease in our third quarter 2005 production volumes. |
· | Our unit ad valorem taxes for the third quarter 2005 were up $0.01 per Mcfe when compared to last year. This increase is primarily due to an increase in total ad valorem taxes due to an increase in property values due to higher oil and natural gas prices in 2004 combined with a decrease in our third quarter 2005 production volumes. |
· | Our unit production taxes for the third quarter 2005 were up $0.04 per Mcfe when compared to last year. This increase is primarily due to an increase in the sales price that we received from the sale of our oil and natural gas partially offset by production tax credits of approximately $517,000 related to six high cost gas wells. |
· | These increases were partially offset by a $0.12 per Mcfe decrease in our third quarter 2005 unit expensed workover costs. This decrease is a result of less workover activity and actual costs associated with expensed workovers that were lower than estimated costs previously accrued. |
For the first nine months of 2005, our unit production cost increased 16% when compared to last year. The following were the primary factors that led to the changes to our unit production cost for the first nine months of 2005.
· | Our unit O&M expenses for the first nine months of 2005 were up $0.16 per Mcfe when compared to last year. Approximately 44% of this increase was due to an increase in costs related to new wells that were not producing during the first nine months of last year. Increases in our unit costs for saltwater disposal, compressor rental and maintenance, third party overhead fees, water treating, contract service and labor, equipment rental and miscellaneous expense combined with a decrease in production volumes were the primary reasons for the remaining increase. |
· | Our unit ad valorem taxes for the first nine months of 2005 were up $0.03 per Mcfe when compared to last year. This increase is primarily due to higher ad valorem taxes due to an increase property values due to higher oil and natural gas prices in 2004 combined with a decrease in our production volumes. |
· | These increases were partially offset by a $0.03 per Mcfe decrease in our unit production taxes and $0.04 decrease in our unit workover expenses. The decrease in our production taxes was primarily due to a decrease in production for the first nine months of 2005 and production tax credits of approximately $1.1 million related to 12 high cost gas wells. The decrease in our unit workover expense for the first nine months of 2005 was due to a result of less workover activity and actual costs associated with expensed workovers that were lower than estimated costs previously accrued. |
General and administrative expenses. We capitalize a portion of our general and administrative costs. The costs capitalized represent the cost of technical employees, who work directly on capital projects. An engineer designing a well is an example of a technical employee working on a capital project. The cost of a technical employee includes associated technical organization costs such as supervision, telephone and postage.
Three months ended Sept. 30, | Nine months ended Sept 30, | ||||||||||||||||||
2005 | % Change | 2004 | 2005 | % Change | 2004 | ||||||||||||||
�� | |||||||||||||||||||
(In thousands, except per unit measurements) | |||||||||||||||||||
General and administrative costs | $ | 2,551 | 5% | $ | 2,441 | $ | 7,355 | 0% | $ | 7,334 | |||||||||
Capitalized general and administrative costs | (1,234 | ) | 9% | (1,137 | ) | (3,636 | ) | 1% | (3,611 | ) | |||||||||
General and administrative expenses | $ | 1,317 | 1% | $ | 1,304 | $ | 3,719 | (0%) | $ | 3,723 | |||||||||
General and administrative expense ($ per Mcfe) | $ | 0.46 | 7% | $ | 0.43 | $ | 0.45 | 13% | $ | 0.40 |
For the third quarter of 2005, our general and administrative expenses increased by 1% when compared to last year. The following were the primary factors that led to the changes to our third quarter 2005 general and administrative expenses.
· | A 7% increase in compensation expense, primarily due to increases in salaries and wages, represented approximately 61% of the total increase in our third quarter 2005 general and administrative costs. Other costs that contributed to the increase of our third quarter 2005 general and administrative costs were increases in costs for financial reporting, office expenses, travel and miscellaneous expenses. |
· | These increases were partially offset by decreases in costs for contract employees and outside consultants, office rent and equipment rental and maintenance cost. Together, these cost decreases represented approximately 95% of the total decrease in our third quarter 2005 general and administrative costs. |
For the first nine months of 2005, our general and administrative expenses decreased by 3% when compared to last year. The following were the primary factors that led to the changes to our general and administrative expenses for the first nine months of 2005.
· | A decrease in costs for incentive compensation, legal expenses, third party reserve engineering, office rent, financial reporting, advertising and franchise taxes. Together, these decreases represented approximately 92% of the total decrease in our general and administrative costs for the first nine months of 2005. |
· | These decreases were partially offset by increases in costs for salaries and wages, third party consultants, audit and tax fees, office expenses, corporate insurance, travel, continuing education and miscellaneous general and administrative costs. Together these increases represented approximately 92% of the total increase in our general and administrative costs for the first nine months of 2005. |
Depletion of oil and natural gas properties. Our full-cost depletion expense is driven by many factors including certain costs spent in the exploration and development of producing reserves, production levels, and estimates of proved reserve quantities and the costs required to develop proved undeveloped reserves. Our 2004 information pertaining to depletion and accumulated depletion that are part of our net proved oil and natural gas properties has been restated. See “Item 1. Financial Statements—Note 3” for further discussion.
Three months ended Sept. 30, | Nine months ended Sept 30, | ||||||||||||||||||
2005 | % Change | 2004 | 2005 | % Change | 2004 | ||||||||||||||
(Restated) | (Restated) | ||||||||||||||||||
(In thousands, except per unit measurements) | |||||||||||||||||||
Depletion of oil and natural gas properties | $ | 7,953 | 36% | $ | 5,860 | $ | 21,612 | 31% | $ | 16,508 | |||||||||
Depletion of oil and natural gas properties ($ per Mcfe) | $ | 2.76 | 44% | $ | 1.92 | $ | 2.62 | 46% | $ | 1.79 |
For the third quarter 2005, an increase in our depletion rate resulted in a $2.4 million increase in our depletion expense, and was partially offset by a $328,000 decrease to our depletion expense due to a decrease in production volumes.
For the first nine months of 2005, an increase in our depletion rate resulted in a $6.9 million increase in our depletion expense, and was partially offset by $1.8 million decrease due to lower production volumes.
The increase in our depletion rate was primarily the result of increased costs of reserve additions during the first nine months of 2005.
Net interest expense. We capitalize interest expense on borrowings associated with major capital projects prior to their completion. Capitalized interest is added to the cost of the underlying assets and is amortized over the lives of the assets.
Three months ended Sept. 30, | Nine months ended Sept 30, | ||||||||||||||||||
2005 | % Change | 2004 | 2005 | % Change | 2004 | ||||||||||||||
(In thousands) | |||||||||||||||||||
Interest on senior credit facility | $ | 668 | 211% | $ | 215 | $ | 1,538 | 137% | $ | 649 | |||||||||
Interest on senior subordinated notes | 574 | 32% | 436 | 1,333 | 1% | 1,320 | |||||||||||||
Commitment fees | 36 | (44%) | 64 | 92 | (46%) | 171 | |||||||||||||
Dividend on mandatorily redeemable preferred stock | 200 | 9% | 184 | 581 | 8% | 538 | |||||||||||||
Amortization of deferred loan and debt issuance cost | 120 | (37%) | 191 | 373 | (35%) | 574 | |||||||||||||
Other general interest expense | 1 | (83%) | 6 | 7 | (65%) | 20 | |||||||||||||
Capitalized interest expense | (461 | ) | 106% | (224 | ) | (1,279 | ) | 67% | (764 | ) | |||||||||
Net interest expense | $ | 1,138 | 31% | $ | 872 | $ | 2,645 | 5% | $ | 2,508 | |||||||||
Weighted average debt outstanding | $ | 91,985 | 69% | $ | 54,508 | $ | 76,241 | 33% | $ | 57,275 | |||||||||
Average interest rate on outstanding indebtedness (a) | 6.4 | % | 6.6 | % | 6.2 | % | 6.2 | % |
(a) Calculated as the sum of the interest expense on our outstanding indebtedness, commitment fees that we pay on unused borrowing capacity and the dividend on our mandatorily redeemable preferred stock divided by the weighted average debt and preferred stock outstanding for the period.
Our net interest expense for the third quarter of 2005 was 31% higher than last year and 5% higher for the first nine months of 2004.
The following were the primary factors that led to the changes to our third quarter 2005 net interest expense.
· | An increase in the total interest expense related to our senior credit facility. An increase in the amounts borrowed under our senior credit facility and the rate that we paid on those borrowings were the primary reasons for this increase. Our weighted average borrowings outstanding under our senior credit facility during the third quarter 2005 were $52.1 million which represented 65% of our available borrowing base during the quarter. This compares to $25.4 million representing 37% of our available borrowing base during the third quarter last year. The increase in the interest rate that we paid on those borrowings was primarily due to an increase in the Eurodollar rate. A decrease in the commitment fees we paid on the unused portion of our borrowing base and a decrease amortized deferred loan costs for the third quarter 2005 partially offset the increases due to additional borrowings and higher interest rates. |
· | An increase in the total interest expense related to our subordinated notes. An increase in the amount borrowed under our subordinated credit agreement and an increase in commitment fees paid on the unused portion of the subordinated credit agreement were the primary reasons for this increase. In the second quarter 2005, we increased our borrowings under our senior credit agreement from $20 million to $30 million and expanded the agreement to provide up to $40 million of total borrowings. A decrease amortized deferred loan costs for the third quarter 2005 partially offset the increases due to increased borrowings and commitment fees. |
· | A $237,000 increase in the amount of interest that we capitalized during the third quarter partially offset the increases discussed above. |
The following were the primary factors that led to the changes to our net interest expense for the first nine months of 2005.
· | An increase in the total interest expense related to our senior credit facility. An increase in the amounts borrowed under our senior credit facility and an increase in the rate that we paid on those borrowings were primary reason for the increase. Our weighted average borrowings outstanding under our senior credit facility during the first nine months of 2005 were $43.1 million which represented 59% of our available borrowing during that period. This compares to $28.3 million outstanding representing 41% of our available borrowing base during the first nine months last year. An increase in the Eurodollar rate was the primary reason for the increase in the interest rate that we paid on those borrowings. A decrease in the commitment fees paid on the unused portion of our senior credit facility and a decrease in amortized deferred loan costs for first nine months of 2005 partially offset the increases due to additional borrowings and higher interest rates. |
· | A $515,000 increase in the amount of interest that we capitalized during the first nine months of 2005 partially offset the increases discussed above. |
Other income (expense). Other income (expense) primarily includes non-cash gains (losses) resulting from the change in fair market value of oil and gas derivative contracts not designated as cash flow hedges, cash gains (losses) on the settlement of these contracts and non-cash gains (losses) related to charges for the ineffective portions of cash flow hedges.
Other income (expense) included:
Three months ended Sept. 30, | Nine months ended Sept 30, | ||||||||||||||||||
2005 | % Change | 2004 | 2005 | % Change | 2004 | ||||||||||||||
(In thousands) | |||||||||||||||||||
Non-cash gain (loss) due to change in fair market value of derivative contracts not designated as cash flow hedges | $ | (52 | ) | 148% | $ | (21 | ) | $ | (105 | ) | 400% | $ | (21 | ) | |||||
Non-cash gain (loss) for ineffective portion of cash flow hedges | (477 | ) | 227% | (146 | ) | (890 | ) | 332% | (206 | ) | |||||||||
Other non-cash gain (loss) | (44 | ) | NM | — | (103 | ) | NM | — | |||||||||||
Other cash income (expense) | 76 | NM | (1 | ) | 247 | 263% | 68 | ||||||||||||
Other income (loss) | $ | (497 | ) | 196% | $ | (168 | ) | $ | (851 | ) | 435% | $ | (159 | ) |
The following table shows the volumes and the weighted average NYMEX reference price for those volumes for our derivative commodity contracts that we did not designate as cash flow hedges for the periods indicated.
Three months ended Sept. 30, | Nine months ended Sept 30, | ||||||||||||||||||
2005 | % Change | 2004 | 2005 | % Change | 2004 | ||||||||||||||
Written puts | |||||||||||||||||||
Oil | |||||||||||||||||||
Volumes (Bbl) | 33,000 | NM | — | 39,000 | NM | $ | — | ||||||||||||
Average price ($ per Bbl) | $ | 34.36 | NM | $ | — | $ | 34.92 | NM | $ | — | |||||||||
Gain /(loss) upon settlement ($ in thousands) | $ | — | NM | $ | — | $ | — | NM | $ | — | |||||||||
Natural gas | |||||||||||||||||||
Volumes (MMbtu) | 480,000 | NM | — | 690,000 | NM | $ | — | ||||||||||||
Average price ($ per MMbtu) | $ | 5.28 | NM | $ | — | $ | 5.35 | NM | $ | — | |||||||||
Gain /(loss) upon settlement ($ in thousands) | $ | — | NM | $ | — | $ | — | NM | $ | — |
Analysis of Changes In Cash and Cash Equivalents
The table below summarizes our sources and uses of cash during the periods indicated.
Nine months ended Sept 30, | ||||||||||
2005 | % Change | 2004 | ||||||||
(In thousands) | ||||||||||
Net income | $ | 15,536 | 7% | $ | 14,554 | |||||
Non-cash items | 32,858 | 28% | 25,698 | |||||||
Changes in working capital and other items | (8,332 | ) | 203% | (2,747 | ) | |||||
Cash flows provided by operating activities | $ | 40,062 | 7% | $ | 37,505 | |||||
Cash flows used by investing activities | (83,285 | ) | 35% | (61,483 | ) | |||||
Cash flows provided by financing activities | 46,815 | 72% | 27,150 | |||||||
Net increase in cash and cash equivalents | $ | 3,592 | 13% | $ | 3,172 |
Analysis of net cash provided by operating activities
Cash flows provided by operating activities for the first nine months of 2005 were 7% higher than cash flows provided by operating activities in the same period of 2004. The following were the primary factors that led to the changes to our cash flows provided by operating activities during the first nine months of 2005.
· | Our total revenues for the first nine months of 2005 increased $14.3 million due to an increase in the prices we received for our oil and natural gas and a decrease in the amounts we lost upon the settlement of our derivative contracts. These changes were partially offset by a $6 million decrease to our total revenue due to a decrease in our production volumes for the first nine months of 2005. |
· | Increases in our production costs and cash interest expense during the first nine months of 2005 resulted in decreases to cash flows provided by operating activities of $262,000 and $295,000 respectively. |
· | The payment of accounts payable in excess of the collection of accounts receivable during the first nine months of 2005 reduced our cash flows provided by operating activities by $3.6 million. |
· | An increase in the amount of royalties we paid during the first nine months of 2005 decreased our cash flows provided by operating activities by $225,000. |
· | A decrease in the amount of participant advances during the first nine months of 2005 resulted in a $1.2 million decrease to our cash flows provided by operating activities. |
Working Capital
Working capital is the amount by which current assets exceed current liabilities. It is normal for us to report a working capital deficit at the end of a period. These deficits are primarily the result of accounts payable related to lease operating expenses, exploration and development costs and royalties payable. Settlement of these payables will be funded by cash flows from operations or, if necessary, by additional borrowing under our senior credit facility or subordinated notes agreement.
Our working capital deficit at September 30, 2005 was $12.3 million compared to a working capital deficit of $19.5 million at December 31, 2004. Our working capital deficit at September 30, 2005, included a net liability of $7 million related to the fair value of our derivative contracts.
Capital expenditures for oil and natural gas activities
Nine months ended Sept 30, | ||||||||||
2005 | % Change | 2004 | ||||||||
(In thousands) | ||||||||||
Drilling (1) | $ | 66,172 | 36% | $ | 48,710 | |||||
Land and seismic | 12,754 | 19% | 10,749 | |||||||
Capitalized cost (2) | 5,156 | 12% | 4,595 | |||||||
Capitalized ARO | 244 | (38%) | 392 | |||||||
Total | $ | 84,326 | 31% | $ | 64,446 |
(1) | Includes $6.6 million and $6.5 million of accrued drilling costs for 2005 and 2004, respectively. |
(2) | For 2005 includes $3.6 million in capitalized general and administrative cost, $1.3 million in capitalized interest cost and $241,000 of capitalized stock compensation expense. For 2004 includes $3.6 million in capitalized general and administrative cost, $764,000 in capitalized interest cost and $220,000 of capitalized stock compensation expense. |
Analysis of changes in cash flows from financing activities
Senior Credit Facility
During first nine months of 2005 we borrowed an additional $49.1 million under our senior credit facility, repaid $12 million of the amount borrowed under our senior credit facility and paid $646,000 in fees to amend and restate our senior credit agreement in January and June 2005. This compares to our borrowing $28 million, repaying $23.5 million and paying $10,000 in deferred loan costs during the first nine months of 2004.
Senior Subordinated Notes
During the first nine months of 2005 we borrowed an additional $10 million under our subordinated credit agreement and paid $245,000 in fees to amend and restate our credit agreement on June 29, 2005. We did not borrow anything under our subordinated credit agreement during the first nine months of 2004.
Common Stock Transactions
Shares Issued | Net Proceeds | ||||||
(In thousands) | |||||||
2005 common stock transactions: | |||||||
Exercise of employee stock options | 217,479 | $ | 797 | ||||
2004 common stock transactions: | |||||||
Exercise of employee stock options | 235,581 | $ | 684 | ||||
Sale of common stock under universal shelf registration statement (a) | 2,598,500 | $ | 22,132 |
(a) | The net proceeds from the sale were used to repay outstanding indebtedness under our senior credit facility. 2,300,000 shares were sold in July 2004 and 298,500 shares were sold in August 2004 when the underwriter exercised its over-allotment option. |
Other Matters
Effects of Inflation and Changes in Prices
Our results of operations and cash flows are affected by changing oil and gas prices. If the price of oil and natural gas increases (decreases), there could be a corresponding increase (decrease) in revenues as well as the operating costs that we are required to bear for operations. Inflation has had a minimal effect on us.
Environmental and Other Regulatory Matters
Our business is subject to certain federal, state and local laws and regulations relating to the exploration for and the development, production and marketing of oil and natural gas, as well as environmental and safety matters. Many of these laws and regulations have become more stringent in recent years, often imposing greater liability on a larger number of potentially responsible parties. Although we believe we are in substantial compliance with all applicable laws and regulations, the requirements imposed by laws and regulations are frequently changed and subject to interpretation, and we cannot predict the ultimate cost of compliance with these requirements or their effect on our operations. Any suspensions, terminations or inability to meet applicable bonding requirements could materially adversely affect our financial condition and operations. Although significant expenditures may be required to comply with governmental laws and regulations applicable to us, compliance has not had a material adverse effect on our earnings or competitive position. Future regulations may add to the cost of, or significantly limit, drilling activity.
New Accounting Pronouncements
In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123R, “Share-Based Payment” (SFAS 123R), which is a revision of SFAS 123 and supersedes APB Opinion No. 25. SFAS 123R requires all share-based payments to employees, including grants of employee stock options, to be valued at fair value on the date of grant, and to be expensed over the applicable vesting period. Pro forma disclosure of the income statement effects of share-based payments is no longer an alternative. In addition, companies must also recognize compensation expense related to any awards that are not fully vested as of the effective date. The fair value is determined using a variety of assumptions, including those related to volatility rates, forfeiture rates and the option pricing model used (e.g. binomial or Black Scholes). These assumptions could differ from those we have utilized in determining our pro forma compensation expense. SFAS 123R will also impact the manner in which we recognize the income tax impacts of our stock compensation programs in the consolidated financial statements. The effective date of SFAS 123R is January 1, 2006 for calendar year companies. Upon adoption we will apply SFAS 123R prospectively for new stock-based compensation arrangements and to the unvested portion of existing arrangements. We are currently assessing the impact of adopting SFAS 123R to our consolidated financial statements.
In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47), which clarifies the impact that uncertainty surrounding the timing or method of settling an obligation should have on accounting for that obligation under SFAS No. 143. FIN 47 is effective no later than the end of the fiscal year ending after December 15, 2005, or December 31, 2005 for calendar year companies. We do not expect the adoption of FIN 47 to have a material impact on our consolidated financial statements.
In May 2005, the FASB issued Statement of Financial Accounting Standards No. 154, “Accounting Changes and Error Corrections — a replacement of APB Opinion No. 20 and FASB Statement No. 3” (SFAS 154). SFAS 154 establishes retrospective application as the required method for reporting a change in accounting principle, unless it is impracticable in which the changes should be applied to the latest practicable date presented for voluntary accounting changes and in the absence of specific guidance provided for in a new pronouncement issued by an authoritative body. SFAS 154 also requires that a correction of an error be reported as a prior period adjustment by restating prior period financial statements. SFAS 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005.
Forward Looking Information
We or our representatives may make forward looking statements, oral or written, including statements in this report, press releases and filings with the SEC, regarding estimated future net revenues from oil and natural gas reserves and the present value thereof, planned capital expenditures (including the amount and nature thereof), increases in oil and gas production, the number of wells we anticipate drilling during 2005 and our financial position, business strategy and other plans and objectives for future operations. Although we believe that the expectations reflected in these forward looking statements are reasonable, there can be no assurance that the actual results or developments anticipated by us will be realized or, even if substantially realized, that they will have the expected effects on our business or operations. Among the factors that could cause actual results to differ materially from our expectations are general economic conditions, inherent uncertainties in interpreting engineering data, operating hazards, delays or cancellations of drilling operations for a variety of reasons, competition, fluctuations in oil and gas prices, availability of sufficient capital resources to us or our project participants, government regulations and other factors set forth among the risk factors noted in the description of our business in Item 1 of our Form 10-K report for the year ended December 31, 2004 or in our Management’s Discussion Analysis of Financial Condition in Item 7 of our Form 10-K report for the year ended December 31, 2004. All subsequent oral and written forward looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. We assume no obligation to update any of these statements.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
The following quantitative and qualitative disclosures about market risk are supplementary to the quantitative and qualitative disclosures provided in our Annual Report on Form 10-K for the fiscal year ended December 31, 2004. As such, the information contained herein should be read in conjunction with the related disclosures in our Annual Report on Form 10-K for the fiscal year ended December 31, 2004.
Derivative Contracts
The following table reflects open commodity derivative contracts at September 30, 2005, the associated volumes and the corresponding NYMEX reference price.
Notional Amount | ||||||||||||||||
Settlement Period | Derivative Instrument | Hedge Strategy | Gas (MMBTU) | Oil (Barrels) | NYMEX Reference Price | |||||||||||
Costless Collars | ||||||||||||||||
10/01/05 - 10/31/05 | Purchased put | Cash flow | 60,000 | $ | 5.45 | |||||||||||
Written call | Cash flow | 60,000 | 8.00 | |||||||||||||
01/01/06 - 03/31/06 | Purchased put | Cash flow | 7,500 | $ | 62.00 | |||||||||||
Written call | Cash flow | 7,500 | 74.50 | |||||||||||||
04/01/06 - 06/30/06 | Purchased put | Cash flow | 16,500 | $ | 54.80 | |||||||||||
Written call | Cash flow | 16,500 | 75.00 | |||||||||||||
Three Way Costless Collars | ||||||||||||||||
10/01/05 - 10/31/05 | Purchased put | Cash flow | 100,000 | $ | 6.00 | |||||||||||
Written call | Cash flow | 100,000 | 7.20 | |||||||||||||
Written put | Undesignated | 100,000 | 5.00 | |||||||||||||
10/01/05 - 10/31/05 | Purchased put | Cash flow | 60,000 | $ | 7.00 | |||||||||||
Written call | Cash flow | 60,000 | 7.76 | |||||||||||||
Written put | Undesignated | 60,000 | 5.75 | |||||||||||||
10/01/05 - 12/31/05 | Purchased put | Cash flow | 15,000 | $ | 40.00 | |||||||||||
Written call | Cash flow | 15,000 | 53.00 | |||||||||||||
Written put | Undesignated | 15,000 | 30.00 | |||||||||||||
10/01/05 - 03/31/06 | Purchased put | Cash flow | 36,000 | $ | 48.00 | |||||||||||
Written call | Cash flow | 36,000 | 60.70 | |||||||||||||
Written put | Undesignated | 36,000 | 38.00 | |||||||||||||
11/01/05 - 03/31/06 | Purchased put | Cash flow | 250,000 | $ | 6.75 | |||||||||||
Written call | Cash flow | 250,000 | 8.80 | |||||||||||||
Written put | Undesignated | 250,000 | 5.50 | |||||||||||||
11/01/05 - 03/31/06 | Purchased put | Cash flow | 350,000 | $ | 8.00 | |||||||||||
Written call | Cash flow | 350,000 | 9.75 | |||||||||||||
Written put | Undesignated | 350,000 | 6.50 | |||||||||||||
11/01/05 - 03/31/06 | Purchased put | Cash flow | 400,000 | $ | 10.00 | |||||||||||
Written call | Cash flow | 400,000 | 13.08 | |||||||||||||
Written put | Undesignated | 400,000 | 8.50 | |||||||||||||
04/01/06 - 06/30/06 | Purchased put | Cash flow | 7,500 | $ | 63.00 | |||||||||||
Written call | Cash flow | 7,500 | 75.25 | |||||||||||||
Written put | Undesignated | 7,500 | 48.00 | |||||||||||||
07/01/06 - 09/30/06 | Purchased put | Cash flow | 15,000 | $ | 63.00 | |||||||||||
Written call | Cash flow | 15,000 | 75.65 | |||||||||||||
Written put | Undesignated | 15,000 | 48.00 | |||||||||||||
04/01/06 - 10/31/06 | Purchased put | Cash flow | 420,000 | $ | 7.50 | |||||||||||
Written call | Cash flow | 420,000 | 9.15 | |||||||||||||
Written put | Undesignated | 420,000 | 6.25 | |||||||||||||
04/01/06 - 10/31/06 | Purchased put | Cash flow | 490,000 | $ | 8.50 | |||||||||||
Written call | Cash flow | 490,000 | 9.96 | |||||||||||||
Written put | Undesignated | 490,000 | 7.00 |
The following table reflects commodity derivative contracts entered into subsequent to September 30, 2005, the associated volumes and the corresponding weighted average NYMEX reference price.
Notional Amount | ||||||||||||||||
Settlement Period | Derivative Instrument | Hedge Strategy | Gas (MMBTU) | Oil (Barrels) | NYMEX Reference Price | |||||||||||
Costless Collars | ||||||||||||||||
04/01/06 - 10/31/06 | Purchased put | Cash flow | 490,000 | $ | 8.00 | |||||||||||
Written call | Cash flow | 490,000 | 14.85 | |||||||||||||
11/01/06 - 03/31/07 | Purchased put | Cash flow | 450,000 | $ | 8.00 | |||||||||||
Written call | Cash flow | 450,000 | 21.20 |
ITEM 4. CONTROLS AND PROCEDURES
Material Control Weakness Previously Disclosed
In our 2004 Annual Report on Form 10-K, we reported that we did not maintain effective control, as of December 31, 2004, over the accounting for depletion expense and accumulated depletion. This resulted in a material control weakness at December 31, 2004 related to accounting for depletion expense and accumulated depletion. Specifically, our controls related to the preparation and review of the quarterly depletion computations were not adequate to ensure that that the changes in depletion rate estimates used to determine depletion expense and the related accumulated depletion of net proved oil and natural gas properties are only applied prospectively in accordance with accounting principles generally accepted in the United States of America. The remedial actions implemented in the first quarter of 2005 related to this material weakness are described below.
Evaluation of Disclosure Controls and Procedures
As of September 30, 2005, our principal executive officer and principal financial officer carried out an evaluation of the effectiveness of our disclosure controls and procedures. Based on their evaluation, they have concluded that our disclosure controls and procedures effectively ensure that the information required to be disclosed in the reports we file with the SEC is recorded, processed, summarized and reported within the time periods specified by the SEC.
Changes in Internal Control over Financial Reporting
During the first quarter of 2005, we took action to remediate the material weakness identified at December 31, 2004 and update related accounting policies and procedures. Due to such remediation, our depletion rate at each respective period end has been applied to the respective current period production only, as required by accounting principles generally accepted in the United States of America. There were no other changes in our internal controls or in other factors that have materially affected, or are reasonably likely to materially affect, our internal controls subsequent to the date of their evaluation of our disclosure controls and procedures.
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
As discussed in Note 5 of Notes to the Consolidated Financial Statements included in Part I. Financial Information, Brigham is party to various legal actions arising in the ordinary course of business and does not expect these matters to have a material adverse effect on its consolidated financial condition, results of operations or cash flows.
ITEM 2. UNREGISTERD SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Issuer Purchases of Equity Securities
Period | Total Number of Shares Purchased | Average Price Paid per Share | |||||
July 1, 2005 - September 30, 2005 | 0 | $ | - - |
No purchases were made under a publicly announced plan.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS
None
ITEM 5. OTHER INFORMATION
None.
ITEM 6. EXHIBITS
Number | Description | |
10.1* † | — | Form of Restricted Stock Agreement |
31.1† | — | Certification of Chief Executive Officer of the Company pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 |
31.2† | — | Certification of Chief Financial Officer of the Company pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 |
32.1 † | — | Certification of Chief Executive Officer of the Company pursuant to 18 U.S.C. § 1350 |
32.2† | — | Certification of Chief Financial Officer of the Company pursuant to 18 U.S.C. § 1350 |
* Management contract or compensatory contract
† Filed herewith
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on November 4, 2005.
BRIGHAM EXPLORATION COMPANY | |||
By: | /s/ BEN M. BRIGHAM | ||
Ben M. Brigham | |||
Chief Executive Officer, President and Chairman of the Board | |||
By: | /s/ EUGENE B. SHEPHERD, JR. | ||
Eugene B. Shepherd, Jr. | |||
Executive Vice President and Chief Financial Officer |
36