Washington, D.C. 20549
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.
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12 b-2 of the Act).
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date.
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
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.
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 presentation 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 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.
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).
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 six month periods ended June 30, 2005 and 2004 would have been the pro forma amounts indicated below:
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 six months ending June 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).
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 June 30, 2005, Brigham had $44.4 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.
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 June 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.
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 November 20, 2001, Brigham filed a lawsuit in the District Court of Travis County, Texas, against Steve Massey Company, Inc. The Petition claimed Massey furnished defective casing to Brigham, which ultimately led to the casing failure of its Palmer 347 #5 well and the loss of the Palmer #5 as a producing well. In 2004, the parties settled the case on terms favorable to Brigham. Brigham received approximately $440,000 as a result of this settlement. The amount of the settlement reduced capitalized well cost. In addition, Massey agreed to drop its $445,819 counterclaim.
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 is currently scheduled to take place in September 2005. Brigham believes it has adequate insurance to cover any potential damage award (subject to a $5,000 deductible). At this point in time, Brigham cannot predict the outcome of this case.
In September 2002, Brigham filed suit in the District Court of Matagorda County, Texas, against one of its contractors in connection with the drilling of the Burkhart #1-R well, claiming that contractor breached its contract with Brigham and negligently performed services on the well. Brigham believes the contractor’s actions damaged Brigham by approximately $650,000. The contractor counterclaimed, claiming it is entitled to recover approximately $315,000. In April 2004, the parties settled the case, resulting in a payment by the contractor to its co-participants and Brigham of $325,000. In addition, the contractor dropped its counterclaim. Based on the amount of the settlement, the additional costs that were covered by insurance, and the insurer being subrogated to Brigham’s claim, Brigham did not receive any incremental recovery as a result of the settlement.
Prior to drilling, the operator of the Stonehocker #1 well disputed Brigham’s ownership in the well. In March 2003, a Motion to Determine Election was filed with the Oklahoma Corporation Commission. In January 2004, an Administrative Law Judge with the Oklahoma Corporation Commission ruled in Brigham’s favor. The operator of the Stonehocker #1 appealed the ruling and the Appellate Referee with the Oklahoma Corporation Commission affirmed the original ruling in March 2004. The full Commission Panel reviewed the reports of the Referee and the original Administrative Law Judge and affirmed those rulings. The operator then filed an appeal with the Oklahoma Supreme Court. In January 2005, the parties settled the dispute. The operator agreed to recognize Brigham’s full interest in the Stonehocker well, and also agreed to reverse certain charges made under the operating agreements of six additional wells in which Brigham owns an interest.
A company that relinquished its ownership interest in the Nold #1S well as a result of a non-consent election in the re-completion of the well asserted that it did not relinquish its entire interest, but rather became subject only to a 400 percent payout provision. In November 2003, this company filed a lawsuit in the District Court of Brazoria County, Texas, against Brigham for breach of contract. If the suit was successful, it could have resulted in a judgment of as much as $700,000. In April 2004, Brigham settled the case, agreeing to pay the company $350,000 in return for the company’s assignment of all its right, title and interest in the unit for the well.
In December 2003, Brigham filed a lawsuit in the United States District Court for the Western District of Texas against another company and a former employee concerning the defendants’ misappropriation of Brigham’s trade secrets and breach of confidentiality obligations. Defendants denied any wrongdoing and asserted a counterclaim against Brigham for alleged tortuous interference with an existing business relationship between the company and its employee. In April 2004, Brigham settled the case. The company agreed not to compete against Brigham in a specified area for two years, assigned Brigham a small overriding royalty in three tracts, paid Brigham $50,000, and dropped its counterclaim.
As of June 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.
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 six months ended June 30, 2005 and 2004 are as follows (in thousands):
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 reports average oil and natural gas prices and revenues including the net results of hedging activities. The following table sets forth Brigham's 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 six month periods ended June 30, 2005 and 2004:
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 six months ended June 30 (in thousands):
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):
| | | June 30, 2005 | | December 31, 2004 | |
Fair value of undesignated derivatives | | $ | (85 | ) | $ | — | |
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 six months ended June 30 (in thousands):
| | | Three Months Ended June 30, | | Six Months Ended June 30, | |
| | | 2005 | | 2004 | | 2005 | | 2004 | |
| Increase (decrease) in earnings due to changes in fair value of undesignated derivatives | | $ | (63 | ) | $ | — | | $ | (53 | ) | $ | — | |
The following table reflects open commodity derivative contracts at June 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 | | | | | | | | | | |
| 07/01/05 - 10/31/05 | | Purchased put | | Cash flow | | 240,000 | | | | $5.45 |
| | | Written call | | Cash flow | | 240,000 | | | | 8.00 |
Three Way Costless Collars | | | | | | | | | | |
| 07/01/05 - 03/31/06 | | Purchased put | | Cash flow | | | | 54,000 | | $48.00 |
| | | Written call | | Cash flow | | | | 54,000 | | 60.70 |
| | | Written put | | Undesignated | | | | 54,000 | | 38.00 |
| 07/01/05 - 10/31/05 | | Purchased put | | Cash flow | | 400,000 | | | | $6.00 |
| | | Written call | | Cash flow | | 400,000 | | | | 7.20 |
| | | Written put | | Undesignated | | 400,000 | | | | 5.00 |
| 07/01/05 - 12/31/05 | | Purchased put | | Cash flow | | | | 30,000 | | $40.00 |
| | | Written call | | Cash flow | | | | 30,000 | | 53.00 |
| | | Written put | | Undesignated | | | | 30,000 | | 30.00 |
| 07/01/05 - 10/31/05 | | Purchased put | | Cash flow | | 240,000 | | | | $7.00 |
| | | Written call | | Cash flow | | 240,000 | | | | 7.76 |
| | | Written put | | Undesignated | | 240,000 | | | | 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 |
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
The following table reflects commodity derivative contracts entered subsequent to June 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 |
Three Way Costless Collars | | | | | | | | | | |
| 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 |
Costless Collars | | | | | | | | | | |
| 04/01/06 - 6/30/06 | | Purchased put | | Cash flow | | | | 16,500 | | $54.80 |
| | | Written call | | Cash flow | | | | 16,500 | | 75.00 |
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 June 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 June 30, 2005, approximately $0.2 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 $0.2 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.
| | | June 30, 2005 | | December 31, 2004 | |
| | | (In thousands) | |
| | | | | | |
| Other current liabilities | | $ | (586 | ) | $ | (870 | ) |
| Other noncurrent liabilities | | | — | | | (1 | ) |
| Other current assets | | | — | | | 142 | |
| Other noncurrent assets | | | 185 | | | 3 | |
| | | $ | (401 | ) | $ | (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 six months ended June 30, 2005 and 2004 (in thousands):
| | | Six Months Ended June 30, | |
| | | 2005 | | 2004 | |
| | | | | | |
| Beginning asset retirement obligations | | $ | 2,896 | | $ | 2,320 | |
| Liabilities incurred for new wells placed on production | | | 160 | | | 336 | |
| Liabilities settled | | | (6 | ) | | (68 | ) |
| Accretion of discount on asset retirement obligations | | | 82 | | | 77 | |
| | | $ | 3,132 | | $ | 2,665 | |
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 accoutnig 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.
| 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 six month periods ended June 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 Second Quarter and First Six Months of 2005
The price of natural gas during the first six months of 2005 has remained relatively high compared to historical prices due to forecasts for continued U.S. production declines, increasing natural gas demand and similarly high crude oil prices, which limits fuel-switching flexibility. The average sales price that we received for our natural gas sales in the second quarter and first six months of 2005 was $6.73 and $6.27, respectively. The average sales price that we received for oil in the second quarter and first six months of 2005 was $51.56 and $49.84, respectively.
Our net capital expenditures for oil and natural gas activities during the second quarter of 2005 were $35.1 million and year to date through June 30, 2005 we have spent $59 million. Our average production was 29.5 MMcfe/d for the second quarter 2005 and 29.8 MMcfe/d for the first six months of 2005 compared to 34.4 MMcfe/d and 34.1 MMcfe/d during the second quarter and first six mouths of 2004, respectively. The decrease in our production is primarily due to natural decline of existing production and the lack of significant wells reaching total depth and coming on line during the quarter to materially contribute to production.
Net income for the second quarter 2005 was $4.8 million, or $0.11 per diluted share, on total revenues of $18.5 million. This compares to reported net income of $5.1 million, or $0.13 per diluted share on revenue of $18 million in the second quarter last year. The decrease in net income was primarily due to an increase in our depletion of oil and natural gas properties and general and administrative expenses, partially offset by increases in our total revenue, interest income and other income and decreases in production costs and interest expense. Net income for the first six months 2005 was $7.9 million, or $0.18 per diluted share, on total revenues of $35.2 million. This compares to reported net income of $10.1 million, or $0.25 per diluted share, on total revenue of $34.8 million in the first half of last year. The decrease in our net income for the first six months of 2005 was primarily due to increases in our depletion of oil and natural gas properties, our production costs and our non-cash losses related to the ineffective portion of our cash flow hedges. These were partially offset by increases in our total revenue and interest income and a decrease in our interest expense.
Net cash provided by operating activities during the second quarter of 2005 funded approximately 61% of our cash used by investing activities and year to date through June 30, 2005, has funded 50% of our cash used by investing activities. During the second quarter 2005, we borrowed an additional $6.3 million of debt under our senior credit facility and an additional $10 million in our senior subordinated notes. As of June 30, 2005, we had borrowed an additional $23.4 million of debt under our senior credit facility and an additional $10 million in our senior subordinated notes.
At June 30, 2005, we had $6.4 million in cash, total assets of $332 million and a debt to capitalization ratio of 30%.
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 maintaining, repairing and 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. |
The table below summarizes our budgeted capital expenditures, the amount spent through June 30, 2005 and the amount of our 2005 budget that remains to be spent.
| | | 2005 Budget | | Amount Spent Through 06/30/05 | | Amount Remaining (1) | |
| | | (In thousands) | |
| Drilling | | $ | 70,308 | | $ | 45,238 | | $ | 25,070 | |
| Net land and seismic | | | 13,065 | | | 10,246 | | | 2,819 | |
| Capitalized interest and G&A | | | 6,184 | | | 3,381 | | | 2,803 | |
| Asset retirement obligation | | | — | | | 160 | | | — | |
| Other assets | | | 615 | | | 86 | | | 529 | |
| Total | | $ | 90,172 | | $ | 59,111 | | $ | 31,221 | |
____________
| (1) | Calculated as the amount budgeted for 2005 less amount spent through June 30, 2005. |
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.
For 2005, we currently plan to spend approximately $34.7 million, or 38% of our total budgeted capital expenditures to drill 17 exploratory wells and to drill and complete wells that were in progress at December 31, 2004. We believe that we possess a multi-year inventory of exploratory drilling prospects, the majority of which have been internally generated by our staff. As a consequence and considering the results that we have achieved in recent years, we expect that we will continue to emphasize our prospect generation and drilling strategy as our primary means of creating value for our stockholders.
Due to our exploratory drilling success, over the last five years, a growing percentage of our capital expenditures have been allocated to the development of past field discoveries. For 2005, we currently plan to spend approximately $35.6 million, or 39% of our total budgeted capital expenditures on development activities, which include the drilling of 20 development wells. We currently plan to allocate approximately $26.5 million of this capital to develop our proved undeveloped reserves at December 31, 2004.
For 2005, we expect to spend approximately $13.1 million or 14% of our total capital expenditures on land and seismic activities.
Additionally, we currently plan to capitalize approximately $6.2 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:
| | · | 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.
Statements in this section include forward-looking statements. See “— Forward-Looking Statements.”
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.
Our borrowing base is subject to redetermination at least semi-annually using the administrative agent and lenders’ usual and customary criteria for oil and gas reserve valuation. While we do not expect the amount that we have borrowed under our senior credit facility to exceed our borrowing base, in the event that our borrowing base is adjusted below the amount that we have borrowed, we have a period of six months to reduce our outstanding debt to the borrowing base available with a requirement to provide additional borrowing base assets or pay down one-sixth of the excess during each of the six months.
We also revised the interest rates that we pay on borrowings outstanding under our senior credit agreement. Borrowings under our senior credit agreement bear interest, at our election, at a base rate or Eurodollar rate, plus in each case an applicable margin. These margins are subject to increase if the total amount borrowed under our senior credit agreement reaches certain percentages of our available borrowing base, as shown below:
Percent of Borrowing Base Utilized | | Eurodollar Rate Advances | | Base Rate Advances (1) |
| < 50% | | 1.250% | | 0.000% |
| ≥ 50% and < 75% | | 1.500% | | 0.000% |
| ≥ 75% and < 90% | | 1.750% | | 0.250% |
| ≥ 90% | | 2.000% | | 0.500% |
(1) Base rate is defined as for any day a fluctuating rate per annum equal to the higher of : (a) the Federal Funds Rate plus 1/2 of 1% or (b) the rate of interest in effect for such day as publicly announced from time to time by Bank of America as its “prime rate.” The “prime rate” is a rate set by Bank of America based upon various factors including Bank of America’s costs and desired return, general economic conditions and other factors, and is used as a reference point for pricing some loans, which may be priced at, above, or below such announced rate. Any change in such rate announced by Bank of America shall take effect at the opening of business on the day specified in the public announcement of such change.
We are also required to pay a quarterly commitment fee on the average daily-unused portion of our borrowing base. The commitment fees we pay are subject to change as the percentage of our available borrowing base that we utilize changes. The margins and commitment fees that we pay are as follows:
Percent of Borrowing Base Utilized | | As Amended |
| < 50% | | 0.250% |
| ≥ 50% and < 75% | | 0.250% |
| ≥ 75% and < 90% | | 0.375% |
| ≥ 90% | | 0.375% |
As of June 30, 2005, we had $44.4 million in borrowings outstanding under our senior credit facility. During the first six months of 2005 we borrowed an additional $31.6 million of additional debt under our senior credit facility and repaid $8.2 million using the proceeds from the additional borrowing of senior subordinated notes. During the first six months of 2005, we utilized approximately 55% of our available borrowing base, compared to 44% in the first six months of last year. Borrowings outstanding under our senior credit facility at August 3, 2005, were $49.4 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 June 30, 2005 and interest coverage ratio for the twelve-month period ended June 30, 2005, were 1.8 to 1 and 18.9 to 1, respectively. As of June 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 outstanding under our subordinated credit agreement to $30 million. We will have the opportunity to draw the additional $10 million of our senior notes available under our subordinated credit agreement until December 29, 2006.
Senior subordinated notes outstanding under our subordinated credit agreement bear interest based on the Eurodollar rate plus a margin. This margin is subject to increases if we borrow the remaining notes available to us under our subordinated credit agreement and the total amount borrowed under our senior credit agreement reaches or exceeds 75% of our available borrowing base, as shown below.
| | | Senior Subordinated Debt Outstanding |
Percent of Senior Credit Facility Borrowing Base Utilized | | ≤ $30 Million | | > $30 Million and ≤ $35 Million | | > $35 Million |
| < 75% | | 3.90% | | 3.90% | | 3.90% |
| ≥ 75% and < 90% | | 3.90% | | 4.25% | | 4.50% |
| ≥ 90% | | 3.90% | | 4.25% | | 4.50% |
Prior to amendment, the interest on notes outstanding under our subordinated credit agreement was based on the Eurodollar rate plus a margin of 3.90%.
We are required to a pay a quarterly commitment fee of 0.750% on the unused portion of our subordinated credit agreement.
We also amended the price deck used to calculate NPV for the Total Calculated NPV to Total Debt Ratio. The amended price assumptions used to determine NPV for reserves will be based upon the following price decks: (i) for natural gas, the Gas Strip Price, provided that if any Gas Strip Price is greater than $4.50 per MMBtu, the price shall be capped at $4.50 per MMBtu; and (ii) for crude oil, the Oil Strip Price, provided that if any Oil Strip Price is greater than $30 per barrel, the price shall be capped at $30 per barrel.
As of June 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 June 30, 2005 and interest coverage ratio for the twelve-month period ended June 30, 2005 were 1.8 to 1 and 18.9 to 1, respectively. At June 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 June 30, 2005, we had $9.9 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 second quarter of 2005 we issued 9,685 shares of additional shares of preferred stock to satisfy our second quarter 2005 dividend requirements. Year to date through June 30, 2005, we have issued 19,078 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 expires on October 31, 2005.
Capital Resources
We intend to fund our remaining 2005 capital expenditure program and contractual commitments through cash flows from operations, borrowings under our both our senior credit facility and subordinated credit agreement and, if required and available, alternative financing sources. Our primary sources of cash during first six months of 2005 were net cash provided by operations and additional borrowings under our senior credit facility and subordinated credit agreement. We made aggregate cash payments of $1.7 million for interest in the first six 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 six months of 2005 funded 50% of our net cash used by investing activities compared to 66% in the first six months last year.
Senior Credit Facility
As of August 3, 2005 the unused committed borrowing capacity available under our senior credit facility was $30.6 million. Our borrowing base increased from $72 million to $80 million when we amended and restated our senior credit agreement on June 29, 2005.
Senior Subordinated Notes
As of June 30, 2005, we had an additional $10 million of senior subordinated notes available to us under our subordinated credit agreement. These 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 is dependent 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 six month periods ended June 30, 2005 and 2004.
Revenues
Production volumes
| | | Three months ended June 30, | | Six months ended June 30, | |
| | | 2005 | | % Change | | 2004 | | 2005 | | % Change | | 2004 | |
| | | | | | | | | | | | | | |
| Oil (MBbls) | | | 103 | | | (27%) | | | 141 | | | 221 | | | (26%) | | | 300 | |
| Natural gas (MMcf) | | | 2,041 | | | (9%) | | | 2,246 | | | 4,035 | | | (7%) | | | 4,339 | |
| Total (MMcfe)(1) | | | 2,659 | | | (14%) | | | 3,092 | | | 5,359 | | | (13%) | | | 6,142 | |
| Average daily production (MMcfe/d) | | | 29.5 | | | | | | 34.4 | | | 29.8 | | | | | | 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 second quarter of 2005 were 2.7 Bcfe (29.5 MMcfe/d) down from 3.1 Bcfe (34.4MMcfe/d) in the second quarter of 2004. Our net equivalent production volumes for the first six months of 2005 were 5.4 Bcfe (29.8 MMcfe/d) down from 6.1 Bcfe (34.1 MMcfe/d) in 2004.
Natural gas represented 77% of our second quarter 2005 production volumes and 75% of our production volumes in the first half of 2005. Comparably, natural gas represented 73% of our second quarter 2004 production and 71% of our production for the first six months of 2004.
The decrease in our production volumes was due to natural decline of existing production and the lack of significant wells reaching total depth and coming on line during the periods to materially contribute to production.
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 June 30, | | Six months ended June 30, | |
| | | 2005 | | % Change | | 2004 | | 2005 | | % Change | | 2004 | |
| | | | | | | | | | | | | | |
Oil swaps | | | | | | | | | | | | | |
| Volumes (Bbls) | | | — | | | (100%) | | | 20,475 | | | — | | | (100%) | | | 50,050 | |
| Average swap price ($ per Bbl) | | $ | — | | | (100%) | | $ | 24.52 | | $ | — | | | (100%) | | $ | 25.01 | |
| Gain /(loss) upon settlement ($ in thousands) | | $ | — | | | (100%) | | $ | (283 | ) | $ | — | | | (100%) | | $ | (573 | ) |
Oil collars | | | | | | | | | | | | | | | | | | | |
| Volumes (Bbls) | | | 24,655 | | | (51%) | | | 50,050 | | | 52,105 | | | (45%) | | | 95,550 | |
| Average floor price ($ per Bbl) | | $ | 31.96 | | | 33% | | $ | 24.09 | | $ | 28.59 | | | 21% | | $ | 23.57 | |
| Average ceiling price ($ per Bbl) | | $ | 39.37 | | | 29% | | $ | 30.60 | | $ | 34.53 | | | 13% | | $ | 30.52 | |
| Gain /(loss) upon settlement ($ in thousands) | | $ | (385 | ) | | (1%) | | $ | (387 | ) | $ | (926 | ) | | 54% | | $ | (602 | ) |
Total oil | | | | | | | | | | | | | | | | | | | |
| Volumes (Bbls) | | | 24,655 | | | (65%) | | | 70,525 | | | 52,105 | | | (64%) | | | 145,600 | |
| Gain /(loss) upon settlement ($ in thousands) | | $ | (385 | ) | | (43%) | | $ | (670 | ) | $ | (926 | ) | | (21%) | | $ | (1,175 | ) |
Natural gas swaps | | | | | | | | | | | | | | | | | | | |
| Volumes (MMbtu) | | | — | | | (100%) | | | 227,500 | | | — | | | (100%) | | | 523,250 | |
| Average swap price ($ per MMbtu) | | $ | — | | | (100%) | | $ | 4.25 | | $ | — | | | (100%) | | $ | 4.65 | |
| Gain /(loss) upon settlement ($ in thousands) | | $ | — | | | (100%) | | $ | (391 | ) | $ | — | | | (100%) | | $ | (607 | ) |
Natural gas collars | | | | | | | | | | | | | | | | | | | |
| Volumes (MMbtu) | | | 635,000 | | | 25% | | | 509,600 | | | 1,362,500 | | | 29% | | | 1,055,600 | |
| Average floor price ($ per MMbtu) | | $ | 4.93 | | | 20% | | $ | 4.11 | | $ | 5.06 | | | 23% | | $ | 4.12 | |
| Average ceiling price ($ per MMbtu) | | $ | 7.08 | | | 25% | | $ | 5.67 | | $ | 7.17 | | | 1% | | $ | 7.10 | |
| Gain /(loss) upon settlement ($ in thousands) | | $ | (231 | ) | | (9%) | | $ | (253 | ) | $ | (241 | ) | | (5%) | | $ | (253 | ) |
Total natural gas | | | | | | | | | | | | | | | | | | | |
| Volumes (MMbtu) | | | 635,000 | | | (14%) | | | 737,100 | | | 1,362,500 | | | (14%) | | | 1,578,850 | |
| Gain /(loss) upon settlement ($ in thousands) | | $ | (231 | ) | | (64%) | | $ | (644 | ) | $ | (241 | ) | | (72%) | | $ | (860 | ) |
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 June 30, | | Six months ended June 30, | |
| | | 2005 | | % Change | | 2004 | | 2005 | | % Change | | 2004 | |
| | | | |
| | | (In thousands, except per unit measurements) | |
Revenue from the sale of oil and natural gas: | | | | | | | | | | | | | |
| Oil sales | | $ | 5,313 | | | (0%) | | $ | 5,327 | | $ | 11,002 | | | 2% | | $ | 10,754 | |
| Gain (loss) due to hedging | | | (385 | ) | | (43%) | | | (670 | ) | | (926 | ) | | (21%) | | | (1,175 | ) |
| Total revenue from the sale of oil | | $ | 4,928 | | | 6% | | $ | 4,657 | | $ | 10,076 | | | 5% | | $ | 9,579 | |
| | | | | | | | | | | | | | | | | | | | |
| Natural gas sales | | $ | 13,737 | | | (1%) | | $ | 13,903 | | $ | 25,302 | | | (3%) | | $ | 26,016 | |
| Gain (loss) due to hedging | | | (231 | ) | | (64%) | | | (644 | ) | | (241 | ) | | (72%) | | | (860 | ) |
| Total revenue from the sale of natural gas | | $ | 13,506 | | | 2% | | $ | 13,259 | | $ | 25,061 | | | (0%) | | $ | 25,156 | |
| | | | | | | | | | | | | | | | | | | | |
| Oil and natural gas sales | | $ | 19,050 | | | (1%) | | $ | 19,230 | | $ | 36,304 | | | (1%) | | $ | 36,770 | |
| Gain (loss) due to hedging | | | (616 | ) | | (53%) | | | (1,314 | ) | | (1,167 | ) | | (43%) | | | (2,035 | ) |
| Total revenue from the sale of oil and natural gas | | $ | 18,434 | | | 3% | | $ | 17,916 | | $ | 35,137 | | | 1% | | $ | 34,735 | |
| | | | | | | | | | | | | | | | | | | | |
Average prices: | | | | | | | | | | | | | | | | | | | |
| Oil sales price (per Bbl) | | $ | 51.56 | | | 36% | | $ | 37.81 | | $ | 49.84 | | | 39% | | $ | 35.79 | |
| Gain (loss) due to hedging (per Bbl) | | | (3.73 | ) | | (22%) | | | (4.76 | ) | | (4.19 | ) | | 7% | | | (3.91 | ) |
| Realized oil price (per Bbl) | | $ | 47.83 | | | 45% | | $ | 33.05 | | $ | 45.65 | | | 43% | | $ | 31.88 | |
| | | | | | | | | | | | | | | | | | | | |
| Natural gas sales price (per Mcf) | | $ | 6.73 | | | 9% | | $ | 6.19 | | $ | 6.27 | | | 4% | | $ | 6.00 | |
| Gain (loss) due to hedging (per Mcf) | | | (0.11 | ) | | (62%) | | | (0.29 | ) | | (0.06 | ) | | (70%) | | | (0.20 | ) |
| Realized natural gas price (per Mcf) | | $ | 6.62 | | | 12% | | $ | 5.90 | | $ | 6.21 | | | 7% | | $ | 5.80 | |
| | | | | | | | | | | | | | | | | | | | |
| Natural gas equivalent sales price (per Mcfe) | | $ | 7.16 | | | 15% | | $ | 6.22 | | $ | 6.77 | | | 13% | | $ | 5.99 | |
| Gain (loss) due to hedging (per Mcfe) | | | (0.23 | ) | | (47%) | | | (0.43 | ) | | (0.21 | ) | | (36%) | | | (0.33 | ) |
| Realized natural gas equivalent (per Mcfe) | | $ | 6.93 | | | 20% | | $ | 5.79 | | $ | 6.56 | | | 16% | | $ | 5.66 | |
| | | For the three month periods ended June 30, 2005 and 2004 | | For the six month periods ended June 30, 2005 and 2004 | |
| | | | | | |
| | | | | | |
Change in revenue from the sale of oil | | | | | |
| Price variance impact | | $ | 1,417 | | $ | 3,102 | |
| Volume variance impact | | | (1,431 | ) | | (2,854 | ) |
| Cash settlement of hedging contracts | | | 285 | | | 249 | |
| Total change | | $ | 271 | | $ | 497 | |
Change in revenue from the sale of natural gas | | | | | | | |
| Price variance impact | | $ | 1,104 | | $ | 1,093 | |
| Volume variance impact | | | (1,270 | ) | | (1,807 | ) |
| Cash settlement of hedging contracts | | | 413 | | | 619 | |
| Total change | | $ | 247 | | $ | (95 | ) |
Our revenue from the sale of oil and natural gas for the second quarter of 2005 increased by 3% when compared to our revenue in the second quarter of 2004. The following were the primary factors that led to the changes in our second quarter 2005 revenue from the sale of oil and natural gas.
| | · | A 15 % increase in our sales price for oil and natural gas combined with a 53% decrease in losses from the cash settlement of derivative commodity contracts led to increases of $2.5 million and $698,000, respectively, to our revenue from the sale of oil and natural gas during the second quarter 2005. |
| | · | These increases were partially offset by a $2.7 million decrease to our second quarter oil and natural gas sales due to a decrease in this year’s second quarter production volumes. |
Our revenue from the sale of oil and natural gas for the first six months of 2005 increased by 1% when compared to revenue in the first six months of 2004. 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 six months of 2005.
| | · | A 13% increase in our sales price for oil and natural gas combined with a 43% decrease in losses from the cash settlement of derivative commodity contracts led to increases of $4.2 million and $868,000, respectively, to our revenue from the sale of oil and natural gas during the first six months of 2005. |
| | · | These increases were partially offset by a $4.7 million decrease to our oil and natural gas sales due to a decrease in our production volumes for the first six months of 2005. |
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 second quarter of 2005 was $56,000 compared to $41,000 in the second quarter last year. Other revenue for the first six months of 2005 was $99,000 compared to $42,000 in the first half 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 June 30, | | Six months ended June 30, | |
| | | 2005 | | % Change | | 2004 | | 2005 | | % Change | | 2004 | |
| | | | |
| | | (In thousands, except per unit measurements) | |
Production costs: | | | | | | | | | | | | | |
| Operating & maintenance | | $ | 1,389 | | | 36% | | $ | 1,021 | | $ | 2,811 | | | 37% | | $ | 2,047 | |
| Expensed workovers | | | (213 | ) | | NM | | | 118 | | | 311 | | | (8%) | | | 339 | |
| Ad valorem taxes | | | 214 | | | 29% | | | 166 | | | 486 | | | 48% | | | 328 | |
| Lease operating expenses | | $ | 1,390 | | | 7% | | $ | 1,305 | | $ | 3,608 | | | 33% | | $ | 2,714 | |
| | | | | | | | | | | | | | | | | | | | |
| Production taxes | | | 366 | | | (59%) | | | 896 | | | 1,168 | | | (34%) | | | 1,759 | |
| Production costs | | $ | 1,756 | | | (20%) | | $ | 2,201 | | $ | 4,776 | | | 7% | | $ | 4,473 | |
| | | | | | | | | | | | | | | | | | | | |
Production cost ($ per Mcfe): | | | | | | | | | | | | | | | | | | | |
| Operating & maintenance | | $ | 0.52 | | | 58% | | $ | 0.33 | | $ | 0.52 | | | 58% | | $ | 0.33 | |
| Expensed workovers | | | (0.08 | ) | | NM | | | 0.04 | | | 0.06 | | | 0% | | | 0.06 | |
| Ad valorem taxes | | | 0.08 | | | 60% | | | 0.05 | | | 0.09 | | | 80% | | | 0.05 | |
| Lease operating expenses | | $ | 0.52 | | | 24% | | $ | 0.42 | | $ | 0.67 | | | 52% | | $ | 0.44 | |
| | | | | | | | | | | | | | | | | | | | |
| Production taxes | | | 0.14 | | | (52%) | | | 0.29 | | | 0.22 | | | (24%) | | | 0.29 | |
| Production costs | | $ | 0.66 | | | (7%) | | $ | 0.71 | | $ | 0.89 | | | 22% | | $ | 0.73 | |
Our second quarter 2005 production costs decreased by 20% when compared to our production costs in the second quarter last year. Our production costs for the second quarter 2005 include a reduction for costs, originally reported as workover expense in the first quarter 2005, that were reclassified to capital cost in the second quarter and for insurance reimbursements and other credits received in the second quarter totaling $350,000. We reclassified the workover costs as capital costs after further information regarding the nature of these costs became available. Excluding this reclassification and insurance reimbursements, our production costs for the second quarter 2005 were 4% lower than the second quarter last year. The following were the primary factors that led to the changes in our production cost.
| | · | A reduction in our second quarter production volumes combined with the receipt of a $540,000 severance tax refund related to six wells were the primary reasons for the decrease in our second quarter 2005 production taxes. These decreases were partially offset by increases in the sales price we received from the sale of oil and natural gas. |
| | · | The decrease in our production taxes was partially offset by increases in our second quarter 2005 costs for operating and maintenance and ad valorem taxes. Approximately 61% of the increase in our second quarter 2005 O&M expenses was related to new wells that were not producing during the second quarter last year. Other items that led to higher O&M expenses were increases in costs for saltwater disposal, compressor rental and maintenance and overhead. The increase in our second quarter 2005 ad valorem taxes was due to higher oil and natural gas prices in 2004. |
Our production costs for the first six months of 2005 were 7% higher than last year. The following were the primary reasons for the changes to our production costs.
| | · | Increases in our O&M expenses and ad valorem taxes during the first six months of 2005 were the primary factors that led to the increase in our production costs. Approximately 64% of the increase in our O&M expenses was related to new wells that were not producing during the first six months of last year. Other items that led to the higher O&M expenses were increases in costs for saltwater disposal, compressor rental and maintenance and miscellaneous lease operating expenses. The increase in our 2005 ad valorem taxes was due to higher oil and natural gas prices in 2004. |
| | · | These increases were partially offset by lower costs for expensed workovers and lower production taxes. A reduction in our second quarter production volumes combined with the receipt of $540,000 severance tax refund related to six wells were the primary reasons for the decrease in our production taxes for the first six months of 2005. These decreases were partially offset by increases in the sales price we received from the sale of oil and natural gas. |
We believe that per unit of production measures are 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 second quarter of 2005, our unit production cost decreased 7% when compared to 2004. Excluding the reclassification and reimbursement mentioned earlier, our unit production cost for the second quarter of 2005 increased 13%. The following were the primary factors that led to the changes in our unit production cost.
| | · | Our unit O&M expenses for the second quarter of 2005 were $0.19 per Mcfe higher when compared to the second quarter last year. Unit O&M expenses related to new wells that were not producing during the second quarter last year represented approximately 42% of this increase. Increases in our unit costs for saltwater disposal, compressor rental and maintenance and overhead were the primary factors for the remainder of the increase. |
| | · | Our unit ad valorem taxes for the second quarter of 2005 were up $0.03 per Mcfe when compared to the second quarter last year. This increase is primarily due to an increase in our total ad valorem taxes due to higher oil and natural gas prices in 2004 combined with a decrease in production volumes. |
| | · | These increases were partially offset by a $0.15 per Mcfe decrease in our second quarter 2005 unit production taxes. This decrease was primarily due to the receipt of a $540,000 severance tax refund. |
For the first six months of 2005, our unit production cost increased 22% when compared to the first half of 2004. The following were the primary factors that led to the changes to our unit production cost for the first six months of 2005.
| | · | Our unit O&M expenses for the first six months of 2005 were up $0.19 per Mcfe when compared to last year. Unit O&M costs related to new wells that were not producing during the first six months of 2004 represented approximately 48% of this increase. Increases in our unit costs for saltwater disposal, compressor rental and maintenance and miscellaneous lease operating expenses were the primary factors for the remainder of the increase. |
| | · | Our unit ad valorem taxes for the first six months of 2005 were up $0.04 per Mcfe when compared to last year. This increase is primarily due to an increase in total ad valorem taxes due to higher oil and natural gas prices in 2004 combined with a decrease in production volumes. |
| | · | These increases were partially offset by a $0.07 per Mcfe decrease in our unit production taxes during the first six months of 2005. This decrease was primarily due to the receipt of a $540,000 severance tax refund. |
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 June 30, | | Six months ended June 30, | |
| | | 2005 | | % Change | | 2004 | | 2005 | | % Change | | 2004 | |
| | | | |
| | | (In thousands, except per unit measurements) | |
| General and administrative costs | | $ | 2,501 | | | 3% | | $ | 2,429 | | $ | 4,804 | | | (2%) | | $ | 4,893 | |
| Capitalized general and administrative costs | | | (1,197 | ) | | (3%) | | | (1,230 | ) | | (2,402 | ) | | (3%) | | | (2,474 | ) |
| General and administrative expenses | | $ | 1,304 | | | 9% | | $ | 1,199 | | $ | 2,402 | | | (1%) | | $ | 2,419 | |
| | | | | | | | | | | | | | | | | | | | |
| General and administrative expense ($ per Mcfe) | | $ | 0.49 | | | 26% | | $ | 0.39 | | $ | 0.45 | | | 15% | | $ | 0.39 | |
For the second quarter of 2005, our general and administrative expenses increased by 9%. The following were the primary factors that led to the changes to our second quarter 2005 general and administrative expenses.
| | · | An increase in fees paid to outside consultants and our independent public accountants for work related to Section 404 of Sarbanes-Oxley and increases in costs for contract employees, employee training, corporate insurance and travel. |
| | · | These increases were partially offset by decreases in employee compensation expenses, office rent, financial reporting expenses and directors fees and costs. |
Our general and administrative expenses for the first and second quarters of 2005 decreased slightly when compared to the general and administrative expenses in the first half of 2004. The following were the primary factors that led to the changes to our general and administrative expenses for the six months of 2005.
| | · | An increase in fees paid to our outside consultants and our independent public accountants for work related to Section 404 of Sarbanes-Oxley and increases in costs for contract employees, employee training, corporate insurance and travel. |
| | · | These increases were offset by decreases in employee compensation expenses, office rent, financial reporting expenses and legal fees. |
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 June 30, | | Six months ended June 30, | |
| | | 2005 | | % Change | | 2004 | | 2005 | | % Change | | 2004 | |
| | | | | | | (Restated) | | | | | | (Restated) | |
| | | (In thousands, except per unit measurements) | |
| | | | |
| Depletion of oil and natural gas properties | | $ | 7,206 | | | 30% | | $ | 5,524 | | $ | 13,659 | | | 28% | | $ | 10,648 | |
| Depletion of oil and natural gas properties ($ per Mcfe) | | $ | 2.71 | | | 51% | | $ | 1.79 | | $ | 2.55 | | | 47% | | $ | 1.73 | |
An increase in our depletion rate resulted in a $2.4 million increase partially offset by a $764,000 decrease to our depletion expense due to a decrease in production volumes.
During the first half of 2005, an increase in our depletion rate resulted in a $4.4 million increase partially offset by $1.4 million decrease due to lower production.
The increase in our depletion rate was primarily the result of increased costs of reserve additions during the first six 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 June 30, | | Six months ended June 30, | |
| | | 2005 | | % Change | | 2004 | | 2005 | | % Change | | 2004 | |
| | | (In thousands) | |
| | | | |
| Interest on senior credit facility | | $ | 547 | | | 120% | | $ | 249 | | $ | 870 | | | 100% | | $ | 434 | |
| Interest on senior subordinated notes | | | 381 | | | (14%) | | | 445 | | | 759 | | | (14%) | | | 884 | |
| Commitment fees | | | 18 | | | (66%) | | | 53 | | | 56 | | | (48%) | | | 107 | |
| Dividend on mandatorily redeemable preferred stock | | | 193 | | | 8% | | | 179 | | | 381 | | | 8% | | | 354 | |
| Amortization of deferred loan and debt issuance cost | | | 127 | | | (34%) | | | 191 | | | 253 | | | (34%) | | | 383 | |
| Other general interest expense | | | 3 | | | (50%) | | | 6 | | | 6 | | | (57%) | | | 14 | |
| Capitalized interest expense | | | (503 | ) | | 87% | | | (269 | ) | | (818 | ) | | 51% | | | (540 | ) |
| Net interest expense | | $ | 766 | | | (10%) | | $ | 854 | | $ | 1,507 | | | (8%) | | $ | 1,636 | |
| | | | | | | | | | | | | | | | | | | | |
| Weighted average debt outstanding | | $ | 74,899 | | | 37% | | $ | 62,675 | | $ | 68,239 | | | 9% | | $ | 58,673 | |
| Average interest rate on outstanding indebtedness(a) | | | 6.1 | % | | | | | 5.9 | % | | 6.1 | % | | | | | 6.1 | % |
(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 second quarter of 2005 and first six months of 2005 was 10% and 8% lower, respectively, than our net interest expense in the same periods last year.
The following were the primary factors that led to the changes to our second quarter 2005 net interest expense.
| · | The decline in our second quarter 2005 net interest expense was primarily due to a $234,000 increase in the amount of interest that we capitalized during the second quarter 2005. This increase more than offset an increase in our total interest for the second quarter 2005. |
| · | The primary factor that led to the increase in our total interest for the second quarter 2005 was an increase in amount of borrowings outstanding under our senior credit facility and an increase in the rate that we paid on those borrowing due to an increase in the Eurodollar rate. |
The following were the primary factors that led to the changes to our net interest expense for the first six months of 2005.
| · | The decline in our net interest expense for the first six months of 2005 was primarily due to a $278,000 increase in the amount of interest that we capitalized during the period. This increase more than offset an increase in our total interest for the first six months of 2005. |
| · | The primary factor that led to the increase in our total interest for the first six months of 2005 was an increase in the total amount we borrowed under our senior credit facility and an increase in the rate that we paid on those borrowing due to an increase in the Eurodollar rate. |
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 June 30, | | Six months ended June 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 | | $ | (63 | ) | | NM | | $ | — | | $ | (413 | ) | | 588% | | $ | (60 | ) |
| Non-cash gain (loss) for ineffective portion of cash flow hedges | | | 203 | | | NM | | | (187 | ) | | (53 | ) | | NM | | | — | |
| Other non-cash gain (loss) | | | (51 | ) | | NM | | | — | | | (59 | ) | | NM | | | — | |
| Other cash income (expense) | | | 88 | | | 28% | | | 69 | | | 171 | | | 148% | | | 69 | |
| Other income (loss) | | $ | 177 | | | NM | | $ | (118 | ) | $ | (354 | ) | | NM | | $ | 9 | |
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 June 30, | | Six months ended June 30, | |
| | | 2005 | | % Change | | 2004 | | 2005 | | % Change | | 2004 | |
| | | | | | | | | | | | | | |
Written puts | | | | | | | | | | | | | |
| Volumes (Bbl) | | | 6,000 | | | NM | | | — | | | 6,000 | | | NM | | $ | — | |
| Average price ($ per Bbl) | | $ | 38.00 | | | NM | | $ | — | | $ | 38.00 | | | 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.
| | | Six months ended June 30, | |
| | | 2005 | | % Change | | 2004 | |
| | | (In thousands) | |
| Net income | | $ | 7,858 | | | (22%) | | $ | 10,063 | |
| Non-cash items | | | 19,589 | | | 15% | | | 17,021 | |
| Changes in working capital and other items | | | 754 | | | NM | | | (1,734 | ) |
| Cash flows provided by operating activities | | $ | 28,201 | | | 11% | | $ | 25,350 | |
| Cash flows used by investing activities | | | (56,813 | ) | | 49% | | | (38,107 | ) |
| Cash flows provided by financing activities | | | 32,756 | | | 81% | | | 18,089 | |
| Net increase in cash and cash equivalents | | $ | 4,144 | | | (22%) | | $ | 5,332 | |
Analysis of net cash provided by operating activities
Cash flows provided by operating activities for the first six months of 2005 were 11% 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 six months of 2005.
| · | Our total revenues for the first six months of 2005 increased $5.1 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 $4.7 million decrease to our total revenue due to a decrease in our production volumes for the first six months of 2005. |
| · | A decrease in our production costs for the first six months of 2005 resulted in a $303,000 increase in our cash flows provided by operating activities. |
| · | The collection of accounts receivable in excess of the payment of accounts payable during the first six months of 2005 increased our cash flows provided by operating activities by $8.9 million. |
| · | An increase in the amount of royalties we paid during the first half of 2005 decreased our cash flows provided by operating activities by $3.3 million. |
| · | A decrease in the amount of participant advances during the first six months of 2005 resulted in a $2.5 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 June 30, 2005 was $17.8 million compared to a working capital deficit of $19.5 million at December 31, 2004. This deficit included a net liability of $586,000 related to the fair value of our derivative contracts.
Capital expenditures for oil and natural gas activities:
| | | Six months ended June 30, | |
| | | 2005 | | % Change | | 2004 | |
| | | | | | | | |
| | | (In thousands) | |
| | | | | | | | |
| Drilling (1) | | $ | 45,238 | | | 45% | | $ | 31,262 | |
| Land and seismic | | | 10,246 | | | 96% | | | 5,221 | |
| Capitalized cost (2) | | | 3,381 | | | 7% | | | 3,161 | |
| Capitalized ARO | | | 160 | | | 7% | | | 335 | |
| Total | | $ | 59,025 | | | 48% | | $ | 39,979 | |
____________
| (1) | Includes $1.8 million and $1.4 million of accrued drilling costs for 2005 and 2004, respectively. |
| (2) | For 2005 includes $2.4 million in capitalized general and administrative cost, $818,000 in capitalized interest cost and $161,000 of capitalized stock compensation expense. For 2004 includes $2.4 million in capitalized general and administrative cost, $540,000 in capitalized interest cost and $146,000 of capitalized stock compensation expense. |
Analysis of changes in cash flows from financing activities
Senior Credit Facility
During first six months of 2005 we borrowed an additional $31.6 million under our senior credit facility, repaid $8.2 million of the amount borrowed under our senior credit facility and paid $680,000 in fees to amend and restate of our senior credit agreement in January and June 2005. This compares to our borrowing $19.7 million, repaying $2 million and paying $43,000 in deferred loan costs during the first six months of 2004.
Senior Subordinated Notes
During the first six months of 2005 borrowed an additional $10 million under our subordinated credit agreement and paid $208,000 in fees to amend our subordinated credit agreement on June 29, 2005.
Common Stock Transactions
| | | Shares Issued | | Net Proceeds | |
| | | | | (In thousands) | |
2005 common stock transactions: | | | | | |
| Exercise of employee stock options | | | 125,500 | | $ | 434 | |
| | | | | | | | |
2004 common stock transactions: | | | | | | | |
| Exercise of employee stock options | | | 208,081 | | $ | 598 | |
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.
| 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 June 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 | | | | | | | | | | |
| 07/01/05 - 10/31/05 | | Purchased put | | Cash flow | | 240,000 | | | | $5.45 |
| | | Written call | | Cash flow | | 240,000 | | | | 8.00 |
Three Way Costless Collars | | | | | | | | | | |
| 07/01/05 - 10/31/05 | | Purchased put | | Cash flow | | 400,000 | | | | $6.00 |
| | | Written call | | Cash flow | | 400,000 | | | | 7.20 |
| | | Written put | | Undesignated | | 400,000 | | | | 5.00 |
| 07/01/05 - 10/31/05 | | Purchased put | | Cash flow | | 240,000 | | | | $7.00 |
| | | Written call | | Cash flow | | 240,000 | | | | 7.76 |
| | | Written put | | Undesignated | | 240,000 | | | | 5.75 |
| 07/01/05 - 12/31/05 | | Purchased put | | Cash flow | | | | 30,000 | | $40.00 |
| | | Written call | | Cash flow | | | | 30,000 | | 53.00 |
| | | Written put | | Undesignated | | | | 30,000 | | 30.00 |
| 07/01/05 - 03/31/06 | | Purchased put | | Cash flow | | | | 54,000 | | $48.00 |
| | | Written call | | Cash flow | | | | 54,000 | | 60.70 |
| | | Written put | | Undesignated | | | | 54,000 | | 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 |
The following table reflects commodity derivative contracts entered into subsequent to June 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 - 06/30/06 | | Purchased put | | Cash flow | | | | 16,500 | | $54.80 |
| | | Written call | | Cash flow | | | | 16,500 | | 75.00 |
Three Way Costless Collars | | | | | | | | | | |
| 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 |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
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 2005 related to this material weakness are described below.
Evaluation of Disclosure Controls and Procedures
As of June 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
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.
| UNREGISTERD SALES OF EQITY SECURITIES AND USE OF PROCEEDS |
Issuer Purchases of Equity Securities
Period | | Total Number of Shares Purchased | | Average Price Paid per Share | |
| | | | | | |
| January 1, 2005 - January 31, 2005 | | | 21,229 | | $ | 8.93 | |
No purchases were made under a publicly announced plan.
| ITEM 3. | DEFAULTS UPON SENIOR SECURITIES |
None.
| SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS |
| (a) | We held our Annual Stockholders meeting on Wednesday, June 8, 2005, in Austin, Texas at 10:00 a.m. local time. |
| (b) | Proxies were solicited by our Board of Directors pursuant to Regualtion 14A under the Securities Exchange Act of 1934. There were no solicitations in opposition to the Board of Directors’ nominees as listed in the proxy statement and all of such nominees were duly elected. |
| (c) | Out of the total 42,489,396 shares of our common stock and outstanding and entitled to vote, 31,425,571 shares were present in person or by proxy, representing approximately 73.96%. They only matters voted on by our stockholders, as fully described in the definitive proxy materials for the annual meeting, are set forth below. The results were as follows: |
| | 1. | To elect eight directors to serve until the Annual Meeting of Stockholders in 2006. |
Nominee | | Number of shares voting for election as director | | Number of shares voting against election as director | | Number of shares withholding authority to vote for election as director |
| | | | | | | |
| Ben M. “Bud” Brigham | | 24,143,828 | | - | | 7,281,743 |
| David T. Brigham | | 23,997,683 | | - | | 7,427,888 |
| Harold D. Carter | | 23,141,813 | | - | | 8,283,758 |
| Stephen C. Hurley | | 31,010,130 | | - | | 415,441 |
| Stephen P. Reynolds | | 30,633,066 | | - | | 792,505 |
| Hobart A. Smith | | 30,814,785 | | - | | 610,786 |
| Steven A. Webster | | 23,167,761 | | - | | 8,257,810 |
| R. Graham Whaling | | 31,010,330 | | - | | 415,241 |
| | 2. | To approve the appointment of PricewaterhouseCoopers LLP as our independent auditors for the year ending December 31, 2005. |
| For | 30,972,445 |
| Against | 452,401 |
| Abstained | 725 |
None.
Number | | Description |
| — | Fourth Amended and Restated Credit Agreement, dated June 29, 2005 between Brigham Oil & Gas, L.P., Bank of America, N.A., The Royal Bank of Scotland plc, BNP Paribas and Banc of America Securities LLC. |
| | | |
| — | The Resignation of Agent, Appointment of Successor Agent and Assignment of Security Instruments dated June 29, 2005 by and among Brigham Oil & Gas, L.P., Société Générale and Bank of America, N.A. |
| | | |
| — | First Amendment to Second Amended and Restated Subordinated Credit Agreement dated June 29, 2005, between Brigham Oil & Gas, L.P., and The Royal Bank of Scotland plc. |
| | | |
| — | Second Amended and Restated Intercreditor and Subordination Agreement, dated January 21, 2005. |
| | | |
| — | First Amendment to the Second Amended and Restated Intercreditor and Subordination Agreement |
| | | |
| — | Certification of Chief Executive Officer of the Company pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 |
| | | |
| — | Certification of Chief Financial Officer of the Company pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 |
| | | |
| — | Certification of Chief Executive Officer of the Company pursuant to 18 U.S.C. § 1350 |
| | | |
| — | Certification of Chief Financial Officer of the Company pursuant to 18 U.S.C. § 1350 |
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 August 5, 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 |
35
