| | |
1 | | Operating expenses, including production tax |
|
2 | | Averages calculated based upon non-rounded figures |
|
3 | | Per equivalent barrel (6 Mcf of gas is equivalent to 1 barrel of oil) |
|
4 | | Excluding impairment expense related to full cost pool ceiling limitation |
Critical Accounting Policies and Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect the actual amounts of assets and liabilities at the date of the financial statements and the actual amounts of revenues and expenses during the reporting period. We base these estimates on assumptions that we understand are reasonable under the circumstances. The estimated results that are produced by this effort will differ under different assumptions or conditions. We understand that these estimates are necessary and that actual results could vary significantly from the estimated amounts for the current and future periods. We understand the following accounting policies and estimates are necessary in the preparation of our consolidated financial statements: the carrying value of our oil and gas property, the accounting for oil and gas reserves, the estimate of our asset retirement obligations and the estimate of our income tax assets and liabilities.
Oil and Gas Property. We utilize the full cost method of accounting for costs related to our oil and gas property. Capitalized costs included in the full cost pool are depleted on an aggregate basis over the estimated lives of the properties using the units-of-production method. These capitalized costs are subject to a ceiling test that limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil and gas reserves discounted at 10 percent plus the lower of cost or market value of unproved properties less any associated tax effects. If the full cost pool of capitalized oil and gas property costs exceeds the ceiling, we will record a ceiling test write-down to the extent of such excess. This write-down is a non-cash charge to earnings. If required, it reduces earnings and impacts shareholders’ equity in the period of occurrence and may result in lower depreciation and depletion in future periods. The write-down can notcannot be reversed in future periods, even though higher oil and gas prices may subsequently increase the ceiling.
Oil and Gas Reserves. The determination of depreciation and depletion expense as well as ceiling test write-downs related to the recorded value of our oil and gas properties are highly dependent on the estimates of the proved oil and gas reserves attributable to these properties. Oil and gas reserves include proved reserves that represent estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. There are numerous uncertainties inherent in estimating oil and gas reserves and their values, including many factors beyond our control. Accordingly, reserve estimates are often different from the quantities of oil and gas ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves. Ninety-eightNinety-three percent of our reported oil and gas reserves at March 31, 20092010 are based on estimates prepared by an independent petroleum engineering firm. The remaining twoseven percent of our oil and gas reserves were prepared in-house. See also Note 12 to the Consolidated Financial Statements.
17
Asset Retirement Obligations. We have significant obligations related to the plugging and abandonment of our oil and gas wells, the removal of equipment and facilities and returning the land to its original condition. SFAS No. 143, “AccountingAs we account for Asset Retirement Obligations” requires thatasset retirement obligations we are required to estimate the future cost of this obligation, discount this cost to its present value, and record a corresponding asset and liability in itsour Consolidated Balance Sheets. The values ultimately derived are based on many significant estimates, including the ultimate expected cost of the obligation, the expected future date of the required cash expenditures and inflation rates. The nature of these estimates requires management to make judgments based on historical experience and future expectations related to timing. We review the estimate of our future asset retirement obligations quarterly. These quarterly reviews may require revisions to these estimates based on such things as changes to cost estimates or the timing of future cash outlays. Any such changes that result in upward or downward revisions in the estimated obligation will result in an adjustment to the related capitalized asset and corresponding liability on a prospective basis. See also Note 5 to the Consolidated Financial Statements.
Off Balance Sheet Transactions, Arrangements or Obligations
We have no significant off balance sheet transactions, arrangements or obligations.
Recent Accounting Pronouncements
There have been several recent accounting pronouncements, but none are expected to have a material effect on our financial position, results of operations, or cash flows. For more information, see Note 1 —– “Recent Accounting Pronouncements” in the Notes to Consolidated Financial Statements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK
Smaller reporting companies are not required to provide the information required by this Item.
18
ITEM 8
FINANCIAL STATEMENTS23
Basic Earth Science Systems, Inc.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Earthstone Energy, Inc.
Table of Contents
Consolidated Financial Statements
and Accompanying Notes
March 31, 20092010 and 20082009
| | | | | |
| | Page | |
| | | 20 | |
| | | | 25 |
| | | 21 | |
| | | | |
| | | 22–23 | |
| | | | 26-27 |
| | | 24 | |
| | | | 28 |
| | | 25 | |
| | | | 29 |
| | | 26 | |
| | | | 30 |
| | | 27–40 | |
| | | | 31-43 |
19
Board of Directors and Shareholders
Basic Earth Science Systems,
Earthstone Energy, Inc.
Denver, Colorado
We have audited the accompanying consolidated balance sheetsheets of Basic Earth Science Systems,Earthstone Energy, Inc. and Subsidiaries (the “Company”) as of March 31, 2010 and 2009, and the related statements of operations, shareholders’ equity, and cash flows for the year thenyears ended March 31, 2010 and 2009. 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 audit.audits.
We conducted our auditaudits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included 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 audit providesaudits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Basic Earth Science Systems,Earthstone Energy, Inc. as of March 31, 2010 and 2009, and the results of itstheir operations and itstheir cash flows for the yearyears ended March 31, 2010 and 2009 in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 1 to the financial statements, as of March 31, 2010, the Company has changed its method of determining quantities of oil and gas reserves which impacted the amount recorded for depreciation and depletion for oil and gas properties.
Ehrhardt Keefe Steiner & Hottman PC
Denver, Colorado
June 17, 200918, 2010
20
REPORT OF PRIOR INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM25
To the Board
We have audited the consolidated balance sheet of Basic Earth Science Systems, Inc. and subsidiaries, (the “Company”) as of March 31, 2008, and the related consolidated statements of operations, shareholders’ equity and cash flows for the year then ended. 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 audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Basic Earth Science Systems, Inc. and subsidiaries as of March 31, 2008 and the results of their operations and their cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.
HEIN& ASSOCIATES LLP
Denver, Colorado
July 11, 2008
21
Basic Earth Science Systems, Inc.
Consolidated Balance Sheets
| | | | | | | | | | |
| | | March 31, | | March 31, | | |
| | | 2009 | | 2008 | | | March 31, | | March 31, | |
| | | | 2010 | | 2009 | |
Assets | | | | | | |
| Current assets: | | | | | | |
| Cash and cash equivalents | | $ | 4,088,000 | | $ | 5,571,000 | | | $ | 4,905,000 | | | $ | 4,088,000 | |
| Accounts receivable: | | | | | | |
| Oil and gas sales | | 1,611,000 | | 1,110,000 | | | | 1,021,000 | | | | 1,611,000 | |
| Joint interest and other receivables, net of $71,000 and $50,000 in allowance, respectively | | 230,000 | | 236,000 | | |
Joint interest and other receivables, net of $86,000 and $71,000 in allowance for bad debt, respectively | | | | 401,000 | | | | 230,000 | |
| Other current assets | | 508,000 | | 280,000 | | | | 732,000 | | | | 508,000 | |
| | | | | | | |
| | | | | | | |
| Total current assets | | 6,437,000 | | 7,197,000 | | | | 7,059,000 | | | | 6,437,000 | |
| | | | | | | |
| Oil and gas property, full cost method: | | | | | | |
| Proved property | | 32,187,000 | | 29,050,000 | | | | 33,915,000 | | | | 32,187,000 | |
| Unproved property | | 1,077,000 | | 2,515,000 | | | | 1,555,000 | | | | 1,077,000 | |
| Accumulated depletion and impairment | | | (22,397,000 | ) | | | (18,515,000 | ) | | | (23,582,000 | ) | | | (22,397,000 | ) |
| | | | | | | | | | | |
| | | |
| Net oil and gas property | | 10,867,000 | | 13,050,000 | | | | 11,888,000 | | | | 10,867,000 | |
| | | | | | | | | | | |
| | | |
| Support equipment and other non-current assets, net of $337,000 and $299,000 in accumulated depreciation, respectively | | 458,000 | | 443,000 | | |
| | | | | | | |
Support equipment and other non-current assets, net of $374,000 and $337,000 in accumulated depreciation, respectively | | | | 451,000 | | | | 458,000 | |
| | | | | | | |
| Total non-current assets | | 11,325,000 | | 13,493,000 | | | | 12,339,000 | | | | 11,325,000 | |
| | | | | | | |
Total assets | | $ | 17,762,000 | | $ | 20,690,000 | | | $ | 19,398,000 | | | $ | 17,762,000 | |
| | | | | | | |
See accompanying notes to consolidated financial statements.
22
Basic Earth Science Systems,Earthstone Energy, Inc.
Consolidated Balance Sheets
| | | | | | | | | | | March 31, | | March 31, | |
| | | March 31, | | March 31, | | | 2010 | | 2009 | |
| | | 2009 | | 2008 | | |
| | | |
Liabilities and Shareholders’ Equity | | |
| Liabilities and Shareholders' Equity | | | | | | |
| Current liabilities: | | | | | | |
| Accounts payable | | $ | 64,000 | | $ | 1,443,000 | | | $ | 161,000 | | | $ | 64,000 | |
| Accrued liabilities | | 1,328,000 | | 2,586,000 | | | | 1,836,000 | | | | 1,328,000 | |
| | | | | | | |
| | | | | | | |
| Total current liabilities | | 1,392,000 | | 4,029,000 | | | | 1,997,000 | | | | 1,392,000 | |
| | | | | | | |
| Long-term liabilities: | | | | | | |
| Deferred tax liability | | 2,242,000 | | 2,800,000 | | | | 2,217,000 | | | | 2,242,000 | |
| Asset retirement obligation | | 1,558,000 | | 1,877,000 | | | | 1,674,000 | | | | 1,558,000 | |
| | | | | | | | | | | |
| | | |
| Total long-term liabilities | | 3,800,000 | | 4,677,000 | | | | 3,891,000 | | | | 3,800,000 | |
| | | | | | | |
| Total liabilities | | 5,192,000 | | 8,706,000 | | | | 5,888,000 | | | | 5,192,000 | |
| | | | | | | | | | | |
| | | |
| Commitments (Note 7) | | |
| Commitments | | | | | | |
| | | | | | | |
| Shareholders’ Equity: | | | | | | |
| Preferred stock, $.001 par value, 3,000,000 authorized, and none issued or outstanding | | — | | — | | |
| Common stock, $.001 par value, 32,000,000 shares authorized, and 17,506,000 and 17,466,000 shares issued and outstanding, respectively | | 18,000 | | 17,000 | | |
| Preferred stock, $.001 par value, 3,000,000 authorized and none issued or outstanding | | | | — | | | | — | |
Common stock, $.001 par value, 32,000,000 shares authorized and 17,704,000 and 17,506,000 shares issued and outstanding, respectively | | | | 18,000 | | | | 18,000 | |
| Additional paid-in capital | | 22,825,000 | | 22,798,000 | | | | 22,945,000 | | | | 22,825,000 | |
| Treasury stock (380,000 shares); at cost | | | (43,000 | ) | | | (23,000 | ) | |
| Treasury stock (646,000 and 380,000 shares respectively) at cost | | | | (251,000 | ) | | | (43,000 | ) |
| Accumulated deficit | | | (10,230,000 | ) | | | (10,808,000 | ) | | | (9,202,000 | ) | | | (10,230,000 | ) |
| | | | | | | |
| | | | | | | |
| Total shareholders’ equity | | 12,570,000 | | 11,984,000 | | | | 13,510,000 | | | | 12,570,000 | |
| | | | | | | |
Total liabilities and shareholders’ equity | | $ | 17,762,000 | | $ | 20,690,000 | | | $ | 19,398,000 | | | $ | 17,762,000 | |
| | | | | | | |
See accompanying notes to consolidated financial statements.
23
Basic Earth Science Systems,
Consolidated Statements of Operations
| | | | | | | | | | |
| | | Years Ended | | | Year Ended | |
| | | March 31, | | | | March 31, | |
| | | 2009 | | 2008 | | | | 2010 | | | 2009 | |
| | | | | | | |
Revenues: | | | | | | |
| Oil and gas sales | | $ | 8,991,000 | | $ | 7,415,000 | | | $ | 7,219,000 | | $ | 8,991,000 | |
| Well service and water disposal revenue | | 95,000 | | 32,000 | | | | 50,000 | | | 95,000 | |
| | | | | | | | | | | |
| | | |
| Total revenues | | 9,086,000 | | 7,447,000 | | | | 7,269,000 | | | 9,086,000 | |
| | | | | | | |
| | | | | | | |
Expenses: | | | | | | |
| Oil and gas production | | 2,539,000 | | 2,085,000 | | | 2,437,000 | | 2,539,000 | |
| Production tax | | 644,000 | | 621,000 | | | 498,000 | | 644,000 | |
| Well servicing expenses | | 33,000 | | 27,000 | | | 43,000 | | 33,000 | |
| Depreciation and depletion | | 1,224,000 | | 685,000 | | | 1,221,000 | | 1,224,000 | |
| Accretion of asset retirement obligation | | 98,000 | | 114,000 | | | 166,000 | | 98,000 | |
| Asset retirement expense | | 164,000 | | 35,000 | | | 7,000 | | 164,000 | |
| Impairment of oil and gas property | | 2,694,000 | | — | | |
| Impairment of oil and gas properties | | | ― | | 2,694,000 | |
| General and administrative | | 1,347,000 | | 716,000 | | | | 1,779,000 | | | 1,347,000 | |
| | | | | | | |
| | | | | | | |
| Total expenses | | 8,743,000 | | 4,283,000 | | | | 6,151,000 | | | 8,743,000 | |
| | | | | | | | | | | |
| | | |
| Income from operations | | 343,000 | | 3,164,000 | | | | 1,118,000 | | | 343,000 | |
| | | | | | | |
| | | | | | | |
Other Income (Expense): | | | | | | |
| Interest and other income | | 57,000 | | 152,000 | | | 90,000 | | 57,000 | |
| Interest and other expenses | | | (34,000 | ) | | | (28,000 | ) | | | (32,000) | | | (34,000) | |
| | | | | | | | | | | |
| | | |
| Total other income | | 23,000 | | 124,000 | | | | 58,000 | | | 23,000 | |
| | | | | | | |
| | | | | | | |
| Income before income taxes | | 366,000 | | 3,288,000 | | | | 1,176,000 | | | 366,000 | |
| | | | | | | | | | | |
| Current income tax expense | | | 172,000 | | 346,000 | |
| Deferred income taxes (benefit) | | | | (24,000) | | | (558,000) | |
| | | | | | | |
| Current income tax expense | | 346,000 | | 179,000 | | |
| Provision for deferred income tax (benefit) expense | | | (558,000 | ) | | 1,346,000 | | |
| | | | | | | |
| | | |
| Total income tax (benefit) expense | | | (212,000 | ) | | 1,525,000 | | |
| | | | | | | |
| Total income tax expense (benefit) | | | | 148,000 | | | (212,000) | |
| | | | | | | |
Net income | | $ | 578,000 | | $ | 1,763,000 | | | $ | 1,028,000 | | $ | 578,000 | |
| | | | | | | | | | | |
| | | |
Per share amounts: | | | | | | |
| Basic | | $ | 0.03 | | $ | 0.10 | | | $ | 0.06 | | $ | 0.03 | |
| | | | | | | |
| Diluted | | $ | 0.03 | | $ | 0.10 | | | $ | 0.06 | | $ | 0.03 | |
| | | | | | | |
| | | | | | | |
| Weighted average common shares outstanding: | | | | | | |
| Basic | | 17,477,216 | | 17,370,256 | | | | 17,073,526 | | | 17,105,352 | |
| | | | | | | |
| Diluted | | 17,477,216 | | 17,480,671 | | | | 17,073,526 | | | 17,105,352 | |
| | | | | | | |
See accompanying notes to consolidated financial statements.
24
Basic Earth Science Systems,
Consolidated Statements of Shareholders’ Equity
Years Ended March 31, 20092010 and 20082009
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Additional | | | | | | | | | |
| | | Additional | | | | | | | | | Common stock | | paid-in | | Treasury stock | | Accumulated | | | |
| | | Common stock | | paid-in | | Treasury stock | | Accumulated | | | | | Shares | | Amount | | capital | | Shares | | Amount | | deficit | | Total | |
| | | Shares | | Par value | | capital | | Shares | | Amount | | deficit | | Total | | | | | | | | | | | | | | | | |
| | | |
Balance, March 31, 2007 | | 17,301,000 | | $ | 17,000 | | $ | 22,749,000 | | | (349,000 | ) | | $ | (23,000 | ) | | $ | (12,571,000 | ) | | $ | 10,172,000 | | |
| | | | | | | | | | | | | | | | | |
| March 31, 2008 | | | | 17,466,000 | | $ | 17,000 | | $ | 22,798,000 | | | (349,000) | | $ | (23,000) | | $ | (10,808,000) | | $ | 11,984,000 | |
| | | | | | | | | | | | | | | | | |
| Purchase of treasury shares | | — | | — | | — | | — | | — | | — | | — | | | — | | — | | — | | (31,000) | | (20,000) | | — | | (20,000) | |
| Shares issued to independent directors | | | 15,000 | | — | | 24,000 | | — | | — | | — | | 24,000 | |
| Stock options exercised | | 165,000 | | — | | 49,000 | | — | | — | | — | | 49,000 | | | 25,000 | | 1,000 | | 3,000 | | — | | — | | — | | 4,000 | |
| Net income | | — | | — | | — | | — | | — | | 1,763,000 | | 1,763,000 | | | | — | | | — | | | — | | | — | | | — | | | 578,000 | | | 578,000 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | |
Balance, March 31, 2008 | | 17,466,000 | | $ | 17,000 | | $ | 22,798,000 | | | (349,000 | ) | | $ | (23,000 | ) | | $ | (10,808,000 | ) | | $ | 11,984,000 | | |
| | | | | | | | | | | | | | | | | |
| March 31, 2009 | | | | 17,506,000 | | $ | 18,000 | | $ | 22,825,000 | | | (380,000) | | $ | (43,000) | | $ | (10,230,000) | | $ | 12,570,000 | |
| | | | | | | | | | | | | | | | | |
| Purchase of treasury shares | | — | | — | | — | | | (31,000 | ) | | | (20,000 | ) | | — | | | (20,000 | ) | | — | | — | | — | | (266,000) | | (208,000) | | — | | (208,000) | |
| Shares issued to independent board members | | 15,000 | | — | | 24,000 | | — | | — | | — | | 24,000 | | |
| Stock options exercised | | 25,000 | | 1,000 | | 3,000 | | — | | — | | — | | 4,000 | | |
| Shares issued to independent directors | | | 192,000 | | — | | 120,000 | | — | | — | | — | | 120,000 | |
| Shares issued to employees | | | 6,000 | | — | | — | | — | | — | | — | | — | |
| Net income | | — | | — | | — | | — | | — | | 578,000 | | 578,000 | | | | — | | | — | | | — | | | — | | | — | | | 1,028,000 | | | 1,028,000 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | |
Balance, March 31, 2009 | | 17,506,000 | | $ | 18,000 | | $ | 22,825,000 | | | (380,000 | ) | | $ | (43,000 | ) | | $ | (10,230,000 | ) | | $ | 12,570,000 | | |
| | | | | | | | | | | | | | | | | |
| March 31, 2010 | | | | 17,704,000 | | $ | 18,000 | | $ | 22,945,000 | | | (646,000) | | $ | (251,000) | | $ | (9,202,000) | | $ | 13,510,000 | |
See accompanying notes to consolidated financial statements.
25
Basic Earth Science Systems,
Consolidated Statements of Cash Flows
| | | | | | | | | | |
| | | Years Ended | | | Year Ended | |
| | | March 31, | | | | March 31, | |
| | | 2009 | | 2008 | | | | 2010 | | | 2009 | |
| | | | | | | |
Cash flows from operating activities: | | | | | | |
| Net income | | $ | 578,000 | | $ | 1,763,000 | | | $ | 1,028,000 | | $ | 578,000 | |
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | |
| Depreciation and depletion | | 1,224,000 | | 685,000 | | | 1,221,000 | | 1,224,000 | |
| Deferred tax liability | | | (558,000 | ) | | 1,311,000 | | | (24,000) | | (558,000) | |
| Additional paid-in capital associated with deferred tax expense | | — | | 35,000 | | |
| Accretion of asset retirement obligation | | 98,000 | | 114,000 | | | 166,000 | | 98,000 | |
| Share based compensation | | 24,000 | | — | | | 72,000 | | 24,000 | |
| Impairment of Oil and Gas Properties | | 2,694,000 | | — | | |
| Impairment of oil and gas properties | | | ― | | 2,694,000 | |
| Change in: | | | | | | |
| Accounts receivable, net | | | (495,000 | ) | | | (85,000 | ) | | 419,000 | | (495,000) | |
| Other assets | | | (287,000 | ) | | | (63,000 | ) | | (224,000) | | (287,000) | |
| Accounts payable and accrued liabilities | | | (406,000 | ) | | | (158,000 | ) | | | 8,000 | | | (406,000) | |
| Other | | — | | 7,000 | | |
| | | | | | | |
| | | | | | | |
Net cash provided by operating activities | | 2,872,000 | | 3,609,000 | | | | 2,666,000 | | | 2,872,000 | |
| | | | | | | |
| | | | | | | |
Cash flows from investing activities: | | | | | | |
| Oil and gas property | | | (4,338,000 | ) | | | (587,000 | ) | | (1,612,000) | | (4,338,000) | |
| Support equipment | | — | | | (16,000 | ) | | | (29,000) | | | ― | |
| Insurance settlements | | — | | 66,000 | | |
| Proceeds from sale of oil and gas property and equipment | | — | | 14,000 | | |
| Other | | — | | | (52,000 | ) | |
| | | | | | | |
| | | | | | | |
Net cash used in investing activities | | | (4,338,000 | ) | | | (575,000 | ) | | | (1,641,000) | | | (4,338,000) | |
| | | | | | | |
| | | | | | | |
Cash flows from financing activities: | | | | | | |
| Proceeds from exercise of common stock options | | 3,000 | | 14,000 | | | ― | | 3,000 | |
| Purchase of treasury shares | | | (20,000 | ) | | — | | | | (208,000) | | | (20,000) | |
| | | | | | | | | | | |
| | | |
Net cash (used in) provided by financing activities | | | (17,000 | ) | | 14,000 | | |
| | | | | | | |
| Net cash used in financing activities | | | | (208,000) | | | (17,000) | |
| | | | | | | |
Cash and cash equivalents: | | | | | | |
| (Decrease) increase in cash and cash equivalents | | | (1,483,000 | ) | | 3,048,000 | | |
| Increase (decrease) in cash and cash equivalents | | | | 817,000 | | | (1,483,000) | |
| Balance, beginning of year | | 5,571,000 | | 2,523,000 | | | | 4,088,000 | | | 5,571,000 | |
| | | | | | | |
| | | | | | | |
Balance, end of period | | $ | 4,088,000 | | $ | 5,571,000 | | | $ | 4,905,000 | | $ | 4,088,000 | |
| | | | | | | | | | | |
| | | |
Supplemental disclosure of cash flow information: | | | | | | |
| Cash paid for interest | | $ | 10,000 | | $ | 28,000 | | | $ | 17,000 | | $ | 10,000 | |
| | | | | | | |
| Cash paid for income tax | | $ | 517,000 | | $ | 171,000 | | | $ | 6,500 | | $ | 517,000 | |
| | | | | | | |
| | | |
| Non-cash: | | | | | | |
| Increase in oil and gas property due to asset retirement obligation | | $ | 33,000 | | $ | 210,000 | | | $ | 54,000 | | $ | 33,000 | |
| | | | | | | |
| Vested shares issued as compensation | | | $ | 48,000 | | $ | 24,000 | |
| Additions to oil and gas also included in accrued liabilities | | $ | 43,000 | | $ | 2,273,000 | | | $ | 687,000 | | $ | 43,000 | |
| | | | | | | |
See accompanying notes to consolidated financial statements.
26
Basic Earth Science Systems,
Notes to Consolidated Financial Statements
1. Summary of Significant Accounting Policies
Organization and Nature of Operations. Basic Earth Science Systems,Earthstone Energy, Inc. (“Basic”Earthstone” or “the Company” or “we” or “our” or “us”), was originally organized in July 1969 and had its first public offeringas Basic Earth Science Systems, Inc. We changed our name in 1980.2010 to Earthstone Energy, Inc. We are principally engaged in the acquisition, exploitation, development, operation and production of crude oil and natural gas. Our primary areas of operation are the Williston basin in North Dakota and Montana, south Texas and the Denver-Julesburg basin in Colorado.
Principles of Consolidation. The consolidated financial statements include our accounts and those of our wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated.
Oil and Gas Sales. We derive revenue primarily from the sale of produced natural gas and crude oil. We report revenue on a gross basis for the amounts received before taking into account production taxes and transportation costs, which are reported as separate expenses. Revenue is recorded using the sales method, which occurs in the month production is delivered to the purchaser, at which time title changes hands. Payment is generally received between 30 and 90 days after the date of production. We make estimates of the amount of production delivered to purchasers and the prices we will receive. We use our knowledge of our properties, their historical performance, the anticipated effect of weather conditions during the month of production, NYMEX and local spot market prices, and other factors as the basis for these estimates. Variances between estimates and the actual amounts received are recorded when payment is received, or when better information is available.
Oil and Gas Producing ActivityProperties. We follow the full cost method of accounting for our oil and gas activity. Accordingly, all costs associated with the acquisition, exploration and development of oil and gas properties are capitalized. These capitalized, with the exception of unproved properties which are periodically reviewed for impairment by reviewing the status of the activity on those properties and surrounding properties either held by us or other parties. Capitalized costs are subject to a ceiling test that limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil and gas reserves using current pricesthe 12 month average price of oil and gas on the first day of each month and costs discounted at 10 percent plus the lower of cost or fair value of unproved properties less any associated tax effects. If the full cost pool of capitalized oil and gas property costs exceeds the ceiling, we will record a ceiling test write-down to the extent of such excess. This write-down is a non-cash charge to earnings. If required, it reduces earnings and impacts shareholders’ equity in the period of occurrence. The write-down may not be reversed in future periods, even though higher oil and gas prices in the future may subsequently and significantly increase reserve estimates in future periods. While we did not incur a ceiling limitation charge for the year ended March 31, 2008,2010, we incurred a ceiling test limitation charge in the amount of $2,694,000 during the year ended March 31, 2009, representing the excess of capitalized costs over the ceiling, as calculated in accordance with these full cost rules.
If a significant portion of our oil and gas reserves are sold, a gain or loss would be recognized; otherwise, proceeds from sales are applied as a reduction of oil and gas property. In 2008, we reduced the carrying value of our oil and gas property $14,000 as a result of the sale of our interest in certain oil and gas property and equipment. Also in 2008, we received insurance settlements of $66,000 related to blowout coverage. The carrying value of our oil and gas property was reduced by the $66,000 received from these settlements.
All capitalized costs are depleted on a composite units-of-production method based on estimated proved reserves attributable to the oil and gas properties we own. Depletion expense per equivalent barrel of production was $10.03$8.65 and $6.34$9.74 for 20092010 and 2008,2009, respectively.
Income Taxes. We account for income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes”FASB issued authoritative guidance which requires the use of the “liability method.” Accordingly, deferred tax liabilities and assets are determined based on the temporary differences between the financial statement and tax bases of assets and liabilities, using enacted tax rates in effect for the year in which the differences are expected to reverse. For further information, see Note 9 below.
27
Earnings Per Share. Our earnings per share is computed by dividing net income by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflects the potential dilution of securities, if any, that could share in the earnings of the Company and is calculated by dividing net income by the diluted weighted average number of common shares. The diluted weighted average number of common shares is computed using the treasury stock method for common stock that may be issued for outstanding stock options. The following is a reconciliation of basic and diluted earnings per share for 2009the years ended March 31, 2010 and 2008:2009:
| | | | | | | | | |
| | | Years Ended | |
| | | March 31, | |
| | | 2009 | | | 2008 | |
| Numerator: | | | | | | | | |
| Net income available to common shareholders | | $ | 578,000 | | | $ | 1,763,000 | |
| | | | | | | |
| | | | | | | | | |
| Denominator: | | | | | | | | |
| Denominator for basic earnings per share | | | 17,477,216 | | | | 17,370,256 | |
| | | | | | | |
| | | | | | | | | |
| Effect of dilutive securities: | | | | | | | | |
| Stock options | | | — | | | | 110,415 | |
| | | | | | | | | |
| Denominator for diluted earnings per share | | | 17,477,216 | | | | 17,480,671 | |
| | | | | | | |
All| | | | 2010 | | | | 2009 | |
| Numerator: | | | | | | | | |
| Net income available to common shareholders | | $ | 1,028,000 | | | $ | 578,000 | |
| | | | | | | | | |
| Denominator: | | | | | | | | |
| Denominator for basic earnings per share | | | 17,073,526 | | | | 17,105,352 | |
| Effect of dilutive securities: | | | | | | | | |
| Stock options | | | — | | | | — | |
| | | | | | | | | |
| Denominator for diluted earnings per share | | | 17,073,526 | | | | 17,105,352 | |
There were no options issued andor outstanding were included in the computation of diluted earnings per share for 2008, and were not applicable for2010 or 2009. See Note 8 below for further discussion of our stock options.
Cash and Cash Equivalents. For purposes of the Consolidated Balance Sheets and Statements of Cash Flows, we consider all highly liquid investments with a maturity of ninety days or less when purchased to be cash equivalents. The carrying amount of cash equivalents approximates fair value because of the short-term maturity of those instruments. During the period and at the balance sheet date, balances of cash and cash equivalents exceeded the federally insured limit.
Fair Value of Financial Instruments.The Company’s financial instruments consist of cash and cash equivalents, trade receivables, trade payables and accrued liabilities. The carrying value of cash and cash equivalents, trade receivables, trade payables and accrued liabilities are considered to be representative of their fair market value, due to the short maturity of these instruments.
Hedging Activities. We had no hedging activities in 20092010 and 2008.2009. Hedging strategies, or absence of hedging, may vary or change due to change of circumstances, unforeseen opportunities, inability to fund margin requirements, lending institution requirements and other events which we are not able to anticipate.
Support Equipment and Other. Support equipment (including such items as vehicles, office furniture and equipment and well servicing equipment) is stated at cost. Depreciation of support equipment and other property is computed using primarily the straight-line method over periods ranging from five to seven years.
Inventory. Inventory, consisting primarily of tubular goods and oil field equipment, is stated at the lower of cost or market, cost being determined by the FIFO method. See also Notes 2 and 3 below.
Long-Term Assets. We apply Statement of Financial Accounting Standards (“SFAS”) No. 144, “Accounting forFASB issued authoritative guidance to long-lived assets not included in oil and gas properties. Under the Impairment or Disposal of Long-Lived Assets” in evaluatingguidance, all long-lived assets exceptare tested for recoverability whenever events or changes in circumstances indicate that their carrying value may not be recoverable. The carrying amount of a long-lived asset is not recoverable if it exceeds the full cost pool for possible impairment. Under SFAS No. 144,sum of the undiscounted cash flows expected to result from its use and eventual disposition. An impairment loss is recognized when the carrying value of a long-lived assets are reported at the lowerasset is not recoverable and exceeds its fair value.
Major Customersand Concentration of Credit Risk.Purchasers of 10% or more of our oil and gas production revenue forreceived at March 31, 2010 and 2009 and 2008 are as follows:
| | | | | | | | | | | | 2010 | | | 2009 | |
| | | 2009 | | 2008 | | | | | | |
| | | |
| Murphy Oil USA, Inc. | | | 25 | % | | | 22 | % | |
| Valero Energy | | | 17 | % | | | 20 | % | | 16% | | 17% | |
| Nexen Marketing USA, Inc. | | | 14 | % | | | 11 | % | | 10% | | 14% | |
| Murphy Oil USA, Inc. | | | 8% | | 25% | |
| Plains Inc. | | | 14 | % | | | 15 | % | | | — | | | 14% | |
| Texon LP | | | 6 | % | | | 10 | % | |
| | | | | | | |
| | | | | | | |
| Total | | | 76 | % | | | 78 | % | | | 34% | | | 70% | |
| | | | | | | |
It is not expected that the loss of any one of these customerspurchasers would cause a material adverse impact on our operations sincebecause alternative markets for our products are readily available.
In the year ended March 31, 2010, approximately 57% of our oil and gas revenue was received from non-operated properties where we have no control over the selection of the purchaser. On these properties our portion of the product was marketed on our behalf by the 21 different companies who operate these wells. These 21 companies may, unbeknownst to us, market to one or more of the same purchasers that we use. Therefore, we are unable to ascertain the total extent of combined purchaser concentration. To the extent of our knowledge, in the event of the bankruptcy of any one of our purchasers, or purchasers on non-operated properties, it has been estimated that the reduction in annual revenue would be less than 10%.
Stock Option Plan. With the issuance of SFAS No. 123(R), Accounting for Share Based Compensation, effective December 2004, weWe are required to recognize all equity-based compensation, including stock option grants, as stock-based compensation expense in our Consolidated Statements of Operations based on the fair value of the compensation. No options have been granted since July 2003, and the plan expired in July 2005. Therefore, we issued no further stock options in either 20092010 or 2008.2009. See Note 8 below for further discussion of the Company’s stock options.
Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles in the United States requires us to make estimates and assumptions that affect the reported amounts of oil and gas reserves as well as the assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. There are many factors, including global events, which may influence the production, processing, marketing, and pricing of crude oil and natural gas. A reduction in the valuation of oil and gas properties resulting from declining prices or production could adversely impact depletion rates and ceiling test limitations. Estimates of oil and gas reserve quantities provide a basis for calculation of depletion expense as well as the potential for impairment.
Reclassifications. Certain prior year amounts may have beenwere reclassified to conform to current year presentation. Such reclassifications had no effect on the prior year net income.
Recent Accounting Pronouncements
In June 2009, the FASB issued Accounting Standards Codification, “Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles” (“Codification”) which will become the source of authoritative U.S. generally accepted accounting principles (“GAAP”) recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. On the effective date of this Statement, the Codification will supersede all then-existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in the Codification will become non-authoritative. This Statement is effective for financial statements issued for interim and annual periods ended after September 15, 2009. The adoption of the Codification did not have a material impact on our consolidated financial statements or results of operations.
In June 2009, the FASB issued guidance related to subsequent events which incorporates the guidance contained in the auditing standards literature into authoritative accounting literature. It also requires entities to disclose the date through which they have evaluated subsequent events and whether the date corresponds with the release of their financial statements. In February 2010, the FASB issued an update to this guidance which no longer requires the Company to disclose the date through which subsequent events have been evaluated. We adopted this update which had no impact on the Company’s consolidated financial statements or results of operations.
On April 29, 2009, the FASB issued FSP SFAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments.” This FSPguidance related to financial instruments, which amends SFAS No. 107, “Disclosures about Fair Value of Financial Instruments,” to requirerequires publicly-traded companies as defined in APB Opinion No. 28, “Interim Financial Reporting,” to provide disclosures on the fair value of financial instruments in interim financial statements. FSP SFAS 107-1statements, and APB 28-1 areis effective for interim periods endingended after June 15, 2009. The adoption of FSP SFAS 107-1 isWe have adopted these new provisions, which did not expected to have a material impact on the Company’s consolidated financial statements or results of operations.
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On April 9, 2009, the FASB issued FSP SFAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly,” which provides additional guidance for estimating fair value in accordance with SFAS No. 157 when the volume and level of activity for the asset or liability have significantly decreased. This FSP re-emphasizes that regardless of market conditions the fair value measurement is an exit price concept as defined in SFAS No. 157. This FSP clarifies and includes additional factors to consider in determining whether there has been a significant decrease in market activity for an asset or liability and provides additional clarification on estimating fair value when the market activity for an asset or liability has declined significantly. FSP SFAS 157-4 is applied prospectively to all fair value measurements where appropriate and will be effective for interim and annual periods ending after June 15, 2009. The adoption of FSP 157-4 is not expected to have a material impact on our consolidated financial statements or results of operations.
On April 1, 2009, the FASB issued FSP 141(R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination that Arise from Contingencies” (FSP 141R-1). FSP 141R-1 amends and clarifies SFAS No. 141Rguidance related to addressbusiness combinations, which addresses application issues associated with initial recognition and measurement, subsequent measurement and accounting and disclosure of assets and liabilities arising from contingencies in a business combination. FSP 141R-1combination, including the treatment of contingent consideration, acquisition costs, research and development assets and restructuring costs. In addition, changes in deferred tax asset valuation allowances and acquired income tax uncertainties in a business combination after the measurement period will impact income taxes. The new guidance is effective for assets or liabilities arising from contingencies in business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. We will apply the new provisions of FSP 141R-1 to future acquisitions.
In December 2008, the SEC announced final approval of new requirements for reporting oil and gas reserves. Among the changes to the disclosure requirements is a broader definition of reserves, which allows reporting of probable and possible reserves, in addition to consideration of new technologies and non-traditional resources. In addition, oil and gas reserves will be reported using an average price based on the first-day-of-the-month price during the prior 12-month period, rather than year-end prices, and allow companies to disclose their probable and possible reserves to investors.prices. The new rules are expected to be effective for years ending on or after December 31, 2009. The adoption of the new rules is considered a change in accounting principle inseparable from a change in accounting estimate. The Company isdoes not believe that provisions of the new guidance, other than pricing, significantly impacted the reserve estimates or financial statements which also impact the amount recorded for depreciation, depletion and amortization and the ceiling test calculation for oil and gas properties. Under the new guidance, subsequent price increases cannot be considered in the process of evaluatingceiling test calculation. The Company does not believe that it is practicable to estimate the effect of theseapplying the new requirements,rules on net loss or the amounts recorded for depreciation, depletion and has not yet determinedamortization and ceiling impairment for the impact that it will have on its financial statements upon full adoption onyear ended March 31, 2010.
In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS 162”). SFAS 162 identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements that are presented in conformity with U.S. generally accepted accounting principles. The adoption of SFAS 162 is not expected to have an impact on the Company’s financial position, results of operations or cash flows.
In December 2007, the FASB issued SFAS No. 141 (Revised 2007), “Business Combinations” (“SFAS 141R”). SFAS 141R will significantly change the accounting for business combinations in a number of areas including the treatment of contingent consideration, contingencies, acquisition costs, research and development assets and restructuring costs. In addition, under SFAS 141R, changes in deferred tax asset valuation allowances and acquired income tax uncertainties in a business combination after the measurement period will impact income taxes. SFAS 141R is effective for fiscal years beginning after December 15, 2008. We anticipate adopting the provisions of SFAS 141R beginning April 1, 2009, and do not anticipate it to have a material effect on our financial position, results of operations, or cash flows.
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In December 2007, the FASB issued SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements, An Amendment of ARB No. 51.” SFAS 160 amends ARB 51 to establish accounting and reporting standards for the non-controlling interest in a subsidiary and for the deconsolidation of a subsidiary. It also amends certain of ARB 51’s consolidation procedures for consistency with the requirements of SFAS 141R. SFAS 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. The statement shall be applied prospectively as of the beginning of the fiscal year in which the statement is initially adopted. We will adopt the provisions of SFAS 160 beginning April 1, 2009, and do not anticipate it to have a material effect on our financial position, results of operations, or cash flows.
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities”, providing companies with an option to report selected financial assets and liabilities at fair value. The Standard’s objective is to reduce both complexity in accounting for financial instruments and the volatility in earnings caused by measuring related assets and liabilities differently. Generally accepted accounting principles have required different measurement attributes for different assets and liabilities that can create artificial volatility in earnings. SFAS 159 helps to mitigate this type of accounting-induced volatility by enabling companies to report related assets and liabilities at fair value, which would likely reduce the need for companies to comply with detailed rules for hedge accounting. SFAS 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. The Standard requires companies to provide additional information that will help investors and other users of financial statements to more easily understand the effect of our choice to use fair value on its earnings. It also requires entities to display the fair value of those assets and liabilities for which the Company has chosen to use fair value on the face of the balance sheet. The effective date of SFAS 159 for our Company is April 1, 2008. We have adopted the provisions of SFAS 159, and it does not have a material effect on our financial position, results of operations, or cash flows as of March 31, 2009. The adoption of SFAS No. 159 did not have a material effect on our financial condition or results of operations as we did not make any such elections under this fair value option.
In September 2006, the FASB issued SFAS Statement No. 157, “Fair Value Measurements.” SFAS 157guidance related to fair value measurements and disclosures, which defines fair value, establishes a framework for measuring fair value in accordance with generally accepted accounting principles and expands disclosures about fair value measurements. SFAS 157The new guidance is effective for fiscal years beginning after November 15, 2007. In February 2008, the FASB issued Staff Position No. FAS 157-2. That guidance proposed a one year deferral of the implementation of SFAS 157 for non-financial assets and liabilities that are recognized or disclosed at fair value on a nonrecurring basis (less frequent than annually). On April 1, 2008, we adopted SFAS No. 157the new guidance with the one-year deferral for non-financial assets and liabilities. The adoption of SFAS No. 157the new guidance did not have a material impact on our financial position, results of operations or cash flows. Beginning April 1, 2009, we expect to adopthave adopted the provisions for non-financial assets and non-financial liabilities that are not required or permitted to be measured at fair value on a recurring basis. While we are in the process of evaluating this standard with respect to its effect on non-financial assets and liabilities, we believe thatThe adoption willdid not have a material impact on our financial statements.
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2. Other Current Assets
Other current assets at March 31, 20092010 and 20082009 consisted of the following:
| | | | | | | | | | |
| | | 2009 | | 2008 | | | | 2010 | | | 2009 | |
| | | | | | | |
| Lease and well equipment inventory | | $ | 170,000 | | $ | 154,000 | | | $ | 399,000 | | $ | 170,000 | |
| Drilling and completion cost prepayments | | 149,000 | | 52,000 | | | 244,000 | | 149,000 | |
| Prepaid insurance premiums | | 44,000 | | 58,000 | | | 49,000 | | 44,000 | |
| Other current assets | | 145,000 | | 16,000 | | | | 40,000 | | | 145,000 | |
| | | | | | | | | | | |
| | | |
| Total other current assets | | $ | 508,000 | | $ | 280,000 | | | $ | 732,000 | | $ | 508,000 | |
| | | | | | | |
The lease and well equipment inventory included in Other Current Assets represents well-site production equipment owned by us that has been removed from wells that we operate. This occurs when we plug a well or replace defective, damaged or suspect equipment on a producing well. In this case, salvaged equipment is valued at prevailing market prices, removed from the full cost pool and made available for sale. This equipment is carried on the balance sheet at a value not to exceed the original carrying value established at the time it was placed in inventory. This equipment is intended for resale to third parties at current fair market prices. Sale of this equipment is expected to occur in less than one year. This policy does not preclude us from further transferring serviceable equipment to other wells that we operate, on an as-needed basis.
Drilling and completion cost prepayments represent cash expenditures advanced by us to outside operators prior to the commencement of drilling and/or completion operations on a well.
3. Other Non-Current Assets
Other non-current assets at March 31, 20092010 and 20082009 consisted of the following:
| | | | | | | | | | | | 2010 | | | 2009 | |
| | | 2009 | | 2008 | | | | | | |
| | | |
| Lease and well equipment inventory | | $ | 261,000 | | $ | 250,000 | | |
| Support equipment and lease and well equipment inventory | | | $ | 272,000 | | $ | 261,000 | |
| Plugging bonds | | 60,000 | | 69,000 | | | 60,000 | | 60,000 | |
| Other non-current assets | | 137,000 | | 124,000 | | | | 119,000 | | | 137,000 | |
| | | | | | | | | | | |
| | | |
| Total other non-current assets | | $ | 458,000 | | $ | 443,000 | | |
| | | | | | | |
| Total support equipment and other non-current assets | | | $ | 451,000 | | $ | 458,000 | |
This lease and well equipment inventory, unlike the equipment inventory in Other Current Assets that is held for resale, is intended for use on leases that we operate. This equipment inventory represents well-site production equipment that we own that has either been purchased or has been removed from wells that we operate. When placed in inventory, new equipment is valued at cost and salvaged equipment is valued at prevailing market prices. The inventory is carried at the lower of the original carrying value or fair market value.
Plugging bonds represent Certificates of Deposit furnished by us to third parties who supply plugging bonds to federal and state agencies where we operate wells. These funds are classified as restricted.
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4. Accrued Liabilities
Accrued liabilities atfor the years ended March 31, 20092010 and 20082009 consisted of the following:
| | | | | | | | | |
| | | Years Ended | |
| | | March 31, | |
| | | 2009 | | | 2008 | |
| | | | | | | | | |
| Revenue and production taxes payable | | $ | 532,000 | | | $ | 574,000 | |
| Accrued payables | | | 368,000 | | | | 1,396,000 | |
| Accrued compensation | | | 288,000 | | | | 313,000 | |
| Short term asset retirement obligation | | | 140,000 | | | | 303,000 | |
| | | | | | | |
| | | | | | | | | |
| Total | | $ | 1,328,000 | | | $ | 2,586,000 | |
| | | | | | | |
| | | | 2010 | | | | 2009 | |
| | | | | | | | | |
| Revenue and production taxes payable | | $ | 348,000 | | | $ | 532,000 | |
| Accrued compensation | | | 172,000 | | | | 288,000 | |
| Accrued operations payable | | | 820,000 | | | | 225,000 | |
| Accrued taxes payable and other | | | 396,000 | | | | 143,000 | |
| Short term asset retirement obligation | | | 100,000 | | | | 140,000 | |
| | | | | | | | | |
| Total | | $ | 1,836,000 | | | $ | 1,328,000 | |
5. Asset Retirement Obligation
SFAS No. 143, “Accounting for Asset Retirement Obligations” requires
We recognize the fair value of an asset retirement obligation to be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated present value of the asset retirement cost is capitalized as part of the carrying amount, and is included in the proved oil and gas properties in the accompanying consolidated balance sheets. We own oil and gas properties that require expenditures to plug and abandon when reserves in the wells are depleted. Under SFAS No. 143 theseThese future expenditures are recorded in the period the liability is incurred (at the time the wells are drilled and completed or acquired).
The following table summarizes the activity related to our estimate of future asset retirement obligations for 2009the years ended March 31, 2010 and 2008:2009:
| | | | | | | | | | |
| | | Years Ended | | |
| | | March 31, | | |
| | | 2009 | | 2008 | | | | 2010 | | | 2009 | |
| | | | | | | |
| Asset retirement obligation at beginning of period | | $ | 2,179,000 | | $ | 1,971,000 | | | $ | 1,698,000 | | $ | 2,179,000 | |
| Liabilities settled during the period | | | (168,000 | ) | | | (116,000 | ) | | (134,000) | | (168,000) | |
| New obligations for wells drilled and completed | | 33,000 | | 84,000 | | | 54,000 | | 33,000 | |
| Accretion of asset retirement obligation | | 98,000 | | 114,000 | | | 166,000 | | 98,000 | |
| Revisions to estimates | | | (444,000 | ) | | 126,000 | | | | (10,000) | | | (444,000) | |
| | | | | | | | | | | |
| | | |
| Asset retirement obligation at end of period | | $ | 1,698,000 | | $ | 2,179,000 | | | $ | 1,774,000 | | $ | 1,698,000 | |
| | | | | | | | | | | |
| | | |
| Current accrued liability | | $ | 140,000 | | $ | 302,000 | | |
| Current liability | | | $ | 100,000 | | $ | 140,000 | |
| Long-term liability | | 1,558,000 | | 1,877,000 | | | | 1,674,000 | | | 1,558,000 | |
| | | | | | | | | | | |
| | | |
| Asset retirement obligation at end of each period | | $ | 1,698,000 | | $ | 2,179,000 | | | $ | 1,774,000 | | $ | 1,698,000 | |
| | | | | | | |
Asset retirement expense as recorded in the years ended March 31, 20092010 and 20082009 represents plugging and abandonment costs in excess of the estimated asset retirement obligation recorded with the adoption of SFAS No. 143.recorded. We based our initial estimates on our knowledge and experience plugging wells in earlier years.
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6. Credit Line
Our current banking relationship, established in March 2002, is with American National Bank (“the Bank”), located in Denver, Colorado. Effective January 3, 2006, we amended the existing loan agreement to increase the line of credit amount from $1,000,000 to $20,000,000 with a concurrent borrowing base increase from $1,000,000 to $4,000,000. Effective December 31, 2008, the loan agreement was amended again to extend the maturity date of the credit agreement from December 31, 2008 to December 31, 2010. The current interest rate is 6.5% or prime plus one-quarter of one percent (0.25%) whichever is greater, and the addition of an unused commitment fee equal to one-half of one percent (0.50%) per annum on the difference between the outstanding balance and the borrowing base amount.
Under the credit facility, we must maintain certain financial covenants. Failure to maintain any covenant, after a curative period, creates a default under the loan agreement and requires repayment of the entire outstanding balance. With the December 31, 2008 amendment, the covenant requiring us to maintain a net worth of at least $1,750,000 was replaced with a covenant requiring us to maintain a debt-to-equity ratio less than one. Another covenant obligates us to maintain a current ratio of at least 1:1 inclusive of unused borrowing capacity and exclusive of the current portion of long-term debt. We were in compliance with all covenants at March 31, 2009.2010.
This credit line is collateralized by a significant portion of our oil and gas properties and production, and as of March 31, 2009,2010, there was no outstanding balance on this line of credit. If necessary, we may borrow funds to reduce payables, finance re-completion or drilling efforts, fund property acquisitions or pursue other opportunities that might arise.
7. Commitments
Effective March 1, 2008, we relocated to a new 4,000 square foot office space located in downtown Denver, Colorado. The lease agreement is for a five-year term through April 2013 and currently requires base rent payments of approximately $5,685$5,853 per month escalating at a rate of approximately $170 at the end of each year. Office rent expense was approximately $87,000$107,000 in 20092010 (including building maintenance charges), and $36,000$87,000 in 2008.2009. We are committed to a total of $281,000 for the five-year term ending April 1, 2013. Prior to expiration of the lease term, we will evaluate the Denver real estate market and the various available options before deciding on where to lease office space after April 2013.
8. Shareholders’ Equity
Preferred Stock. We have 3,000,000 shares of authorized preferred stock that can be issued in such series and preferences as determined by the Board of Directors.
Stock Option Plan. Effective July 27, 1995, our shareholders approved the 1995 Incentive Stock Option Plan (“the Plan”) authorizing option grants to employees and outside directors to purchase up to 1,000,000 shares of our common stock. The Plan was structured as a 10-year plan and, as such, ended on July 26, 2005. During the Plan’s existence, a total of 665,000 options were granted; of this amount, 50,000 options expired unexercised, 590,000 options were exercised at strike prices ranging from $0.0325 to $0.175 per share and the remaining 25,000 options were exercised as of March 31, 2009 (see the table below).2009.
34
A summary of the status of our stock option plan and outstanding options as of March 31, 20092010 and 2008,2009, and changes during the years endingended on those dates is presented below:
| | | | | | | | | | | | | | | | | | |
| | | 2009 | | 2008 | | | 2010 | | | 2009 | |
| | | Weighted | | Weighted | | | | | Weighted | | | | Weighted | |
| | | Average | | Average | | | | | Average | | | | Average | |
| | | Exercise | | Exercise | | | | | Exercise | | | | Exercise | |
| | | Shares | | Price | | Shares | | Price | | | Shares | | Price | | Shares | | Price | |
| | | | | | | | | | | | | | | | | | |
| Options unexercised, beginning of year | | 25,000 | | $ | 0.1325 | | 190,000 | | $ | 0.0936 | | | | — | | | $ | — | | | | 25,000 | | | $ | 0.1325 | |
| | | | | | | | | | | |
| Granted | | — | | — | | — | | — | | | | — | | | | — | | | | — | | | | — | |
| Cancelled | | — | | — | | — | | — | | | | — | | | | — | | | | — | | | | — | |
| Exercised | | | (25,000 | ) | | | (0.1325 | ) | | | (165,000 | ) | | | (0.0941 | ) | | | — | | | | — | | | | (25,000 | ) | | | (0.1325 | ) |
| | | | | | | | | | | | | | | | | | | |
| | | |
| Options unexercised and exercisable, end of year | | — | | $ | — | | 25,000 | | $ | 0.1325 | | | | — | | | $ | — | | | | — | | | $ | — | |
| | | | | | | | | | | |
Since all options are fully vested, and the plan has expired, we will have no stock-based compensation expense related to stock options in future periods unless a new plan is adopted and additional options are granted.
Director Stock Compensation.On March 8, 2007, the Board of Directors adopted a new Director Compensation Plan. In connection with this plan, an annual stock grant equal to $36,000 is awarded to each independent director. The number of shares included in each grant is calculated based upon the average closing price of the ten trading days preceding each April 1st anniversary date.
9. Income Tax
Our provision for income taxes for the years ended March 31, 2010 and 2009 comprised of the following:
| | | | | | | | | |
| | | For the Years Ended | |
| | | March 31, | |
| | | 2009 | | | 2008 | |
| | | | | | | | | |
| Current: | | | | | | | | |
| Federal | | $ | 305,000 | | | $ | 155,000 | |
| State | | | 41,000 | | | | 24,000 | |
| | | | | | | |
| Total current | | | 346,000 | | | | 179,000 | |
| | | | | | | | | |
| Deferred : | | | | | | | | |
| Federal | | | (483,000 | ) | | | 1,166,000 | |
| State | | | (75,000 | ) | | | 180,000 | |
| | | | | | | |
| Total deferred (benefit) | | | (558,000 | ) | | | 1,346,000 | |
| | | | | | | | | |
| Total income tax provision | | $ | (212,000 | ) | | $ | 1,525,000 | |
| | | | | | | |
35
| | | 2010 | | | 2009 | |
| Current: | | | | | | |
| Federal | | $ | 171,000 | | | $ | 305,000 | |
| State | | | 1,000 | | | | 41,000 | |
| Total current income tax expense | | | 172,000 | | | | 346,000 | |
| | | | | | | | | |
| Deferred: | | | | | | | | |
| Federal | | | (23,000 | ) | | | (483,000 | ) |
| State | | | (1,000 | ) | | | (75,000 | ) |
| Total deferred income tax expense (benefit) | | | (24,000 | ) | | | (558,000 | ) |
| | | | | | | | | |
| Income tax expense (benefit) | | $ | 148,000 | | | $ | (212,000 | ) |
A reconciliation between the income tax provision at the statutory rate on income taxes and the income tax provision for the years ended March 31, 2010 and 2009 is as follows:
| | | | | | | | | |
| | | For the Years Ended | |
| | | March 31, | |
| | | 2009 | | | 2008 | |
| | | | | | | | | |
| Federal income tax provision at statutory rates | | $ | 124,000 | | | $ | 1,118,000 | |
| State income tax | | | (18,000 | ) | | | 164,000 | |
| Change in depletion carryforward | | | — | | | | 592,000 | |
| Excess percentage depletion | | | (322,000 | ) | | | (346,000 | ) |
| Other | | | 4,000 | | | | (3,000 | ) |
| | | | | | | |
| | | | | | | | | |
| Income tax expense | | $ | (212,000 | ) | | $ | 1,525,000 | |
| | | | | | | |
| | | 2010 | | | 2009 | |
| | | | | | | | | |
| Federal taxes at statutory rate | | $ | 400,000 | | | $ | 124,000 | |
| State taxes, net of federal benefit | | | 9,000 | | | | (18,000 | ) |
| Excess percentage depletion | | | (283,000 | ) | | | (322,000 | ) |
| Other adjustments | | | 22,000 | | | | 4,000 | |
| | | | | | | | | |
| Income tax expense (benefit) | | $ | 148,000 | | | $ | (212,000 | ) |
The components of the net deferred tax assets and liabilities for the years ended March 31, 2010 and 2009 are shown below:as follows:
| | | | | | | | | | | 2010 | | 2009 | |
| | | For the Years Ended | | |
| | | March 31, | | |
| | | 2009 | | 2008 | | |
| | | |
| Deferred tax assets: | | | | | | |
| Allowance for doubtful accounts | | $ | 26,000 | | $ | 20,000 | | | $ | 31,000 | | | $ | 26,000 | |
| Asset retirement obligation | | 633,000 | | 850,000 | | | | 647,000 | | | | 633,000 | |
| Other accruals | | | (4,000 | ) | | 112,000 | | |
| Statutory depletion carryforward | | 858,000 | | 1,043,000 | | | | 1,074,000 | | | | 858,000 | |
| | | | | | | | | | | | | | |
| Gross deferred tax assets | | | | 1,752,000 | | | | 1,517,000 | |
| | | | | | | |
| Total gross deferred tax assets | | 1,513,000 | | 2,025,000 | | |
| Other accruals | | | | 47,000 | | | | (4,000 | ) |
| Depreciation, depletion and intangible drilling costs | | | | (4,016,000 | ) | | | (3,755,000 | ) |
| | | | | | | | | | | | | | |
| Gross deferred tax liabilities | | | | (3,969,000 | ) | | | (3,759,000 | ) |
| | | | | | | |
| Deferred tax liability — Depreciation, depletion and intangible drilling costs | | | (3,755,000 | ) | | | (4,825,000 | ) | |
| | | | | | | |
| | | |
| Net deferred tax liability | | $ | (2,242,000 | ) | | $ | (2,800,000 | ) | |
| | | | | | | |
| Deferred tax assets (liabilities), net | | | $ | (2,217,000 | ) | | $ | (2,242,000 | ) |
We follow authoritative guidance for the financial statement recognition, measurement and disclosure of uncertain tax positions recognized in the financial statements. Tax positions must meet a “more-likely-than-not” recognition threshold before a benefit is recognized in the financial statements. As of March 31, 2009, we had fully utilized our net operating loss carry-forward2010, the Company has not recorded a liability for uncertain tax purposes. We have statutory depletion carryforwards of $2,300,000 that do not expire.
positions. The adoption of FIN 48 had no impact on our consolidated financial statements. We are subjectCompany recognizes interest and penalties related to U.S. federaluncertain tax positions in income tax expense. No interest and incomepenalties related to uncertain tax from multiple state jurisdictions.positions were accrued at March 31, 2010. The tax years remaining subject to examination by tax authorities are fiscal years 20042005 through 2008. We recognize interest and penalties related to uncertain tax positions in income tax expense. As2009.
10. Related Party Transactions
It is our policy that officers or directors may assign to us or receive assignments from us in oil and gas prospects, but only on the same terms and conditions as accepted by independent third parties. It is also our policy that officers or directors and the Company may participate together in oil and gas prospects generated by independent third parties, but only on the same terms and conditions as accepted by each other.non-related third parties. In 2010, Ray Singleton, President of the Company, participated in the drilling of the Crown 41-31 in Sheridan County, Montana on the same terms and conditions as other third parties. The well resulted in a dry hole. During 20092010 and 20082009, none of our officersother directors or directorsofficer participated with the Company in any of our oil and gas transactions. In prior years, RayMr. Singleton President of the Company, has participated with us in certain acquisitions.the acquisition of producing properties on the same terms and conditions as the Company and other third parties. As such, Mr. Singleton paid for his proportionate share of the acquisition costs at the time of the acquisition. With respect to his working interest in the four producing wells in which he currently participates,has an ownership, at March 31, 20092010, the Company had a balance due fromto Mr. Singleton for less than $1,000approximately $10,000 compared to a payable balance due tofrom him of approximately $2,000less than $1,000 at March 31, 2008.2009. This was due to his share of operating expensesoil and gas revenue exceeding the amount due tofrom him for his share of oil and gas revenueoperating expenses from these wells.
11. Oil and Gas Property
The aggregate amount of capitalized costs related to oil and gas properties and the aggregate amount of related accumulated depreciation and depletion at March 31, 20092010 and 20082009 are as follows:
| | | | | | | | | | |
| | | 2009 | | 2008 | | | | 2010 | | | 2009 | |
| | | | | | |
| Proved property | | $ | 32,187,000 | | $ | 29,050,000 | | | $ | 33,915,000 | | $ | 32,187,000 | |
| Unproved property | | 1,077,000 | | 2,515,000 | | | | 1,555,000 | | | 1,077,000 | |
| | | | | | | | | | | |
| | | | 35,470,000 | | 33,264,000 | |
| Gross oil and gas property | | 33,264,000 | | 31,565,000 | | |
| Accumulated depletion and impairment | | | (22,397,000 | ) | | | (18,515,000 | ) | | | (23,582,000) | | | (22,397,000) | |
| | | | | | | | | | | |
| | | |
| Net oil and gas property | | $ | 10,867,000 | | $ | 13,050,000 | | |
| | | | | | | |
| Net capitalized oil and gas property | | | $ | 11,888,000 | | $ | 10,867,000 | |
Costs directly associated with the acquisition and evaluation of unproved property are excluded from the full cost pool depreciation, depletion and amortization computation until the properties can be classified as proved. These costs have been incurred over the last fourfive fiscal years and are not yet evaluated as proved. Upon proving these properties the costs will be reclassified as proved property, or in the event that a decision is made to cease operations on the property without further work estimated to be performed, the costs will be removed from unproved property and included in the full cost pool to be amortized. Primarily, these costs relate to the following properties:
Williston Basin. Five new wells in the Williston Basin primarily within McKenzie County, North Dakota represent $763,000 for 49.1% of the total unproved property costs. These wells will be removed from the unproved property classification upon evaluation.
Banks ProspectField. The Banks ProspectField represents approximately 55.3%20.5% of total unproved property costs, $596,000,$318,000, associated with a 13,000 gross acre horizontal Bakken play in McKenzie County, North Dakota. For further information seeAreas of Focusof Item 1. “Description of Business.”
Christmas Meadows. The Christmas Meadows prospect consists of approximately 36.8%25.5% of total unproved property costs, $396,000, related to 40,000+ acres operated by Double Eagle Petroleum Company (Double Eagle). For further information seeAreasCompany.
South Flat Lake Prospect. The South Flat Lake prospect represents approximately 5.5% of total unproved property costs, $59,000, associated with a 4,200 gross acres (2,100 net) prospect in northern Sheridan County near the Flat Lake Field. For further information seeAreas of Focusof Item 1. “Description of Business.”
37
The following table shows, by category and date incurred, the oil and gas property costs applicable to unproved property that were excluded from the depreciation and depletion computation at March 31, 2009:2010:
| | | | | | | | | | | | | | | | | | |
| | | Total | | |
| Costs Incurred During | | Exploration | | Development | | Acquisition | | Unproved | | | Exploration | | Development | | Acquisition | | Total Unproved | |
| Year Ended | | Costs | | Costs | | Costs | | Property | | | Costs | | Costs | | Costs | | Property | |
| | | | | | | | | | | | | | | | | | |
| March 31, 2010 | | | $ | 1,000 | | | $ | 791,000 | | | $ | — | | | $ | 792,000 | |
| March 31, 2009 | | $ | 249,000 | | $ | — | | $ | — | | $ | 249,000 | | | | 249,000 | | | | — | | | | — | | | | 249,000 | |
| March 31, 2008 | | 29,000 | | — | | — | | 29,000 | | | | 29,000 | | | | — | | | | — | | | | 29,000 | |
| March 31, 2007 | | 308,000 | | — | | — | | 308,000 | | | | 308,000 | | | | — | | | | — | | | | 308,000 | |
| March 31, 2006 | | 428,000 | | 39,000 | | — | | 467,000 | | | | 134,000 | | | | 39,000 | | | | — | | | | 173,000 | |
| March 31, 2005 | | 24,000 | | — | | — | | 24,000 | | | | 4,000 | | | | — | | | | — | | | | 4,000 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | |
| Total | | $ | 1,038,000 | | $ | 39,000 | | $ | — | | $ | 1,077,000 | | | $ | 725,000 | | | $ | 830,000 | | | $ | — | | | $ | 1,555,000 | |
| | | | | | | | | | | |
Costs incurred in oil and gas property development, exploration and acquisition activities during the years ended March 31, 20092010 and 20082009 are summarized as follows:
| | | | | | | | | |
| | | For the Years Ended | |
| | | March 31, | |
| | | 2009 | | | 2008 | |
| | | | | | | | | |
| Development costs | | $ | 2,177,000 | | | $ | 2,410,000 | |
| Exploration costs | | | — | | | | 40,000 | |
| Acquisitions: | | | | | | | | |
| Proved | | | — | | | | 250,000 | |
| Unproved | | | — | | | | — | |
| | | | | | | |
| | | | | | | | | |
| Total | | $ | 2,177,000 | | | $ | 2,700,000 | |
| | | | | | | |
| | | | 2010 | | | | 2009 | |
| | | | | | | | | |
| Development costs | | $ | 1,536,000 | | | $ | 2,177,000 | |
| Exploration costs | | | 620,000 | | | | — | |
| Acquisitions: | | | | | | | | |
| Proved | | | — | | | | — | |
| Unproved | | | — | | | | — | |
| | | | | | | | | |
| Total | | $ | 2,156,000 | | | $ | 2,177,000 | |
12. Unaudited Oil and Gas Reserves Information
At March 31, 2010 and 2009, 93% and 2008, 98% and 93% respectively, of the estimated oil and gas reserves presented herein were derived from reports prepared by independent petroleum engineering firm Ryder Scott Company. The remaining 27% and 7 percent2% of the reserve estimates, respectively, were prepared internally by our management. There are many inherent uncertainties in estimating proved reserve quantities and in projecting future production rates and the timing of development expenditures. Accordingly, these estimates are likely to change as future information becomes available, and these changes could be material.
Proved oil and gas reserves are the estimated quantities of crude oil, condensate, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are reserves expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are reserves expected to be recovered through wells yet to be completed.
38
Analysis of Changes in Proved Reserves. Estimated quantities of proved developed reserves (all of which are located within the United States), as well as the changes in proved developed reserves during the periods indicated, are presented in the following tables:
Proved Reserves
| | | | | | | | | |
| | | Oil and | | | | |
| | | Natural | | | | |
| | | gas | | | Natural | |
| | | liquids | | | gas | |
| | | (Bbls) | | | (Mcf) | |
| | | | | | | | | |
| Proved developed reserves at March 31, 2007 | | | 995,000 | | | | 1,138,000 | |
| | | | | | | |
| | | | | | | | | |
| Revisions of previous estimates | | | 112,000 | | | | (113,000 | ) |
| Extensions and discoveries | | | 19,000 | | | | 203,000 | |
| Sales of reserves in place | | | — | | | | — | |
| Improved recovery | | | 15,000 | | | | 1,000 | |
| Purchase of reserves | | | 22,000 | | | | — | |
| Production | | | (89,000 | ) | | | (109,000 | ) |
| | | | | | | |
| | | | | | | | | |
| Proved developed reserves at March 31, 2008 | | | 1,074,000 | | | | 1,120,000 | |
| | | | | | | |
| | | | | | | | | |
| Revisions of previous estimates | | | (429,000 | ) | | | (262,000 | ) |
| Extensions and discoveries | | | 86,000 | | | | 253,000 | |
| Sales of reserves in place | | | — | | | | — | |
| Improved recovery | | | — | | | | — | |
| Purchase of reserves | | | — | | | | — | |
| Production | | | (93,000 | ) | | | (175,000 | ) |
| | | | | | | |
| | | | | | | | | |
| Proved developed and undeveloped reserves at March 31, 2009 | | | 638,000 | | | | 936,000 | |
| | | | | | | |
As of March 31, 2009, we have proved reserves related to undeveloped property, whereas for March 31, 2008, all of our oil and gas reserves were classified as Proved Developed, Producing.| | | March 31, 2010 | | | March 31, 2009 | | | March 31, 2008 | |
| | | Oil (Bbls) | | | Gas (Mcf) | | | Oil (Bbls) | | | Gas (Mcf) | | | Oil (Bbls) | | | Gas (Mcf) | |
| Proved reserves: | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance, beginning of year | | | 638,000 | | | | 936,000 | | | | 1,074,000 | | | | 1,120,000 | | | | 995,000 | | | | 1,138,000 | |
| Revisions of previous estimates (1) | | | 275,000 | | | | 195,000 | | | | (429,000) | | | | (262,000) | | | | 112,000 | | | | (113,000) | |
| Extensions and discoveries (2) | | | 4,000 | | | | 10,000 | | | | 86,000 | | | | 253,000 | | | | 19,000 | | | | 203,000 | |
| Sales of reserves in place | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | |
| Improved recovery | | | — | | | | — | | | | — | | | | — | | | | 15,000 | | | | 1,000 | |
| Purchase of reserves | | | — | | | | — | | | | — | | | | — | | | | 22,000 | | | | — | |
| Production (3) | | | (99,000) | | | | (229,000) | | | | (93,000) | | | | (175,000) | | | | (89,000) | | | | (109,000) | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance, end of year | | | 818,000 | | | | 912,000 | | | | 638,000 | | | | 936,000 | | | | 1,074,000 | | | | 1,120,000 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Proved developed reserves: | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance, beginning of year | | | 587,000 | | | | 907,000 | | | | 1,074,000 | | | | 1,120,000 | | | | 995,000 | | | | 1,138,000 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance, end of year | | | 727,000 | | | | 912,000 | | | | 587,000 | | | | 907,000 | | | | 1,074,000 | | | | 1,120,000 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Proved undeveloped reserves: | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance, beginning of year | | | 51,000 | | | | 29,000 | | | | — | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance, end of year | | | 91,000 | | | | — | | | | 51,000 | | | | 29,000 | | | | — | | | | — | |
| (1) | Revisions of Previous Estimates – Overall our properties experienced an increase in estimated economic life due to increases in oil and gas prices during the year ended March 31, 2010. Changes in performance constitute less than 10% of the total amount of revisions of previous estimates. |
| (2) | Extensions and Discoveries – The additions consisted of two new well in wells in Weld County, Colorado and one new well in the Dunn County, North Dakota. |
| (3) | Production – This change in reserves is due to volumes of oil and gas that was produced and removed from reserves during the year. |
The table below sets forth a standardized measure of the estimated discounted future net cash flows attributable to our proved oil and gas reserves. Estimated future cash inflows were computed by applying year end (March 31) pricesthe 12 month average price of oil and gas on the first day of each month (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved oil and gas reserves at March 31, 2010, 2009 and 2008. The future production and development costs represent the estimated future expenditures to be incurred in producing and developing the proved reserves, assuming continuation of existing economic conditions. Discounting the annual net cash flows at 10% illustrates the impact of timing on these future cash flows.
39
Standardized Measure of Estimated Discounted Future Net Cash Flows
| | | | | | | | | | |
| | | For the Years Ended | | |
| | | March 31, | | | | For the Years Ended March 31, | |
| | | 2009 | | 2008 | | | | 2010 | | | 2009 | | | 2008 | |
| | | | | | | | | | | | |
| Future cash inflows | | $ | 31,793,000 | | $ | 114,296,000 | | | $ | 55,991,000 | | | $ | 31,793,000 | | $ | 114,296,000 | |
| Future cash outflows: | | | | | | | | |
| Production cost | | | (17,924,000 | ) | | | (49,599,000 | ) | | | (29,065,000) | | | | (17,924,000) | | (49,599,000) | |
| Development cost | | | (490,000 | ) | | — | | | | (991,000) | | | | (490,000) | | — | |
| Future income taxes | | | (2,100,000 | ) | | | (17,826,000 | ) | | | (3,361,000) | | | | (2,100,000) | | (17,826,000) | |
| | | | | | | | | | | | | |
| | | |
| Future net cash flows | | 11,279,000 | | 46,871,000 | | | | 22,574,000 | | | | 11,279,000 | | 46,871,000 | |
| Adjustment to discount future annual net cash flows at 10% | | | (4,080,000 | ) | | | (21,911,000 | ) | | | (10,060,000) | | | | (4,080,000) | | | (21,911,000) | |
| | | | | | | | | | | | | |
| | | |
| Standardized measure of discounted future net cash flows | | $ | 7,199,000 | | $ | 24,960,000 | | | $ | 12,514,000 | | | $ | 7,199,000 | | $ | 24,960,000 | |
| | | | | | | |
The following table summarizes the principal factors comprising the changes in the standardized measure of estimated discounted net cash flows for 2010, 2009 and 2008.
Changes in Standardized Measure of Estimated Discounted Net Cash Flows
| | | | | | | | | |
| | | For the Years Ended | |
| | | March 31, | |
| | | 2009 | | | 2008 | |
| | | | | | | | | |
| Standardized measure, beginning of period | | $ | 24,960,000 | | | $ | 14,624,000 | |
| | | | | | | |
| Sales of oil and gas, net of production cost | | | (5,808,000 | ) | | | (4,727,000 | ) |
| Net change in sales prices, net of production cost | | | (25,977,000 | ) | | | 14,598,000 | |
| Discoveries, extensions and improved recoveries, net of future development cost | | | 2,298,000 | | | | 3,054,000 | |
| Change in future development costs | | | — | | | | — | |
| Development costs incurred during the period that reduced future development cost | | | — | | | | — | |
| Sales of reserves in place | | | — | | | | — | |
| Revisions of quantity estimates | | | (4,745,000 | ) | | | 2,639,000 | |
| Accretion of discount | | | 4,279,000 | | | | 1,865,000 | |
| Net change in income taxes | | | 16,594,000 | | | | (4,221,000 | ) |
| Purchase of reserves | | | — | | | | 361,000 | |
| Changes in timing of rates of production | | | (4,402,000 | ) | | | (3,233,000 | ) |
| | | | | | | |
| | | | | | | | | |
| Standardized measure, end of period | | $ | 7,199,000 | | | $ | 24,960,000 | |
| | | | | | | |
40
| | | | For the Years Ended March, 31 | |
| | | | 2010 | | | | 2009 | | | | 2008 | |
| | | | | | | | | | | | | |
| Standardized measure, beginning of period | | $ | 7,199,000 | | | $ | 24,960,000 | | | $ | 14,624,000 | |
| | | | | | | | | | | | | |
| Sales of oil and gas, net of production cost | | | (4,284,000) | | | | (5,808,000) | | | | (4,727,000) | |
| Net change in sales prices, net of production cost | | | 6,279,000 | | | | (25,977,000) | | | | 14,598,000 | |
| Discoveries, extensions and improved recoveries, net of future development cost | | | 154,000 | | | | 2,298,000 | | | | 3,054,000 | |
| Change in future development costs | | | 467,000 | | | | — | | | | — | |
| Development costs incurred during the period that reduced future development cost | | | — | | | | — | | | | — | |
| Sales of reserves in place | | | — | | | | — | | | | — | |
| Revisions of quantity estimates | | | 5,280,000 | | | | (4,745,000) | | | | 2,639,000 | |
| Accretion of discount | | | 720,000 | | | | 4,279,000 | | | | 1,865,000 | |
| Net change in income taxes | | | (1,582,000) | | | | 16,594,000 | | | | (4,221,000) | |
| Purchase of reserves | | | — | | | | — | | | | 361,000 | |
| Changes in timing of rates of production | | | (1,719,000) | | | | (4,402,000) | | | | (3,233,000) | |
| | | | | | | | | | | | | |
| Standardized measure, end of period | | $ | 12,514,000 | | | $ | 7,199,000 | | | $ | 24,960,000 | |
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
As defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act, of 1934 (the “Exchange Act”), the termphrase “disclosure controls and procedures” means controls and other procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuerus in the reports that it fileswe file or submitssubmit under the Exchange Act is accumulated and communicated to the issuer’sour management, including its principal executiveour Chief Executive Officer and principal financial officers, or persons performing similar functions,Principal Accounting Officer, as appropriate to allow timely decisions regarding required disclosure.
The
We conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as of March 31, 2010. This evaluation was conducted under the supervision and with the participation of management, including our Chief Executive Officer and Principal Accounting Officer. Based on this evaluation, our Chief Executive Officer and Principal Accounting Officer evaluated the effectiveness of the Company’s disclosure controls and procedures and concluded that, following implementationas of the changes in internal control over financial reporting discussed below, the Company’sMarch 31, 2010, our disclosure controls and procedures were effective as of March 31, 2009.effective.
Changes in Internal Control Over Financial Reporting
There were no changes in our internal control over financial reporting during the year ended March 31, 2009our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, the Company’sour internal control over financial reporting.
Management’s
Management's Annual Report on Internal Control Over Financial Reporting
The management of Basic Earth Science Systems,Earthstone Energy, Inc. is responsible for establishing and maintaining adequate internal control over financial reporting for the Company as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. This system is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.
Our internal control over financial reporting includes those policies and procedures that;
(i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;
(ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and the directors of the Company; and
(iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’sCompany's assets that could have a material effect on the financial statements, and provide reasonable assurance as to the detectionstatements.
Because of its inherent limitations, a system of internal control over financial reporting can provide only reasonable assurance and may not prevent or detect misstatements. Further, because of changes in conditions, effectiveness of internal controls over financial reporting may vary over time.
With
Under the supervision of, and with the participation of our management, including the Chief Executive Officer and Principal Accounting Officer, the Company’s managementwe conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting based on the framework and criteria established inInternal Control-Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, the Company’s management concluded that the Company’sCompany's internal control over financial reporting was effective as of March 31, 2009.2010.
Management’s report was not subject to attestation by the Company’s independent registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this Annual Report on Form 10-K. Therefore, this Annual Report on Form 10-K does not include such an attestation.
| | | | | | | | |
By: | | /s/ Ray Singleton | | By: | | /s/ Joseph Young | | |
| | Ray Singleton, President | | | | Joseph Young | | |
| | Chief Executive Officer | | | | Principal Accounting Officer | | |
| | June 18, 2009 | | | | June 18, 2009 | | |
OTHER INFORMATION
There is no information required to be disclosed on Form 8-K during the fourth quarter
None.
Part III
ITEM 10
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Directors
The following sets forth the names and ages of the members of the Board of Directors of Basic Earth Science Systems, Inc. (“Basic” or “the Company” or “we” or “our” or “us”) who served during the past year, their respective principal occupations or employment during the past five years, and the period during which each has served as a director of the Company.
Ray Singleton(58) has been a director of Basic since July 1989. Mr. Singleton joined the CompanyInformation relating to this item will be included in June 1988 as Production Manager/Petroleum Engineer. In October 1989, he was elected Vice President, and was appointed President and Chief Executive Officer in March 1993. Mr. Singleton began his career with Amoco Production Company in Texas as a production engineer. He was subsequently employed by the predecessor of Union Pacific Resources as a drilling, completion and production engineer and in 1981 began his own engineering consulting firm, serving the needs of some 40 oil and gas companies. As a consultant he was retained by the Company on various projects from 1981an amendment to 1987. Mr. Singleton currently serves on the Board of Directors of the Independent Petroleum Association of Mountain States (IPAMS) and is a former president of that organization. IPAMS is a thirteen-state, regional trade association that represents the interests of independent oil and gas companies in the Rocky Mountain region. In addition, Mr. Singleton is a member of the Society of Petroleum Engineers. Mr. Singleton received a Bachelor of Science degree in Petroleum Engineering from Texas A&M University in 1973 and received a Masters Degree in Business Administration from Colorado State University’s Executive MBA Program in 1992.
Richard K. Rodgers(49) has been a director of Basic since December 2006. Mr. Rodgers was originally appointed to fill the vacancy created by the resignation of a prior director, and was then elected as a director at the Company’s shareholder meeting held on January 15, 2007. For the last three years, Mr. Rodgers has provided business development, planning and financial consulting services to various banking and business development clients. During the past five years, Mr. Rodgers was employed by several Denver area banks including Key Bank, Guaranty Bank & Trust Company and Colorado Capital Bank. In his most recent employment with Colorado Capital Bank from 2004 to 2005, he was the President, and was responsible for the start-up, of its Cherry Creek branch office and served on the Board of Directors of Colorado Capital Bank. Mr. Rodgers attended the University of Denver and received his Bachelor of Science degree in International Business Administration in 1995 and his Master of Science degree in International Business Administration in 1997.
Monroe W. Robertson(59) was originally appointed to fill the vacancy created when the Board, on April 4, 2007, amended the Company’s Bylaws to increase the number of members of the Board from three (3) members to four (4) members. Subsequently, he was elected as a director at the Company’s shareholder meeting held on January 21, 2008. Mr. Robertson currently serves on the Board of Directors of Cimarex Energy Company and is chairman of that board’s Audit Committee. Mr. Robertson began his career in 1973 with Gulf Oil Corporation and held various positions in engineering, corporate planning and financial analysis until 1986. From 1986 to 1992 he held various positions at Terra Resources and Apache Corporation. In 1992 Mr. Robertson joined Key Production Company as its Senior Vice President and Chief Financial Officer. In 1999 he was appointed President and Chief Operating Officer of that company and served in that role until 2002. Other than his service on Cimarex’s board which began in October 2005, for the past five years Mr. Robertson has been a private investor. Mr. Robertson received a Bachelor of Science degree in Mechanical Engineering along with Master of Science degrees in both Mechanical Engineering and Nuclear Engineering from the Massachusetts Institute of Technology in 1973. He also has received a Masters Degree in Business Administration from National University in 1979. Mr. Robertson is a member of the National Association of Corporate Directors.
43
Directors are elected by the Company’s shareholders at each annual meetingthis report or in the case of a vacancy, are appointed by the directors then in office, to serve until the next annual meeting or until their successors are elected and qualified. Officers are appointed by and serve at the discretion of the Board of Directors. There are no family relationships between or among the Board of Directors.
Executive Officers
In February 2008, Mr. Flake resigned as an officer of the Company, and then as a director in October 2008. Prior to this, the Company’s executive officers were Ray Singleton and David Flake. Both were also board members. Subsequent to Mr. Flake’s resignation as an officer, we hired on a contract basis Joseph Young as Principal Accounting Officer. The names, ages, principal occupations and/or employment during the past five years are set forth above for Ray Singleton and below for Joseph Young. There are no family relationships between or among the officers and Board of Directors.
Joseph Young
Joseph Young (30) joined the Company in March 2008 as the Company’s Principal Accounting Officer, subsequent to the resignation of David Flake. Mr. Young began his public accounting career at PricewaterhouseCoopers in the Silicon Valley area, where he audited multiple public and private companies for financial reporting and Sarbanes-Oxley compliance. Since then, he has provided accounting, reporting, and compliance services to a variety of businesses within the oil and gas, mining and technology sectors. Mr. Young previously served as Chief Financial Officer for JayHawk Energy, Inc. and Controller for Fellows Energy, Inc. Mr. Young received his Bachelor of Arts degree in Accounting from the University of Utah in 2002.
Involvement in Certain Legal Proceedings
During the past five years, no present director or executive officer of the Company has been the subject matter of any of the following legal proceedings: (a) any bankruptcy petition filed by or against any business of which such person was a general partner or executive officer either at the time of the bankruptcy or within two years prior to that time; (b) any criminal convictions; (c) any order, judgment, or decree permanently or temporarily enjoining, barring, suspending or otherwise limiting his involvement in any type of business, securities or banking activities; or (d) any finding by a court, the SEC or the CFTC to have violated a federal or state securities or commodities law. Further, no such legal proceedings are believed to be contemplated by governmental authorities against any director or executive officer.
Corporate Governance
Independent Directors.Each of the Company’s directors, except for Mr. Singleton, qualifies as an “independent director” as defined under the published listing requirements of the American Stock Exchange. The independence definition includes a series of objective tests. For example, an independent director may not be employed by Basic and may not engage in certain types of business dealings with the Company. In addition, the Board has made a subjective determination as to each independent director that no relationship exists, which in the opinion of the Board, would interfere with the exercise of independent judgment in carrying out the responsibilities of a director. In making these determinations, the Board reviewed and discussed information provided by the directors and by the Company with regard to each director’s business and personal activities as they may relate to the Company and its management. Also, the Board determined that the members of the Audit Committee each qualify as “independent” under special standards established by the American Stock Exchange and the SEC for members of audit committees.
44
Audit Committee.The Board of Directors has a standing Audit Committee which, at March 31, 2009, consisted of Richard Rodgers and Monroe Robertson. During fiscal 2009 the Audit Committee met eight times. The Audit Committee is authorized to review, with the Company’s independent accountants, the annual financial statements of the Company prior to publication and to make annual recommendations to the Board for the appointment of independent public accountants for the ensuing year. It is the responsibility of the Audit Committee to review the effectiveness of the financial and accounting functions, operations, and internal controls implemented by Basic’s management.
The Board has certified both Mr. Robertson and Mr. Rodgers as financially literate, and Mr. Robertson as an “audit committee financial expert,” as defined under Regulation S-K under the Exchange Act. Both Mr. Robertson and Mr. Rodgers are considered “independent directors” under the listing standards of the American Stock Exchange.
Compensation Committee.The Board of Directors has a standing Compensation Committee which, at March 31, 2009, consisted of Richard Rodgers and Monroe Robertson, both of whom are independent under the guidelines of the American Stock Exchange listing standards. Mr. Rodgers serves as the Committee’s chairman. The responsibilities of the Compensation Committee (the “Committee”) of the Board of Directors are three-fold: first, establishing and administering the general compensation policies of the Company, second, setting the specific compensation for the Company’s chief executive officer (CEO) and lastly, recommending to the Board of Directors the independent director compensation.
No interlocking relationship exists between the members of the Company’s Board of Directors or Compensation Committee and the board of directors or compensation committee of any other company.
Nominating Committee.The Board of Directors has a standing Nominating Committee which, at March 31, 2009, consisted of Richard Rodgers and Monroe Robertson.
No material changes have been made to the procedures by which security holders may recommend nominees to the Board of Directors since we filed with the Securities and Exchange Commission, on October 28, 2008, its definitive proxy statement for the 2008 Annual Meeting of Shareholders.our 2010 annual stockholders’ meeting and is incorporated by reference in this report.
Code of Ethics.We have adopted a Code of Ethics as defined in Regulation S-K that applies to our directors, principal executive and financial officer and persons performing similar functions. The Code of Ethics can be found on our website athttp://www.basicearth.net.
Compliance with Section 16(a) of the Securities Exchange Act
Section 16(a) of the Securities Exchange Act requires the Company’s officers and directors and shareholders of more than ten percent of the Company’s common stock to file reports of ownership and changes in ownership of the Company’s common stock with the Securities and Exchange Commission (SEC). Officers and directors are required by SEC regulations to furnish Basic with the information necessary for the Company to file all required Section 16(a) reports. During fiscal 2009 all required reports were filed timely.
45
ITEM 11
EXECUTIVE COMPENSATION
Summary Compensation Table
The following table sets forth the compensation paidInformation relating to this item will be included in an amendment to this report or accrued by the Company to its Chief Executive Officer and Principal Accounting Officer for fiscal 2009 and 2008. No other director, officer or employee received annual compensation that exceeded $100,000.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | Non-Equity | | | All | | | | |
| Name and | | Fiscal | | | Salary | | | Bonus | | | Incentive Plan | | | Other | | | Total | |
| Principal Position | | Year | | | ($) | | | ($) | | | Compensation | | | Compensation | | | ($) | |
| | | | | | | | | | | (1) | | | (2) | | | (3) | | | | | |
| Ray Singleton | | | 2009 | | | $ | 183,574 | | | $ | 29,307 | | | $ | 9,563 | | | $ | 6,073 | | | $ | 228,517 | |
| President and Chief Executive Officer | | | 2008 | | | $ | 134,250 | | | $ | 6,346 | | | $ | 4,053 | | | $ | 6,176 | | | $ | 150,825 | |
| |
| Joseph Young | | | 2009 | | | $ | 110,169 | | | $ | 5,000 | | | $ | — | | | $ | — | | | $ | 115,169 | |
| Principal Accounting Officer | | | | | | | | | | | | | | | | | | | | | | | | |
| | |
(1) | | The amount shown for each executive officer is the amount accrued for in prior periods and paid in fiscal 2009. |
|
(2) | | The amount shown for each executive officer is the amount accrued for fiscal 2009 and paid for fiscal 2008 through the Oil and Gas Incentive Compensation Plan. |
|
(3) | | For Mr. Singleton, amount includes matching funds contributed by the Company to its 401(k) plan of $5,826 and $5,204 for fiscal 2009 and 2008, respectively. It also includes $247 and $850 for premiums paid by the Company on a life insurance policy for Mr. Singleton during fiscal 2009 and 2008, respectively. Mr. Singleton designates the beneficiary. |
Effective April 1, 1980 the Company adopted an Oil and Gas Incentive Compensation Plan (the O&G Plan) for key employees. Through this O&G Plan, Basic pays to the O&G Plan participants, consisting of both former and current key employees, a portion of its net revenue (after deducting operating expenses) from certain properties. Under the O&G Plan rules, the portion of the net revenue contributed from any property cannot exceed 5% of the Company’s interest in that property. While payments are still made to the O&G Plan participants due to previous grants, the last time a new property was added to the O&G Plan was in 1988.
The participants in the O&G Plan made no cash outlay at the time of grantproxy statement for our 2010 annual stockholders’ meeting and is incorporated by reference in order to participate; it was entirely non-contributory, and an interest is not assignable, transferable, nor can it be pledged by the participant. Interest in the O&G Plan vested over a period ranging from four to eleven years. We can sell or otherwise transfer its interest in properties designated for the O&G Plan. If we sell a property in the O&G Plan, the participants shall receive their respective percentages of the sales price. There are currently five participants in the O&G Plan including Mr. Singleton. The other four participants are former officers who have vested interests in the O&G Plan ranging from 60 percent to 100 percent. Compensation paid or accrued through this plan to Mr. Singleton is included in the Other Annual Compensation column in the Executive Officer Compensation table above.
46
On July 27, 1995 the Board of Directors adopted the 1995 Incentive Stock Option Plan (the ISO Plan) and in October 1995, our shareholders approved the ISO Plan. The ISO Plan remained in effect for a period of ten years, expiring on July 26, 2005. This ISO Plan was established to provide a flexible and comprehensive stock option and incentive plan which permitted the granting of long-term incentive awards to employees, including officers and directors employed by us or our subsidiary, as a means of enhancing and strengthening our ability to attract and retain those individuals on whom the continued success of the Company most depends.report.
Of the 1,000,000 shares authorized under the ISO Plan, prior to its expiration, options for only 665,000 shares were granted. Of that amount and as of March 31, 2009, 50,000 options expired unexercised, and 615,000 options were exercised at strike prices ranging from $0.0325 to $0.175 per share.
In October 1997 we implemented a savings plan that allows participants to make contributions by salary reduction pursuant to Section 401(k) of the Internal Revenue Code. Employees are required to work for the Company one year before they become eligible to participate in the 401(k) Plan. The Company matches 100% of the employee’s contribution up to 3% of the employee’s salary. Contributions are vested when made. Contributions to the 401(k) Plan on behalf of Mr. Singleton are also included in the All Other Compensation column in the Summary Compensation Table above.
Outstanding Equity Awards at Fiscal Year End
As of March 31, 2009, there were no outstanding equity option awards held by either executive officer or by any of the directors.
We have no contract with any officer which would give rise to any cash or non-cash compensation resulting from the resignation, retirement or any other termination of such officer’s employment with the Company or from a change in control of the Company or a change in any officer’s responsibilities following a change in control.
Director Compensation
Prior to fiscal 2008, directors received no cash compensation for their services to the Company as directors, but were reimbursed for out-of-pocket expenses incurred to attend board meetings. However, from July 1995 until its expiration in July 2005, the Incentive Stock Option Plan (“the ISO Plan”), noted above, provided eligible, non-employee members of the Board of Directors of Basic or its subsidiaries (Non-Employee Directors), grants of certain options to purchase common stock of the Company, as compensation for their services. During the years the ISO Plan was active, 425,000 non-qualified options were granted to independent directors: 175,000 to David Flake, our former CFO, who was then an outside director of the Company. As of March 31, 2009, there were no unexercised stock options.
On March 8, 2007, the Board of Directors adopted a new Director Compensation Plan. On April 12, 2007 the Board of Directors resolved issues concerning the Plan and then ratified the Plan effective April 1, 2007.
With respect to this Plan, independent director compensation consists of a cash retainer, meeting fees, committee fees and stock grants. Independent directors receive an annual cash retainer of $16,000, in addition to $2,000 and $500 for quarterly board meetings and committee meetings (which take place as needed), respectively. Committee chairpersons of the Audit, Compensation, and Nominating Committees receive $5,500, $4,500 and $3,500, respectively. Additionally, independent board members receive an annual stock grant equal to $36,000 vested over three years. The number of shares included in each grant is calculated based upon the average closing price of the ten trading days preceding each April 1st anniversary date. Thus, effective April 1, 2008 and April 1, 2009, subject to vesting, Messrs. Robertson and Rodgers are entitled to stock grants of 36,036 and 44,888 shares each, respectively.
47
| | | | | | | | | | | | | | | | | |
| | | Fees Earned or | | | | | | | All Other | | | | |
| | | Paid in Cash | | | Stock Awards | | | Compensation | | | Total | |
| Name | | ($) | | | ($) | | | ($) | | | ($) | |
| | | | | | | (1) | | | | | | | | | |
| Richard Rodgers | | $ | 33,000 | | | $ | 36,000 | | | $ | — | | | $ | 69,000 | |
| Monroe Robertson | | | 34,000 | | | | 36,000 | | | | — | | | | 70,000 | |
| | | | | | | | | | | | | |
| Total | | | 67,000 | | | | 72,000 | | | | — | | | | 139,000 | |
| | | | | | | | | | | | | |
| | |
(1) | | The amount shown for each director is the amount awarded each year vesting over a three year period. |
ITEM 12
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Set forth below, as of June 18, 2009,
Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2010 annual stockholders’ meeting and is information concerning stock ownership of all persons, or group of persons, knownincorporated by the Company to own beneficially 5% or more of the shares of Basic’s common stock and all directors and executive officers of the Company, both individually and as a group, who held such positionsreference in fiscal 2009. Basic has no knowledge of any other persons, or group of persons, owning beneficially more than 5% of the outstanding common stock of the Company as of March 31, 2009.this report.
| | | | | | | | | | | | | |
| | | | | | | Shares of | | | Percent of | |
| | | | | | | Common | | | Outstanding | |
| | | | | | | Stock | | | Shares | |
| | | | | | | Beneficially | | | Beneficially | |
| Name and Address of Beneficial Owner | | Type and Class | | | Owned | | | Owned | |
| | | | | | | | | | | | | |
| Ray Singleton, Denver CO (a) | | Common Stock | | | 4,505,912 | | | | 25.7 | % |
| | | | | | | | | | | | | |
| Richard Rodgers, Denver, CO (c) | | Common Stock | | | 7,571 | | | | | (d) |
| | | | | | | | | | | | | |
| Monroe W. Robertson, Denver, CO (d) | | Common Stock | | | 13,471 | | | | | (d) |
| | | | | | | | | | | |
| | | | | | | | | | | | | |
| All officers and directors as a group (3 persons) (a), (b), and (c) | | Common Stock | | | 4,526,954 | | | | 25.7 | % |
| | |
(a) | | All 4,505,912 shares are owned directly by Mr. Singleton. |
|
(b) | | All 7,571 shares are fully vested and owned directly by Mr. Rodgers |
|
(c) | | All 13,471 shares are fully vested and owned directly by Mr. Robertson. |
|
(d) | | Less than 1% |
Company management knows of no arrangements that may result in a change in control of Basic.
48
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
It is Company policy that officersAND DIRECTOR INDEPENDENCE
Information relating to this item will be included in an amendment to this report or directors may assign to or receive assignments from Basic in oil and gas prospects only on the same terms and conditions as accepted by independent third parties. It is also the policy of Basic that officers or directors and Basic may participate together in oil and gas prospects generated by independent third parties only on the same terms and conditions as accepted by each other.
With respect to prospects initiated during either fiscal 2009 or 2008, none of Basic’s officers or directors participated with the Company. However, in previous years, Mr. Singleton participated with the Company in certain acquisitions. With respect to his working interest in the four wellsproxy statement for our 2010 annual stockholders’ meeting and is incorporated by reference in which he currently has a working interest, at March 31, 2009 Mr. Singleton had a balance owed to the Company of less than $1,000 compared to a balance due to him of approximately $2,000 at March 31, 2008. This was due to his share of operating expenses exceeding the amount due to him for his share of oil and gas revenue from these wells.this report.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
The following table discloses
Information relating to this item will be included in an amendment to this report or in the fees that the Company was billed (and anticipates being billed)proxy statement for professional services renderedour 2010 annual stockholders’ meeting and is incorporated by its independent public accounting firmreference in eachthis report.
| | | | | | | | | |
| | | Years Ended | |
| | | March 31, | |
| | | 2009 | | | 2008 | |
| Audit fees (1) | | $ | 92,000 | | | $ | 70,000 | |
Audit-related fees(2) | | | 4,000 | | | | — | |
Tax fees(3) | | | — | | | | 11,500 | |
All other fees(4) | | | — | | | | — | |
| | | | | | | |
| |
| Total | | $ | 96,000 | | | $ | 81,500 | |
| | | | | | | |
Part IV
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
| (a) | | |
(1) | | Reflects fees billed for the auditDocuments filed as part of the Company’s consolidated financial statements included in its Form 10-K and review of its quarterly reportsthis Annual Report on Form 10-Q.10-K. |
|
(2) | | Reflects fees, if any, for services related to financial accounting and reporting matters. |
|
(3) | | Reflects fees billed for tax compliance, tax advice and preparation of the Company’s federal tax return. |
|
(4) | | Reflects fees, if any, for other products or professional services not related to the audit of the Company’s consolidated financial statements and review of its quarterly reports, or for tax services. |
Pre-Approval Policies and Procedures
The Audit Committee approves all audit, audit-related services, tax services and other services provided. Any services provided that are not specifically included within the scope of the audit must be pre-approved by the Audit Committee in advance of any engagement. Under the Sarbanes-Oxley Act of 2002, audit committees are permitted to approve certain fees for audit-related services, tax services and other services pursuant to a de minimus exception prior to the completion of an audit engagement. In fiscal 2009, none of the fees paid to Ehrhardt Keefe Steiner & Hottman PC were approved pursuant to the de minimus exception.
49
Part IV
ITEM 15
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
Exhibits
| | | | | |
Exhibit | | (1) | | Financial Statements |
| | | | All financial statements as set forth under Item 8 of this report. |
| | | | |
| | (2) | | Supplementary Financial Statement Schedules |
| | | | None. |
| | | | |
| | (3) | | Exhibits |
| | | | See (b) below |
| | | | |
| (b) | | Exhibits |
| | | | |
| | The following exhibits are filed pursuant to Item 601 of Regulation S-K: |
| | |
| Exhibit No. | | Document |
| 3i | 13(i)a | | Restated Certificate of Incorporation includedof Earthstone Energy, Inc., effective May 12, 1981, as amended by (i) Certificate of Amendment of Certificate of Incorporation, effective November 20, 1986; (ii) Certificate of Amendment of Certificate of Incorporation, effective July 1, 1996; and (iii) Certificate of Designations of Series A Junior Participating Preferred Stock, effective February 5, 2009, incorporated by reference to Exhibit 3(i) of our Quarterly Report on Form 10-Q for the quarter ended December 31, 2009, filed with the SEC on February 17, 2009. |
| 3(i)b | | Amended and Restated Certificate of Incorporation as approved by stockholders of the Company at the Company’s 2009 Annual Meeting of Stockholders and the amendments to the Company’s Certificate of Incorporation previously disclosed in Basic’sthe Company’s proxy statement on Schedule 14A filed with the Securities and Exchange Commission on November 5, 2009, incorporated by reference to Exhibit 3(i) on Form 8-K filed with the SEC on March 3, 2010. |
| 3(ii)a | | Bylaws of Earthstone Energy, Inc., dated July 15, 1986, as amended by First Amendment to Bylaws, dated February 4, 2009, incorporated by reference to Exhibit 3(ii) of our Quarterly Report on Form 10-Q for the quarter ended December 31, 2009, filed with the SEC on February 17, 2009. |
| 3(ii)b | | Amended and Restated Bylaws reflecting recent changes made to the Company’s Certificate of Incorporation to remove certain outdated and redundant provisions that existed in our prior bylaws with respect to corporate governance, stockholder and director meeting procedures, and indemnification procedures. Changes to the bylaws include, among other things: (i) amendments to reflect the new name of the Company; (ii) expansion of certain provisions with respect to stockholders’ meetings and record dates; (iii) amendments in respect of corporate governance, board committees, and board meetings; (iv) amendments to certain provisions in respect of officers and their duties; (v) amendments to certain provisions in respect of share certificates; and (vi) removal of indemnification provisions are incorporated by reference to Exhibit 3(ii) on Form 8-K filed with the SEC on March 3, 2010. |
| 4.1 | | Rights Agreement, dated February 4, 2009, between Earthstone Energy, Inc. and Corporate Stock Transfer, Inc., incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K., filed with the SEC on February 5, 2009. |
| 10.1* | | Oil and Gas Incentive Compensation Plan, dated April 1, 1980, as amended, incorporated by reference to our Annual Report on Form 10-K for the fiscal year ended March 31, 19811985, filed with the SEC. |
| 3i | 1(b) | | By-laws included in Basic’s Form S-1 filed October 24, 1980Exhibits (continued) |
| 3i | 1Exhibit No. | | Certificate of Amendment to Basic’s Restated Certificate of Incorporation dated March 31, 1996Document |
| 10(i)a | 110.2 | | Loan Agreement, dated March 4, 2002, between The Bank of Cherry Creek and Basic, datedEarthstone, incorporated by reference to Exhibit 10(i)a of our Annual Report on Form 10-KSB for the fiscal year ended March 4,31, 2002, |
| 10(i)a | 1 | | filed with the SEC on June 28, 2002; as amended by Amended Loan Agreement, dated January 3, 2006, between American National Bank (formerly The Bank of Cherry Creek) and Basic dated January 3, 2006. |
| Earthstone, incorporated by reference to Exhibit 10(i)a | 1 | | of our Annual Report on Form 10-KSB for the fiscal year ended March 31, 2006, filed with the SEC on July 14, 2006; and as further amended by Amended Loan Agreement, dated December 31, 2006, between American National Bank (formerly The Bankand Earthstone, incorporated by reference to Exhibit 10(i)a of Cherry Creek) and Basic dated December 31, 2006 |
| 10(ii) | 1 | | Oil and Gas Incentive Compensation Plan included in Basic’sour Annual Report on Form 10-K10-KSB for the fiscal year ended March 31, 19852009, filed with the SEC on June 29, 2007. |
| 10(ii) | 110.3* | | Performance Bonus Plan, dated effective April 1, 2007, incorporated by reference to Exhibit 10.3 of our Amended 10-K/A, filed with the SEC on October 9, 2009. |
| 10.4* | | Director Compensation Plan, dated effective April 1, 2007, incorporated by reference to Exhibit 10.4 of our Amended 10-K/A, filed with the SEC on October 9, 2009 as amended by board resolution dated March 31, 2010, filed herewith. |
| 10.5* | | Form of Restricted Stock Agreement dated effective aspursuant to the Director Compensation Plan, incorporated by reference to Exhibit 10(ii) of April 7, 2007 |
| 21 | 1 | | Subsidiaries of Basic included in Basic’sthe Annual Report on Form 10-KSB for the fiscal year ended March 31, 20022008, filed with the SEC on July 11, 2008. |
| 31.110.6* | | Part-Time Employment and Confidentiality Agreement, effective March 31,2008, between Joseph Young and Earthstone, incorporated by reference to Exhibit 10.6 of our Amended 10-K/A, filed with the SEC on October 9, 2009. |
| 14.1 | | Code of Business Conduct and Ethics, incorporated by reference to Exhibit 14.1 of our Annual Report on Form 10-KSB/A for the fiscal year ended March 31, 2004, filed with the SEC on May 11, 2005. |
| 16.1 | | Letter Regarding Change in Certifying Accountant, incorporated herein by reference to Exhibit 16.1 of our Current Report on Form 8-K, filed with the SEC on July 21, 2008. |
| 21 | | List of Subsidiaries of Earthstone, incorporated by reference to Exhibit 21 of our Amended 10-K/A, filed with the SEC on October 9, 2009. |
| | Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Ray Singleton, Chief Executive Officer) |
| | | | Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Joseph Young, Principal Accounting Officer) |
| | | | Certification Pursuant to 18 U.S.C. §1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Ray Singleton, Chief Executive Officer) |
| | | | Certification Pursuant to 18 U.S.C. §1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Joseph Young, Principal Accounting Officer). |
| | Nominating Committee Charter, adopted September 28, 2009, incorporated by reference to Exhibit 99.1 of our Amended 10-K/A, filed with the SEC on October 9, 2009. |
199.2 | | PreviouslyCompensation Committee Charter, adopted September 28, 2009, incorporated by reference to Exhibit 99.2 of our Amended 10-K/A, filed and incorporated herein by referencewith the SEC on October 9, 2009. |
| | Report of Ryder Scott Company filed herewith. |
Other exhibits and schedules are omitted because they are not applicable, not required or the information is included in the financial statements or notes thereto.
50
| * | | Indicates management contracts or compensatory plans or arrangements required to be filed as exhibits pursuant to Item 15 of Form 10-K. |
In accordance with the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this reportamendment to be signed on its behalf by the undersigned, thereunto duly authorized.authorized by the following in the capacities and on the dates indicated.
BASIC EARTH SCIENCE SYSTEMS,
EARTHSTONE ENERGY, INC.
| | | | | | |
| | | Date |
| | | Date |
By: /s/ Ray Singleton | | June 18, 2010 |
| | |
Ray Singleton, President | | |
| | | |
By: /s/ Joseph Young | | June 18, 2010 |
| | | |
| | | | | | |
By: | | /s/ Ray Singleton | | June 18, 2009 | | |
| | Ray Singleton, President | | | | |
| | | | | | |
By: | | /s/ Joseph Young | | June 18, 2009 | | |
| | Joseph Young, | | | | |
| | Principal Accounting Officer | | | | |
In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
| | | | | | |
| Name and Capacity | | Date |
| | | |
By: /s/ Ray Singleton | | June 18, 2010 |
| | | |
| Ray Singleton, Director | | |
| | | |
By: /s/ Richard K. Rodgers | | June 18, 2010 |
| | | |
By: | | /s/ Ray Singleton | | June 18, 2009Richard K. Rodgers, Director and | | |
| | Ray Singleton, Director | | Compensation Committee Chairman | | |
| | | |
By: /s/ Monroe W. Robertson | | June 18, 2010 |
| | | |
By: | | /s/ Richard K. Rodgers | | June 18, 2009 | | |
| | Richard K. Rodgers, Director and | | | | |
| | Compensation Committee Chairman | | | | |
| | | | | | |
By: | | /s/ Monroe W. Robertson | | June 18, 2009 | | |
| | Monroe W. Robertson, Director and | | | | |
| | Audit Committee Chairman | | | | |
51
EXHIBIT INDEX
Exhibits
| | | | |
Exhibit | | |
No. | | Document |
| 3i | 1 | | Restated Certificate of Incorporation included in Basic’s Form 10-K for the year ended March 31, 1981 |
| 3i | 1 | | By-laws included in Basic’s Form S-1 filed October 24, 1980 |
| 3i | 1 | | Certificate of Amendment to Basic’s Restated Certificate of Incorporation dated March 31, 1996 |
| 10(i)a | 1 | | Loan Agreement between The Bank of Cherry Creek and Basic, dated March 4, 2002 |
| 10(i)a | 1 | | Amended Loan Agreement between American National Bank (formerly The Bank of Cherry Creek) and Basic dated January 3, 2006. |
| 10(i)a | 1 | | Amended Loan Agreement between American National Bank (formerly The Bank of Cherry Creek) and Basic dated December 31, 2006 |
| 10(ii) | 1 | | Oil and Gas Incentive Compensation Plan included in Basic’s Form 10-K for the year ended March 31, 1985 |
| 10(ii) | 1 | | Restricted Stock Agreement dated effective as of April 7, 2007 |
| 21 | 1 | | Subsidiaries of Basic included in Basic’s Form 10-KSB for the year ended March 31, 2002 |
| 31.1 | | | Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Ray Singleton, Chief Executive Officer) |
| 31.2 | | | Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Joseph Young, Principal Accounting Officer) |
| 32.1 | | | Certification Pursuant to 18 U.S.C. §1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Ray Singleton, Chief Executive Officer) |
| 32.2 | | | Certification Pursuant to 18 U.S.C. §1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Joseph Young, Principal Accounting Officer). |
| | |
1 | | Previously filed and incorporated herein by reference |
Other exhibits and schedules are omitted because they are not applicable, not required or the information is included in the financial statements or notes thereto.
52
