Exhibit 99.1
AMVEST OSAGE, INC.
AND SUBSIDIARIES
Consolidated Financial Statements for the Years ended July 31, 2006, 2005, and 2004,
together with the Independent Auditors’ Report, and Consolidated Condensed
Financial Statements for the Nine Months ended April 30, 2007 and 2006 (Unaudited)
INDEPENDENT AUDITORS’ REPORT
To the Stockholder of
AMVEST Osage, Inc.
Charlottesville, Virginia
We have audited the accompanying consolidated balance sheets of AMVEST Osage, Inc. and subsidiaries (the Company) as of July 31, 2006 and 2005, and the related consolidated statements of income, stockholder’s equity, and cash flows for each of the three years in the period ended July 31, 2006. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the companies as of July 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended July 31, 2006 in conformity with accounting principles generally accepted in the United States of America.
Our audits were conducted for the purpose of forming an opinion on the basic financial statements taken as a whole. The supplemental information in Note 11 to the consolidated financial statements is presented for the purpose of additional analysis and is not a required part of the basic financial statements. This additional information is the responsibility of the Company’s management. Such information has not been subjected to the auditing procedures applied in our audits of the basic financial statements, and accordingly, we express no opinion on it.
Deloitte & Touche LLP
Richmond, Virginia
September 13, 2007
AMVEST OSAGE, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (In thousands)
April 30, | July 31, | |||||||||||
2007 | 2006 | 2005 | ||||||||||
(Unaudited) | ||||||||||||
ASSETS | ||||||||||||
CURRENT ASSETS | ||||||||||||
Cash | $ | 3 | $ | 3 | $ | 3 | ||||||
Affiliate cash pool | — | 1,050 | 748 | |||||||||
Accounts receivable | 3,982 | 4,711 | 3,581 | |||||||||
Parts inventory | 1,808 | 1,759 | 1,379 | |||||||||
Prepaid assets | 166 | 125 | 163 | |||||||||
Deferred income taxes | — | — | 17 | |||||||||
5,959 | 7,648 | 5,891 | ||||||||||
PROPERTY AND EQUIPMENT | ||||||||||||
Equipment | 1,444 | 1,337 | 1,214 | |||||||||
Land | 407 | 407 | 372 | |||||||||
Buildings | 412 | 412 | 172 | |||||||||
Oil and gas properties (successful efforts) | 124,180 | 102,134 | 78,468 | |||||||||
126,443 | 104,290 | 80,226 | ||||||||||
Accumulated depreciation, depletion and amortization | (26,414 | ) | (18,965 | ) | (11,767 | ) | ||||||
100,029 | 85,325 | 68,459 | ||||||||||
DEPOSITS | 12 | 12 | 28 | |||||||||
TOTAL ASSETS | $ | 106,000 | $ | 92,985 | $ | 74,378 | ||||||
LIABILITIES AND STOCKHOLDER’S EQUITY | ||||||||||||
CURRENT LIABILITIES | ||||||||||||
Accounts payable | $ | 2,014 | $ | 2,271 | $ | 1,292 | ||||||
Accrued royalties | 1,692 | 1,540 | 1,313 | |||||||||
Accrued expenses | 922 | 803 | 785 | |||||||||
Affiliate cash pool | 6,715 | — | — | |||||||||
Due to affiliates | 24,682 | 29,096 | 23,991 | |||||||||
Deferred income taxes | 82 | 72 | — | |||||||||
36,107 | 33,782 | 27,381 | ||||||||||
DEFERRED INCOME TAXES | 23,259 | 18,161 | 13,038 | |||||||||
RECLAMATION OBLIGATIONS | 864 | 763 | 701 | |||||||||
TOTAL LIABILITIES | 60,230 | 52,706 | 41,120 | |||||||||
COMMITMENTS AND CONTINGENCIES, note 7 | ||||||||||||
STOCKHOLDER’S EQUITY | ||||||||||||
Common stock | — | — | — | |||||||||
Additional paid-in capital | 27,267 | 26,807 | 26,500 | |||||||||
Retained earnings | 18,503 | 13,472 | 6,758 | |||||||||
TOTAL STOCKHOLDER’S EQUITY | 45,770 | 40,279 | 33,258 | |||||||||
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY | $ | 106,000 | $ | 92,985 | $ | 74,378 | ||||||
See accompanying notes to consolidated financial statements.
AMVEST OSAGE, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME (In thousands)
Nine Months Ended April 30, | Year Ended July 31, | |||||||||||||||||||
2007 | 2006 | 2006 | 2005 | 2004 | ||||||||||||||||
(Unaudited) | (Unaudited) | |||||||||||||||||||
REVENUES | ||||||||||||||||||||
Net sales | $ | 27,955 | $ | 30,912 | $ | 39,808 | $ | 26,812 | $ | 16,575 | ||||||||||
Gain/(loss) on mark-to-market activities | — | 150 | 150 | (150 | ) | — | ||||||||||||||
TOTAL REVENUES | 27,955 | 31,062 | 39,958 | 26,662 | 16,575 | |||||||||||||||
EXPENSES | ||||||||||||||||||||
Operating expenses: | ||||||||||||||||||||
Lease operating expenses | 5,628 | 4,455 | 6,237 | 5,313 | 4,000 | |||||||||||||||
Cost of Sales | 1,111 | 1,076 | 1,476 | 1,382 | 850 | |||||||||||||||
Production taxes | 1,633 | 1,820 | 2,341 | 1,461 | 872 | |||||||||||||||
General and administrative | 3,483 | 3,219 | 4,581 | 3,172 | 2,778 | |||||||||||||||
Depreciation, depletion, and amortization | 7,619 | 5,362 | 7,363 | 5,335 | 3,336 | |||||||||||||||
Accretion expense | 32 | 32 | 42 | 36 | 29 | |||||||||||||||
Total operating expenses | 19,506 | 15,964 | 22,040 | 16,699 | 11,865 | |||||||||||||||
Other expense (income): | ||||||||||||||||||||
Affiliate interest expense | 1,183 | 594 | 844 | 573 | 148 | |||||||||||||||
Interest income | — | (1 | ) | (1 | ) | (1 | ) | — | ||||||||||||
Other expense (income) | (46 | ) | 1 | 1 | (2 | ) | (21 | ) | ||||||||||||
Total other expense, net | 1,137 | 594 | 844 | 570 | 127 | |||||||||||||||
INCOME BEFORE INCOME TAXES | 7,312 | 14,504 | 17,074 | 9,393 | 4,583 | |||||||||||||||
INCOME TAX PROVISION | ||||||||||||||||||||
Current | (2,827 | ) | 2,380 | 1,148 | (2,565 | ) | (205 | ) | ||||||||||||
Deferred | 5,108 | 2,890 | 5,212 | 5,410 | 1,508 | |||||||||||||||
2,281 | 5,270 | 6,360 | 2,845 | 1,303 | ||||||||||||||||
NET INCOME | $ | 5,031 | $ | 9,234 | $ | 10,714 | $ | 6,548 | $ | 3,280 | ||||||||||
See accompanying notes to consolidated financial statements.
AMVEST OSAGE, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands)
Nine Months Ended April 30, | Year Ended July 31, | |||||||||||||||||||
2007 | 2006 | 2006 | 2005 | 2004 | ||||||||||||||||
(Unaudited) | (Unaudited) | |||||||||||||||||||
OPERATING ACTIVITIES | ||||||||||||||||||||
Net income | $ | 5,031 | $ | 9,234 | $ | 10,714 | $ | 6,548 | $ | 3,280 | ||||||||||
ADJUSTMENTS TO RECONCILE NET INCOME TO CASH PROVIDED BY OPERATIONS: | ||||||||||||||||||||
Deferred income taxes | 5,108 | 2,890 | 5,212 | 5,410 | 1,508 | |||||||||||||||
Depreciation, depletion, and amortization | 7,619 | 5,362 | 7,363 | 5,335 | 3,336 | |||||||||||||||
(Gains) / loss on sale of property | (22 | ) | 4 | 5 | — | (7 | ) | |||||||||||||
Bad debt expense and other | — | — | — | (6 | ) | (11 | ) | |||||||||||||
Accretion expense | 32 | 32 | 42 | 36 | 29 | |||||||||||||||
Stock appreciation rights | 460 | 188 | 307 | — | ||||||||||||||||
CHANGES IN ASSETS AND LIABILITIES: | ||||||||||||||||||||
Accounts receivable | 729 | 97 | (1,130 | ) | (1,005 | ) | (690 | ) | ||||||||||||
Parts inventory | (49 | ) | (206 | ) | (380 | ) | (528 | ) | (233 | ) | ||||||||||
Prepaid Expenses | (41 | ) | 19 | 38 | (75 | ) | (69 | ) | ||||||||||||
Deposits | — | 16 | 16 | 1 | (1 | ) | ||||||||||||||
Accounts payable | (161 | ) | 104 | 432 | (14 | ) | 71 | |||||||||||||
Accrued royalties | 152 | 120 | 227 | 485 | 247 | |||||||||||||||
Accrued expenses | 119 | (20 | ) | 18 | 494 | 11 | ||||||||||||||
Reclamation obligations settled | — | (36 | ) | (207 | ) | (19 | ) | (21 | ) | |||||||||||
CASH PROVIDED BY OPERATING ACTIVITIES | 18,977 | 17,804 | 22,657 | 16,662 | 7,450 | |||||||||||||||
INVESTING ACTIVITIES | ||||||||||||||||||||
Affiliate cash pool, net | 1,050 | 748 | (302 | ) | (620 | ) | (21 | ) | ||||||||||||
Acquisition of oil and gas properties | — | — | (7,038 | ) | — | — | ||||||||||||||
Capital expenditures | (22,378 | ) | (17,045 | ) | (22,689 | ) | (25,414 | ) | (17,709 | ) | ||||||||||
Proceeds from disposal of property | 50 | 6,083 | 6,267 | 301 | 19 | |||||||||||||||
CASH USED IN INVESTING ACTIVITIES | (21,278 | ) | (10,214 | ) | (23,762 | ) | (25,733 | ) | (17,711 | ) | ||||||||||
FINANCING ACTIVITIES | ||||||||||||||||||||
Due to affiliates, net | (4,414 | ) | (13,663 | ) | 1,105 | 9,071 | 10,260 | |||||||||||||
Affiliate cash pool, net | 6,715 | 6,073 | — | — | — | |||||||||||||||
CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES | 2,301 | (7,590 | ) | 1,105 | 9,071 | 10,260 | ||||||||||||||
INCREASE (DECREASE) IN CASH | — | — | — | — | (1 | ) | ||||||||||||||
CASH, beginning of year | 3 | 3 | 3 | 3 | 4 | |||||||||||||||
CASH, end of year | $ | 3 | $ | 3 | $ | 3 | $ | 3 | $ | 3 | ||||||||||
See accompanying notes to consolidated financial statements.
AMVEST OSAGE, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER’S EQUITY (In thousands)
COMMON STOCK * | ADDITIONAL PAID-IN CAPITAL | RETAINED EARNINGS | TOTAL | |||||||||||
Balance at August 1, 2003 | $ | — | $ | 26,500 | $ | (3,070 | ) | $ | 23,430 | |||||
Net income | — | — | 3,280 | 3,280 | ||||||||||
Balance at July 31, 2004 | — | 26,500 | 210 | 26,710 | ||||||||||
Net income | — | — | 6,548 | 6,548 | ||||||||||
Balance at July 31, 2005 | — | 26,500 | 6,758 | 33,258 | ||||||||||
Net income | — | — | 10,714 | 10,714 | ||||||||||
Capital contribution | — | 307 | — | 307 | ||||||||||
Dividends paid | — | — | (4,000 | ) | (4,000 | ) | ||||||||
Balance at July 31, 2006 | — | 26,807 | 13,472 | 40,279 | ||||||||||
Net income (unaudited) | — | — | 5,031 | 5,031 | ||||||||||
Capital contribution (unaudited) | — | 460 | — | 460 | ||||||||||
Balance at April 30, 2007 (unaudited) | $ | — | $ | 27,267 | $ | 18,503 | $ | 45,770 | ||||||
* | 100 shares issued and outstanding at $1 par value, 1,000 shares authorized. |
See accompanying notes to consolidated financial statements.
AMVEST OSAGE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For the Years Ended July 31, 2006, 2005 and 2004 and the Nine Months Ended April 30, 2007 and 2006 (unaudited) in thousands
1. Summary of Significant Accounting Policies
Nature of Business
AMVEST Osage, Inc. is an oil and gas company formed in September 2000 for the purpose of developing and operating oil and gas reserves in Oklahoma. The company owns and operates 343 natural gas wells in Osage County, Oklahoma under a concession from the Osage Nation covering approximately 560,000 net acres. AMVEST Osage, Inc.’s wholly owned subsidiaries include Northeast Shelf Energy, LLC and Mid-Continent Oilfield Supply, LLC (collectively the Company).
The Company was a wholly owned subsidiary of AMVEST Corporation (AMVEST) through the date of the transaction described in Note 10.
Unaudited Consolidated Financial Statements for the Nine Months ended April 30, 2007 and 2006
As permitted by the rules and regulations of the Securities and Exchange Commission (SEC), the accompanying unaudited consolidated financial statements contain certain condensed financial information and exclude certain footnote disclosures normally included in annual audited consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America. In the opinion of the Company’s management, the accompanying unaudited consolidated financial statements contain all adjustments, including normal recurring accruals, necessary to present fairly the Company’s financial position as of April 30, 2007, and the results of its operations and cash flows for the nine months ended April 30, 2007 and 2006. The results of operations for the nine months ended April 30, 2007 are not necessarily indicative of the results expected for the full year.
Principles of Consolidation and Reporting
The consolidated financial statements of the Company include the accounts of AMVEST Osage, Inc. and its subsidiaries. All intercompany transactions have been eliminated in consolidation.
Derivatives
During the years ended July 31, 2006 and 2005, the Company entered into forward sales contracts for the delivery of natural gas. During the year ended July 31, 2006, the Company determined and formally documented that such agreements qualify for normal purchase and sale accounting. During the year ended July 31, 2005, a
determination as to whether such agreements qualify for normal purchase and sale accounting was not made and a liability to reflect the estimated fair value of such agreements of $150 was included in Accrued Expenses in the accompanying consolidated balance sheet.
Parts Inventory
Parts inventory is valued at the lower of average cost or market.
Properties
Proved
Oil and gas properties are accounted for using the successful efforts method. Under this method, all development and acquisition costs of proved developed properties are capitalized and amortized on a unit-of-production basis over the remaining life of proved developed reserves and proved reserves, respectively. Costs of drilling exploratory wells are initially capitalized, but charged to expense if and when a well is determined to be unsuccessful.
The Company evaluates the impairment of its proved oil and gas properties by field whenever events or changes in circumstances indicate an asset’s carrying amount may not be recoverable. Unamortized capital costs are reduced to fair value if the expected undiscounted future cash flows are less than the asset’s net book value. Cash flows are determined based upon reserves using prices and costs consistent with those used for internal decision making. The underlying commodity prices embedded in the Company’s estimated cash flows are the product of a process that begins with the New York Mercantile Exchange pricing and adjusted for estimated location and quality differentials, as well as other factors that management believes will impact realizable prices. Although prices used are likely to approximate market, they do not necessarily represent current market prices. Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects (by greater than ten percent) the unit-of-production amortization rate, in which case a gain or loss is recognized currently. Gains or losses from the disposal of other properties are recognized currently. Expenditures for maintenance, repairs and minor renewals necessary to maintain properties in operating condition are expensed as incurred. Major replacements and renewals are capitalized. Estimated dismantlement and abandonment costs for oil and gas properties are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves.
Unproved
Unproved properties consist of costs incurred to acquire unproved leases (lease acquisition costs) as well as costs incurred to acquire unproved reserves. These costs are capitalized and amortized on a composite basis, based on past success, experience and average lease-term lives. Unamortized lease acquisition costs related to successful exploratory drilling are reclassified to proved properties and depleted on a
unit-of-production basis. The Company assesses unproved reserves for impairment annually by comparing book value to fair value, which is determined using discounted estimates of future cash flows.
Exploration
Costs of drilling exploratory wells are initially capitalized, but charged to expense if and when a well is determined to be unsuccessful. All other exploration costs are expensed as incurred. Determination is usually made within one year from the date drilling and other necessary activities have been completed. If a determination cannot be made after one year, all costs associated with the well are expensed.
Other
Other properties include pipelines, buildings, and other equipment. These items are recorded at cost and are depreciated using either the straight-line method based on expected lives of the individual assets or group of assets or the unit-of-production method over the remaining life of related proved reserves.
Revenue Recognition
Oil and gas revenues are recorded using the entitlement method. Under the entitlement method, revenue is recorded when title passes based on the Company’s net working interest. The Company records its entitled share of revenues based on entitled volumes and contracted sales prices (net of royalty). The sales price for oil and gas are adjusted for transportation cost and other related deductions. The transportation costs and other deductions are based on contractual or historical data and do not require significant judgment. Subsequently, these deductions and transportation costs are adjusted to reflect actual charges based on third party documents. These adjustments have historically been insignificant. Since there is a ready market for oil and gas, the Company sells the majority of its products soon after production at various locations at which time title and risk of loss pass to the buyer. As a result, the Company does not maintain product inventory.
Royalty Payable
It is the Company’s policy to calculate and pay royalties on natural gas and crude oil in accordance with the particular contractual provisions of the lease, license or concession agreements and the laws and regulations applicable to those agreements. Royalty liabilities are recorded in the period in which the natural gas or crude oil are produced and are included in Accrued Expenses on the Company’s Consolidated Balance Sheets. Oil and gas revenues are presented net of royalties.
Credit and Market Risks
The Company manages and controls market and counterparty credit risk through established formal internal control procedures which are reviewed on an ongoing basis. In the normal course of business, collateral is not required for financial instruments with credit risk. The Company uses the specific identification method of providing allowances for doubtful accounts.
Income Taxes
The Company files a consolidated federal income tax return with AMVEST Corporation. The Company’s income taxes are computed on a separate return basis and are provided for based on the Company’s taxable income in addition to a provision for deferred income taxes. Deferred income taxes are provided to reflect the tax consequences in future years of differences between the financial statement and tax basis of assets and liabilities. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil and gas reserves and related cash flow estimates used in impairment tests of other long-lived assets, estimates of future development, income taxes, dismantlement and abandonment costs, estimates relating to certain oil and gas revenues and expenses as well as estimates of expenses related to legal, environmental and other contingencies. Actual results could differ from those estimates.
Fair Value of Financial Instruments
The fair value of the Company’s assets and liabilities that qualify as financial instruments, including accounts receivable and accounts payable, approximate carrying value given their short-term nature.
Recently Issued Accounting Pronouncements
In July 2006, the Financial Accounting Standards Board, or FASB, issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes, or FIN 48. FIN 48 prescribes a two-step process for the financial statement recognition and measurement of tax positions taken or expected to be taken in a tax return. The first step involves evaluation of a tax position to determine whether it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. The second step involves measuring the benefit to recognize in the financial statements for those tax positions that meet the more-likely-than-not recognition threshold. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 will become effective for the Company beginning August 1, 2007. The Company has not yet determined the effects that FIN 48 will have on its consolidated financial statements.
In September 2006, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 157, Fair Value Measurements (SFAS No. 157), which defines fair value, establishes a framework for measuring fair value and expands disclosures related to fair value measurements. SFAS No. 157 clarifies that fair value should be based on assumptions that market participants would use when
pricing an asset or liability and establishes a fair value hierarchy of three levels that prioritizes the information used to develop those assumptions. The fair value hierarchy gives the highest priority to quoted prices in active markets and the lowest priority to unobservable data. SFAS No. 157 requires fair value measurements to be separately disclosed by level within the fair value hierarchy. The provisions of SFAS No. 157 will become effective for the Company beginning August 1, 2008. The Company has not yet determined the effects that SFAS No. 157 will have on its consolidated financial statements.
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (SFAS No. 159). SFAS No. 159 provides an entity with the option, at specified election dates, to measure certain financial assets and liabilities and other items at fair value, with changes in fair value recognized in earnings as those changes occur. SFAS No. 159 also establishes presentation and disclosure requirements that include displaying the fair value of those assets and liabilities for which the entity elected the fair value option on the face of the balance sheet and providing management’s reasons for electing the fair value option for each eligible item. The provisions of SFAS No. 159 will become effective for the Company beginning August 1, 2008. The Company has not yet determined the effects that SFAS No. 159 will have on its consolidated financial statements.
2. Oil and Gas and Other Properties
Oil and gas properties and related equipment (successful efforts method) consists of the following:
July 31 | ||||||||
2006 | 2005 | |||||||
Property Costs | ||||||||
Proved | $ | 96,350 | $ | 75,724 | ||||
Unproved | 1,633 | 576 | ||||||
Total Property Costs | 97,983 | 76,300 | ||||||
Land | 407 | 372 | ||||||
Buildings | 412 | 172 | ||||||
Equipment | 1,337 | 1,214 | ||||||
Pipelines | 4,151 | 2,168 | ||||||
Less: Accumulated depreciation, depletion and amortization | (18,965 | ) | (11,767 | ) | ||||
Oil and gas properties and equipment, net | $ | 85,325 | $ | 68,459 | ||||
3. Acquisitions and Divestitures
Acquisitions
In July 2006, the Company acquired certain oil and gas properties located in Oklahoma for $7,038 paid for in cash and the assumption of reclamation obligations. The fair value of assets acquired and liabilities assumed is as follows:
Property Costs | ||||
Proved | $ | 5,478 | ||
Unproved | 1,325 | |||
Parts inventory | 113 | |||
Land | 20 | |||
Buildings | 230 | |||
Equipment | 6 | |||
Reclamation Obligations | (134 | ) | ||
$ | 7,038 | |||
Divestitures
In September 2005, the Company sold certain oil and gas properties located in Oklahoma that constituted a portion of the Company’s amortization base for cash and the buyer’s assumption of reclamation obligations totaling $6,200. The total consideration received for this sale was credited to the Company’s oil and gas properties account used in calculating amortization expense. No gain was recognized on the sale.
4. Reclamation Obligations
The Company records the fair value of a liability for a reclamation obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the reclamation costs included in the carrying amount of the related asset is allocated to expense through depreciation or depletion of the asset. The majority of the Company’s reclamation obligations relate to plugging and abandoning oil and gas wells and related equipment.
The following table reflects the changes in the Company’s reclamation obligations:
Reclamation obligation at August 1, 2003 | $ | 472 | ||
Liabilities incurred | 78 | |||
Liabilities settled | (21 | ) | ||
Current year accretion expense | 29 | |||
Reclamation obligation at July 31, 2004 | 558 | |||
Liabilities incurred | 126 | |||
Liabilities settled | (19 | ) | ||
Current year accretion expense | 36 | |||
Reclamation obligation at July 31, 2005 | 701 | |||
Liabilities incurred | 227 | |||
Liabilities settled | (207 | ) | ||
Current year accretion expense | 42 | |||
Reclamation obligation at July 31, 2006 | $ | 763 | ||
5. Related Party Transactions
In the normal course of business, the Company enters into transactions with AMVEST and certain subsidiaries of AMVEST (collectively Affiliates).
Services Provided by Affiliates
Management services including accounting, marketing, human resources, and information technology are provided to the Company by Affiliates. Specific identifiable costs associated with these services are recorded as General and Administrative Expense in the accompanying Consolidated Statements of Income. Costs associated with these services that are not specifically identifiable are allocated to the Company based on its share of specifically identifiable costs. Management of the Company believes this method of allocation is reasonable. The total of such costs were $1,469, $1,295 and $1,225 for the years ended July 31, 2006, 2005 and 2004, respectively, and $1,247 and $1,103 for the nine month periods ended April 30, 2007 and 2006, respectively (unaudited).
The Company also pays a management fee to affiliates based on two percent of allocated management services cost that is included in General and Administrative Expense in the accompanying Consolidated Statements of Income. Management fees for the years ended July 31, 2006, 2005 and 2004 amounted to $29, $26 and $24, respectively.
Certain of the Company’s employees began participating in a stock appreciation rights program sponsored by AMVEST during the year ended July 31, 2006. Costs associated with these employees and amounts allocable to the Company as part of the general overhead allocation discussed above amounted to $307 for the year ended July 31, 2006 and $460 and $188 for the nine month periods ended April 30, 2007 and 2006, respectively (unaudited), and are included in General and Administrative Expense in the accompanying Consolidated Statements of Income and as an increase in the Company’s Additional Paid-In Capital. The stock appreciation rights were settled in connection with the transaction discussed in Note 10.
Substantially all of the Company’s employees participate in defined contribution plans sponsored by AMVEST. The Company’s contributions to these plans are based either on a percentage of salary or matching programs and amounted to $141, $117, and $85 for the years ended July 31, 2006, 2005 and 2004, respectively and $129 and $109 for the nine month periods ended April 30, 2007 and April 30, 2006, respectively (unaudited).
Services Provided to Affiliates
The Company provides land and inventory purchasing services to Affiliates. Reimbursements associated with these services amounted to $1, $3 and $11 for the years ended July 31, 2006, 2005 and 2004, respectively.
Due to Affiliates and Affiliate Cash Pool
Advances between the Company and AMVEST Corporation occur in the normal course of business. Such transactions are primarily related to funding activities for working capital and capital expansion programs for the Company’s drilling operations in Oklahoma. These amounts are included in Due to Affiliates in the accompanying Consolidated Balance Sheets and amounted to $29,096 and $23,991 at July 31, 2006 and 2005, respectively, and $24,682 at April 30, 2007 (unaudited). AMVEST Corporation also collects and disburses cash on behalf of the Company. Such transactions are included in Affiliate Cash Pool in the accompanying Consolidated Balance Sheets and amounted to $1,050 and $748 at July 31, 2006 and 2005, respectively, and $(6,715) at April 30, 2007 (unaudited).
Interest on the Due to Affiliates and Affiliate Cash Pool balances are based on applicable federal rates in effect each month and the weighted average rates were 4.25%, 2.83% and 1.44% for the years ended July 31, 2006, 2005 and 2004, respectively and 3.66% and 3.17% for the nine month periods ended April 30, 2007 and 2006, respectively (unaudited). Interest expense for the years ended July 31, 2006, 2005 and 2004 was $844, $573 and $148, respectively and $1,183 and $594 for the nine month periods ended April 30, 2007 and 2006, respectively (unaudited).
6. Income Taxes
Pretax Income and Income Tax Expense. The table below shows the Company’s components of income tax expense for each of the three years ended July 31:
2006 | 2005 | 2004 | |||||||||
Income Tax Expense | |||||||||||
Current | |||||||||||
Federal | $ | 1,148 | $ | (2,565 | ) | $ | (205 | ) | |||
State | — | — | — | ||||||||
Total Current | 1,148 | (2,565 | ) | (205 | ) | ||||||
Deferred | |||||||||||
Federal | 4,458 | 5,402 | 1,508 | ||||||||
State | 754 | 8 | — | ||||||||
Total Deferred | 5,212 | 5,410 | 1,508 | ||||||||
Total Income Tax Expense | $ | 6,360 | $ | 2,845 | $ | 1,303 | |||||
Effective Tax Rate Reconciliation. The Company’s income taxes, included in net income, differ from the amount computed by applying the statutory federal income tax rate of 35 percent for the following reasons for each of the three years ended July 31:
2006 | 2005 | 2004 | ||||||||||
Income tax at federal rate of 35% | $ | 5,976 | $ | 3,288 | $ | 1,604 | ||||||
State income tax, net of federal benefit | 754 | 209 | 108 | |||||||||
Change in valuation allowance | — | (201 | ) | (108 | ) | |||||||
Percentage depletion in excess of cost | (531 | ) | (379 | ) | (296 | ) | ||||||
Other, net | 161 | (72 | ) | (5 | ) | |||||||
Total tax expense | $ | 6,360 | $ | 2,845 | $ | 1,303 | ||||||
Effective tax rate | 37.3 | % | 30.3 | % | 28.4 | % | ||||||
Deferred Tax Assets and Liabilities. The following are the components of the Company’s deferred tax assets and liabilities as of July 31:
2006 | 2005 | |||||
Deferred Tax Liabilities | ||||||
Fixed assets | $ | 8,412 | $ | 5,653 | ||
Mineral reserves and intangible drilling costs | 11,497 | 8,904 | ||||
Total Deferred Tax Liabilities | $ | 19,909 | $ | 14,557 | ||
Deferred Tax Assets | ||||||
Accrued derivative liability | $ | — | $ | 58 | ||
Accrued stock compensation | 119 | — | ||||
Oklahoma net operating loss carryforward | 1,554 | 1,469 | ||||
Other, net | 3 | 9 | ||||
Total Deferred Tax Assets | $ | 1,676 | $ | 1,536 | ||
Net operating loss and tax carryovers. The Company has an Oklahoma state net operating loss carryforward of $38,880 which expires July 31, 2016 through July 31, 2027.
Valuation Allowances. Deferred tax assets are recorded on net operating losses and temporary differences in the book and tax basis of assets and liabilities expected to produce tax deductions in future periods. The realization of these assets depends on recognition of sufficient future taxable income in specific tax jurisdictions during periods in which those temporary differences or net operating losses are deductible. In assessing the need for a valuation allowance on deferred tax assets, the Company considers whether it is more likely than not that some portion or all of them will not be realized. As part of the assessment, the Company considers future reversals of existing taxable temporary differences, primarily related to depreciation. The Company believes it is more likely than not that it will realize the benefit of the deferred tax assets at July 31, 2006 and 2005.
7. Commitments and Contingencies
Legal Proceedings
The Company and its subsidiaries can be named defendants in numerous lawsuits and governmental proceedings that arise in the ordinary course of business. For each legal proceeding and other contingent matters, the Company evaluates the merits of the case, its exposure, possible legal or settlement strategies and the likelihood of an
unfavorable outcome. If the Company determines that an unfavorable outcome is probable and can be estimated, it establishes the necessary accruals. As of July 31, 2006 and 2005, the Company had no outstanding legal and other contingent matters.
Other Commercial Commitments
At July 31, 2006, the Company had various commercial commitments primarily related to commitments associated with drilling and gas gathering activities in Oklahoma. The Company is party to two two-year compressor operating lease contracts with annual payments amounting to $285 in 2007 and $261 in 2008.
In connection with the concession agreement with the Osage Nation, the Company is obligated to drill or earn 440 wells by December 31, 2008 to continue earning acreage and to perpetuate the concession. As of July 31, 2006, the Company has drilled or earned 320 wells toward this commitment. The agreement further provides three additional four-year phases commencing on January 1, 2009 and extending through December 31, 2020 in which the Company is obligated to drill 240 wells per phase to continue earning acreage and perpetuating the concession.
In connection with a gas purchase agreement, the Company is obligated to throughput commitments of 2.6 BCF of natural gas per year during the two year term, beginning January 1, 2006.
8. Cash Flow Information
During the year ended July 31, 2006, the Company paid a dividend of $4,000 that was settled through Due to Affiliates. In addition, the Company recognized $307 in expense for year ended July 31, 2006 and $460 and $188 for the nine month periods ended April 30, 2007 and 2006, respectively (unaudited), associated with AMVEST Corporation’s stock appreciation rights program that was treated as an equity contribution.
Accounts payable includes amounts related to purchases of property and equipment in the amount of $1,393, $846, and $863 for the years ended July 31, 2006, 2005, and 2004, respectively and $1,297 and $999 for the nine month periods ended April 30, 2007 and 2006 (unaudited).
The Company incurred reclamation obligations of $227, $126 and $78 during the years ended July 31, 2006, 2005, and 2004, respectively, and $71 and $59 for the nine months ended April 30, 2007 and 2006, respectively (unaudited). Corresponding increases were recognized in oil and gas properties.
9. Other Information
Information About Major Customers.The Company has transactions with two major customers that amounted to approximately 94%, 82%, and 79%, of the Company’s revenues for the years ended July 31, 2006, 2005 and 2004, respectively. Accounts receivables due from these customers were $4,495 and $2,905 at July 31, 2006 and 2005, respectively.
10. Subsequent Events
In June 2007, the Company’s Due to Affiliates and Affiliate Cash Pool balances were settled with a corresponding increase in Additional Paid-In Capital.
In July 2007, the Company was purchased by Constellation Energy Partners LLC.
11. Supplemental Oil and Gas Disclosures – Unaudited
The Company is engaged in the exploration for, and the acquisition, development and production of oil and natural gas in the Cherokee Basin of Oklahoma.
Capitalized Costs. Capitalized costs relating to oil and gas producing activities and related accumulated depreciation, depletion and amortization were as follows at July 31:
2006 | 2005 | 2004 | ||||||||||
Property Costs | ||||||||||||
Proved | $ | 96,350 | $ | 75,724 | $ | 50,921 | ||||||
Unproved | 1,633 | 576 | 1,509 | |||||||||
Total property costs | 97,983 | 76,300 | 52,430 | |||||||||
Other | 6,307 | 3,926 | 2,843 | |||||||||
Less: accumulated depreciation, depletion and amortization | (18,965 | ) | (11,767 | ) | (6,604 | ) | ||||||
TOTAL OIL AND GAS PROPERTIES AND EQUIPMENT, NET | $ | 85,325 | $ | 68,459 | $ | 48,669 | ||||||
Total Costs Incurred.Costs incurred in oil and gas producing activities were as follows for each of the years ended July 31:
2006 | 2005 | 2004 | |||||||
Property acquisition costs | |||||||||
Proved | $ | 4,460 | $ | 414 | $ | 97 | |||
Unproved | 1,323 | 186 | 255 | ||||||
Total property acquisition costs | 5,783 | 600 | 352 | ||||||
Exploration costs | 459 | 243 | 255 | ||||||
Development costs | 21,434 | 23,312 | 15,541 | ||||||
Other | 2,826 | 1,367 | 1,072 | ||||||
TOTAL COST INCURRED | $ | 30,502 | $ | 25,522 | $ | 17,220 | |||
Oil and Gas Reserves. Net quantities of proved developed and undeveloped reserves of natural gas and oil, and changes in these reserves at July 31, 2006, 2005, and 2004 are presented below. Net proved reserves exclude royalties and interests owned by others and reflect contractual arrangements and royalty obligations in effect at the time of the estimate.
Natural Gas (MMCF) | Oil (MMBBL) | Equivalents (MMCFE) | |||||||
July 31, 2003 | 88,406 | 27 | 88,571 | ||||||
Extensions and discoveries | |||||||||
Purchases of reserves in place | |||||||||
Sales of reserves in place | |||||||||
Revisions of previous estimates | (16,717 | ) | 95 | (16,149 | ) | ||||
Production | (3,025 | ) | (19 | ) | (3,140 | ) | |||
July 31, 2004 | 68,664 | 103 | 69,282 | ||||||
Extensions and discoveries | 14,354 | 5 | 14,384 | ||||||
Purchases of reserves in place | 1,831 | 1,831 | |||||||
Sales of reserves in place | |||||||||
Revisions of previous estimates | 713 | 149 | 1,609 | ||||||
Production | (4,027 | ) | (31 | ) | (4,212 | ) | |||
July 31, 2005 | 81,535 | 226 | 82,894 | ||||||
Extensions and discoveries | 12,955 | 12,955 | |||||||
Purchases of reserves in place | 3,665 | 3,665 | |||||||
Sales of reserves in place | (2,040 | ) | (2,040 | ) | |||||
Revisions of previous estimates | (18,688 | ) | 25 | (18,535 | ) | ||||
Production | (5,000 | ) | (25 | ) | (5,159 | ) | |||
July 31, 2006 | 72,427 | 226 | 73,780 | ||||||
Total developed reserves - 2004 | 40,127 | 103 | 40,745 | ||||||
Total developed reserves - 2005 | 47,378 | 226 | 48,737 | ||||||
Total developed reserves - 2006 | 46,539 | 226 | 47,892 | ||||||
There are numerous uncertainties inherent in estimating quantities of proved reserves, projecting future rates of production and projecting the timing of development expenditures, including many factors beyond the Company’s control. The reserve data represents only estimates. Reservoir engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretations and judgment. All estimates of proved reserves are determined according to the rules prescribed by the SEC. These rules indicate that the standard of “reasonable certainty” be applied to proved reserve estimates. This concept of reasonable certainty implies that as more technical data becomes available, a positive, or upward, revision is more likely than a negative, or downward, revision. Estimates are subject to revision based upon a number of factors, including reservoir performance, prices, economic conditions and government restrictions. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of that estimate. Reserve estimates are often different from the quantities of oil and gas that are ultimately recovered. The meaningfulness of reserve estimates is highly dependent on the accuracy of the assumptions on which they were based. In general, the volume of production from oil and gas properties the Company owns decline as reserves are depleted. Except to the extent the Company conducts successful exploration and development activities or acquires additional properties containing proved reserves, or both, the Company’s proved reserves will decline as reserves are produced. There have been no major discoveries or other events, favorable or adverse, that may be considered to have caused a significant change in the estimated proved reserves since July 31, 2006.
Standardized Measure of Discounted Future Net Cash Flows. The standardized measure of discounted future net cash flows relating to proved oil and gas reserves at July 31:
2006 | 2005 | 2004 | ||||||||||
Future cash inflows | $ | 484,781 | $ | 597,542 | $ | 394,760 | ||||||
Future production costs | (185,115 | ) | (193,694 | ) | (132,294 | ) | ||||||
Future development costs | (40,742 | ) | (45,375 | ) | (38,845 | ) | ||||||
Future income tax expenses | (83,266 | ) | (97,706 | ) | (54,780 | ) | ||||||
Future net cash flows | 175,658 | 260,767 | 168,841 | |||||||||
10% annual discount for estimated timing of cash flows | (72,082 | ) | (109,856 | ) | (72,041 | ) | ||||||
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves | $ | 103,576 | $ | 150,911 | $ | 96,800 | ||||||
Changes in Standardized Measure of Discounted Future Net Cash Flows. The following are the principal sources of change in the standardized measure of discounted future net cash flows:
Standardized Measure as of July 31, 2003 | $ | 54,621 | ||
Sales and transfers of oil and gas produced, net of production costs | (9,611 | ) | ||
Net changes in prices and production costs | 70,906 | |||
Extensions and discoveries, less related costs | — | |||
Previously estimated development costs incurred during the period | 17,670 | |||
Revisions of previous quantity estimates | (29,984 | ) | ||
Purchases and sales of mineral interests | — | |||
Accretion of discount | 7,256 | |||
Net change in income taxes | (14,058 | ) | ||
Other | — | |||
Standardized Measure as of July 31, 2004 | 96,800 | |||
Sales and transfers of oil and gas produced, net of production costs | (19,815 | ) | ||
Net changes in prices and production costs | 41,671 | |||
Extensions and discoveries, less related costs | 21,297 | |||
Previously estimated development costs incurred during the period | 10,668 | |||
Revisions of previous quantity estimates | 11,586 | |||
Purchases and sales of mineral Interests | 1,313 | |||
Accretion of discount | 12,879 | |||
Net change in income taxes | (25,488 | ) | ||
Other | — | |||
Standardized Measure as of July 31, 2005 | 150,911 | |||
Sales and transfers of oil and gas produced, net of production costs | (30,123 | ) | ||
Net changes in prices and production costs | (40,285 | ) | ||
Extensions and discoveries, less related costs | 18,700 | |||
Previously estimated development costs incurred during the period | 14,469 | |||
Revisions of previous quantity estimates | (39,990 | ) | ||
Purchases and sales of mineral Interests | 2,189 | |||
Accretion of discount | 20,839 | |||
Net change in income taxes | 6,866 | |||
Other | — | |||
Standardized Measure as of July 31, 2006 | $ | 103,576 | ||